Item 1. BUSINESS.
TECO ENERGY
TECO Energy, Inc. (TECO Energy) was incorporated in Florida in 1981 as part of a restructuring in which it became the parent corporation of Tampa Electric Company. TECO Energy and its subsidiaries had 5,200 employees as of Dec. 31, 2006.
TECO Energy’s Corporate Governance Guidelines, the charter of each committee of the Board of Directors, and the code of ethics applicable to all directors, officers and employees, the Standards of Integrity, are available in the Investors section of TECO Energy’s website, www.tecoenergy.com, or in print free of charge to any investor who requests the information. TECO Energy also makes its Securities and Exchange Commission (SEC) (www.sec.gov) filings available free of charge on the Investors section of TECO Energy’s website as soon as reasonably practicable after they are filed with or furnished to the SEC.
TECO Energy is a holding company for regulated utilities and other unregulated 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., the other subsidiaries listed below. Unless otherwise indicated by the context, “TECO Energy” means the holding company, TECO Energy, Inc., and its subsidiaries, and references to individual subsidiaries of TECO Energy, Inc. refer to that company and its respective subsidiaries. TECO Energy’s significant business segments, and revenues for those segments for the years indicated, are identified below.
Tampa Electric Company, a Florida corporation and TECO Energy’s largest subsidiary, has two business segments. Its Tampa Electric division (Tampa Electric) provides retail electric service to more than 661,000 customers in West Central Florida with a net winter system generating capability of 4,383 megawatts (MW). Peoples Gas System (PGS), the other 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 332,000 customers, PGS has operations in Florida’s major metropolitan areas. Annual natural gas throughput (the amount of gas delivered to its customers, including transportation-only service) in 2006 was 1.3 billion therms.
TECO Coal Corporation (TECO Coal), a Kentucky corporation, has 13 subsidiaries, located in Eastern Kentucky, Tennessee and Virginia. These entities own interests in coal processing and loading facilities, synthetic fuel production facilities and mineral rights, and own or operate surface and underground mines.
TECO Transport Corporation (TECO Transport), a Florida corporation, owns no operating assets but owns all of the common stock of, or membership interests in, nine subsidiaries which provide waterborne transportation, storage and transfer services of coal and other dry-bulk commodities.
TECO Guatemala, Inc. (TECO Guatemala), a Florida corporation, primarily has investments in unconsolidated subsidiaries that participate in independent power projects and electric distribution in Guatemala.
TWG Merchant, Inc. (TWG Merchant), a Florida corporation, had subsidiaries that formerly held interests in merchant power projects. TWG Merchant continuing operations included the results of operations for the Dell power plant, which was sold in 2005 and the uncompleted McAdams power plant, the turbines from which were sold to Tampa Electric in 2006 and the balance of the plant sold to an unrelated party in 2006. Effective with 2006 results, all assets were divested and any residual results of operations were included in the “Other and eliminations” segment.
Revenues from Continuing Operations
(1)
Revenues are exclusive of entities deconsolidated as a result of Financial Accounting Standards Board Interpretation No. 46R, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 (FIN 46R) and include only revenues for the consolidated Guatemalan entities.
For additional financial information regarding TECO Energy’s significant business segments including geographic areas, see Note 14 to the TECO Energy Consolidated Financial Statements. Also, see Note 19 for additional information regarding the deconsolidation of Guatemala subsidiaries and its related revenues as of Jan. 1, 2004.
Discontinued Operations/Asset Dispositions
TECO Energy completed a number of asset dispositions in 2006, 2005, and 2004 as part of a business strategy to focus on the electric and gas utilities and long-term profitable unregulated businesses and to reduce exposure to the merchant power sector.
In the first quarter of 2006, TPS McAdams, LLC (TPS McAdams), an indirect subsidiary of the company, sold combustion turbines to Tampa Electric Company and in the second quarter, all remaining assets of TPS McAdams were sold to a third party. Also in the second quarter, the company sold the remaining assets of TECO Thermal which were classified as held for sale as of Dec. 31, 2005. Two remaining steam turbines located in Arizona were sold in the last half of 2006.
In 2005, TWG Merchant sold its membership interest in Commonwealth Chesapeake Power Station (CCC) in Virginia and substantially all the assets of the Dell Power Station in Arkansas. BCH Mechanical, Inc. (BCH Mechanical) was also sold in 2005.
In 2004, TWG Merchant completed both the sale of its 50% indirect interest in Texas Independent Energy, LP (TIE) and the sale of Frontera Generation Limited Partnership (Frontera), the owner of the Frontera Power Station in Texas. In 2004, TECO Guatemala sold its 50% indirect interest in the Hamakua Power Station (Hamakua) in Hawaii. TECO BGA, Inc. (TECO BGA), TECO AGC, Ltd. (TECO AGC), and substantially all the assets of Prior Energy were also sold in 2004. Also in 2004, TECO Energy completed the sale of its general and limited partnership interests in Heritage Propane Partners, L.P. as part of a larger transaction that involved the merging of privately held Energy Transfer Company with Heritage Propane Partners.
Results for CCC, BCH Mechanical, TECO Thermal, Frontera, Prior Energy, TECO BGA, and TECO AGC have been accounted for as discontinued operations for all periods reported. Revenues from these discontinued operations were $0.8 million, $10.6 million and $141.7 million in 2006, 2005 and 2004, respectively (see Notes 16 and 20 to the TECO Energy Consolidated Financial Statements). Included in continuing operations prior to their respective sales were the results of the Dell Power Station, TIE, Hamakua and our interest in TECO Propane Ventures.
In 2005, TECO Energy completed the sale and transfer of the Union and Gila River project companies (see Notes 16 and 20 to the TECO Energy Consolidated Financial Statements). TPGC’s results are accounted for as discontinued operations for 2005 and 2004. Revenues from the discontinued operations of TPGC in 2005 and 2004 were $109.1 million and $510.7 million, respectively. Net income (loss) from the discontinued operations of TPGC were $65.1 million and $(96.0) million in 2005 and 2004, respectively.
TAMPA ELECTRIC - Electric Operations
Tampa Electric Company was incorporated in Florida in 1899 and was reincorporated in 1949. Tampa Electric Company is a public utility operating within the state of Florida. 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 located near Sebring, a city located in Highlands County in South Central Florida.
Tampa Electric had 2,452 employees as of Dec. 31, 2006, of which 897 were represented by the International Brotherhood of Electrical Workers and 237 were represented by the Office and Professional Employees International Union.
In 2006, approximately 46% of Tampa Electric’s total operating revenue was derived from residential sales, 29% from commercial sales, 8% from industrial sales and 17% from other sales, including bulk power sales for resale. The sources of operating revenue and megawatt-hour sales for the years indicated were as follows:
No significant part of Tampa Electric’s business is dependent upon a single customer or a few customers, the loss of any one or more of whom would have a significant adverse effect on Tampa Electric. The Mosaic Company, a large phosphate producer, is Tampa Electric’s largest customer and represents less than 3% of Tampa Electric’s 2006 base revenues.
Tampa Electric’s business is not highly seasonal, but winter peak loads are experienced due to electric heating, fewer daylight hours and colder temperatures, and summer peak loads are experienced due to the use of air conditioning and other cooling equipment.
Regulation
The retail operations of Tampa Electric are regulated by the Florida Public Service Commission (FPSC), which has jurisdiction over retail rates, quality of service and reliability, issuances of securities, planning, siting and construction of facilities, accounting and depreciation practices, and other matters.
In general, the FPSC’s pricing objective is to set rates at a level that allows the utility to collect total revenues (revenue requirements) equal to its cost of providing service, plus a reasonable return on invested capital.
The costs of owning, operating and maintaining the utility system, other than fuel, purchased power, conservation and certain environmental costs, are recovered through base rates. These costs include operation and maintenance expenses, depreciation and taxes, as well as a return on Tampa Electric’s investment in assets used and useful in providing electric service (rate base). The rate of return on rate base, which is intended to approximate Tampa Electric’s weighted cost of capital, primarily includes its costs for debt, deferred income taxes at a zero cost rate and an allowed return on common equity. Base rates are determined in FPSC rate setting hearings which occur at irregular intervals at the initiative of Tampa Electric, the FPSC or other parties.
Tampa Electric’s rates and allowed return on equity (ROE) range of 10.75% to 12.75% with a midpoint of 11.75% are in effect until such time as changes are occasioned by an agreement approved by the FPSC or other FPSC actions as a result of rate or other proceedings initiated by Tampa Electric, the FPSC or other interested parties.
Fuel, purchased power, conservation and certain environmental costs are recovered through levelized monthly charges established pursuant to the FPSC’s cost recovery clauses. These charges, which are reset annually in an FPSC proceeding, are based on estimated costs of fuel, environmental compliance, conservation programs and purchased power and estimated customer usage for a specific recovery period, with a true-up adjustment to reflect the variance of actual costs from the projected costs. The FPSC may disallow recovery of any costs that it considers imprudently incurred.
In September 2006, Tampa Electric filed with the FPSC for approval of fuel and purchased power, capacity, environmental and conservation cost recovery rates for the period January 2007 through December 2007. In November 2006, the FPSC approved Tampa Electric’s requested changes. The rates include the impacts of natural gas and coal prices expected in 2007, the collection of the underestimated 2006 fuel and purchased power expenses, the collection of previously unrecovered 2005 fuel and purchased power expenses, the proceeds from the actual and projected sale of excess sulfur dioxide (SO2) emissions allowances in 2006 and 2007 and the operating cost for and a return on the capital invested in the first pre-selective catalytic reduction (SCR) project to enter service on Big Bend Unit 4 as well as the operating and maintenance (O&M) costs associated with the Big Bend Units 1 - 3 pre- SCR projects, which are required by the Environmental Protection Agency (EPA) Consent Decree and Florida Department of
Environmental Protection (FDEP) Consent Final Judgment. In addition, the rates reflect the FPSC’s September 2004 decision to reduce the annual cost recovery amount for water transportation services for coal and petroleum coke provided under Tampa Electric’s contract with TECO Transport described below. See Regulation-Cost Recovery Clauses-Tampa Electric sections of MD&A.
Tampa Electric is also subject to regulation by the Federal Energy Regulatory Commission (FERC) in various respects, including wholesale power sales, certain wholesale power purchases, transmission services, and accounting and depreciation practices. In June 2006, Tampa Electric received a notice that FERC had commenced an audit, which arose out of the normal course of the enforcement activities, to determine whether and how Tampa Electric and its affiliates complied with: (1) the practices and procedures contained within its Open Access Transmission Tariff (OATT); (2) the conditions by which FERC granted market-based rate authority to each respective affiliate of Tampa Electric; (3) the Standards of Conduct requirements; (4) the preservation of records requirements; (5) Tampa Electric’s wholesale fuel adjustment clause tariff; and (6) Tampa Electric’s reporting of capacity and energy shortages. It is anticipated that the audit will be complete in the first half of 2007. See also the Regulation - Regional Transmission Organization (RTO) and FERC Audit sections 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 effective Feb 8, 2006. TECO Energy is a holding company that was exempt from the provisions of the PUHCA of 1935, as amended except for Section 9(c)(2).
Federal, state and local environmental laws and regulations cover air quality, water quality, land use, power plant, substation and transmission line siting, noise and aesthetics, solid waste and other environmental matters (see Environmental Matters section below).
The transactions between Tampa Electric and its affiliates are subject to regulation by the FPSC and FERC, and any charges deemed to be imprudently incurred may be disallowed for recovery from Tampa Electric’s customers. For information about Tampa Electric’s contract for coal transportation and dry-bulk storage services with TECO Transport, see the Regulation - Coal Transportation Contract section of MD&A.
Competition
Tampa Electric’s retail electric business is substantially free from direct competition with other electric utilities, municipalities and public agencies. At the present time, the principal form of competition at the retail level consists of self-generation available to larger users of electric energy. Such users may seek to expand their alternatives through various initiatives, including legislative and/or regulatory changes that would permit competition at the retail level. Tampa Electric intends to retain and expand its retail business by managing costs and providing high-quality service to retail customers.
In 1999, the FERC approved a three-year market-based sales tariff for Tampa Electric, which allows Tampa Electric to sell excess wholesale power at market prices within Florida. The FERC had already approved market-based prices for interstate sales for Tampa Electric and the other investor-owned utilities (IOUs) operating in the state; however, Tampa Electric is the only IOU in the state with intrastate market-based sales authority.
In November 2004, Tampa Electric and the market-based rate authorized entities within TECO Energy filed a triennial market power study update. On Mar. 2, 2005, after a review of that filing and supporting information, the FERC determined that Tampa Electric had failed certain tests for market power within certain regions of Florida. The FERC instituted an investigation of Tampa Electric's potential market power in those regions and ordered Tampa Electric to make a compliance filing to determine if Tampa Electric has market power in other regions of the state. Tampa Electric submitted compliance filings after which FERC staff requested additional information to rebut the presumption that Tampa Electric has generation market power, which Tampa Electric submitted in September 2005. In November 2005, FERC found that Tampa Electric did have generation market power in its own control and within the area served by Reedy Creek. Rather than continuing to contest FERC’s conclusion, Tampa Electric agreed to limit itself to only conducting wholesale cost-based transactions in these two parts of Florida. After gathering additional data and performing an updated market analysis, Tampa Electric filed to reinstate its ability to utilize market pricing for energy transactions with Reedy Creek in November 2006. FERC approved Tampa Electric’s reinstatement request and the company is once again able to transact with Reedy Creek at market-determined prices, which will provide benefits for both entities.
There is presently competition in Florida’s wholesale power markets, largely as a result of the Energy Policy Act of 1992 and related federal initiatives. However, the state’s Power Plant Siting Act, which sets the state’s electric energy and environmental policy and governs the building of new generation involving steam capacity of 75 megawatts or more, requires that applicants demonstrate that a plant is needed prior to receiving construction and operating permits. In 2003, the FPSC implemented rules that modified rules from 1994 that required IOUs to issue requests 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. The new rules became effective for requests for proposal for applicable capacity additions, prospectively. See Regulation - Utility Competition - Electric section of MD&A.
FERC requires transmission system owners to operate an Open Access Non-discriminatory Transmission, Standard Costs, Same-time Information System (OASIS) providing, via the Internet, access to transmission service information (including price and availability) and to rely exclusively on their own OASIS system for such information for purposes of their own wholesale power transactions. This rule works to open access for wholesale power flows on transmission systems and requires utilities such as Tampa Electric, which own transmission facilities, to provide services to wholesale transmission customers comparable to those they provide to themselves on comparable terms and conditions, including price. Among other things, the rules require transmission services to be unbundled from power sales and owners of transmission systems to take transmission service under their own transmission tariffs. To facilitate compliance, owners must maintain Standards of Conduct to ensure that personnel involved in marketing wholesale power are functionally separated from personnel involved in transmission services and reliability functions. Tampa Electric, together with other utilities, has an OASIS system and believes it is in compliance with the Standards of Conduct.
In 2004, FERC also issued Standards of Conduct for Transmission Providers to ensure that all transmission customers, affiliated and non-affiliated, are treated on a non-discriminatory basis and required TECO Energy affiliates have implemented programs to ensure compliance.
Fuel
Approximately 62% of Tampa Electric’s generation of electricity for 2006 was coal-fired, with natural gas representing approximately 37% and oil representing approximately 1%. Tampa Electric used its generating units to meet approximately 87% of the system load requirements, with the remaining 13% coming from purchased power. Tampa Electric’s average delivered fuel cost per million British thermal unit (Btu) and average delivered cost per ton of coal burned, have been as follows:
Tampa Electric’s generating stations burn fuels as follows: Bayside 1, which entered commercial operation in April of 2003, and Bayside 2, which entered commercial operation in January of 2004, burn natural gas; Big Bend Station, which has sulfur dioxide scrubber capabilities, burns a combination of high-sulfur coal, petroleum coke and No. 2 fuel oil; Polk Power Station burns a blend of low-sulfur coal, and petroleum coke which is gasified and subject to sulfur and particulate matter removal prior to combustion, natural gas and oil; and Phillips Station burns residual fuel oil.
Coal. Tampa Electric burned approximately 5.0 million tons of coal and petroleum coke during 2006 and estimates that its combined coal and petroleum coke consumption will be about 4.9 million tons for 2007. During 2006, Tampa Electric purchased approximately 81% of its coal under long-term contracts with nine suppliers, and approximately 19% of its coal and petroleum coke in the spot market. Tampa Electric expects to obtain approximately 77% of its coal requirements in 2007 under long-term contracts with seven suppliers and the remaining 23% in the spot market.
Tampa Electric’s long-term contracts provide for revisions in the base price to reflect changes in several important cost factors and for suspension or reduction of deliveries if environmental regulations should prevent Tampa Electric from burning the coal supplied, provided that a good faith effort has been made to continue burning such coal.
For information concerning transportation services by affiliated companies to Tampa Electric, see the TECO Transport section below.
In 2006, approximately 60% of Tampa Electric’s coal supply was deep-mined, approximately 31% was surface-mined and the remaining was a processed oil by-product known as petroleum coke. Federal surface-mining laws and regulations have not had any material adverse impact on Tampa Electric’s coal supply or results of its operations. Tampa Electric, however, cannot predict the effect of any future mining laws and regulations.
Natural Gas. As of Dec. 31, 2006, Tampa Electric has 90% of the expected gas needs for the January 2007 - September 2007 period and 80% for the October 2007 period under contract, and has already contracted for 40% of its November 2007 through March 2008 expected gas supply needs. Additional volume requirements in excess of expected gas needs are purchased on the short-term spot market.
Oil. Tampa Electric has agreements in place to purchase No. 2 oil, low sulfur No. 2 oil and No. 6 oil for its Big Bend, Polk and Phillips stations. All of these agreements have prices that are based on spot indices.
Franchises and Other Rights
Tampa Electric holds franchises and other rights that, together with its charter powers, govern the placement of Tampa Electric’s facilities on the public rights of way as it carries on its retail business in the localities it serves. The franchises specify the negotiated terms and conditions governing Tampa Electric’s use of public rights-of-way and other public property within the municipalities it serves during the term of the franchise agreement, and are irrevocable and not subject to amendment without the consent of Tampa Electric (except to the extent certain city ordinances relating to permitting and like matters are modified from time to time), although, in certain events, they are subject to forfeiture.
Florida municipalities are prohibited from granting any franchise for a term exceeding 30 years. None of the municipalities that have franchise agreements with Tampa Electric, except for the cities of Oldsmar and Temple Terrace, have reserved the right to purchase Tampa Electric’s property used in the exercise of its franchise if the franchise is not renewed. In the absence of such right to purchase, based on judicial precedent, if the franchise agreement is not renewed Tampa Electric would be able to continue to use public rights of way within the municipality, subject to reasonable rules and regulations imposed by the municipalities.
Tampa Electric has franchise agreements with 13 incorporated municipalities within its retail service area. These agreements have various expiration dates through September 2021.
Franchise fees payable by Tampa Electric, which totaled $35.0 million in 2006, are calculated using a formula based primarily on electric revenues and are collected on customers’ bills.
Utility operations in Hillsborough, Pasco, Pinellas and Polk Counties outside of incorporated municipalities are conducted in each case under one or more permits to use state or county rights-of-way granted by the Florida Department of Transportation or the county commissioners of such counties. There is no law limiting the time for which such permits may be granted by counties. There are no fixed expiration dates for the Hillsborough County, Pinellas County and Polk County agreements. The agreement covering electric operations in Pasco County expires in 2023.
Environmental Matters
Consent Decree
Tampa Electric Company, as a result of negotiations with the EPA, the U.S. Department of Justice and the FDEP, signed a Consent Decree which became effective Feb. 29, 2000, and a Consent Final Judgment which became effective Dec. 6, 1999, both in 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 that has and will in the future dramatically decrease emissions from the company’s power plants.
The emission reduction requirements included specific detail with respect to the availability of the flue gas desulfurization systems (scrubbers) to help reduce SO2, projects for NOx reduction efforts on Big Bend Units 1 through 4, and the repowering of the coal-fired Gannon Station to natural gas. The commercial operation dates for the two repowered Gannon units (now known as Bayside) were Apr. 24, 2003 and Jan. 15, 2004. The completed station has total station capacity of about 1,800 megawatts (nominal) of natural gas-fueled electric generation.
Tampa Electric is installing SCRs for NOx control on Big Bend Unit 4, with an expected in-service date by Jun. 1, 2007. Tampa Electric is also installing SCRs on Big Bend Units 1, 2 and 3 with expected in-service dates for Unit 3 by May 1, 2008, Unit 2 by May 1, 2009 and Unit 1 by May 1, 2010. The engineering, design and construction of the SCRs are currently in progress. Tampa Electric’s capital investment forecast includes amounts through 2011 for compliance with the NOx, SO2 and particulate matter reduction requirements (see Environmental Matters - Capital Expenditures section below).
Emission Reductions
Projects to which Tampa Electric has committed under the Consent Decree and Consent Final Judgment will result in significant reductions in emissions. Since 1998, Tampa Electric has reduced annual SO2, NOx, and particulate matter (PM) emissions from its facilities by 160,000 tons, 41,000 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 Station remove more than 95% of the SO2 emissions from the flue gas streams.
The repowering of Gannon Station to Bayside Power Station in April 2003 (Bayside Unit 1) and January 2004 (Bayside Unit 2) resulted in the significant reduction in emissions of all pollutant types. Tampa Electric’s decision to install additional NOx emissions controls on all Big Bend Units will result in the further reduction of emissions. By 2010, these projects are expected to result in the total phased reduction of NOx by 62,000 tons per year, which is a 91% reduction from 1998 levels.
To date, these projects have resulted in the reduction of SO2, NOx and PM emissions by 93%, 65%, and 77%, respectively, below 1998 levels. In total, by 2010 Tampa Electric’s system-wide emission reduction initiatives will result in the reduction of SO2, NOx and PM emissions by 89%, 90%, and 72%, respectively, below 1998 levels. With these improvements in place, Tampa Electric’s facilities will meet the same standards required of newer power generating facilities and help to significantly enhance the quality of the air in the community.
Due to pollution control co-benefits from the Consent Decree and Consent Final Judgment, reductions in mercury emissions have occurred due to the re-powering of Gannon Station to Bayside Station. At Bayside, where mercury levels have decreased 99% below 1998 levels, there are virtually zero mercury emissions. Additional mercury reductions are also anticipated from the installation of NOx controls at Big Bend Station, which would lead to a mercury removal efficiency of approximately 70%.
Tampa Electric has supported voluntary efforts to reduce carbon emissions and has taken significant steps to reduce its overall emissions at its facilities. Since 1998, Tampa Electric has reduced its system-wide emissions of CO2 by approximately 19%, bringing emissions to below 1990 levels and through 2010, those reductions are expected to be very close to 1990 levels. Emissions of CO2 should remain near 1990 levels until the addition of the next base load unit which is expected after 2012. As of 2006, the repowering resulted in a decrease in CO2 emissions of approximately 4.0 million tons below 1998 levels. During this same timeframe, the numbers of retail customers and retail energy sales have risen by approximately 25%.
For information concerning potential new state and/or federal legislation limiting CO2 emissions, see the Environmental Compliance - Carbon Reductions section of MD&A.
Superfund and Former Manufactured Gas Plant Sites
Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a potentially responsible party (PRP) for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Dec. 31, 2006, Tampa Electric Company has estimated its ultimate financial liability to be approximately $12.3 million, with the majority attributable to the Peoples Gas division, and this amount has been reflected in the consolidated financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.
The estimated amounts represent only the estimated portion of the cleanup costs attributable to Tampa Electric Company. The estimates to perform the work are based on actual estimates obtained from contractors or Tampa Electric Company’s experience with similar work adjusted for site specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.
Allocation of the responsibility for remediation costs among Tampa Electric Company and other PRPs is based on each party’s relative ownership interest in or usage of a site. Accordingly, Tampa Electric Company’s share of remediation costs varies with each site. In virtually all instances where other PRPs are involved, those PRPs are considered creditworthy.
Factors that could impact these estimates include the ability of other PRPs to pay their pro rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. These costs may be recoverable through customer rates established in future base rate proceedings.
Capital Expenditures
During the five years ended Dec. 31, 2006, Tampa Electric spent $147.5 million, excluding the Gannon repowering, on capital additions to meet environmental requirements.
In total, Tampa Electric spent an estimated $78.5 million in 2006 on environmental projects. Environmental expenditures are estimated at $120.8 million for 2007 and an additional $223.7 million in total for 2008 through 2011. These totals include the expenditures required to comply with the EPA Consent Decree and to undertake comprehensive environmental operations improvements at Big Bend Station, the largest project of which is to install SCRs on each of the coal-fired units.
In 2006, Tampa Electric spent approximately $3.6 million for compliance with the EPA Consent Decree requirements at Big Bend Station for early NOx and PM emissions reductions and to improve the scrubber systems to reduce SO2 emissions. Estimated expenditures for the on-going early NOx emission reductions and to improve the scrubber systems in 2007 are estimated at $11.9 million and an additional $16.5 million in 2008-2011. In a letter dated Aug. 19, 2004, Tampa Electric notified the EPA that based on the results of a comprehensive study performed on Big Bend Station, Big Bend Units 1, 2, 3 and 4 would continue to be fired on coal and as such will comply with the applicable provisions of the Consent Decree associated with this decision, including installation of SCRs for the reduction of NOx. Based on this decision, $68.1 million was spent in 2006 to support the on-going design, engineering and construction of the SCRs. Additional expenditures will be required in 2007, estimated at $87.1 million, and it is forecast that $210.6 million will be spent from 2008 through 2011.
In addition, Tampa Electric is undertaking a number of large environmental projects at Big Bend Station that were identified voluntarily to enhance environmental operations at the site, including the recycle/settling ponds, new slag de-watering bins that will replace the existing Industrial Waste Water permitted slag pond system, a new gypsum storage area, and upgrades to the storm water system. Also, the company will remove the vast majority of coal-combustion product source material from the exiting systems in conjunction with construction of the new/replacement systems. In 2006, Tampa Electric spent approximately $6.7 million on these environmental operations projects. Estimated expenditures for the continued implementation of these projects in 2007 are estimated at $21.7 million, with an additional $126.8 million in 2008-2011.
PEOPLES GAS SYSTEM - Gas Operations
PGS operates as the Peoples Gas System division of Tampa Electric Company. PGS is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and electric power generation customers in the State of Florida.
Gas is delivered to the PGS system through three interstate pipelines. PGS does not engage in the exploration for or production of natural gas. PGS operates a natural gas distribution system that serves over 332,000 customers. The system includes approximately 10,000 miles of mains and 6,000 miles of service lines. (See PGS’ Franchises section below.)
In 2006, the total throughput for PGS was 1.3 billion therms. Of this total throughput, 11% was gas purchased and resold to retail customers by PGS, 70% 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 65% of PGS’ annual therm volume, commercial customers used approximately 29%, and the balance was consumed by residential customers.
While the residential market represents only a small percentage of total therm volume, residential operations generally comprise 26% 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 580 employees as of Dec. 31, 2006. A total of 88 employees in six of PGS’ 15 operating divisions are represented by various union organizations.
Regulation
The operations of PGS are regulated by the FPSC separately from the regulation of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety, accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows a utility such as PGS to collect total revenues (revenue requirements) equal to its cost of providing service, plus a reasonable return on invested capital.
The basic costs of providing natural gas service, other than the costs of purchased gas and interstate pipeline capacity, are recovered through base rates. Base rates are designed to recover the costs of owning, operating and maintaining the utility system. The rate of return on rate base, which is intended to approximate PGS’ weighted cost of capital, primarily includes its cost for debt, deferred income taxes at a zero cost rate, and an allowed return on common equity. Base rates are determined in FPSC proceedings which occur at irregular intervals at the initiative of PGS, the FPSC or other parties. For a description of recent proceeding activity, see the Regulation - PGS Rates section of MD&A.
PGS recovers the costs it pays for gas supply and interstate transportation for system supply through the purchased gas adjustment clause. This charge is designed to recover the costs incurred by PGS for purchased gas, and for holding and using interstate pipeline capacity for the transportation of gas it sells to its customers. These charges 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. For a description of the most recent adjustment, see the Regulation - Cost Recovery Clauses - Peoples Gas section of MD&A.
In addition to its base rates and purchased gas adjustment clause charges for system supply customers, PGS customers (except interruptible customers) also pay a per-therm 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, expenditures made in connection with these programs if it demonstrates that the programs are cost effective for its ratepayers.
The FPSC requires natural gas utilities to offer transportation-only service to all non-residential customers. As a result, PGS receives its base rate for distribution regardless of whether a customer decides to opt for transportation-only service or continue bundled service. PGS had approximately 12,600 transportation customers as of Dec. 31, 2006 out of 29,400 eligible customers.
In addition to economic regulation, PGS is subject to the FPSC’s safety jurisdiction, pursuant to which the FPSC regulates the construction, operation and maintenance of PGS’ distribution system. In general, the FPSC has implemented this by adopting the
Minimum Federal Safety Standards and reporting requirements for pipeline facilities and transportation of gas prescribed by the U.S. Department of Transportation in Parts 191, 192 and 199, Title 49, Code of Federal Regulations.
PGS is also subject to federal, state and local environmental laws and regulations pertaining to air and water quality, land use, noise and aesthetics, solid waste and other environmental matters.
Competition
PGS is not in direct competition with any other distributors of natural gas for customers within its service areas. At the present time, the principal form of competition for residential and small commercial customers is from companies providing other sources of energy, including electricity. In general, PGS faces competition from other energy source suppliers offering fuel oil, electricity and, in some cases, propane. PGS has taken actions to retain and expand its commodity and transportation business, including managing costs and providing high quality service to customers.
In Florida, gas service is unbundled for all non-residential customers. In 2000, PGS implemented its “NaturalChoice” program offering unbundled transportation service to all eligible customers. This means that non-residential customers can purchase commodity gas from a third party but continue to pay PGS for the transportation of the gas.
Competition is most prevalent in the large commercial and industrial markets. In recent years, these classes of customers have been targeted by competing companies seeking to sell alternate fuels or transport gas through other facilities, thereby bypassing PGS facilities. In response to this competition, PGS has developed various programs, including the provision of transportation services at discounted rates. See the Regulation - Utility Competition - Gas section of MD&A.
Gas Supplies
PGS purchases gas from various suppliers depending on the needs of its customers. The gas is delivered to the PGS distribution system through three interstate pipelines on which PGS has reserved firm transportation capacity for delivery by PGS to its customers.
Gas is delivered by Florida Gas Transmission Company (FGT) through more than 57 interconnections (gate stations) serving PGS’ operating divisions. In addition, PGS’ Jacksonville Division receives gas delivered by the South Georgia Natural Gas Company pipeline through two gate stations located northwest of Jacksonville. Gulfstream Natural Gas Pipeline provides delivery through five gate stations. The addition of the Gulfstream pipeline enhances reliability of service and helps meet the capacity needs for PGS’ growing customer base.
Companies with firm pipeline capacity receive priority in scheduling deliveries during times when the pipeline is operating at its maximum capacity. PGS presently holds sufficient firm capacity to permit it to meet the gas requirements of its system commodity customers, except during localized emergencies affecting the PGS distribution system and on abnormally cold days.
Firm transportation rights on an interstate pipeline represent a right to use the amount of the capacity reserved for transportation of gas on any given day. PGS pays reservation charges on the full amount of the reserved capacity whether or not it actually uses such capacity on any given day. When the capacity is actually used, PGS pays a volumetrically-based usage charge for the amount of the capacity actually used. The levels of the reservation and usage charges are regulated by FERC. PGS actively markets any excess capacity available on a day-to-day basis to partially offset costs recovered through the Purchased Gas Adjustment Clause.
PGS procures natural gas supplies using base-load and swing-supply contracts with various suppliers along with spot market purchases. Pricing generally takes the form of either a variable price based on published indices or a fixed price for the contract term.
Neither PGS nor any of the interconnected interstate pipelines have storage facilities in Florida. PGS occasionally faces situations when the demands of all of its customers for the delivery of gas cannot be met. In these instances, it is necessary that PGS interrupt or curtail deliveries to its interruptible customers. In general, the largest of PGS’ industrial customers are in the categories that are first curtailed in such situations. PGS’ tariff and transportation agreements with these customers give PGS the right to divert these customers’ gas to other higher priority users during the period of curtailment or interruption. PGS pays these customers for such gas at the price they paid their suppliers, or at a published index price, and in either case pays the customer for charges incurred for interstate pipeline transportation to the PGS system.
Franchises
PGS holds franchise and other rights with approximately 100 municipalities throughout Florida. These franchises give PGS a right to occupy municipal rights-of-way within the franchise area. The franchises are irrevocable and are not subject to amendment without the consent of PGS, although in certain events, they are subject to forfeiture.
Municipalities are prohibited from granting any franchise for a term exceeding 30 years. Several franchises contain purchase options with respect to the purchase of PGS’ property located in the franchise area, if the franchise is not renewed; otherwise, based on judicial precedent, PGS is able to keep its facilities in place subject to reasonable rules and regulations imposed by the municipalities.
PGS’ franchise agreements with the incorporated municipalities within its service area have various expiration dates ranging from the present through 2032. PGS expects to negotiate 10 to 12 franchises in 2007, the majority of which will be renewals of
existing agreements. Franchise fees payable by PGS, which totaled $9.5 million in 2006, are calculated using various formulas which are based principally on natural gas revenues. Franchise fees are collected from only those customers within each franchise area.
Utility operations in areas outside of incorporated municipalities are conducted in each case under one or more permits to use state or county rights-of-way granted by the Florida Department of Transportation or the county commissioners of such counties. There is no law limiting the time for which such permits may be granted by counties. There are no fixed expiration dates and these rights are, therefore, considered perpetual.
Environmental Matters
PGS’ operations are subject to federal, state and local statutes, rules and regulations relating to the discharge of materials into the environment and the protection of the environment generally that require monitoring, permitting and ongoing expenditures.
Tampa Electric Company is one of several potentially responsible parties for certain superfund sites and, through PGS, for former manufactured gas plant sites. See the previous discussion in the Environmental Matters section of Tampa Electric - Electric Operations.
Expenditures
During the five years ended Dec. 31, 2006, PGS has not incurred any material capital expenditures to meet environmental requirements, nor are any anticipated for 2007 through 2011.
TECO COAL
Overview
TECO Coal, along with its subsidiaries, is a wholly owned subsidiary of TECO Energy, Inc. TECO Coal and its subsidiaries operate surface and underground mines as well as coal processing facilities in eastern Kentucky, Tennessee and southwestern Virginia. TECO Coal has administration offices located in Corbin, Kentucky.
TECO Coal Corporation, the holding company for TECO Coal and its subsidiaries, 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 Holdings, LLC and TECO Synfuel Operations, LLC. TECO Coal and its subsidiaries own or control, by lease, mineral rights, and owns or operates surface and underground mines, synthetic fuel production facilities and coal processing and loading facilities. TECO Coal and its subsidiaries produce, process and sell bituminous, predominately low sulfur coal of steam, industrial and metallurgical grades.
TECO Coal and its subsidiaries currently operate 24 underground mines which employ the room and pillar mining method and 17 surface mines.
In 2006, TECO Coal and its subsidiaries sold 9.8 million tons of coal. All of this coal was sold to customers other than Tampa Electric. Of the total sold, 5.3 million tons were produced and sold as synthetic fuel. As of Dec. 31, 2006, the TECO Coal operating companies had a combined estimated 273.9 million tons of proven and probable recoverable reserves.
History
In 1967, Cal-Glo Coal Company was formed. It mined a product containing low sulfur, low ash fusion characteristic and high energy content. Realizing the potential for this product to meet its combustion, quality, and environmental requirements, Tampa Electric 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 as Gatliff Coal Company. Rich Mountain Coal Company was established in 1987 when leases were signed for properties in Campbell County, Tennessee.
1988 saw a marketing change in which Gatliff Coal Company began selling ferro-silicon and silicon grade 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, 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 Operations, LLC were formed in 2003 to administer the production and sale of synthethic fuel product at various TECO Coal subsidiaries.
In 2004, the acquisition of properties and the Millard Preparation Facilities (currently idle) from AEP, Kentucky Coal, LLC was completed. The properties and facilities are located in Pike County, Kentucky.
Mining Operations
TECO Coal and its subsidiaries have four mining complexes, all operating in Kentucky with a portion of Clintwood Elkhorn Mining Company operating in Virginia as well. A mining complex is defined as all mines that supply a single wash plant, except in the case of Clintwood Elkhorn Mining Company and Premier Elkhorn Coal Company, which provide production for two wash plants. These complexes blend, process and ship coal that is produced from one or more mines, with a single complex handling the coal production of as many as 15 individual underground or surface mines. TECO Coal and its subsidiaries use two distinct extraction techniques: continuous underground mining and dozer and front-end loader surface mining. The complexes have been developed at strategic locations in close proximity to the TECO Coal preparation plants and rail shipping facilities. Coal is transported from TECO Coal and its subsidiaries’ mining complexes to customers by means of railroad cars, trucks, barge or vessels, with rail shipments representing approximately 92% of 2006 coal shipments. The map below shows the locations of the four mining complexes and TECO Coal’s offices in Corbin, Kentucky.
Facilities
Coal mined by the operating companies of TECO Coal is processed and shipped from facilities located at each of the operating companies, with Clintwood Elkhorn Mining Company and Premier Elkhorn Coal Company having two facilities. The Clintwood facilities are located at Biggs, Kentucky and Hurley, Virginia, the Premier facilities are located at Myra, Kentucky and the Millard facility, which is presently idle, is 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 TECO Coal subsidiaries’ processing facilities:
PROCESSING FACILITIES SUMMARY
Table 1
COMPANY
FACILITY
LOCATION
RAILROAD
SERVICE
UTILITY SERVICE
Gatliff Coal
Ada Tipple
Himyar, KY
CSXT Railroad
Cumberland Valley Electric
Clintwood Elkhorn
Clintwood #2 Plant
Biggs, KY
Norfolk Southern
American Electric Power
Clintwood Elkhorn
Clintwood #3 Plant
Hurley, VA
Norfolk Southern
American Electric Power
Premier Elkhorn
Burk Branch Plant
Myra, KY
CSXT Railroad
American Electric Power
Premier Elkhorn
Millard Plant
Millard, KY
CSXT Railroad
American Electric Power
Perry County Coal
Perry County Plant
Hazard, KY
CSXT Railroad
American Electric Power
Significant Projects
Significant projects for 2006 included the following:
Perry County Coal
•
The HZ4-1 mine, which opened in 1960, was closed in July 2006. The employees were moved to the E4-1 mine, creating the 4th working section at this mine.
•
Construction of the E4-2 mine slope and shaft began in July 2006. Completion of the project is expected in late summer, 2007. This will be the access point for the reserves in the Southwest Project area, which is a large boundary of coal reserves in the Elkhorn #4 seam and located to the southwest of existing Perry County Coal facilities.
•
A fine coal recovery circuit (column flotation) was installed at the preparation plant. The recovery of fines will result in more coal to be shipped (approximately 1 to 2 trains per month) and less coal being sent to the refuse area, thereby extending the life of the refuse facility.
•
During 2006, a major lease was signed with Kentucky River Properties, adding 9,500 acres and 15.9 million tons to the Southwest Project area.
Premier Elkhorn Coal
•
The Burke Branch Impoundment design revision was approved, extending the life of the impoundment to 2026.
Mining Complexes
Table 2 below shows annual production for each mining complex for each of the last three years.
MINING COMPLEXES
Table 2
S - Surface
U - Underground
CM - Continuous Miner
D/L - Dozers and Front-End loaders
HM - Highwall Miner
A - Auger
R - Rail
R/B - Rail to Barge
R/V - Rail to Ocean Vessel
T - Truck
T/B - Truck to Barge
Gatliff Coal Company
Located in Bell County, Kentucky, Gatliff Coal Company is supplied by one surface mine. Principal products at this location consist primarily of high quality steam coal for utilities. Products from this operation are transported by trucking contractors. Rich Mountain Coal Company formerly operated as a contractor for Gatliff Coal Company’s Tennessee production which is currently in non-producing reclamation status. Gatliff Coal Company produced 0.36 million tons of coal in 2006, leaving a reserve base of 9.1 million recoverable tons.
Clintwood Elkhorn Mining Company
Clintwood Elkhorn Mining Company has two facilities. One is located near Biggs, Kentucky in Pike County, and is supplied by ten underground mines and four surface mines. Principal products at the Biggs, Kentucky location include high volatile metallurgical coals and steam coals. The second Clintwood Elkhorn Mining Company facility is located near Hurley, Virginia and is supplied by three underground mines and four 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. In total, Clintwood Elkhorn Mining Company produced 2.63 million tons of coal in 2006, leaving a reserve base of 39.0 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 seven 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 200 car siding capable of loading at 6,000 tons per hour as well as a single car siding. Products from this location are shipped domestically via CSXT Railroad and trucking contractors. Metallurgical coal is also shipped to be sold in international markets. 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 3.33 million tons of coal in 2006, leaving a reserve base of 84.9 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 and industrial stoker 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 domestically via CSXT Railroad and trucking contractors. During 2006, a major lease was signed with Kentucky River Properties, adding over 9,500 acres and 15.9 million tons to the Southwest project area. Exploration for this project will continue in 2007. Perry County Coal Corporation produced 3.57 million tons of coal in 2006, leaving a reserve base of 140.9 million recoverable tons.
TECO Synfuel Operations, LLC
In April 2003, TECO Coal sold a 49.5 percent ownership interest in its synthetic fuel production facilities, an additional 40.5 percent in June of 2004 and 8 percent in July of 2005 (See the TECO Coal section of MD&A). Sales of the fuel processed through these types of facilities are eligible for non-conventional fuels tax credits under the Internal Revenue Code, which are available through 2007. TECO Coal received Private Letter Rulings from the Internal Revenue Service confirming that the facilities produce a qualified fuel eligible for synthetic fuel tax credits available for the production of such non-conventional fuels and resolved any uncertainty related to the sale of its interest in the production facilities.
The synthetic fuel tax credit, determined annually, is estimated to be $1.17 per million Btu in 2006. The actual tax credit for 2005 and 2004 was $1.15 per million Btu and $1.13 per million Btu, respectively. This rate escalates with inflation but could be limited by domestic oil prices. The weighted average price of domestic oil for 2006 exceeded $62 per barrel resulting in an estimated 35% phase-out of the credits allowed for 2006. See the Outlook - Synthetic Fuel Section of the MD&A for further discussion of the synthetic fuel tax credit.
Sales and Marketing
The TECO Coal marketing and sales force includes sales managers, distribution/transportation managers and administrative personnel. Primary customers are utilities, steel companies and industrial plants. TECO Coal sells coal under long-term agreements, which are generally greater than 12 months, and on a spot basis, which is generally less than 12 months.
The terms of these coal sales contracts result from bidding and negotiations with customers. Among our customers, these contracts typically vary in price, quantity, quality, duration and delivery point. In addition, individual contracts may contain terms and conditions that allow for periodic price reviews, price adjustment mechanisms, recovery of governmental impositions as well as provisions for force majeure, suspension, termination, treatment of environmental legislation and assignment.
Distribution
TECO Coal and its subsidiaries transport coal from its mining complexes to customers by rail, barge, vessel and trucks. TECO Coal and its subsidiaries employ transportation specialists who coordinate the development of acceptable shipping schedules with our customers, transportation providers and mining facilities.
Competition
Primary competitors of TECO Coal’s subsidiaries are other coal suppliers, many of which are located in Central Appalachia. Even though consolidation and bankruptcy have decreased the number of coal suppliers, the industry is still intensely competitive. To date, TECO Coal and its subsidiaries have been able to compete for coal sales by mining high-quality steam and specialty coals and by effectively managing production and processing costs.
Employees
As of Dec. 31, 2006, TECO Coal and its subsidiaries employed a total of 1,019 employees.
Regulations
Mine Safety and Health
The operations of underground mines, including all related surface facilities, are subject to the Federal Coal Mine Safety and Health Act of 1969, the 1977 Amendment and the Miner Act of 2006. TECO Coal’s subsidiaries are also subject to various Kentucky, Tennessee and Virginia mining laws which require approval of roof control, ventilation, dust control and other facets of the coal mining business. Federal and state inspectors inspect the mines to ensure compliance with these laws. TECO Coal and its subsidiaries believe 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 recent mining accidents within the industry could lead to new legislation that could impose additional costs on TECO Coal and its subsidiaries.
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 December 2000, the Department of Labor issued new amendments to the regulations implementing the federal Black Lung laws that, among other things, establish a presumption in favor of a claimant’s treating physician, limit a coal operator’s ability to introduce medical evidence, and redefine Coal Workers Pneumoconiosis to include chronic obstructive pulmonary disease. These changes in the regulations will increase the percentage of claims approved and the overall cost of Black Lung to coal operators. TECO Coal and its subsidiaries, with the help of its consulting actuaries, intend to continue monitoring claims very closely.
Workers’ Compensation
TECO Coal and its subsidiaries are liable for workers’ compensation benefits for traumatic injury and occupational exposure claims under state workers’ compensation laws. Workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment.
Environmental Laws
Surface Mining Control and Reclamation Act
Coal mining operations are subject to the Surface Mining Control and Reclamation Act of 1977 which places a charge of $0.15 and $0.35 on every net ton of underground and surface coal mined, respectively, to create a fund for reclaiming land and water adversely affected by coal mining. Other provisions establish standards for the control of environmental effects and reclamation of surface coal mining and the surface effects of underground coal mining and requirements for federal and state inspections.
Clean Air Act/Clean Water Act
While conducting their mining operations, TECO Coal’s subsidiaries are subject to various federal, state and local air and water pollution standards. In 2006, TECO Coal spent approximately $2.6 million on environmental protection and reclamation programs. TECO Coal and its subsidiaries expect to spend a similar amount in 2007 on these programs.
For information concerning potential new state and/or federal legislation limiting CO2 emissions, see the Environmental Compliance-Carbon Reductions section of MD&A.
CERCLA (Superfund)
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA” - commonly known as Superfund) affects coal mining and hard rock operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under Superfund, joint and several liabilities may be imposed on waste generators, site owners or operators and others regardless of fault.
Under EPA’s Toxic Release Inventory process, companies are required to report annually listed toxic materials that exceed defined quantities.
Glossary of Selected Mining Terms
Assigned reserves. Coal which has been committed by the coal company to operating mine shafts, mining equipment, and plant facilities, and all coal which has been leased by the company to others.
Bituminous coal. The most common type of coal with moisture content less than 20% by weight and heating value of 10,500 to 14,000 Btu per pound. It is dense and black and often has well-defined bands of bright and dull material.
Btu. (British Thermal Unit). A measure of the energy required to raise the temperature of one pound of water one degree Fahrenheit.
Central Appalachia. Coal producing states and regions of eastern Kentucky, eastern Tennessee, western Virginia and southern West Virginia.
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 Btus, which is equivalent to .72% sulfur per pound of 12,000 Btu coal. Compliance coal requires no mixing with other coals or use of sulfur dioxide reduction technologies by generators of electricity to comply with the requirements of the federal Clean Air Act.
Continuous miner. A machine used in underground mining to cut coal from the seam and load it onto conveyors or into shuttle cars in a continuous operation.
Continuous mining. One of two major underground mining methods now used in the United States. This process utilizes a continuous miner. The continuous miner removes or “cuts” the coal from the seam. The loosened coal then falls on a conveyor for removal to a shuttle car or larger conveyor belt system.
Deep mine. An underground coal mine.
Dozer and Front-end loader mining. An open-cast method of mining that uses large 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 from the surface up to 1,000 feet deep.
Industrial coal. Coal used by industrial steam boilers to produce electricity or process steam. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal.
Long term contracts. Contracts with terms of one year or longer.
Low ash fusion. Coal that when burned typically produces ash that has a melting point below 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 coal’s sulfur content.
Probable (Indicated) reserves. Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart; therefore, the degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.
Proven (Measured) reserves. Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well established.
Pulverized coal injection (PCI). A system whereby coal is pulverized and injected into blast furnaces in the production of steel and/or steel products.
Reclamation. The process of restoring land and the environment to their approximate original state following mining activities. The process commonly includes “recontouring” or reshaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers. Reclamation operations are usually underway before the mining of a particular site is completed. Reclamation is closely regulated by both state and federal law.
Recoverable reserves. The amount of proven and probable reserves that can actually be recovered from the reserve base taking into account all mining and preparation losses involved in producing a saleable product using existing methods and under current law.
Reserves. That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.
Resource (Non-reserve coal deposit). A coal-bearing body that does not qualify as a commercially viable coal reserve. Resources may be classified as such by either limited property control, geologic limitations, insufficient exploration or other limitations. In the future, it is possible that portions of the resource could be re-classified as reserve if those limitations are removed or mitigated by: improving market conditions, additional property control, favorable results of exploration, advances in technology, etc.
Roof. The stratum of rock or other mineral above a coal seam; the overhead surface of a coal working place. Same as “top.”
Room and pillar mining. In the underground room and pillar method of mining, continuous mining machines cut three to nine entries into the coal bed and connect them by driving crosscuts, leaving a series of rectangular pillars, or columns of coal to help support the mine roof and control the flow of air. As mining advances, a grid-like pattern of entries and pillars is formed. Additional coal may be recovered from the pillars as this panel of coal is retreated.
Spot market. Sales of coal under an agreement for shipments over a period of one year or less.
Steam coal. Coal used by power plants and industrial steam boilers to produce electricity or process steam. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal.
Sulfur. One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide is produced as a gaseous by-product of coal combustion.
Sulfur content. Coal is commonly described by its sulfur content due to the importance of sulfur in environmental regulations. “Low sulfur” coal has a variety of definitions but is typically used to describe coal consisting of 1.0% or less sulfur. A majority of TECO Coal’s Central Appalachian reserves are of low sulfur grades.
Surface mine. A mine in which the coal lies near the surface and can be extracted by removing overburden.
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” tonne is approximately 2,205 pounds. The short ton is the unit of measure referred to in this Form 10-K.
Unassigned reserves. Coal which has not been committed, and which would require new mineshafts, mining equipment, or plant facilities before operations could begin in the property.
Underground mine. Also known as a “deep” mine. Usually located several hundred feet below the earth’s surface, an underground mine’s coal is removed mechanically and transferred by shuttle car or conveyor to the surface.
Unit train. A train of a specified number of cars carrying only coal. A typical unit train can carry at least 10,000 tons of coal in a single shipment.
Utility coal. Coal used by power plants to produce electricity or process steam. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal.
TECO TRANSPORT
TECO Transport directly or indirectly owns an interest in nine subsidiaries which are involved in waterborne transportation, storage and transfer of coal and other dry-bulk commodities. These subsidiaries include TECO Ocean Shipping, Inc. (Ocean Shipping), TECO Barge Line, Inc. (Barge Line), TECO Bulk Terminal, LLC (Bulk Terminal) and TECO Towing Company. TECO Transport currently owns no operating assets. TECO Transport and its subsidiaries had 849 employees as of Dec. 31, 2006.
TECO Transport’s subsidiaries perform substantial services for Tampa Electric. In 2006, approximately 30% of TECO Transport’s revenues were from Tampa Electric and approximately 70% were from third-party customers including phosphate customers, steel industry customers, grain customers, coal and petroleum coke customers, and participation in the U.S. Government’s cargo preference programs. The pricing for services performed by TECO Transport’s operating companies for Tampa Electric is based on a market-based fixed-price per ton, generally adjusted quarterly for changes in certain fuel and price indices. Most of the third-party utilization of the ocean-going vessels (ships and barges) is for domestic and international movements of dry-bulk commodities and domestic phosphate movements. Both the terminal and river transport operations handle a variety of dry-bulk commodities for third-party customers.
Ocean Shipping transports products in the Gulf of Mexico and worldwide, while Barge Line operates on the Mississippi, Ohio and Illinois rivers and their tributaries. Their primary competitors are other barge and shipping lines and railroads, as well as a number of other companies offering transportation services on the waterways used by TECO Transport’s subsidiaries. Ocean Shipping is the largest U.S. flag coastwise dry-bulk operator based on capacity, while Barge Line is one of the ten largest companies in its business, based on number of barges. To date, physical and technological improvements have allowed ship and barge operators to maintain competitive rate structures with alternate methods of transporting bulk commodities when the origin and destination of such shipments are contiguous to navigable waterways.
Bulk Terminal operates the largest transfer and storage terminal on the Gulf coast. Demand for the use of such terminals is dependent upon customers’ use of water transportation versus alternate means of moving bulk commodities and the demand for these commodities. Competition consists primarily of mid-stream operators who operate floating cranes or other floating discharge and loading equipment, and other land-based terminals.
Competition within TECO Transport’s markets is based primarily on geographic markets served, pricing, and service level. The majority of the ocean business and all of the river business is subject to the Jones Act, which prohibits the use of non-U.S. flag vessels for movement between U.S. ports.
The business of TECO Transport’s subsidiaries, taken as a whole, is not subject to significant seasonal fluctuation, but is sensitive to weather and economic conditions.
The Interstate Commerce Act exempts from regulation water transportation of certain dry-bulk commodities. In 2006, all transportation services provided by TECO Transport’s subsidiaries were within this exemption.
TECO Transport’s subsidiaries are subject to the provisions of the Clean Water Act of 1977 which authorizes the Coast Guard and the EPA to assess penalties for oil and hazardous substance discharges. Under this Act, these agencies are also empowered to assess clean-up costs for such discharges. In 2006, TECO Transport spent $0.2 million for environmental compliance. Environmental expenditures are estimated at $0.4 million in 2007, primarily for work on solid waste disposal and storm water drainage at the Bulk Terminal facility in Louisiana and for expenses related to oil and bilge water disposal at its river-barge repair facility in Illinois.
TECO GUATEMALA
TECO Guatemala, Inc. (Formerly TWG Non-Merchant, Inc.), has subsidiaries that have interests in independent power projects in Guatemala and a minority ownership interest in an electrical distribution utility. The TECO Guatemala subsidiaries had 123 employees as of Dec. 31, 2006.
TECO Guatemala indirectly owns 100% of Central Generadora Eléctrica San José, Limitada (CGESJ), the owner of a project located in Guatemala, which consists of a single-unit pulverized-coal baseload facility (the San José Power Station). This facility was the first coal-fueled plant in Central America and meets environmental standards set by the World Bank. In 1996, CGESJ signed a U.S. dollar-denominated power purchase agreement (PPA) with Empresa Eléctrica de Guatemala, S.A. (EEGSA), the largest private distribution and generation 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. In 2002, CGESJ transferred the port assets to Tecnología Marítima, S.A. (TEMSA), a new indirect wholly-owned subsidiary. TEMSA, in addition to receiving the coal shipments for CGESJ, provides unloading services to third parties. Affiliates of TECO Guatemala had originally obtained $114 million of limited recourse financing from Bank of America (BOA), Overseas Private Investment Corporation (OPIC) and Trust Company of the West (TCW) for the San José Power Station. In 2004, CGESJ paid off its loans with BOA, OPIC and TCW with proceeds from a non-recourse $120 million loan from a syndication led by Banco Industrial, a local bank in Guatemala. Political risk insurance is in place for currency inconvertibility, expropriation and political violence covering up to 100% of TECO Guatemala’s indirect equity investment and economic returns.
Tampa Centro Americana de Electricidad, Limitada (TCAE), an entity 96.06% owned by TPS Guatemala One, Inc., a subsidiary of TECO Guatemala, and the owner of a natural gas-powered 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. Affiliates of TECO Guatemala had originally obtained $29 million of limited recourse financing from OPIC for the Alborada Power Station. In 2002, TCAE paid off its loan with OPIC with a portion of the proceeds from a non-recourse $25 million loan from Banco Industrial, a local bank in Guatemala. Political risk insurance is in place for currency inconvertibility, expropriation and political violence covering up to 100% of TECO Guatemala’s indirect equity investment and economic returns.
In 1998, a consortium that includes affiliates of TECO Energy, Iberdrola, an electric utility in Spain, and Electricidade de Portugal, an electric utility in Portugal, completed the purchase of an 80.9% 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. EEGSA serves more than 800,000 customers in and around the metropolitan area of Guatemala City. TECO Guatemala has obtained political risk insurance for currency inconvertibility, expropriation and political violence covering up to 100% of TECO Guatemala’s indirect equity investment and economic returns.
Our existing plants in Guatemala operate under environmental permits issued by the local environmental authorities. The plants were built in accordance to World Bank Guidelines of 1988 and 1994, at the time of construction of these assets. 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 assuring worker health and safety and reducing environmental impacts.
As a result of the adoption of FIN 46R, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51, effective Jan. 1, 2004, CGESJ and TCAE were deconsolidated. See Note 19 to the TECO Energy Consolidated Financial Statements for additional information about the adoption of FIN 46R. For financial information about geographic areas, see Note 14 to the TECO Energy Consolidated Financial Statements.
TWG MERCHANT, INC.
The TWG Merchant entity was created to own interests in merchant power projects. In 2003, TECO Energy announced that its strategy going forward was to focus on the Florida utilities and profitable unregulated businesses and to reduce the company’s exposure to the merchant power markets. As of Dec. 31, 2006, TWG Merchant has sold its interests in all independent power projects and has effectively reduced the company’s exposure. Any residual results of operations for the fiscal year ending Dec. 31, 2006, are reported in “Other and eliminations”, removing TWG Merchant as a reportable segment. Also effective as of Dec. 31, 2006, TWG Merchant has no remaining employees.
Item 1A.
Item 1A. RISK FACTORS.
RISK FACTORS
The following are certain factors that could affect our future results. They should be considered in connection with evaluating forward-looking statements, and are otherwise made by, or on behalf of, us, because these factors could cause actual results and conditions to differ materially from those projected in those forward-looking statements.
Financing Risks
We have substantial indebtedness, which could adversely affect our financial condition and financial flexibility.
We have significant indebtedness, which has resulted in an increase in the amount of 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 and could prevent the payment of dividends if those payments would cause a violation of the covenants.
We and Tampa Electric Company must meet certain financial tests as defined in the applicable agreements to use our and its respective credit facilities. Also, we, 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, 2006, we were in compliance with required financial covenants, but we cannot assure you 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 Financing and Liquidity, Capital Resources sections of the MD&A. In addition, our unconsolidated affiliates have incurred non-recourse debt. Although we are not obligated on that debt, our investments in those unconsolidated affiliates are at risk if the affiliates default on their debt.
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 below investment grade by Standard & Poor’s (S&P) at BB with a stable outlook, by Moody’s Investor’s Services (Moody’s) at Ba2 with a stable outlook and by Fitch Ratings (Fitch) at BB+ with a stable outlook. The senior unsecured debt of Tampa Electric Company is rated by S&P at BBB- with a stable outlook, by Moody’s at Baa2 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 our current credit ratings or future downgrades. In addition, downgrades could adversely affect our relationships with customers and counterparties.
At current ratings, Tampa Electric and PGS are able to purchase gas and electricity without providing collateral. If the ratings of Tampa Electric Company declined to below investment grade, Tampa Electric and PGS could be required to post collateral to support their purchases of gas and electricity.
Our financial condition and results could be adversely affected if our capital expenditures are greater than forecast.
We are forecasting higher levels of capital expenditures, primarily at Tampa Electric, for compliance with our environmental consent decree, to support normal customer growth, to comply with the FPSC’s mandated design changes to harden transmission and distribution facilities against hurricane damage, and to improve coal-fired generating unit reliability. We are also in the early stages of exploring the technology options for the next large generating capacity needs at Tampa Electric. There are large differences in the capital needs depending on the final technology chosen. Pending a technology decision, the costs for the next large generating capacity addition are not factored into our current capital spending forecast shown in the Capital Expenditures section of MD&A.
Our capital expenditures may exceed the planned amount. 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.
If we are not able to complete the sale of TECO Transport we are considering, our plans to accelerate the retirement of parent level debt and support Tampa Electric’s increased capital spending needs may be adversely affected.
If we are unable to complete a sale of TECO Transport, we would not be positioned to accelerate our goal of retiring our parent level debt earlier than our current forecast. In addition, if a sale were not completed, we would have to consider other options to support Tampa Electric’s capital spending plans, which could include the sale of other businesses or capital markets transactions.
Because we are a holding company, we are dependent on cash flow from our subsidiaries, which may not be available in the amounts and at the times we need it.
We are a holding company and are dependent on cash flow from our subsidiaries to meet our cash requirements that are not satisfied from external funding sources. Some of our subsidiaries have indebtedness containing restrictive covenants which, if violated, would prevent them from making cash distributions to us. In particular, certain long-term debt at PGS prohibits payment of dividends to us if Tampa Electric Company’s consolidated shareholders’ equity is lower than $500 million. At Dec. 31, 2006, Tampa Electric Company’s consolidated shareholders’ equity was approximately $1.7 billion. Also, our wholly owned subsidiary, TECO Diversified, Inc., the holding company for TECO Transport, TECO Coal and TECO Solutions, has a guarantee related to a coal supply agreement that could limit the payment of dividends by TECO Diversified to us.
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, including the floating rate notes we issued in June 2005. 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.
General Business and Operational Risks
General economic conditions may adversely affect our businesses.
Our businesses are affected by general economic conditions. In particular, the projected growth in Tampa Electric’s service area and in Florida is important to the realization of Tampa Electric’s and PGS’ respective forecasts for annual energy sales growth. An unanticipated downturn or a failure of market conditions to improve, such as the current slowdown in the housing markets, in the Tampa Electric service areas or in Florida’s economy could adversely affect Tampa Electric’s or PGS’ expected performance.
Our unregulated businesses, TECO Transport, TECO Coal and TECO Guatemala, are also affected by general economic conditions in the industries and geographic areas they serve, both nationally and internationally.
Potential competitive changes may adversely affect our regulated electric and gas businesses.
The U.S. electric power industry has been undergoing restructuring. Competition in wholesale power sales has been introduced on a national level. Some states have mandated or encouraged competition at the retail level and, in some situations, required divestiture of generating assets. While there is active wholesale competition in Florida, the retail electric business has remained substantially free from direct competition. Although not expected in the foreseeable future, changes in the competitive environment occasioned by legislation, regulation, market conditions or initiatives of other electric power providers, particularly with respect to retail competition, could adversely affect Tampa Electric’s business and its 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.
Our electric and gas businesses are highly regulated, and any changes in regulatory structures could lower revenues or increase costs or competition.
Tampa Electric and PGS operate in highly regulated industries. Their retail operations, including the prices charged, are regulated by the FPSC, and Tampa Electric’s wholesale power sales and transmission services are subject to regulation by the FERC. Changes in regulatory requirements or adverse regulatory actions could have an adverse effect on Tampa Electric’s or PGS’ financial performance by, for example, increasing competition or costs, threatening investment recovery or impacting rate structure.
Tampa Electric’s earnings may decrease and it may not be able to earn its allowed return with the current base rates.
Tampa Electric’s profitability may decrease and it may not be able to earn within its allowed ROE range under its current base rates due to higher recurring capital spending primarily in the transmission and distribution areas and generally higher levels of non-fuel operations and maintenance spending, even without the construction of new generating capacity.
In order to earn within its allowed ROE range given its higher operations and maintenance costs and the increased investment in infrastructure and facilities, Tampa Electric may have to file for higher rates with the FPSC. While the FPSC has a history of constructive regulation, we cannot predict the outcome of any such regulatory proceeding.
Our businesses are sensitive to variations in weather and the effects of extreme weather, and have seasonal variations.
Most of our businesses are affected by variations in general weather conditions and unusually severe weather. Tampa Electric’s and PGS’ energy sales are particularly sensitive to variations in weather conditions. Those companies forecast energy sales on the basis of normal weather, which represents a long-term historical average. Significant variations from normal weather could have a material impact on energy sales. Unusual weather, such as hurricanes, could adversely affect operating costs and sales and cause damage to our facilities, requiring additional costs to repair.
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. TECO Transport is also impacted by weather because of its effects on the supply of and demand for the products transported. Severe weather conditions could interrupt or slow service and increase operating costs of those businesses.
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 natural gas and pipeline capacity are recovered through retail customers’ bills, but increases in natural 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.
Changes in customer energy usage patterns may affect sales at our utility companies.
The average energy usage per Tampa Electric residential customer declined in 2006. We believe that this was in response to mild weather, higher energy prices reflected both through the fuel charge on electric bills and for higher energy prices in general, and to changes in residential construction patterns in Tampa Electric’s service area.
Tampa Electric’s forecasts are based on normal weather patterns and long-term historical trends in customer energy use patterns. Tampa Electric’s 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 higher energy prices.
In 2006, the number of multi-family residences completed in Tampa Electric’s service area was the highest level since 2001. New multi-family residential construction tends to be smaller and more energy efficient than traditional detached residences, therefore the per-residential customer usage is lower for these residences. The number of multi-family building permits issued in Tampa Electric’s service area in 2006 compared to detached residences indicates that this trend may continue in 2007. A higher percentage of multi-family residences may cause a further decline in per-residential customer usage.
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.
Changes in the relationship between the Producer First Purchase Price and the NYMEX oil prices could affect the value of our hedges.
We have entered into oil price hedge transactions to protect the earnings and cash benefits for the vast majority of our expected 2007 synthetic fuel production. We have hedged approximately $195 million of the expected proceeds from investors related to the production of synthetic fuel in 2007 on the assumption that the Producer First Purchase Price would average 90% of the NYMEX per barrel oil price. Changes in this relationship could change the range over which the oil price hedge instruments that we have in place protect our synthetic fuel production benefits.
Impairment testing of certain long-lived assets and goodwill could result in impairment charges.
We test our long-lived assets and goodwill for impairment annually or more frequently if certain triggering events occur. Should the current carrying values of any of these assets not be recoverable, we would incur charges to write down the assets to fair market value.
Problems with operations could cause us to incur substantial costs.
Each of our subsidiaries is subject to various operational risks, including accidents, 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.
There is increasing debate and discussion regarding the regulation of greenhouse gas emissions and some states have already proposed or enacted regulations relating to these emissions, which if 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. The form of any greenhouse gas emission regulation, either federal or state, is unknown at this time and potential costs to reduce greenhouse gases are unknown. Presently there is no viable technology to remove CO2 post-combustion from conventional coal-fired units such as Tampa Electric’s Big Bend units.
Regulation in Florida allows utility companies to recover from customers prudently incurred costs for compliance with new environmental regulations. Tampa Electric would expect to recover from customers the costs of power plant modifications or other costs required to comply with new greenhouse gas emission regulation, but increased costs for electricity may cause customers to change usage patterns, which would impact Tampa Electric’s sales. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the Environmental Cost Recovery Clause, Tampa Electric could seek to recover those costs through a base-rate proceeding, but we cannot predict whether the FPSC would grant such recovery.
In the case of TECO Coal, the use of coal to generate electricity is considered a significant source of greenhouse gas emissions. New regulations, depending on final form, could cause the consumption of coal to decrease or the cost of sales to increase, which could negatively impact TECO Coal’s earnings.
TECO Transport does a significant amount of business under certain U.S. government programs that are dependent on annual appropriations.
TECO Transport participates in the U.S. Cargo Preference Program and the in PL480 program for shipments of U.S. aid grain, which are funded annually through the U.S. government’s appropriation process. While these programs have been funded at stable levels for many years, Congress could reduce funding in the future. Our outlook, however, assumes that these programs continue to be funded at levels similar to the last several years.
A repeal of the Jones Act could result in increased competition and reduced profitability for TECO Transport.
TECO Transport is a U.S. flag carrier with a major portion of its business subject to the Jones Act. The Jones Act restricts oceangoing shipments directly between U.S. ports and all inland waterway business to U.S. vessels built in U.S. shipyards, owned by citizens of the U.S., and with U.S. citizen crews and it has, on occasion, been cited as a cause for higher costs by certain domestic industries which have lobbied for repeal of the act or waivers for shipments carried by non-U.S. flag vessels under certain circumstances. A repeal or modification of the Jones Act opening this trade to non-U.S. flag vessels could potentially increase competition and reduce profitability.
Our international projects and the operations of TECO Transport 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 increasing fuel and corresponding electricity prices. As a result, TECO Guatemala’s operations are exposed to increased risks as the country’s government and regulatory authorities seek ways to reduce the cost of energy to its consumers.
TECO Transport is exposed to operational risks in international ports, primarily due to its need for suitable labor and equipment to safely discharge its cargoes in a timely manner. TECO Transport attempts to manage these risks through a variety of risk mitigation measures, including retaining agents with local knowledge and experience in successfully discharging cargoes and vessels similar to those used by TECO Transport, but these measures may not be successful.
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.
We are currently defending lawsuits in which we could be liable for damages.
TECO Energy and certain of its subsidiaries have been named as defendants in lawsuits, as more fully described under Legal Contingencies, in Note 12 to the TECO Energy Consolidated Financial Statements. We intend to vigorously defend all of these proceedings, however, we cannot predict the ultimate resolution of any of these matters at this time, and there can be no assurance that these matters will not have a material adverse impact on our financial condition or results of operations.
Item 1B.
Item 1B. UNRESOLVED STAFF COMMENTS.
None.
Item 2.
Item 2. PROPERTIES.
TECO Energy believes that the physical properties of its operating companies are adequate to carry on their businesses as currently conducted. The properties of Tampa Electric are subject to a first mortgage bond indenture under which no bonds are currently outstanding.
TAMPA ELECTRIC
Tampa Electric has five electric generating plants and five combustion turbine units in service with a total net winter generating capability of 4,383 megawatts, including Big Bend (1,697-MW capability from four coal units), Bayside (1,841-MW capability from two natural gas units), Phillips (36-MW capability from two diesel units), Polk (260-MW capability from one integrated gasification combined cycle (IGCC) unit), three combustion turbine units (CTs) located at Big Bend (175-MW) and two CTs at Polk (368-MW). Additionally, Tampa Electric has 6-MW of generating capability from generation units located at the Howard Curren Advanced Waste Water Treatment Plant in the City of Tampa. The capability indicated represents the demonstrable dependable load carrying abilities of the generating units during winter peak periods. Units at Big Bend went into service from 1970-1985. The Polk IGCC unit began commercial operation in 1996. In 1991, Tampa Electric purchased two power plants (Dinner Lake and Phillips) from the Sebring Utilities Commission (Sebring). Phillips was placed in service by Sebring in 1983. Dinner Lake was retired from service in January 2003. Bayside Unit 1 was completed in April 2003, and Bayside Unit 2 was completed in January 2004.
Tampa Electric owns 184 substations having an aggregate transformer capacity of 21,226 Mega Volts Amps (MVA). The transmission system consists of approximately 1,307 pole miles (including underground and double-circuit) of high voltage transmission lines, and the distribution system consists of 7,079 pole miles of overhead lines and 3,425 trench miles of underground lines. As of Dec. 31, 2006, there were 661,278 meters in service. All of this property is located in Florida.
All plants and important fixed assets are held in fee except that title to some of the properties is subject to easements, leases, contracts, covenants and similar encumbrances and minor defects of a nature common to properties of the size and character of those of Tampa Electric.
Tampa Electric has easements for rights-of-way adequate for the maintenance and operation of its electrical transmission and distribution lines that are not constructed upon public highways, roads and streets. It has the power of eminent domain under Florida law for the acquisition of any such rights-of-way for the operation of transmission and distribution lines. Transmission and distribution lines located in public ways are maintained under franchises or permits.
Tampa Electric has a long-term lease for the office building in downtown Tampa which serves as headquarters for TECO Energy, Tampa Electric, PGS, TECO Transport, and TECO Guatemala.
PEOPLES GAS SYSTEM
PGS’ distribution system extends throughout the areas it serves in Florida and consists of approximately 16,000 miles of pipe, including approximately 10,000 miles of mains and 6,000 miles of service lines. Mains and service lines are maintained under rights-of-way, franchises or permits.
PGS’ operations are located in 15 operating divisions throughout Florida. While most of the operations and administrative facilities are owned, a small number are leased.
TECO COAL
Property Control
Operations of TECO Coal and its subsidiaries are conducted on both owned and leased properties totaling nearly 250,000 acres in Kentucky, Tennessee and Virginia. TECO Coal’s current practice is to obtain a title review from a licensed attorney prior to purchasing or leasing property. As is typical in the coal mining industry, TECO Coal generally has not obtained title insurance in connection with its acquisitions of coal reserves and/or related surface properties. In many cases, the seller or lessor will grant the purchasing or leasing entity a warranty of property title. When leasing coal reserves and/or related surface properties where mining has previously occurred, TECO Coal may opt not to perform a separate title confirmation due to the previous mining activities on such a property. 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.
Coal Reserves
As of Dec. 31, 2006, the TECO Coal operating companies had a combined estimated 273.9 million tons of proven and probable recoverable reserves. All of the reserves consist of High Vol A Bituminous Coal. Reserves are the portion of the proven and probable tonnage that meet TECO Coal’s economic criteria regarding mining height, preparation plant recovery, depth of overburden and stripping ratio. Generally, these reserves would be commercially mineable at year-end price and cost levels. Additionally, 48.2 million tons of coal classified as “resource” were identified in earlier third-party audit reports. Another 15.8 million tons of coal classified as “resource” were identified in the third-party audit report prepared by Marshall Miller & Associates, bringing the total identified resource to 64.0 million tons of coal.
Reserves are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows:
Proven (Measured) Reserves - Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, working or drill holes: grade and/or quality are computed from the results of detailed sampling; and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.
Probable (Indicated) Reserves - Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but for which the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.
Drill hole spacing for confidence levels in reserve calculations is based on guidelines in U.S. Geological Survey Circular 891 (Coal Resource Classification System of the U.S. Geological Survey). In this method of classification, “proven” reserves are considered to be those lying within one-quarter mile (1,320 feet) of a valid point of measurement and “probable” reserves are those lying between one-quarter mile and three-quarters mile (3,960 feet) from such an observation point.
Our reserve estimates are prepared by our staff of geologists, whose experience range from 15 years to 30 years. We also have two chief geologists with the responsibility to track changes in reserve estimates, supervise TECO Coal’s other geologists and coordinate third party reviews of our reserve estimates by qualified mining consultants. In 2006, a third-party reserve audit was performed by Marshall Miller & Associates on the portion of reserves acquired during 2006. 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 3
Notes:
(1) Recoverable reserves represent the amount of proven and probable reserves that can actually be recovered from the reserve base taking into account all mining and preparation losses involved in producing a saleable product using existing methods under current law. Reserve information reflects a moisture of 6.5%. This moisture factor represents the average moisture present in TECO Coal’s delivered coal.
(2) Assigned reserves means coal which has been committed by the coal company to operating mine shafts, mining equipment, and plant facilities, and all coal which has been leased by the company to others. Unassigned reserves represent coal which has not been committed, and which would require new mineshafts, mining equipment, or plant facilities before operations could begin in the property.
Table 4 below shows the recoverable reserves by quality, including sulfur content and coal type, per mining complex:
RECOVERABLE RESERVES BY QUALITY (1)
(Millions of tons)
Table 4
Notes:
(1) Reserve information reflects a moisture factor of 6.5%. This moisture factor represents the average moisture present in TECO Coal’s delivered coal.
(2) <1% or >1% refers to sulfur content as a percentage in coal by weight.
(3) Compliance coal is any coal that emits less than 1.2 pounds of sulfur dioxide per million BTU when burned. Compliance coal meets sulfur emission standards imposed by Title IV of the Clean Air Act.
(4) Reserve holdings include metallurgical coal reserves. Although these metallurgical coal reserves receive the highest selling price in the current market when marketed to steel-making customers, they can also be marketed as an ultra-high BTU, low sulfur utility coal for electricity generation.
HVM - High Vol Met
LSU - Low Sulfur Utility
PCI - Pulverized Coal Injection
SF - Synthethic fuel Product
V - Various
Reserve Estimation Procedure
TECO Coal’s reserves are based on over 2,700 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 Coal’s reserve evaluation and mine planning, TECO Coal takes into account factors such as restrictions under railroads, roads, buildings, power lines, or other structures. Depending on these factors, coal recovery may be limited or, in some instances, entirely prohibited. Current engineering practices are used to determine potential subsidence zones. The footprint of the relevant structure, as well as a safety angle-of-draw, are considered when mining near or under such facilities. Also, as part of TECO Coal’s reserve and mineability evaluation, TECO Coal reviews legal, economic and other technical factors. Final review and recoverable reserve determination is completed after a thorough analysis by in-house engineers, geologists and finance associates.
TECO TRANSPORT
Bulk Terminal’s storage and transfer terminal is on a 1,070-acre site fronting on the Mississippi River, approximately 40 miles south of New Orleans. Bulk Terminal owns 342 of these acres in fee, with the remainder held under long-term leases.
Barge Line operates a fleet of 14 line vessels, 6 harbor vessels, and 627 river barges, approximately 74% of which it owns, on the Mississippi, Ohio and Illinois rivers and their tributaries. TECO Barge owns 15 acres of land fronting on the Ohio River at Metropolis, Illinois on which its operating offices, warehouse and repair facilities are located. Fleeting and repair services for its barges and those of other barge lines are performed at this location. Additionally, Barge Line performs fleeting activities in Davant, Louisiana, where Bulk Terminal is located.
As of Dec. 31, 2006, Ocean Shipping owns or operates a fleet of 8 ocean-going tug/barge units, a 33,500 short ton ocean-going ship, a 40,900 short ton ocean-going ship, and a 41,400 short ton ocean-going ship, with a combined cargo capacity of over 376,500 tons.
TECO GUATEMALA
TPS San José, LDC, a subsidiary of TECO Guatemala, Inc., 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 Operairones, a subsidiary of TECO Guatemala which provides operations, maintenance and administrative support to CGESJ and TCAE, owns approximately 43 acres in Masagua, Guatemala.
Item 3.
Item 3. LEGAL PROCEEDINGS.
For significant legal proceedings and discussion of environmental matters see Notes 12 and 8, Commitments and Contingencies, of the TECO Energy and Tampa Electric Company Consolidated Financial Statements, respectively.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matter was submitted during the fourth quarter of 2006 to a vote of TECO Energy’s security holders, through the solicitation of proxies or otherwise.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages, current positions and principal occupations during the last five years of the current executive officers of TECO Energy are described below.
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 2, 2007, and until such officer’s successor is elected and qualified.
PART II
Item 5.
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The following table shows the high and low sale prices for shares of TECO Energy common stock, which is listed on the New York Stock Exchange, and dividends paid per share, per quarter.
The approximate number of shareholders of record of common stock of TECO Energy as of Feb. 23, 2007 was 17,933.
Dividends on TECO Energy’s common stock are declared and paid at the discretion of its Board of Directors. The primary sources of funds to pay dividends to its common shareholders are dividends and other distributions from its operating companies. TECO Energy’s $200 million credit facility contains a covenant that could limit the payment of dividends exceeding $50 million, subject to increase in the event TECO Energy issues additional shares of common stock, 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.
In addition, TECO Diversified, Inc., a wholly-owned subsidiary of TECO Energy and the holding company for TECO Transport and TECO Coal, has a guarantee related to a coal supply agreement that limits the payment of dividends to its common shareholder, TECO Energy, but does not limit loans or advances.
See Liquidity, Capital Resources - Covenants in Financing Agreements section of MD&A, and Notes 6, 7 and 12 to the TECO Energy Consolidated Financial Statements for additional information regarding significant financial covenants.
All of Tampa Electric Company’s common stock is owned by TECO Energy, Inc. and, therefore, there is no market for the stock. Tampa Electric Company pays dividends substantially equal to its net income applicable to common stock to TECO Energy. Such dividends totaled $140.0 million in 2006, $173.4 million in 2005, and $163.2 million in 2004. 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.
(1) These shares were not repurchased through a publicly announced plan or program, but rather relate to compensation or retirement plans of the company. Specifically, these shares represent shares delivered in satisfaction of the exercise price and/or tax withholding obligations by holders of stock options who exercised options (granted under TECO Energy’s incentive compensation plans), shares delivered or withheld (under the terms of grants under TECO Energy’s incentive compensation plans) to offset tax withholding obligations associated with the vesting of restricted shares and shares purchased by the TECO Energy Group Retirement Savings Plan pursuant to directions from plan participants or dividend reinvestment.
Item 6.
Item 6. SELECTED FINANCIAL DATA OF TECO ENERGY, INC.
(1) Amounts shown include reclassifications to reflect discontinued operations as discussed in Note 20 to the TECO Energy Consolidated Financial Statements.
(2) 2004 and 2003 include impairment charges of $558.6 million and $100.1 million, respectively. See Notes 17 and 18 to the TECO Energy Consolidated Financial Statements.
Item 7.
Item 7. MANAGEMENT’S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION & RESULTS OF OPERATIONS.
This Management’s Discussion and Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. Such statements are based on our current expectations, and we do not undertake to update or revise such forward-looking statements. These forward-looking statements include references to our anticipated capital expenditures, liquidity and financing requirements, projected operating results, future transactions, and other plans. Important factors that could cause actual results to differ materially from those projected in these forward-looking statements are discussed under “Risk Factors.”
TECO Energy, Inc. is a holding company, and all of its business is conducted through its subsidiaries. In this Management’s Discussion and Analysis, “we,” “our,” “ours” and “us” refer to TECO Energy, Inc. and its consolidated group of companies, unless the context otherwise requires.
OVERVIEW
We are a diversified energy-related holding company with five businesses consisting of regulated electric and gas utility operations in Florida and other operating companies engaged in coal mining and synthetic fuel production, waterborne transportation services and, in Guatemala, unregulated electric generation with long-term contracts and regulated electricity distribution.
Our regulated utility companies, Tampa Electric and Peoples Gas System (PGS) operate in the high-growth Florida market. Tampa Electric serves more than 661,000 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 4,383 megawatts. PGS, Florida’s largest regulated gas distribution utility, serves more than 332,000 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 1.3 billion therms in 2006.
Our other energy-related operating companies are TECO Coal, TECO Transport and TECO Guatemala. TECO Coal, through its subsidiaries, operates surface and underground mines and related coal processing facilities in eastern Kentucky, Tennessee and southwestern Virginia producing metallurgical-grade and high-quality steam coals. Sales in 2006 were 9.8 million tons, of which 5.3 million tons were sold as synthetic fuel. TECO Transport, our waterborne transportation company, through its subsidiaries, operates a fleet of inland river barges and towboats on the Ohio, Mississippi and Illinois rivers and their tributaries; a fleet of eight oceangoing tug-barge combination units and three ships that operate in the Gulf of Mexico and worldwide transporting dry-bulk cargos; and a dry-bulk storage and transfer terminal located on the Mississippi River southeast of New Orleans. 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 Guatemala’s largest distribution utility.
Since 2003, our business strategy has been to focus on these five businesses and also to divest of our merchant power and unregulated energy services businesses, which was substantially completed in 2005. This strategy was implemented following a series of major investments in unregulated domestic power generation facilities outside of Florida, and other smaller unregulated energy service providers within Florida made during the years 2000 through 2003. These investments were made in anticipation of a movement toward competitive energy markets in Florida and other states. However, the wholesale power markets evolved in a manner that was much different than we expected at the time the investment decisions were made, and the independent power business changed dramatically. These changes reduced the prospects for the profitability of the investments in our unregulated domestic independent power generation facilities for several years to come, such that we decided to reduce the risk to cash flow and earnings from our involvement in the merchant power sector by divesting the assets (see the TWG Merchant section). In the exiting of the merchant power business, we sold assets at prices below those we paid and recorded large write-offs, and in the case of the large Union and Gila River power plants we wrote off our entire equity investment. We had issued significant amounts of debt at the TECO Energy parent level to fund portions of these investments, which negatively impacted our balance sheet and credit ratings.
As a result of our renewed focus on our utility operations and profitable unregulated businesses and the aggressive and successful execution of our plans to exit the merchant power business, our financial position has improved, our business risk profile has been reduced, and all three of the debt rating agencies moved their outlook on TECO Energy’s and Tampa Electric’s debt ratings from “negative” to “stable” in 2005. One of our goals, over time, is to return to an investment-grade credit rating at the parent level and to improve Tampa Electric’s credit ratings through our actions to improve our cash flows, reduce debt and reduce business risk.
Our cash priorities are to reduce parent debt levels and to invest in Tampa Electric to support its capital needs associated with customer growth and environmental compliance. As part of our efforts to return to investment grade, in 2006, we announced plans to retire $500 million of TECO Energy parent-level debt beyond the retirement of the $357 million maturing in 2007 and the $200 million of 8.5% trust preferred securities (TruPS) retired in 2005 and 2006. We are now considering various options to meet or exceed our debt retirement goals, and to make additional investments in Tampa Electric to support its growing capital requirements (see the Tampa Electric and Capital Expenditures sections).
Given the growth opportunities available in water transportation, we want to ensure that TECO Transport is best positioned to realize its potential in today’s strong marine transportation market. Among the alternatives we are considering to address our financial and business priorities is a review of the options for the long-term future of TECO Transport, including its sale.
The sale of TECO Transport is not a decision we take lightly, as it has a long history as a solid and profitable performer in our family of companies. However, the current strong market for transportation services and for transportation company mergers and acquisitions makes this an opportunity that we must consider, with the potential for good value to TECO Energy and growth for TECO Transport from an investor focused on marine transportation markets.
In 2006, we remained focused on growing earnings and building our cash and liquidity position to enable us to grow our utility businesses and to further reduce TECO Energy parent debt. Our per-share results, excluding charges, gains and synthetic fuel results, improved over 2005 levels. Despite the reduced cash generation from the production of synthetic fuel due to high oil prices, our businesses provided strong cash generation, which allowed us to build a significant cash position. This allowed us to continue our accelerated efforts to reduce parent debt with the retirement of the remaining $100 million of our highest cost debt, the 8.5% TruPS due in 2041. We also made a planned $52 million cash equity contribution to Tampa Electric to support its higher capital expenditures as the construction of the two peaking units at the Polk Power Station and the selective catalytic reduction (SCR) equipment for nitrogen oxides (NOx) control on the coal-fired units at the Big Bend Power Station continued, and we made a voluntary, previously unplanned $30 million contribution to the TECO Energy pension plan to accelerate improvement in the funded status of the plan. We also invested in additional facilities at TECO Coal to replace higher cost mines that are being idled and to increase production after 2007, if market conditions warrant it. Even after these actions, and despite reduced cash proceeds from investors in our synthetic fuel production facilities, we ended 2006 with over $400 million of cash available at the TECO Energy parent level.
Our earnings in 2006 reflected improved results at PGS and TECO Transport, the elimination of operating losses related to merchant power activities, and lower parent interest expense as a result of the early retirement of $380 million of 10.5% notes in June 2005 and the first $100 million of TruPS in late 2005. Tampa Electric continued to benefit from strong customer growth, but the planned increased spending on customer service enhancements, distribution system reliability, and reliability and capacity factor improvements on its coal-fired generating units offset higher base revenues. Results also reflected the impact of the temporary idling of our synthetic fuel production facilities for approximately eight weeks during the summer due to high oil prices and the partial phase-out of the tax credits for the production of synthetic fuel due to high oil prices and the resulting reduction in revenues from the third-party investors. Excluding synthetic fuel, TECO Coal benefited from the contracts signed in 2005 and early 2006 during a period of very strong coal prices.
We also completed the disposition of the remaining assets associated with the merchant power plants and small energy services businesses in 2006. We sold the remaining McAdams Power Station assets along with the site, two unused stream turbines and a district cooling plant in Miami, Florida.
OUTLOOK
Focus on our core businesses
For 2007, we plan to continue to focus on improving earnings and maintaining our strong cash and liquidity positions (see the Liquidity, Capital Resources section). We currently estimate our 2007 per share results from continuing operations, excluding synthetic fuel, to be in a range of $0.97 to $1.07. This estimate is driven by the expected continued customer and energy sales growth at the Florida utilities, lower coal production at TECO Coal at margins consistent with 2006 levels, continued strong river barge rates and good operations in the oceangoing business at TECO Transport, and continued strong operating results at TECO Guatemala. This estimate also includes expected lower parent interest expense as a result of debt retirements completed in 2006 and planned in 2007.
In 2007, we expect reported net income calculated in accordance with Generally Accepted Accounting Principles (GAAP) to include approximately $0.33 per share of benefits expected from synthetic fuel production. Cash generated by synthetic fuel production in 2007 will help add to the cash position that we have built for future debt retirement. Due to the idling of the synthetic fuel production facilities for a portion of 2006 and the end of the program after 2007, we think it is important to provide a non-GAAP results measure that excludes all costs or benefits related to the production of synthetic fuel. This measure provides investors additional information to assess the company’s results and future earnings potential without the production of synthetic fuel.
Since July 2006, we have provided two measures to allow comparison of our results both 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, and non-GAAP results excluding synthetic fuel (Non-GAAP Results Excluding Synthetic Fuel), which excludes charges, gains and benefits associated with the production of synthetic fuel (see the Non-GAAP Information section). We will continue to provide Non-GAAP Results Excluding Synthetic Fuel, and are providing our 2007 results expectations on this basis.
With the expiration of the synthetic fuel tax credits at the end of 2007, we expect to partially mitigate the corresponding reduction in earnings and cash flow that will result by optimizing our coal operations, improving results from all of the operating companies, and reducing interest expense at the parent level. We expect that interest expense will be lower in 2008 as a result of our planned retirement of the remaining TECO Energy parent debt maturing in 2007, as well as the retirements accomplished in 2006.
These forecasted results are based on our current assumptions described in each operating company discussion, which are subject to risks and uncertainties (see the Risk Factors section).
We are maintaining our priorities for the use of cash to improve our financial profile through debt reductions at the TECO Energy parent level and to invest in our regulated businesses. Our near-term debt reduction efforts are focused on the retirement of the remaining 2007 debt maturities and longer-term on reducing parent-level debt by an additional $500 million in the 2008 to 2010 period. We expect to make an additional $80 million equity contribution to Tampa Electric in 2007 to support its continued capital spending for environmental controls and to serve its growing customer base.
Capital expenditures increased in 2006, primarily at Tampa Electric for additional peak-load generating units, equipment to control NOx emissions and heat rate and capacity factor improvements in coal-fired units. We also invested in new mining equipment and mines at TECO Coal. We forecast capital expenditures to increase further in the 2007 through 2011 period at Tampa Electric to meet normal customer growth and generation plant maintenance, for distribution system improvements to provide higher reliability, for its portion of transmission system expansion and upgrades in the Central Florida area to meet the new National Electric Reliability Council (NERC) reliability standards, for modest distribution system expansion at Peoples Gas, and for the completion of incremental production capacity increases at TECO Coal that commenced in 2006 (see the Liquidity, Capital Resources section). In addition, Tampa Electric is evaluating alternatives for meeting its needs for additional generating capacity in the 2009 - 2013 period, including the potential for new baseload generating capacity in 2013, which will affect capital spending in 2008 through 2012 and is not reflected in our current forecast (see the Capital Expenditures section).
Expected Effects of Synthetic Fuel Production on Cash and Earnings
A major source of the GAAP earnings and cash that we expect to generate in 2007 comes from TECO Coal’s previously completed sales of ownership interests in its synthetic fuel production facilities and the synthetic fuel related tax credits generated for the third-party owners. In 2007, the synthetic fuel tax credits could be reduced if oil prices exceed a certain threshold level and completely phased out if oil prices exceed the top of a range, which we estimate to be a range of $63 to $79 per barrel, as measured on a New York Mercantile Exchange (NYMEX) basis.
In January 2007, TECO Coal entered into oil price hedge instruments that protect against the risk of a reduction in the revenues we expect from the third-party investors from the production of synthetic fuel in 2007 due to high oil prices. When combined with hedges entered into in October 2006, the additional instruments protect approximately $195 million of the gross cash benefits expected from the third-party investors for the production of synthetic fuel over the full expected average annual oil price range of $63 to $79 per barrel on a NYMEX basis. The hedges in place provide very close to a dollar-for-dollar recovery of lost synthetic fuel revenues in the event of a phase-out over the estimated phase-out range. The total cost of the hedges was approximately $37 million.
The value of the hedge instruments may vary during the year, depending on year-to-date actual oil prices plus oil price futures for the remainder of the year, which will be reflected as mark-to-market adjustments in quarterly earnings from synthetic fuel production.
The following table illustrates the estimated components of synthetic fuel earnings and cash at various oil prices for the 5.7 million tons of synthetic fuel production expected in 2007.
2007 Synthetic Fuel Earnings and Cash
(1) Incremental costs associated with the production of synthetic fuel.
TECO Coal has agreements with the investors in its synthetic fuel production facilities that provide TECO Coal with flexibility to cease producing synthetic fuel under certain conditions. If the calendar-year average oil price, on the basis of actual plus futures prices, exceeds $62 per barrel on a NYMEX basis, TECO Coal has the right to cease or reduce production, and the third-party investors have the right to not participate in the production (see the TECO Coal section).
The tax credit program will expire on Dec. 31, 2007, and while we do not expect the period for the tax credit program to be extended or renewed in the current form, we are assuming that there will be no change in the current legislation. Based on the assumption that the program expires as scheduled, both net income and cash flow at TECO Coal are expected to decline in 2008, due to the loss of the benefits from the sale of the third-party ownership interests.
In 2008, TECO Coal expects to no longer produce synthetic fuel, but it expects to produce conventional coal at a level that keeps its total production similar to amounts expected to be sold in 2007. When production of synthetic fuel ends in 2008, TECO Coal will stop mining the high cost coals currently being mined for use in the production of synthetic fuel and will stop operating the synthetic fuel production equipment, which are expected to reduce production costs. At that time, the earnings and cash flow from TECO Coal will be dependent on the selling price of coal, and its ability to manage production costs.
RESULTS SUMMARY
Our results in 2006 reflect lower earnings from the production of synthetic fuel at TECO Coal, lower earnings at Tampa Electric, and lower earnings at TECO Guatemala partially offset by improved results at TECO Transport, slightly higher results at
PGS, the elimination of operating losses related to merchant power activities, and lower parent-level interest expense. In 2006, net income and earnings-per-share were $246.3 million, or $1.19 per share, compared to $274.5 million, or $1.33 per share, in 2005. Net income and earnings-per-share from continuing operations were $244.4 million, or $1.18 per share, in 2006, compared to $211.0 million, or $1.02 per share, in 2005. Results in 2006 included a $32.1 million, or $0.16 per share, benefit to earnings from synthetic fuel production, compared to $82.4 million, or $0.40 per share, in the 2005 period. In 2006, results from continuing operations also included an $8.1 million after-tax gain from the sale of the McAdams Power Station assets, $5.7 million of after-tax gains from the sale of two unused steam turbines, and $3.0 million of after-tax charges related to Hurricane Katrina damage at TECO Transport. In 2005, results from continuing operations included $46.7 million, or $0.23 per share, of after-tax charges for early debt retirement, and a $14.6 million after-tax, or $0.07 per share, loss at TWG Merchant related primarily to the unfinished Dell and Mc Adams merchant power plants. Results from discontinued operations in 2006 primarily included the recovery of amounts that had been previously written off and tax adjustments at the small energy services companies.
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 GAAP to non-GAAP reconciliation tables for each year shown, which follows hereafter. A non-GAAP financial measure is a numerical measure that includes amounts, or is subject to adjustments that have the effect of including amounts, that are excluded from the most directly comparable GAAP measure (see the Non-GAAP Information section).
Results Comparisons
Our results in 2005 were driven by stronger markets for TECO Coal and TECO Transport, continued customer and energy sales growth at Tampa Electric and Peoples Gas, and lower TECO Energy parent-level interest expense. In 2005, net income and earnings-per-share were $274.5 million and $1.33, respectively, compared to a loss of $552.0 million and a per-share loss of $2.87 in 2004. Results in 2005 included the $45.0 million after-tax debt-extinguishment charge associated with the June 2005 redemption of $380 million of 10.5% notes and a $76.5 million after-tax gain recorded in discontinued operations upon the final sale and transfer of the Union and Gila River power stations to the lenders in May 2005. The gain represented the reversal of the accumulated unfunded operating losses recorded against equity for the period from Dec. 31, 2003, the date we decided to exit the projects, through the effective date of the transfer to the lenders group. Also included in results are smaller charges and gains, which are detailed in the table that reconciles 2005 GAAP net income to non-GAAP results. Results from discontinued operations in 2005 include the operating results for the Union, Gila River and Commonwealth Chesapeake power stations until the time of the transfers to the respective buyers, including the gain on the transfer discussed above, and true-up amounts from previously divested assets.
In 2005, net income and earnings-per-share from continuing operations were $211.0 million and $1.02, respectively, compared to a loss of $355.5 million and a per-share loss of $1.85 for 2004. Non-GAAP Results With Synthetic Fuel, which exclude certain charges and gains included in GAAP net income from continuing operations but includes synthetic fuel, were $254.7 million in 2005, compared to $153.1 million in 2004. In 2005, results from continuing operations reflected improved results from the business segments, particularly the unregulated businesses. TECO Coal’s net income was significantly higher, driven by higher prices for coal and the sale of an additional 8% ownership interest in its synthetic fuel production facilities. TECO Transport’s increased earnings reflected higher river barge rates due to better balance in supply and demand, and the qualification of two vessels for the positive benefit of tax law changes under the Jobs Creation Act. TECO Guatemala reported strong results from continued good operation of the power generating plants, customer and energy sales growth at the distribution utility and favorable tax rates due to the Jobs Creation Act. Tampa Electric and Peoples Gas both experienced continued customer and energy sales growth.
2006 Earnings Summary
(1) See the GAAP to non-GAAP reconciliation tables that follow.
(2) A non-GAAP financial measure is a numerical measure that includes amounts, or is subject to adjustments that have the effect of including amounts, that are excluded from the most directly comparable GAAP measure (see the Non-GAAP Information section).
(3) Average shares outstanding for 2004 include the issuance of 10.2 million shares in September in conjunction with the early settlement of the 9.5% adjustable conversion-rate equity security units.
(4) Average shares outstanding for 2005 include the issuance of 6.85 million shares in conjunction with the final settlement of the 9.5% adjustable conversion-rate equity security units.
The following tables show the specific adjustments made to GAAP net income for each segment to develop our non-GAAP results.
2006 Reconciliation of GAAP net income from continuing operations to non-GAAP results
2005 Reconciliation of GAAP net income from continuing operations to non-GAAP results
2004 Reconciliation of GAAP net income from continuing operations to non-GAAP results
Non-GAAP Information
From time to time, in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, we present non-GAAP results, which present financial results after elimination of the effects of certain identified gains and charges. We believe that the presentation of this non-GAAP financial performance provides investors a measure that reflects the company’s operations under our business strategy. We also believe that it is helpful to present a non-GAAP measure of performance that clearly reflects the ongoing operations of our business and allows investors to better understand and evaluate the business as it is expected to operate in future periods. Management and the Board of Directors use this non-GAAP presentation as a yardstick for measuring our performance, making decisions that are dependent upon the profitability of our various operating units and in determining levels of incentive compensation.
The non-GAAP measure of financial performance we use is not a measure of performance under accounting principles generally accepted in the United States and should not be considered an alternative to net income or other GAAP figures as an indicator of our financial performance or liquidity. Our non-GAAP presentation of net income 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 true-ups to charges related to merchant power facilities 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. With the exception of synthetic fuel, hurricane costs and hurricane related insurance recoveries, substantially all of the items included in charges and gains for the periods detailed in the tables above are associated with our exit from the merchant power business and small energy services businesses.
OPERATING RESULTS
Management’s Discussion & Analysis of Financial Condition and Results of Operations utilizes TECO Energy’s consolidated financial statements, which have been prepared in accordance with GAAP and separate non-GAAP measures, to analyze the financial condition of the company. Our reported operating results are affected by a number of critical accounting estimates such as those involved in our accounting for regulated activities, asset impairment testing, and others (see the Critical Accounting Policies and Estimates section).
The following table shows the segment revenues, net income, and earnings per share contributions from continuing operations of our business segments (see Note 14 to the TECO Energy Consolidated Financial Statements).
(1) Revenues for all periods have been adjusted to reflect the presentation of energy marketing-related revenues on a net basis and the reclassification of the results from those businesses that have been sold to discontinued operations (see the Discontinued Operations section). Segment revenues include intercompany transactions that are eliminated in the preparation of TECO Energy’s consolidated financial statements.
(2) TECO Guatemala was deconsolidated under FIN 46R effective Jan. 1, 2004. Actual revenues in 2006, 2005 and 2004, which are not included in this table due to the effects of deconsolidation, were $113.7 million, $104.0 million and $102.1 million, respectively. Note 14 to the TECO Energy Consolidated Financial Statements provides additional information and the condensed financial information for the Guatemalan operations.
(3) Effective with 2006 only historical information is provided for TWG Merchant. Any remaining results are included in Parent/other.
(4) Segment net income and earnings are reported on a basis that includes internally allocated financing costs to the unregulated companies. Internally allocated finance costs for 2006, 2005 and 2004 were at a pretax rate of 8%, based on the average investment in each unregulated subsidiary.
(5) In 2004, results for TECO Guatemala included various charges related to merchant power activities recorded in that segment, but unrelated to its basic operations (see the 2004 GAAP to non-GAAP reconciliation table).
(6) The number of shares used in the earnings-per-share calculations are basic shares.
TAMPA ELECTRIC
Electric Operations Results
Tampa Electric is entering a period of growth through increasing capital expenditures to support customer growth, statewide transmission system reliability standards, implementation of the storm hardening plans mandated by the Florida Public Service Commission (FPSC) and additional baseload generating capacity needs.
Tampa Electric’s 2006 net income was $135.9 million, compared to $147.1 million in 2005. These results were driven by the planned increase in non-fuel operations expense, which more than offset continued strong customer growth and slightly higher energy sales. Weather patterns in 2006 resulted in 3% lower total degree-days than normal but 1% higher total degree-days than 2005, when total degree-days were 5% below normal. Results also included a $9.4 million after-tax disallowance by the FPSC for the recovery of a portion of the waterborne transportation costs for the delivery of solid fuel (see the Regulation section).
Tampa Electric’s 2005 net income was $147.1 million, compared to $146.0 million in 2004. These results were driven by continued strong customer growth and higher energy sales partially offset by weather patterns that resulted in 5% lower total degree-days than normal and 1% lower total degree-days than 2004, when total degree-days were 3% below normal, and higher non-fuel operating expenses, which include higher depreciation expense from normal plant additions. Results also included an $8.6 million after-tax disallowance by the FPSC for the recovery of a portion of the waterborne transportation costs for the delivery of solid fuel (see the Regulation section).
Summary of Operating Results
Tampa Electric Operating Revenues
Retail megawatt-hour sales rose 0.6% in 2006, driven by customer growth despite the effects of mild weather. In 2006, average annual customer growth of 2.8% (almost 18,000 new customers) was partially offset by mild weather and 1% lower average residential per-customer energy usage. Total degree days in Tampa Electric’s service area were 3% below normal but 1% above 2005. Tampa Electric estimates that the pattern of mild weather characterized by relatively few sustained periods of extreme temperatures reduced energy sales approximately 1% in 2006 compared to normal weather patterns.
In 2006, energy consumption per residential customer declined due to the combined effects of weather, price elasticity and changes in residential building trends. One of the factors contributing to this phenomenon is an increase in the number of condominiums and multi-family units, such as apartments, recently completed in the Tampa metropolitan area. Condominiums and multi-family units, which comprised about 36% of new customers in 2006, tend to have fewer square feet of air conditioned space per residence and use less energy per square foot due to more energy efficient construction. In addition, the higher costs for natural gas and coal, which are reflected in customers’ bills through the fuel adjustment clause, have caused customers to use less electricity in general. On a weather-normalized basis, retail energy sales to customers other than the phosphate industry, which is not weather-sensitive, increased 1.8% in 2006 compared to 2005.
Electricity sales to the lower margin industrial customers in the phosphate industry decreased an additional 18.5% in 2006 after a 6.5% decrease in 2005. The decline in sales to phosphate customers was driven by the idling of some mining operations in 2006 due to market conditions for the product. The longer-term decline in sales to phosphate customers reflects the natural reserve depletion and migration of mining operations out of Tampa Electric’s service area. Base revenues from phosphate sales represented less than 2% of base revenues in 2006 and less than 3% in 2005. Sales to commercial customers increased 2.0% in 2006, driven by the strong local economy.
Base rates for all customers were unchanged in 2006. Fuel-related revenues increased in 2006 and 2005 under the FPSC-approved fuel cost recovery clause, due to the recovery of previous under-recoveries of fuel expense in 2005 and 2004 and higher gas prices. Customers’ rates under the fuel clause increased in 2007 in accordance with the rates approved by the FPSC in November 2006, to reflect higher fuel costs, the under-recovery of $51 million of 2006 fuel cost due to higher cost of natural gas early in the year and the remaining $107 million portion of previously under-recovered 2005 fuel costs partially offset by the sale of a net $45 million of excess sulfur dioxide (SO2) emission credits, which appears as a credit on customers’ bills through the Environmental Cost Recovery Clause (see the Regulation section).
Energy sold to other utilities for resale increased 11% in 2006 due to a new contract for wholesale energy sales with a new customer and increased wholesale sales volumes to an existing customer. Energy sold to other utilities for resale increased in 2005 due to a planned increase in the energy sold under a long-term contract.
Energy Sales Growth Forecast
Based on projected growth from continued population increases and business expansion, Tampa Electric expects weather-normalized average retail energy sales growth of more than 2.5% annually over the next five years, with combined energy sales growth in the residential and commercial sectors of about 2.8% annually. This energy sales growth projection is 0.2% lower than previous projections to reflect the change in usage patterns experienced in 2006. Tampa Electric’s forecasts indicate that summer retail peak demand growth is expected to average more than 135 megawatts per year for the next five years. These growth projections assume continued local area economic growth, normal weather, and a continuation of the current energy market structure (see the Risk Factors section).
The economy in Tampa Electric’s service area continued to grow in 2006, aided by continued population growth in Florida, the region’s relatively low labor rates and attractive cost of living. The Tampa metropolitan area’s non-farm employment grew 2.0% in 2006, despite a 3.9% decline in construction employment, due to the strong local economy. Employment grew 2.5% in 2005 as the local economy recovered from the U.S. economic slowdown in the first half of 2004. The local Tampa area unemployment rate increased slightly to 3.0% at year-end 2006, compared with 2.9% in December 2005, and 4.6% in December 2004. These rates are lower than the year-end 3.3% unemployment rate for the State of Florida and 4.5% for the nation at Dec. 31, 2006.
As in many areas of the country, the housing market in Tampa Electric’s service area slowed in 2006 after significant growth in 2004 and 2005. The numbers of existing homes for sale and unsold new homes has increased over the 2005 and 2004 levels. Economists and real estate associations indicate that, while inventories of unsold homes are above the past two years, the housing market is expected to start to recover in late 2007.
Tampa Electric Operating Expenses
Total operating expense increased in 2006 primarily due to higher costs for coal partially offset by lower purchased power expense due to increased coal-fired generation from improved coal-fired unit availability. Non-fuel operations and maintenance expense increased, as planned, by $24.3 million after-tax. This increase reflected, among other items, after-tax increases of $8.3 million of additional spending on transmission and distribution system reliability and customer service enhancements, $5.3 million of additional spending on coal-fired unit performance improvements, $6.3 million of higher employee-related costs and $3.3 million of increased property insurance cost.
Total operating expenses increased in 2005 due to higher purchased power expenses as a result of lower coal-fired unit availability and the higher cost of natural gas for all utilities in Florida that is reflected in the cost of purchased power. Non-fuel operating and maintenance expenses increased as a result of higher power distribution expenses in 2005 due to more normal work activities following the 2004 hurricane restoration efforts. Other non-fuel operations and maintenance expenses increased due to increased employee-related expenses for items such as pensions, disability and medical reserves, and higher customer expenses, which included higher levels of uncollectible accounts.
Non-fuel operations and maintenance expenses are expected to increase at about inflationary levels in 2007 after the significant step up in 2006. The 2006 non-fuel operations and maintenance expense increase was for enhanced customer service, distribution system reliability improvements and to improved coal-fired generating unit availability and capacity factors. That portion of the higher non-fuel operations and maintenance expense related to the initial implementation of elements of the storm hardening plan that was submitted to and approved by the FPSC in 2006 are expected to continue with the full implementation of the storm hardening plan in 2007.
Depreciation decreased in 2006 due to the retirement of short-lived fully depreciated assets, such as telecommunications equipment, tools and test equipment, which more than offset the additional depreciation associated with normal plant additions. Depreciation expense is projected to increase in 2007, due to normal plant additions to serve Tampa Electric’s growing customer base and maintain system reliability and a partial year of depreciation on the first NOx control project to be completed on Big Bend Unit 4, which is expected to enter service in May. Depreciation expense increased in 2005 due to normal plant additions to serve the growing customer base.
Fuel Prices and Fuel Cost Recovery
Under regulatory accounting, the cost of fuel on the income statement represents the amounts authorized by the FPSC for recovery through the fuel adjustment clause, but the actual cost of fuel purchased may differ from those amounts. The difference between actual fuel cost and the amount authorized for recovery is deferred on the balance sheet as either under- or over-recovered fuel cost, and therefore does not impact net income.
Included in Tampa Electric’s fuel adjustment filing for rates effective in 2007 was $51 million of 2006 under-recovered fuel cost and the remaining $107 million of 2005 under-recovered fuel cost that was incurred after the 2006 fuel filing was made. In November 2006, the FPSC authorized the recovery of this amount and the full projected 2007 fuel expense (see the Regulation section). The increase in the fuel adjustment clause will be partially offset by a $35 million net benefit to customers primarily from the sale of excess SO2 emission credits, which appears as a credit on customers’ bills through the Environmental Cost Recovery Clause (see the Regulation section).
Fuel prices increased in 2006 driven primarily by higher natural gas prices early in the year and higher coal prices throughout the year. For the year, at $9.61/mmBTU, the average delivered cost of natural gas decreased compared to 2005 when natural gas prices spiked upward following hurricanes Katrina and Rita. Coal prices also increased during that period from a delivered cost of $2.14 per million BTU in 2004 to $2.49 per million BTU in 2006 due to supply and demand for utility steam coal.
Natural gas prices were extremely volatile during the 2004 through 2006 period as a result of supply constraints due to damage to production and transportation infrastructure from hurricanes and increased demand nationwide due to the higher percentage of electricity now being generated from natural gas-fired generation, particularly during peak-load periods. Natural gas price volatility is expected to continue due to the balance in supply and demand and market prices being driven by commodity investors rather than physical supply users. Coal prices, while less volatile, have increased steadily for the past three years. Coal prices are expected to decline in 2007 due to the current over supply of steam coal in the U.S. market following a mild summer in 2006 and a mild start to the winter (see the TECO Coal section).
Energy Supply
On a retail energy supply basis, Tampa Electric generation accounted for 95%, 92% and 95% of the total retail energy sales in 2006, 2005 and 2004, respectively, with the remainder of the energy supplied by purchased power. Purchased power expense decreased 18% and the volume of power purchased decreased 17% in 2006 due to improved coal-fired unit availability and generation. The amount of power purchased by Tampa Electric to serve its customers increased in 2005 following a decrease in 2004, primarily due to lower coal-fired unit availability. Purchased power is expected to increase in 2007 due to the planned extended maintenance period on Big Bend Unit 4 for the completion of the SCR project for that unit.
Prior to 2003, nearly all of Tampa Electric’s generation was from coal. Starting in April 2003, the mix started to shift, with increased use of natural gas at Bayside. Nevertheless, coal is expected to continue to be more than half of Tampa Electric’s fuel mix due to the baseload units at Big Bend and the coal gasification unit, Polk Unit One. Beginning in 2007 and through 2010, one of the four Big Bend coal-fired units will undergo an extensive outage each year to complete the construction of the NOx control equipment (see the Environmental Compliance section), which is expected to reduce the generation from coal in those years.
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.
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. In addition to a wood pole inspection program instituted separately, the plans address vegetation management, audits of pole attachments, transmission structure inspections and hardening, data gathering and analysis, natural disaster planning, coordination with local governmental agencies and collaborative research. In October 2006, the FPSC approved Tampa Electric’s plan to comply with the directive. Tampa Electric is implementing its plan and estimates that the average incremental non-fuel operations and maintenance expense of this plan to be approximately $15 million annually.
The FPSC also modified its rule regarding the design standards for new and replacement transmission and distribution line construction, including certain critical circuits in a utility’s system. Beyond employing accepted engineering practices and complying with the applicable edition of the National Electric Safety Code (NESC), the new design standard requires adoption of the NESC extreme wind loading standards for distribution facilities. The new design standards also encourage the placement of new or modified facilities underground when feasible. These new requirements are expected to increase the capital expenditures required to expand the system to meet growing customer demand and to maintain system reliability by approximately $20 million annually (see the Regulation section).
Higher Capital Spending
Tampa Electric is entering a period of increasing capital spending for infrastructure to reliably serve its growing customer base and to address the needs for future baseload generating capacity additions. In addition to the capital spending to comply with the storm hardening plan described above and the need for additional generating capacity discussed below, Tampa Electric expects
to make additional capital investments for its pro rata portion of transmission system improvements to meet the new NERC reliability standards for Central Florida. It also expects to invest additional amounts in its transmission and distribution system to improve reliability and reduce customer outages.
Based on its current forecast of energy demand and sales growth, Tampa Electric has identified a need for new baseload capacity in early 2013 due to continued customer growth and the expiration of a long-term power purchase agreement with Hardee Power Partners. Its options to satisfy the baseload capacity need range from purchasing the power to constructing its own generating facility. Tampa Electric has initiated a request for proposal (RFP) process, for interim peak capacity needs and, as required in Florida for baseload capacity additions, to potentially purchase the needed power under power purchase agreements. If construction of a baseload generating unit by Tampa Electric is found to be the most cost-effective method to meet customers’ needs, there are additional regulatory and permitting steps required prior to Tampa Electric moving forward with such a construction program.
The capital expenditures required under the various options currently being evaluated vary significantly from only transmission system improvements to allow the import of power to the construction of peaking capacity and baseload capacity. In addition to an evaluation of the purchase versus build option, Tampa Electric has options regarding the type of baseload plant to be constructed, ranging from natural gas-fired combined cycle to an Integrated Gasification Combined Cycle (IGCC) unit. Tampa Electric’s preferred option is a 630-megawatt, coal- and petroleum coke-fueled IGCC unit in order to diversify its own fuel mix (which is expected to be more than 50% natural gas by that time); to meet the State of Florida’s goal of diversifying the fuel supplies used to generate power; and to take advantage of an IGCC unit’s ability to more easily capture and sequester carbon dioxide (CO2) emissions if required in the future (see the Capital Expenditures and Environmental Compliance sections). In 2006, under the Energy Policy Act of 2005, Tampa Electric was awarded an opportunity to receive $133.5 million of tax credits from the Internal Revenue Service (IRS) and U.S. Department of Energy (DOE) for its proposed IGCC plant.
In 2006, the Florida Legislature enacted a new statute related to new nuclear plants that might be constructed in Florida that provided for, among other things, the recovery of pre-construction costs and carrying costs of construction through the capacity cost recovery clause; a base rate increase when the plant is put in service to recover the costs of the plant; and the recovery of prudently incurred costs in the event that the plant is not completed. Tampa Electric is seeking similar legislative treatment for IGCC plants as they accomplish the same goal of increasing fuel diversity in Florida.
Tampa Electric has not sought a base rate increase since 1992. Since that last rate proceeding it has earned within its allowed ROE range while adding almost 190,000 customers and making significant investments in facilities and infrastructure, including baseload and peaking generating capacity additions, to serve the growing customer base. Over time, current base rates may not support the additional transmission and distribution system reliability capital spending, storm hardening capital and operations and maintenance spending, other recurring capital expenditures and generally higher non-fuel operations and maintenance expenditures and still earn a return within its allowed ROE range.
PEOPLES GAS
Operating Results
PGS reported net income of $29.7 million in 2006, compared to $29.6 million in 2005. Customer growth of 3.3%, increased sales to residential customers, and strong sales to power generating and off-system customers due to declining natural gas prices were partially offset by non-fuel operation and maintenance expenses that were $2.2 million higher. The higher off-system sales and increased volumes transported for power generation customers helped offset the impact of mild winter weather early in the year and then again in December 2006. After a very strong 2005 performance, sales to commercial customers declined slightly due to higher natural gas prices in early 2006. Results in 2006 included $1.7 million from the small energy services companies, which provide marketing, sales support and gas management services.
In 2006, the total throughput for PGS was 1.3 billion therms. Of this total throughput, 11% was gas purchased and resold to retail customers by PGS, 70% 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 65% of PGS’ annual therm volume, commercial customers used approximately 29%, and the balance was consumed by residential customers.
PGS had 2005 net income of $29.6 million, compared with $27.7 million for the same period in 2004, including the 2004 restructuring charge (see the 2004 GAAP to Non-GAAP reconciliation table). Customer growth of 3.6%, increased sales to residential and commercial customers and increased off-system sales were partially offset by higher operations and maintenance expenses in 2005. Results in 2005 reflected strong sales to commercial customers as a result of growth in the Florida economy and high levels of tourism, which enhanced commercial sales to hotels and restaurants, while sales of low-margin transportation service for interruptible customers declined.
In 2005, residential and commercial therm sales increased through customer growth and increased usage per customer. Increased residential usage reflected increased sales to customers with multiple uses for gas as a result of marketing to high-end residential developers. The increased commercial usage reflected the continued strong Florida economy and the strong 2005 tourist business at hotels, restaurants and theme parks served by PGS.
While the residential market represents only a small percentage of total therm volume, residential operations generally comprise 25% of total revenues. New residential construction that includes natural gas and conversions of existing residences to gas have steadily increased since the late 1980s. Like all natural gas distribution utilities, PGS is faced with potential decreases in per-customer usage due to improving appliance efficiency. As customers replace existing gas appliances with newer more efficient models, usage may 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). The PGA rate, which is approved by the FPSC annually, is a band and can vary monthly due to changes in actual fuel costs and normally results in lower under- or over-recovered gas cost variances at PGS than at Tampa Electric.
Summary of Operating Results
In Florida, natural gas service is unbundled for any non-residential customers that elect this option, affording these customers the opportunity to purchase gas from any provider. The net result of this 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 financial impact to the company when a customer shifts to transportation-only sales. PGS markets its unbundled gas delivery services to these customers through its “NaturalChoice” program. At year end 2006, approximately 42% of PGS’ non-residential customers had elected to take service under this program. Participation in this program was essentially unchanged in 2006.
Non-fuel operations and maintenance expense increased in 2006 primarily due to higher employee-related costs, such as pay and benefits. Operations and maintenance expense increased in 2005 primarily due to higher customer charges for uncollectible accounts, which have risen due to the high natural gas prices and higher personnel-related expenses. Depreciation expense increased in both years, in line with the capital expenditures made over the past several years to expand the system.
Depreciation is expected to increase in 2007 from normal plant additions and as a result of a depreciation study required every five years by the FPSC, which was approved in January 2007. Operations and maintenance expense, excluding costs related to FPSC-approved energy conservation programs recovered separately, are expected to increase at about inflationary levels.
PGS forecasts customer growth of approximately 2.5% in 2007, which is lower than the average customer growth experienced for the past five years. A major contributor to the slower growth is the slowdown in the housing market. PGS does serve some of the areas of Florida that experienced some of the most rapid growth and greatest housing price appreciation in 2005 and 2006, including the Ft. Myers and Naples areas. These areas are now experiencing the most significant impacts of the slowdown in the housing market.
Since its acquisition by TECO Energy in 1997, PGS has expanded its gas distribution system through system extensions 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. PGS’ expansion strategy for the past several years has been to take advantage of the significant capital investments in main pipeline expansions to connect customers to that existing infrastructure. In 2007, PGS expects its capital spending to support modest system expansion. It also expects continued customer additions and related revenues from its build-out efforts throughout the state of Florida, assuming continued local economic growth, normal weather, and other factors (see the Risk Factors section).
Gas Supplies
PGS purchases gas from various suppliers depending on the needs of its customers. The gas is delivered to the PGS distribution system through three interstate pipelines on which PGS has reserved firm transportation capacity for delivery by PGS to its customers.
Gas is delivered by the Florida Gas Transmission Company (FGT) through more than 57 interconnections (gate stations) serving PGS’ operating divisions. In addition, PGS’ Jacksonville Division receives gas delivered by the South Georgia Natural Gas Company pipeline through two gate stations located northwest of Jacksonville. Gulfstream Natural Gas Pipeline initiated gas delivery in 2003 through five gate stations. The addition of the Gulfstream pipeline enhances reliability of service and helps meet the capacity needs for PGS’ growing customer base.
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
TECO Coal recorded 2006 net income of $78.8 million, compared to $115.4 million in 2005. Excluding the $32.1 million benefit associated with the production of synthetic fuel, TECO Coal’s full-year 2006 Non-GAAP Results Excluding Synthetic Fuel were $46.7 million, compared to $33.0 million in 2005, which excluded $82.4 million of earnings benefits from the production of synthetic fuel, (see the 2006 GAAP Results Reconciliation to Non-GAAP table). Compared to 2005, results reflect a 13% higher average net per-ton selling price across all products, excluding transportation allowances, partially offset by higher production costs. Results also reflect a $3.8 million after-tax charge to reduce deferred tax assets consistent with a recent reduction in the Kentucky state income tax rate and a $2.7 million after-tax benefit from the true-up in 2006 of the 2005 synthetic fuel tax credit rate. The 2005 tax credit was adjusted to reflect $1.17 per million Btu on an actual basis versus the estimated $1.15 per million Btu used in 2005.
In 2006, the cash cost of production increased 12% over 2005. Higher production costs reflect higher costs associated with new safety regulations, the costs associated with relocating mining equipment from high cost mining areas and areas where the reserves were depleted, costs associated with additional exploration expenses to optimize future mining plans, and higher costs for diesel fuel, explosives, conveyor belts and steel-related products .
Total sales were 9.8 million tons in 2006, including 5.3 million tons of synthetic fuel, compared to 9.7 million tons, including 6.4 million tons of synthetic fuel in 2005. Lower synthetic fuel sales volumes reflect the idling of production facilities from late July through mid-September due to estimated average annual oil prices above the break-even level. Total coal sales were not impacted as synthetic fuel sales contracts permitted the substitution of conventional coal for synthetic fuel while the synthetic fuel production was idled.
TECO Coal’s 2005 net income was $115.4 million, driven by higher selling prices and margins, on total sales of 9.7 million tons, compared to $61.3 million for the same period in 2004, which included the $7.0 million benefit from a tax credit true-up, on sales of 9.1 million tons. Full-year tonnage includes 6.4 million tons of synthetic fuel sales in 2005, compared to 6.3 million tons in the 2004 period. Results reflect an average net selling price per ton, which excludes transportation allowances, almost 48% higher than in 2004; average cash cost of sales, excluding synthetic fuel costs, almost 20% higher than in 2004; and increased third-party ownership in the synthetic fuel production facilities. The cash cost of sales was driven by higher prices for diesel fuel, labor and steel products. Results in 2005 also included a $1.6 million after-tax benefit from the 2004 synthetic fuel tax credit rate, which was $1.13 per million Btu on an actual basis versus the $1.12 per million Btu estimated in 2004, and a $2.4 million negative adjustment to deferred tax assets due to a reduction in the Kentucky state income tax rate.
Synthetic Fuel
The benefits from the production of synthetic fuel reflect the estimated 35% reduction in revenues from third-party synthetic fuel investors based on estimated average annual oil prices of $66/Bbl at Dec. 31,2006. The phase-out range will be based on oil prices represented by the annual average of Producer First Purchase Prices reported by the U.S. Department of Energy. Based on the actual relationship of these prices reported through October and NYMEX prices, TECO Coal estimates the initial phase-out level for 2006 to begin at $62/Bbl on a NYMEX basis, and that the tax credits would be fully phased out at $76/Bbl on a NYMEX basis. Actual Department of Energy Producer First Purchase Prices for the full year, which are normally reported in late March of the following year, may cause positive or negative adjustments to estimated 2006 results and would be recorded in the first quarter of 2007.
Actual net cash generation from synthetic fuel production in 2006 was approximately $65 million, which includes the reduction of revenue from third-party investors, the effects of the temporary idling of synthetic fuel production and the cost of production, compared to a potential $140 million without the effects of high oil prices.
In 2005, synthetic fuel production and sales were 6.4 million tons, compared to 6.3 million tons in 2004. TECO Synfuel Holdings, LLC had sold 90% of its ownership interest to two third party investors by the end of 2004, along with associated percentage rights to benefits in the business that adjust from time to time. Allocation of the benefits varied in 2004 such that more
than 90% of the benefits were to third parties. Allocation of the benefits in 2005 was temporarily increased 8% in the first and second quarters such that 98% of the benefits went to the third parties. In July 2005, a permanent increase in the third-party ownership of the synthetic fuel facilities to 98% was achieved through the sale of an additional 8% interest to a new participant.
Under these third-party ownership transactions, TECO Coal is paid to provide feedstock, operate the synthetic fuel production facilities and sell the output; TECO Coal also recognizes a gain on the sale of the ownership interests in the facilities for each ton of synthetic fuel sold. The purchasers have the risks and rewards of ownership and are allocated 98% of the tax credits and operating costs. The net cash benefit to TECO Coal from the investors for the production of synthetic fuel was approximately $65 million and $158 million in 2006 and 2005, respectively.
TECO Coal has agreements with the investors in its synthetic fuel production facilities that were amended to provide TECO Coal with flexibility to cease producing synthetic fuel. These amendments were entered into in order to provide the parties additional flexibility in the event that high oil prices impact the level of the tax credits. Under the amendments, TECO Coal and the investors will review actual and forecasted oil prices monthly to determine if and at what level synthetic fuel production should continue. If the calendar-year average oil price, on the basis of actual plus futures prices exceed $62 per barrel on the NYMEX basis, TECO Coal has the right to cease or reduce production and the third-party investors have the right to not participate in the production. If production is idled, and oil prices then moderate, full production can resume later in the year.
The economics of the sale of the ownership interests in the synthetic fuel production facilities are reasonably constant, as they are determined by the level of the tax credits and not the price received from the sale of output. The synthetic fuel tax credit is determined annually and is estimated to be $1.21 per million Btu for 2006, and was $1.17 per million Btu in 2005 and $1.13 per million Btu in 2004. This rate escalates with inflation but could be limited by domestic oil prices. TECO Coal has hedged its risk from high oil prices for 2007 (see the discussion above and the Synthetic Fuel discussion in the Outlook section).
TECO Coal recorded $2.1 million of after-tax benefits from the production associated with its remaining synthetic fuel ownership interest in 2006, but recorded no synthetic fuel tax credits in earnings for 2005 or 2004 because of TECO Energy’s actual 2004 and 2005 tax positions, which were driven by tax losses incurred upon the disposition of merchant power plants. In 2004, a $7.0 million positive true-up to income taxes was related to synthetic fuel tax credits that, due to projected limitations on taxable income, were reserved for in 2003 but were found to be recognizable in 2004 upon finalizing the 2003 tax return.
TECO Coal Outlook
We expect TECO Coal’s Non-GAAP Results Excluding Synthetic Fuel to decline in 2007. Total sales are expected to be in a range between 9 and 9.5 million tons in 2007, which includes 5.7 million tons of synthetic fuel, compared to 9.8 million tons, including 5.3 million tons of synthetic fuel in 2006. The lower expected sales volume reflects the current coal market conditions where inventory accumulation due to mild weather in 2006 and early 2007 has depressed prices for utility steam coal. Excluding synthetic fuel, the average fully-loaded cash and pretax margins per ton are expected to be in line with 2006 margins of about $10 and $6 per ton, respectively.
In January 2007, TECO Coal entered into oil price hedge instruments that protect against the risk of high oil prices reducing the value of the tax credits related to the production of synthetic fuel in 2007. When combined with the hedges entered into in October 2006, the additional instruments protect approximately $195 million of the gross cash benefits expected from the third-party investors for the production of synthetic fuel over the full expected average annual oil price range of $63 to $79 per barrel on a NYMEX basis. The oil price range between $63 and $79 per barrel is the expected phase-out range for synthetic fuel benefits for 2007. The hedges in place provide approximately a dollar-for-dollar recovery of lost synthetic fuel revenues in the event of a phase-out over the estimated phase-out range. The total cost of the hedges was approximately $37 million (see the Synthetic Fuel discussion in the Outlook section). The value of the hedge instruments may vary during the year, depending on year-to-date actual oil prices plus oil price futures for the remainder of the year, which will be reflected as mark-to-market adjustments in quarterly earnings from synthetic fuel production.
Following the expiration of the synthetic fuel tax credit program on Dec. 31, 2007, we expect both net income and cash flow at TECO Coal to decline due to the loss of the benefits from the sale of the third-party ownership interests. In 2008, TECO Coal expects to no longer produce synthetic fuel, and it expects to produce only conventional coal at levels consistent with 2007 in the current market conditions. When production of synthetic fuel ends, TECO Coal will stop mining the high-cost coals currently being mined for use in the production of synthetic fuel and will stop operating the synthetic fuel production equipment, which are expected to reduce total production costs. At that time, the earnings and cash flow from TECO Coal will be dependent on the selling price of coal in 2008, and its ability to manage production costs.
Coal Markets
In 2004 and 2005 the coal industry benefited from higher prices for competing fuels, increased demand worldwide for metallurgical coal, better balance in supply and demand, lower producer and consumer inventories and consolidation in the mining industry all of which contributed to higher prices for coal. In addition, changes that have occurred over the past several years, including industry consolidation, longer environmental permitting time for new mines, fewer skilled coal miners, and gradual depletion of high-quality Central Appalachian reserves allowed producers to contract production for 2006 at average prices above 2005 average levels.
Following a mild 2006 summer and a mild start to the 2006 - 2007 winter, spot market prices for Central Appalachian utility steam coal have declined more than 40% since the summer of 2006 due to low usage and increased inventories at utility users to above normal levels. A number of Central Appalachian coal producers, including TECO Coal, have announced plans to produce less coal in 2007 in response to the weaker market conditions. Current indications within the domestic coal industry are that until the
utility inventories return to more normal levels and supply and demand are balanced there will be few long-term contracts signed for 2008 and beyond and that prices are expected to remain weaker than those experienced in 2005 and 2006.
TECO Coal sells almost all of its annual production under either multi-year contracts or contracts that are finalized late in the previous year or early in the current year. In 2006, TECO Coal benefited from contracts, which included some multi-year contracts, signed in the stronger 2005 price environment. It currently has 86% of its planned 2007 sales under contract with most of the uncontracted tons expected to be sold to European metallurgical coal customers. Contract negotiations with these customers were underway in January and are expected to be completed by the end of the first quarter of 2007 for sales in 2007. Due to its high percentage of coal under contract, TECO Coal expects its average realized price per ton in 2007 to be at levels similar to 2006. For 2008, TECO Coal currently has 45% of its expected sales contracted, all of which is utility steam coal.
The significant factors that could influence TECO Coal’s results in 2007 are the higher expected costs of production and the weaker prices for the 14% of production that remains unsold. Longer-term factors that could influence results include inventories at steam coal users, weather, general economic conditions, the level of oil and natural gas prices, commodity price changes which impact the cost of production, and CO2 reductions if required (see the Environmental Compliance and Risk Factors sections).
TECO TRANSPORT
In 2006, TECO Transport recorded net income of $22.8 million, compared to $20.2 million in 2005. The 2006 results reflected higher river barge rates and equipment utilization, improved oceangoing equipment utilization, lower repair costs at TECO Ocean Shipping, and higher Tampa Electric movements, partially offset by higher fuel costs and lower tonnage for third-party customers. Non-GAAP results of $25.8 million in 2006 excluded $4.5 million of after-tax direct costs associated with damage from Hurricane Katrina at TECO Bulk Terminal and TECO Barge Line, and $1.5 million of after-tax insurance recovery at TECO Barge Line, compared to 2005 non-GAAP results of $19.1 million, which excluded $12.6 million of direct Hurricane Katrina costs and $13.7 million of insurance recovery (see the 2006 and 2005 GAAP to non-GAAP reconciliation tables). Results in 2006 reflect four oceangoing vessels in international trade which qualified them for the favorable tax treatment of tax law changes under the Jobs Creation Act, which reduces taxes on income earned by U.S.-flag vessels engaged in full-time international trade.
TECO Transport’s 2005 net income was $20.2 million, compared to $10.2 million in the same period in 2004. Non-GAAP results in 2005 were $19.1 million, which excluded direct hurricane costs and insurance recovery, compared to $11.9 million in 2004, which excluded management restructuring costs and valuation adjustments on oceangoing equipment. Non-GAAP results in 2005 excluded the $12.6 million after-tax direct costs associated with the restoration and recovery efforts for Hurricane Katrina and the $13.7 million after-tax benefit for insurance recovery related to the hurricane restoration costs at TECO Bulk Terminal (see the 2005 GAAP to non-GAAP reconciliation table ). Results in 2005 were positively affected by the qualification of two oceangoing vessels for the benefits of the tax law changes related to vessels operating in full-time international trade. Results in 2005 were also affected by improved operating efficiencies at TECO Barge Line, higher river barge rates and increased northbound river shipments as well as increased movements of export coal, petroleum coke and other products through TECO Bulk Terminal early in 2005. Higher fuel costs were partially offset by a $3.0 million after-tax benefit from fuel hedges. In 2005, TECO Transport’s net income was reduced by an estimated $4.9 million due to the ongoing business interruptions associated with operations at TECO Bulk Terminal as a result of Hurricane Katrina.
In 2005, TECO Bulk Terminal, which is located about 55 miles below New Orleans on the Mississippi River in Davant, Louisiana, was directly in the path of Hurricane Katrina and experienced side effects from Hurricane Rita. Following Hurricane Katrina, the terminal was flooded and without power. There was no damage to the oceangoing fleet and manageable impacts to the river fleet. The more lightly utilized of two cranes that unload in-bound oceangoing vessels was destroyed by the storm. The majority of the river fleet was returned to service and the terminal resumed major operations both in mid-October. Repairs at the terminal continued with near normal river barge unloading achieved in early January 2006. Near normal oceangoing vessel loading operations resumed in early 2006 and major repairs were completed in April 2006.
The river barge industry continues to experience a better balance in supply and demand for river barge services due to improvements in the U.S. economy, increased international movements and the scrapping of a large number of obsolete river barges by operators throughout the country. A number of river barges which were built in the 1980s, driven mainly by tax incentives, are now at the end of their useful lives and are being scrapped. The increased rate of barge retirements and the high cost of steel, which has increased the cost of construction of replacement barges, have reduced the supply of barges at a time of increasing demand. The improved U.S. economy and the reduced supply of barges is expected to maintain the improved pricing for river barge services in 2007. TECO Barge Line received 50 new river barges in mid-2006 to replace older barges that it retired in 2005 and 2006. It also received an additional 50 new barges starting in February 2007 to replace older barges that it expects to retire in 2007. The new barges received in 2006 and 2007 were chartered under an operating lease.
The demand for non-U.S. flag oceangoing vessels to meet the demand for shipments to China caused rates for these vessels, as measured by the Baltic Dry Index, to climb to a record high in November 2004. These rates have since declined to about 50% of the peak values but they are still more than double the long-term historical levels. As a U.S. flag carrier, TECO Transport does not benefit directly from these increased rates since it does not compete against non-U.S. flag vessels in these markets. However, the high international shipping rates create additional opportunities for spot cargo shipments for TECO Transport’s oceangoing vessels.
In 2007, TECO Transport expects higher net income from higher oceangoing rates, higher utilization of tonnage tax qualified vessels, improved operating efficiencies at the terminal and increased tonnage through the terminal in Louisiana. TECO Ocean Shipping expects increased shipyard days and associated repair expense due to the normal cycle of regulatory required inspections and repairs.
Future growth at TECO Transport is dependent upon improved pricing, higher asset utilization, and potential asset additions at both the river and oceangoing businesses. Significant factors that could influence results include weather, bulk commodity prices, fuel prices, domestic and international economic conditions, and import and export patterns (see the Risk Factors section).
Potential Sale of TECO Transport
In February 2007, we announced that we were considering our options to fund investments in Tampa Electric’s growth and to continue our debt retirement plans.
As discussed in the Overview section, in 2006, we committed to a plan to retire an additional $500 million of parent debt in the 2008 to 2010 period, beyond the $357 million of parent debt maturing in 2007. We are now exploring our options to meet or exceed our debt retirement goals, and to make additional investments in Tampa Electric to support its growing capital requirements.
At the same time, given the growth opportunities available to TECO Transport, we want to ensure that the business is best positioned to realize its potential in today’s transportation market. For this reason, among the alternatives we are considering to address our capital priorities is a review of the options for the long-term future of TECO Transport, including its sale.
We have retained Morgan Stanley to assist in evaluating potential strategic opportunities for TECO Transport. At this early stage in the strategic review process, it is not practical to predict the cash and earnings impacts of actions that might result if a sale were completed (see the Overview section).
TECO GUATEMALA
Our TECO Guatemala operations consist of two non-merchant power plants operating in Guatemala and an ownership interest in Guatemala’s largest distribution utility, Empresa Eléctrica de Guatemala (EEGSA). The San José and Alborada power stations in Guatemala both have long-term power purchase contracts. TECO Guatemala’s ownership interest in EEGSA is held jointly with partners Iberdrola of Spain and Electricidad of Portugal (EDP) that together own an 81% controlling interest in EEGSA and other affiliate companies in Guatemala. Iberdrola is the operating partner of EEGSA.
The Guatemalan operations are utility-like in nature due to the long-term contracts and stable operations of the power generating facilities. The San José Power Station is a baseload coal-fired station with high capacity and availability factors. In 2005, the San José Power Station supplied approximately 13% of Guatemala’s energy needs.
The Alborada Power Station, which consists of oil-fired, simple-cycle combustion turbines, is a peak-load facility with high availability, but low capacity factor by design. Guatemala is heavily dependent on hydro-electric sources for power generation. Seasonally or in periods of low rainfall, the Alborada Power Station will operate more.
TECO Guatemala had net income of $37.6 million in 2006, compared to $40.4 million in 2005, which was driven by 4.3% customer growth at EEGSA, 3% higher generation at the San José Power Station, higher capacity payments at the Alborada Power Station, lower insurance and interest expense, and operating and maintenance expenses essentially unchanged from 2005 levels more than offset by a higher tax rate. Results in 2005 included the one-year benefit of the 5% tax rate on dividends under the Jobs Creation Act, while 2006 reflects the normal 35% tax rate.
Net income for TECO Guatemala in 2005 was $40.4 million, compared to $5.7 million in 2004, which included a $6.7 million after-tax charge related to debt extinguishment, $17.4 million of taxes on repatriated cash, and a $12.8 million after-tax write-off of unused steam turbines. Although it is included in the TECO Guatemala segment for accounting purposes due to the redefining of our segments, the 2004 steam turbine write-off was not directly related to the Guatemalan operation; it related to turbines purchased in anticipation of a non-merchant project for TWG Merchant that was terminated. The 2005 results reflect higher operations and maintenance expenses early in the year and somewhat higher tax rates, partially offset by energy sales and customer growth at EEGSA and higher non-fuel revenues for the power plants.
At TECO Guatemala, we expect 2007 net income consistent with the strong 2006 levels. We expect continued strong operations and sales at the power plants and EEGSA. At San José, we expect to benefit from lower interest rates and from the lower principal balance on the non-recourse debt. At EEGSA, we expect flat results as continued customer and energy sales growth will be essentially offset by lower transmission wheeling revenues. Customer and energy sales growth are expected to be 3.5% and 1%, respectively, in 2007. We also expect benefits and other costs to be higher.
The Comisión Nacional de Energia Eléctrica (CNEE) was created under the General Electricity Law of 1996 as a branch of the Ministry of Energy and Mines in Guatemala and regulates the energy sector in Guatemala. EEGSA expects to undergo a new rate case process and renegotiation of the Value Added Distribution (VAD) charge applicable in the tariffs, leading up to new rates effective in May 2008. The new VAD rates that EEGSA can charge its customers for the use of its distribution lines will be set for a term of five years. The current VAD rates were established in May 2003. The Ministry of Energy and Mines and the CNEE are also in the midst of a review of the existing electricity regulations for the country. TECO Guatemala personnel are monitoring and participating in this process.
PARENT/OTHER
In 2006, the Parent/Other cost was $60.4 million, compared to $127.1 million in 2005. In 2006, the Parent/other non-GAAP cost was $74.2 million, compared to $80.4 million in 2005. 2006 Non-GAAP results in Parent/Other excluded the $8.1 million after-tax gain on the sale of the remaining assets of the unfinished McAdams Power Station, which had been previously impaired, and $5.7 million of after-tax gains on unused steam turbines that had been previously impaired. Non-GAAP results in 2005 excluded $46.7 million of after-tax charges associated with the early retirement of debt (see the 2005 and 2006 GAAP to non-GAAP reconciliation tables). These results were driven by pretax parent interest expense which was $18.1 million lower in 2006 due to the debt redemption and refinancing actions initiated in mid-2005. This was offset, in part, by no longer allocating interest to TWG Merchant. Parent interest allocated to the operating companies was $23.1 million in 2006, compared to $36.2 million in 2005. Investment income on cash and short-term investments increased $6.6 million over 2005 as a result of higher interest rates and higher investment balances.
We expect costs at TECO Energy parent to decline in 2007 due to the retirement of the remaining $100 million of 8.5% trust preferred securities in December 2006; the repayment of the $57 million of 5.93% junior subordinated notes, which was completed in January 2007; and the repayment of the $300 million of 6.125% notes maturing in May 2007. Investment income is expected to decline due to lower cash balances as debt is retired.
TWG MERCHANT
In 2003, we announced that our strategy going forward was to focus on our Florida utilities and our profitable unregulated businesses and to reduce our exposure to the merchant power markets. In 2005, we essentially completed our exit from the merchant power business and the sales of the minor remaining assets were completed in 2006 (see the Overview section).
In 1999, we announced that a component of our strategy was to expand our presence in the domestic independent energy industry. Our decision to invest in this industry was based on the outlook at that time for the energy markets beyond 2001, and the expectation that there would be wide-spread deregulation of these markets. Starting in late 2001 and early 2002, after we had committed to the major investments in unregulated power, conditions in energy markets changed. Wholesale power prices declined significantly in markets across the country for many reasons, including a general slowing, or in some states a reversal, of the movement towards wholesale electric competition. In addition, the large amount of new generating capacity which came online in 2002 and 2003 contributed to significant excess generating capacity in many areas of the country and thus lower wholesale power prices.
These changed market conditions and the prospects for operating losses and negative cash flow at most of the merchant facilities we were constructing for several years, caused us to delay some projects and sell others commencing in 2003.
In 2004 and 2005, we took aggressive actions to complete our exit from the merchant power business. We completed the sale and transfer of the ownership of the Union and Gila River projects to the lenders; we sold our interests in the remaining operating projects and the uncompleted Dell Power Station. In 2005, we announced our decision to terminate the uncompleted McAdams Power Station and to transfer combustion turbines from that project to Tampa Electric in 2006 to meet its peaking generation needs. In 2006, we completed the sale of the remaining assets associated with the McAdams Power Station.
LIQUIDITY, CAPITAL RESOURCES
The table below sets forth the Dec. 31, 2006 consolidated liquidity and cash balances, the cash balances at the operating companies and TECO Energy parent, and amounts available under the TECO Energy and Tampa Electric credit facilities.
Consolidated restricted cash of $37.3 million includes $30.0 million held in escrow until early 2008 related to the sale of an interest in the synthetic coal production facilities. In addition to consolidated cash, as of Dec. 31, 2006, unconsolidated affiliates owned by TECO Guatemala, CGESJ (San José) and TCAE (Alborada), had unrestricted cash balances of $18.7 million and restricted cash of $8.2 million, which are not included in the table above, as these project companies were deconsolidated due to the adoption of FIN 46R, Consolidation of Variable Interest Entities, effective Jan. 1, 2004.
In 2006, we met our cash needs from a mix of internal sources, asset sales and long-term notes issued at Tampa Electric Company. Cash from operations was $567 million in 2006. Other sources of cash in 2006 included $123 million of proceeds from third-party investors for ownership interests in TECO Coal’s synthetic fuel production facilities, $250 million from the issuance of long-term debt at Tampa Electric, and $42 million from the sale of the land at TECO Properties and the remaining merchant power and energy services assets. We used cash to retire the remaining $100 million of 8.5% trust preferred securities outstanding prior to maturity, and the regulated companies reduced short-term borrowings $167 million. We paid dividends in 2006 of $159 million on TECO Energy common stock. Our capital expenditures for the year were $456 million.
In 2005, we met our cash needs from a mix of internal sources, asset sales and short-term borrowings under Tampa Electric Company’s credit facilities. Cash from operations was $177 million in 2005. Other sources of cash in 2005 included $206 million of proceeds from third-party investors for ownership interests in TECO Coal’s synthetic fuel production facilities, $180 million from the final settlement of the 9.5% adjustable conversion-rate equity security units, $300 million from the issuance of long-term debt, regulated short-term borrowings of $100 million and $165 million from the sale of the Commonwealth Chesapeake and Dell power stations. We utilized the proceeds from the long-term debt issuance in combination with cash on hand to retire prior to maturity $480 million of our highest-cost debt. We paid dividends in 2005 of $158 million on TECO Energy common stock. Our capital expenditures for the year were $295 million, and we paid $32 million to the lenders upon the final transfer of the Union and Gila River power stations.
In 2006 the impact of discontinued operations on cash from operations was not material. In 2005 and 2004, consolidated cash from operations included the cash operating losses from the Union and Gila River power stations that were in discontinued operations prior to the final transfer to the lenders in May 2005. Consolidated cash was not affected by these losses since investing activities included an offsetting source of cash that was included as restricted cash at the project companies.
Cash from Operations
In 2006, consolidated cash flow from operations was $566.9 million, which included, among normal operating items, net cash of $53.4 million reflecting the FPSC-approved recovery of previously under-recovered 2005 fuel costs, which was partially offset by the credit on customers’ bills related to Tampa Electric’s sale of $45 million of excess SO2 emissions credits. In addition, cash from operations reflects a $30 million early contribution to the pension plan in 2006. The accounting treatment of the sale of interests in the synthetic fuel production facilities at TECO Coal includes the costs associated with synthetic fuel production in cash flow from operations, but the proceeds from the third-party synthetic fuel investors are reported as cash from investing and financing activities.
In 2004 and 2005, TECO Coal sold a total of 98% of the ownership interests in its synthetic fuel production facilities to third-party investors. In 2006, cash flow from operations includes the operating losses of approximately $11 per ton (pretax) associated with the production of synthetic fuel, while the cash benefits from the sale of the synthetic fuel production facilities of approximately $33 per ton (pretax) are included in the investing and financing activities on the Consolidated Statement of Cash Flows. Investing activity includes cash from the gain on the sale of the synthetic fuel facilities, which was reduced as a result of high oil prices in 2006 (see the TECO Coal section). The cash paid by the owner for its portion of the operating loss from the production of synthetic fuel is included in financing activities as a minority interest.
We expect cash from operations to increase in 2007 from improved operating results, collection by Tampa Electric of its remaining under-recovered fuel expense from 2005 and 2006, and lower interest expense due to the retirement of $100 million of parent debt in 2006 and the retirement of $357 million of parent debt in 2007 (see the Cash and Liquidity Outlook section).
We made the minimum required contributions to our pension plan in 2006 and 2005 of $6 million and $17 million, respectively. In November 2006, we made a voluntary and previously unplanned $30 million contribution to the plan to accelerate improvement in the plan’s funded status. We plan to also contribute $30 million in 2007, which is above the minimum amount required. We estimate that our contribution will average about $22 million annually in 2008 through 2011 (see Note 5 to the TECO Energy Consolidated Financial Statements).
Cash from Investing Activities
Our investing activities in 2006 resulted in a net use of cash of $352 million, including, among other items, capital expenditures totaling $456 million and net asset sale proceeds of $100 million. Asset sales included $8 million from the sale of two unused steam turbines remaining from the TWG Merchant operations, $10 million from the sale of a district cooling plant in Miami, $57 million from the sale of the 98% ownership interests in TECO Coal’s synthetic fuel facilities, $15 million from the sale of land and $7 million from the sale of marine transportation equipment no longer used by TECO Transport.
We expect capital spending for the next several years to be higher, primarily at Tampa Electric. Our capital spending forecast currently does not include amounts for Tampa Electric’s next baseload generating capacity addition, which is expected to be required in early 2013 (see the Tampa Electric and Capital Expenditures sections).
We have completed our disposition of merchant and energy services assets, and do not anticipate significant additional proceeds from sales of this nature. Proceeds from investors in the synthetic fuel production facilities will conclude after 2007 when the non-conventional fuels tax credit program expires.
Cash from Financing Activities
Our financing activities in 2006 resulted in net use of cash of $119 million. Major items included the early retirement of $100 million of the remaining 8.5% TruPS securities outstanding, Tampa Electric’s issuance of $250 million of long-term notes (see the Financing Activity section) and $167 million reduction of short-term borrowings, and $159 million in common stock dividends. In addition, we received $66 million for providing the feedstock and reimbursement of the operating costs of TECO Coal’s synthetic fuel production facilities in the form of minority interest payments from the third-party owners.
In 2007, we retired the $57 million of junior subordinated notes due Jan. 16 and we plan to retire the $300 million of notes maturing in May. In 2007, Tampa Electric Company expects to refinance $150 million of notes maturing in August and utilize short-term borrowings under its credit facilities to support its capital spending program and for normal working capital fluctuations.
TECO Transport is considering options for its $110 million of tax-exempt dock and wharf bonds that mature in September, including either refinancing or retirement. See the Cash and Liquidity Outlook section below for a discussion of financing expectations beyond 2007.
Cash and Liquidity Outlook
In general, we target consolidated liquidity (unrestricted cash on hand plus undrawn credit facilities) of approximately $500 million, comprised of $300 million for Tampa Electric Company and $200 million for TECO Energy. In 2006, because we accumulated cash in excess of our general targets for the planned retirement of $357 million of maturing TECO Energy parent notes in 2007, at Dec. 31, 2006 our consolidated liquidity was $1,059 million. Of this total, Tampa Electric had total liquidity of $432 million. TECO Energy parent had total liquidity of $593 million. The consolidated unregulated operating companies had $34 million of unrestricted cash. In addition, there was $19 million of unrestricted cash at the unconsolidated operating companies.
We currently forecast our 2007 consolidated cash flow from operations to be approximately $660 million and expect a consolidated net use of cash of approximately $160 million after dividends. Our forecast of cash from operations includes recovery in 2007 of approximately $123 million of 2005 and 2006 net fuel and other clause under-recoveries at Tampa Electric. Cash flow from operations includes the projected $58 million cost of producing synthetic fuel for the full year, but excludes the projected $195 million of synthetic fuel investor proceeds, as these proceeds are reported in cash from investing and financing activities. The forecast of consolidated net cash generation assumes estimated capital expenditures of approximately $523 million, net Tampa Electric Company borrowing of approximately $60 million, the $29 million we spent in January 2007 for oil price hedge instruments and the repayment of the $357 million of TECO Energy parent notes maturing in 2007.
This forecast assumes that there is no reduction in proceeds that would occur if oil prices exceed the threshold level at which the synthetic fuel tax credits would begin to be reduced (see the Synthetic Fuel discussion in the Outlook section). If oil prices exceed the phase-out threshold, the oil price hedge instruments become the source of cash and replace lost investor proceeds. However, the cash from the hedges would be received in early 2008 rather than in 2007. Our forecast also does not include the potential sale of TECO Transport, which we would expect to provide cash to meet our parent-level debt retirement goals earlier than currently forecast (see the Overview and TECO Transport sections).
We expect TECO Energy parent to have net use of cash of approximately $180 million after dividends in 2007. This forecast is based on the assumptions described above and also assumes that we make an $80 million equity contribution to Tampa Electric and pay common stock dividends at current levels.
TECO Energy plans to reduce parent debt levels by an additional $500 million in the 2008 through 2010 period and does not expect to access the capital markets until such time as it seeks to refinance any of its notes maturing in 2010 through 2012 that would remain outstanding after its $500 million of repayments and any additional repayments that we elect to make. Tampa Electric Company expects to access the debt capital markets for long-term debt to refinance existing debt and to support its capital spending program, and expects to utilize its credit facilities for normal working capital fluctuations.
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, coal production levels and coal sales prices. In addition, actual fuel and other regulatory clause net recoveries will typically vary from those forecasts; however, these 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 or to require external capital to meet future TECO Energy parent debt maturities (see the Risk Factors section).
Higher expected capital expenditures at Tampa Electric over the next several years are expected to require additional equity contributions from TECO Energy in order to maintain the utility capital structure and financial integrity. Tampa Electric expects to fund approximately 50% of its capital needs with internally generated cash and external borrowing. If a sale of TECO Transport is completed, we would expect to use proceeds for the early implementation of our parent debt retirement plans in the 2008 through 2010 period. This would position us to redeploy cash that was planned for debt retirement in those years to Tampa Electric in the form of parent equity contributions to fund its generation expansion and other capital needs.
Credit Facilities
At Dec. 31, 2006 and 2005, the following credit facilities and related borrowings existed:
(1) Borrowings outstanding are reported as notes payable.
These credit facilities require commitment fees ranging from 12.5 to 37.5 basis points. The weighted average interest rate on outstanding notes payable under the credit facilities at Dec. 31, 2006 and 2005 was 5.45% and 4.45%, respectively.
At Dec. 31, 2006, TECO Energy had a bank credit facility in place of $200 million with a maturity date of October 2010, and Tampa Electric Company had a bank credit facility totaling $325 million, also maturing in October 2010. In addition, Tampa Electric Company had a $150 million accounts receivable securitized borrowing facility. The TECO Energy and Tampa Electric Company bank credit facilities include sub-limits for letters of credit of $100 million and $50 million, respectively. The TECO Energy facility was undrawn at Dec. 31, 2006, except for $9.5 million of outstanding letters of credit. At Dec. 31, 2006, $48 million was drawn on the Tampa Electric Company credit facilities.
Our $200 million credit facility, which was amended and extended to its current maturity in October 2005, is secured by the stock of TECO Transport Corporation, which is to be released upon our achieving an investment grade credit rating at both Standard & Poor’s (S&P) and Moody’s. The facility has two financial covenants, earnings before interest, taxes, depreciation, and amortization (EBITDA)-to-interest and debt-to-EBITDA, but no debt-to-total capital covenant (see the Covenants in Financing Agreements section).
At current ratings, TECO Energy’s and Tampa Electric Company’s bank credit facilities require commitment fees of 37.5 basis points and 12.5 basis points, respectively, and drawn amounts are charged interest at LIBOR plus 125 - 150 basis points and 52.5 - 65.0 basis points, respectively. At Dec. 31, 2006, the LIBOR interest rate was 5.32%.
In January 2005, Tampa Electric Company and TEC Receivables Corp. (TRC), a wholly-owned subsidiary of Tampa Electric, entered into 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 Company’s credit ratings, which total 35 basis points at its current ratings. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to either the London interbank deposit rate plus a margin of 100 basis points at Tampa Electric’s current ratings or at Citibank’s prime rate (or the federal funds rate plus 50 basis points, if higher). The facility includes the following financial covenants: (1) at each quarter-end, Tampa Electric Company’s debt-to-capital ratio, as defined in the agreement, must not exceed 65%; and (2) certain dilution and delinquency ratios with respect to the receivables. At Dec. 31, 2006, the interest rate for borrowings under the Tampa Electric accounts receivable facility was 5.33%.
Covenants in Financing Agreements
In order to utilize their respective bank credit facilities, TECO Energy and Tampa Electric Company must meet certain financial tests as defined in the applicable agreements (see Credit Facilities above). In addition, TECO Energy, Tampa Electric Company, and other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Dec. 31, 2006, TECO Energy, 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, 2006. Reference is made to the specific agreements and instruments for more details.
TECO Energy Significant Financial Covenants
(1) As defined in each applicable instrument.
(2) EBIT generally represents earnings before interest and taxes. EBITDA generally represents EBIT before depreciation and amortization. However, in each circumstance, the term is subject to the definition prescribed under the relevant agreements.
(3) See description of credit facilities in Note 6 to the TECO Energy Consolidated Financial Statements.
(4) TECO Energy cannot declare quarterly dividends in excess of the restricted amount unless liquidity projections, demonstrating sufficient cash or cash equivalents to make each of the next three quarterly dividend payments, are delivered to the Administrative Agent.
(5) If the limitation on liens is exceeded the company is required to provide ratable security to the holders of these notes.
(6) The indentures for these notes contain restrictions which limit secured debt of TECO Energy if secured by Principal Property or Capital Stock or indebtedness of directly held subsidiaries (with exceptions as defined in the indentures) without equally and ratably securing these notes.
Credit Ratings of Senior Unsecured Debt at Dec. 31, 2006
Standard & Poor’s
Moody’s
Fitch
Tampa Electric Company
BBB-
Baa2
BBB+
TECO Energy/TECO Finance
BB
Ba2
BB+
All three credit rating agencies have assigned stable outlooks to our ratings. In February 2007, Moody’s Investor Service affirmed the rating of Tampa Electric Company and placed TECO Energy ratings on review for possible upgrade.
Standard & Poor’s, Moody’s and Fitch describe credit ratings in the BBB or Baa category as representing adequate capacity for payment of financial obligations. The lowest investment grade credit ratings for Standard & Poor’s is BBB-, for Moody’s is Baa3 and for Fitch is BBB-; thus all three credit rating agencies assign Tampa Electric Company’s senior unsecured debt investment grade ratings. The ratings assigned by all three rating agencies to TECO Energy and TECO Finance are below investment grade.
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 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, 2006
(1) Includes debt at TECO Energy, Tampa Electric, Peoples Gas and the other operating companies (see Note 7 to the TECO Energy Consolidated Financial Statements for a list of long-term debt and the respective due dates).
(2) Reflects an intercompany loan at TECO Guatemala between its consolidated Cayman Island entity and an unconsolidated Guatemalan affiliate.
(3) These notes were retired on January 16, 2007, as required.
(4) Excludes TECO Transport’s outstanding commitment of $21 million for the construction of 50 replacement river barges, as the company is chartering these barges under an operating lease signed Feb. 16, 2007.
(5)
Reflects those contractual obligations and commitments considered material to the respective operating companies, individually. At the end of 2006, these commitments included Tampa Electric’s outstanding commitments of about $371 million primarily for materials and contracts related to the NOx control equipment and long-term capitalized maintenance agreements for its combustion turbines.
(6) Includes variable rate notes at interest rates as of Dec. 31, 2006. Included in 2007 interest payments is $1.1 million related to the $71.4 million of 5.93% junior subordinated notes (see Note 22 to the TECO Energy Consolidated Financial Statements) and $7.7 million of interest payments related to the planned retirement of the $300 million of 6.125% notes due in May 2007.
(7) The total includes the estimated minimum required contributions to the qualified pension plan as of the measurement date. Future contributions are included but they are subject to annual valuation reviews, which may vary significantly due to changes in interest rates, discount rate assumptions, plan asset performance, which is affected by stock market performance, and other factors (see Liquidity, Capital Resources - Cash from Operations section and Note 5 to the TECO Energy Consolidated Financial Statements).
Summary of Contingent Obligations
The following table summarizes the letters of credit and guarantees outstanding that are not included in the 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, 2006
(1) Expected final expiration date with annual renewals.
(2) Expected maximum exposure.
(3) These guarantee amounts renew annually and are shown on the basis of our intent to renew beyond the current expiration date.
CAPITAL EXPENDITURES
(1) Except for the amounts shown in 2007 for completion of two peaking units, this forecast excludes capital expenditures for new generating capacity that is expected to be needed in the 2009 - 2012 period. See the discussion below and the Tampa Electric section.
(2) Represents only the capital expenditures of the consolidated operations of TECO Guatemala. Under FIN 46R the major operations of TECO Guatemala are unconsolidated, and the related capital expenditures are not included in this table.
TECO Energy’s 2006 capital expenditures of $454 million (without reduction for asset and business sale proceeds) included $363 million, excluding Allowance for Funds Used During Construction (AFUDC), for Tampa Electric and $54 million for PGS. Tampa Electric’s capital expenditures in 2006 were primarily for equipment and facilities to meet its growing customer base, generating equipment maintenance, capital expenditures required for additional generating capacity in the form of two peaking units and environmental compliance including $67 million for NOx control projects (see the Environmental Compliance section). Capital expenditures for PGS were approximately $36 million for system expansion and approximately $18 million for maintenance of the existing system. TECO Coal’s capital expenditures included $22 million primarily for normal mining equipment replacement, $6 million for new mine development and $12 million for equipment to improve recoveries of coal from two coal-preparation plants. TECO Transport invested $17 million in 2006, including $14 million for normal steel replacements and shipyard periods for oceangoing vessels, and $3 million of capitalized repairs at its terminal in Louisiana for Hurricane Katrina-related damage repairs. The $(20) million amount in the “Other” category represents the purchase of two combustion turbines from the unfinished TWG Merchant McAdams Power Station, which are included in Tampa Electric’s capital expenditures.
TECO Energy estimates capital spending for ongoing operations to be $523 million for 2007 and approximately $1.9 billion during the 2008 - 2011 period.
For 2007, Tampa Electric expects to spend $400 million, consisting of about $235 million to support system growth and generation reliability, which includes $13 million for transmission and distribution system storm hardening and $4 million for new high-voltage transmission system improvements to meet reliability requirements. In addition, Tampa Electric expects to spend $16 million for an additional natural gas pipeline to improve reliability of supply to the Bayside Power Station, $20 million for coal-fired generation capacity factor and availability improvements, $6 million to complete the addition of two combustion turbines at the Polk Power Station to meet its peaking generation capacity needs, $87 million for the addition of SCR equipment at the Big Bend Station for NOx control, and $34 million for other environmental compliance programs in 2007.
Tampa Electric’s total capital expenditures over the 2008 - 2011 period are projected to be $1,466 million, excluding its next baseload generating capacity addition which is currently expected to be required in early 2013 or any peak load generating capacity additions required in the 2009 - 2012 period. After the initial ramp-up in spending on the required transmission system improvements and storm hardening in 2007, Tampa Electric expects to spend approximately $300 million annually to support normal system growth and reliability. This increased level of ongoing capital expenditures reflects the general higher costs for materials and contractors, new long-term regulatory requirements for storm hardening, and an active program of transmission and distribution system upgrades which will occur over the forecast period. These new programs and requirements include: approximately $30 million annually for repair and refurbishments of combustion turbines under long-term agreements with equipment manufacturers; $20 million annually for transmission and distribution system storm hardening; approximately $35 million annually for transmission and distribution system reliability and capacity improvements; and an average of $25 million annually for high-voltage transmission system improvements to meet NERC reliability requirements in Central Florida. In addition to the $300 million of ongoing annual capital expenditures, Tampa Electric expects to spend $127 million for compliance with the Environmental Consent Decree for the SCR equipment and $97 million for other required environmental capital expenditures in the 2008 - 2011 period. The Environmental Consent Decree compliance expenditures are eligible for recovery of depreciation and a return on investment through the Environmental Cost Recovery Clause (see the Environmental Compliance section).
Capital expenditures for PGS are expected to be about $50 million in 2007 and $200 million during the 2008 - 2011 period. Included in these amounts is an average of approximately $33 million annually for projects associated with customer growth and system expansion. The remainder represents capital expenditures for ongoing renewal, replacement and system safety.
TECO Coal expects to invest $40 million in 2007 and $143 million during the 2008 - 2011 period. Included in these amounts are new mine development projects to replace higher cost of production mines and position TECO Coal to increase production when coal markets improve. Also included is normal renewal and replacement capital, including coal mining equipment. TECO Transport expects to spend $17 million in 2007 and $108 million during the 2008 - 2011 period primarily for normal steel replacements and shipyard periods for oceangoing vessels and inland river transportation equipment. TECO Coal had outstanding commitments of approximately $27 million, primarily for replacement of coal mining equipment at Dec. 31, 2006. TECO Transport had an outstanding commitment of $21 million for the construction of 50 replacement river barges, which is not included in the capital spending forecast. In February 2007, TECO Barge Line amended an existing charter agreement to include these 50 replacement river barges (see the footnotes to the Contractual Cash Obligation table and the Financing Activity section).
The forecast capital expenditures shown above are based on our current estimates and assumptions for normal maintenance capital at the operating companies; capital expenditures to support normal system growth at Tampa Electric and PGS (excluding new generating capacity at Tampa Electric); the new programs for transmission and distribution system storm hardening and new transmission system reliability requirements; and incremental investments above normal maintenance capital to expand the PGS system and capacity at TECO Coal. Actual capital expenditures could vary materially from these estimates due to changes in costs for materials or labor or changes in plans (see the Risk Factors section).
Tampa Electric Future Generating Capacity Additions
The above forecasted amounts do not include any expenditures for Tampa Electric’s next baseload generating capacity addition, which, based on its current forecast of energy demand and sales growth, is expected to be required in early 2013, or any peak load generating capacity additions required in the interim period. Tampa Electric’s options to satisfy the generating capacity needs range from purchasing the power to constructing its own generating facilities. Tampa Electric has initiated a RFP for incremental peak capacity needs it projects to have in the 2009 - 2012 period, and, as required in Florida for baseload capacity additions, to potentially purchase the needed power under power purchase agreements. If construction of generating capacity by Tampa Electric, including a baseload unit, is found to be the most cost-effective method of meeting customers’ needs, there are additional regulatory and permitting steps required prior to Tampa Electric moving forward with such a construction program for the baseload capacity. The RFP process and the regulatory approval process for baseload generating capacity are expected to be completed in late 2007.
The capital expenditures required under the various options currently being evaluated vary significantly from only transmission system improvements to allow the import of power to construction of peaking capacity and baseload capacity. In addition to an evaluation of the purchase versus build option, Tampa Electric has options regarding the type of baseload plant to be constructed ranging from natural gas-fired combined cycle to an Integrated Gasification Combined Cycle (IGCC) unit. Tampa Electric’s preferred option is a 630-megawatt, coal- and petroleum coke-fueled IGCC unit in order to meet the State of Florida’s goal of diversifying the fuel supplies used to generate power, and the ability to more easily capture and sequester CO2 emissions if required in the future (see the Environmental Compliance section). Capital expenditures to meet Tampa Electric’s peaking and baseload capacity needs are estimated to be in excess of $1.5 billion, excluding AFUDC, starting in 2008, peaking in 2010 and ending in 2013.
In 2006, the Florida Legislature enacted a new statute related to new nuclear plants that might be constructed in Florida that provided for, among other things, the recovery of pre-construction costs and carrying costs of construction through the capacity cost recovery clause; a base rate increase when the plant is put in service to recover the costs of the plant; and the recovery of prudently incurred costs in the event that the plant is not completed. Tampa Electric is seeking similar legislative treatment for IGCC plants as they accomplish the same goal of increasing fuel diversity in Florida.
FINANCING ACTIVITY
Our 2006 year-end capital structure was 68.0% senior debt, 1.3% junior subordinated debt, and 30.7% common equity. The debt-to-total-capital ratio improved from last year, primarily due to the December 2006 call and retirement of the remaining junior subordinated notes related to our 8.5% TruPS of TECO Capital Trust I.
In 2006, we issued no new debt at the TECO Energy parent level. We did raise a small, recurring amount of equity primarily through our dividend reinvestment plan. Tampa Electric refinanced $86 million of 6.25% tax-exempt bonds to an auction-rate mode, on which the average interest rate was 3.25% in 2006. Tampa Electric also issued $250 million of 30-year notes at 6.55%. The proceeds of this issuance were used to retire short-term borrowings under Tampa Electric’s credit facilities, for working capital needs and to support its capital spending program.
In April 2006, TECO Barge Line entered into a 15 year charter agreement for the lease of 50 newly constructed river barges to replace barges that had either already been retired or were scheduled for retirement. In February 2007, the charter agreement was amended to include an additional 50 newly constructed replacement river barges.
In 2005, as part of our overall efforts to manage our debt and reduce interest expense, we accessed the debt markets for new capital on two occasions for $200 million of fixed-rate notes and $100 million of floating-rate notes. The proceeds from the fixed-rate notes, together with cash on hand, were used to retire in full the $380 million aggregate principal amount outstanding of our 10.5% notes due 2007. The floating-rate notes were issued to provide us the increased financial flexibility to call and retire $100 million, or 50%, of our 8.5% TruPS of TECO Capital Trust I. In addition, Tampa Electric used short-term borrowings under its credit facilities for working capital needs, which included temporarily under-recovered fuel costs, and to support its environmental capital spending program.
In 2004, we completed an early settlement offer on our 9.5% adjustable conversion-rate equity security units (units). Under the terms of the offer, each unit holder received 0.9509 shares of TECO Energy common stock for each unit held and $1.39 per unit in cash, which included the future quarterly distributions through the normal settlement date and a $0.20 per unit incentive. Under the early settlement offer, 10.8 million units were exchanged for 10.2 million shares of our common stock, and we paid $14.9 million of cash for future distributions and incentives. The effect of the exchange was the retirement of $269 million, or about 60%, of the associated trust preferred securities and increased the common shares outstanding three months earlier than would have otherwise occurred.
In 2004, we remarketed the remaining $163 million of outstanding trust preferred securities associated with the units within TECO Capital Trust II, as required. We purchased and subsequently retired $123 million of the securities offered in this transaction. Our purchase was funded through a $124 million bridge loan with Merrill Lynch and JP Morgan, which we repaid in December 2004. Trust preferred securities totaling $71 million of this series remained outstanding at Dec. 31, 2006, including the 3% ($14 million) held by TECO Capital Trust II. These securities, which had a coupon rate of 5.93% set in the remarketing, were repaid at maturity in January 2007. The proceeds from the remarketing were used by the trustee to purchase a portfolio of U.S. Treasury securities with a January 2005 maturity. Upon final settlement of the units in January 2005, we issued 6.85 million shares of TECO Energy common stock and received $180 million of cash proceeds from the matured U.S. Treasury securities.
The following table provides details of financings beginning in 2004
(1) 6.8 million shares issued in the final settlement of the 9.5% convertible equity units.
(2) No increase in outstanding debt, interest rate reset.
(3) 10.2 million shares issued in an early settlement offer on the 9.5% convertible equity units.
OFF-BALANCE SHEET FINANCING
Unconsolidated affiliates have project debt balances as follows at Dec. 31, 2006. The two power plant financings are non-recourse project loans, and the debt associated with EEGSA is general corporate debt at EEGSA; all of this debt is held at the project entity level. Although we are not directly obligated on the debt, our equity interest in those unconsolidated affiliates and its commitments with respect to those projects are at risk if interest and principal payments on these loans are not made timely. Our investment in TECO Guatemala was $401.5 million at Dec. 31, 2006.
Off-Balance Sheet Debt at Dec. 31,
The equity method of accounting is used to account for investments in partnership and corporate entities in which we, or our subsidiary companies, do not have either a majority ownership or exercise control.
We deconsolidated the project entities for the San José and Alborada power stations listed above in the first quarter of 2004 as a result of implementing FIN 46R. These projects were partially financed with non-recourse debt, which following the deconsolidation is considered to be off-balance sheet financing. (This and other effects of implementing FIN 46R are described in Note 2 to the TECO Energy Consolidated Financial Statements.)
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of consolidated financial statements requires management to make various estimates and assumptions that affect revenues, expenses, assets, liabilities, and the disclosure of contingencies. The policies and estimates identified below are, in the view of management, the more significant accounting policies and estimates used in the preparation of our consolidated financial statements. These estimates and assumptions are based on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and judgments under different assumptions or conditions. See Note 1 to the TECO Energy Consolidated Financial Statements for a description of our significant accounting policies and the estimates and assumptions used in the preparation of the consolidated financial statements.
Synthetic Fuel and Section 29 Tax credits
The company earns income indirectly through the production of synthetic fuel at TECO Coal. TECO Coal sold its ownership interests in the synthetic fuel facilities to third-party investors based on the amount of future production and the resulting gains are adjusted by the estimated value of the tax benefits provided under Section 45 (formerly Section 29) of the tax code. The tax credit begins to phase out when the average annual oil price exceeds a reference price, which was estimated to $62.00/ Bbl on a NYMEX basis in 2006. The final determination of the actual 2006 reference price and any resulting phase-out of the tax credit benefits will not be made by the Internal Revenue Service until March of 2007, as a result management is required to estimate the potential phase-out and adjust the payments expected for the sale of the ownership interests accordingly. At the end of 2006, the annual average oil price was calculated to be $65.90 on a NYMEX basis. Based on this average, a 90% actual Producer First Purchase Price to NYMEX adjustment factor and a 3.08% inflation rate, the phase-out was estimated to be 35%, resulting in a reduction in revenues from the third-party investors of $61.1 million on $174.5 million in sales. The company has also determined that a 0.25% increase in inflation would result in a reduction of 1.03% in the amount of the phase-out, which would result in a $1.2 million pretax reduction in revenue from the third-party investors. The actual final inflation rates will be known in late March or early April. Any adjustments to 2006 earnings as a result of changes in the inflation rate will be reflected in 2007’s results. The payments received for the sale of the synthetic fuel ownership interests are reflected as other income and minority interest classifications in the income statement.
Deferred Income Taxes
We use the liability method in the measurement of deferred income taxes. Under the liability method, we estimate our current tax exposure and assess the temporary differences resulting from differing treatment of items, such as depreciation for financial statement and tax purposes. These differences are reported as deferred taxes measured at current rates in the consolidated financial statements. Management reviews all reasonably available current and historical information, including forward-looking information, to determine if it is more likely than not that some or all of the deferred tax asset will not be realized. If we determine that it is likely that some or all of a deferred tax asset will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized.
At Dec. 31, 2006, we had net deferred income tax assets of $630.2 million, attributable primarily to losses, property-related items, alternative minimum tax credit carryover of synthetic fuel non-conventional fuel tax credits, and operating loss carry-forwards. Based primarily on historical income levels and the steady growth expectations for future earnings of the company’s core utility operations, management has determined that the net deferred tax assets recorded at Dec. 31, 2006 will be realized in future periods.
We believe that the accounting estimate related to deferred income taxes, and any related valuation allowance, is a critical estimate for the following reasons: (1) realization of the deferred tax asset is dependent upon the generation of sufficient taxable income in future periods; (2) a change in the estimated valuation reserves could have a material impact on reported assets and results of operations; and (3) administrative actions of the IRS or the U.S. Treasury or changes in law or regulation could change our deferred tax levels, including the potential for elimination or reduction of our ability to utilize the deferred tax assets (see Note 4 to the TECO Energy Consolidated Financial Statements).
In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109 (FIN 48). FIN 48 prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. See further discussion of FIN 48 in Note 2 to the TECO Energy Consolidated Financial Statements and the “Recently Issued Accounting Standards” section below.
Employee Postretirement Benefits
We sponsor a defined benefit pension plan (pension plan) that covers substantially all of our employees. In addition, we have unfunded non-qualified, non-contributory supplemental executive retirement benefit plans available to certain senior management. Several statistical and other factors, which attempt to anticipate future events, are used in calculating the expense and liability related to these plans. Key factors include assumptions about the expected rates of return on plan assets, discount rates, and health care cost trend rates. These factors are determined by us within certain guidelines and with the help of external consultants. We consider market conditions, including changes in investment returns and interest rates, in making these assumptions.
Pension plan assets (plan assets) are invested in a mix of equity and fixed income securities. The assumptions for the expected return on plan assets are developed based on an analysis of historical market returns, the pension plan’s actual past experience, and current market conditions. The expected return on assets assumption was based on expectations of long-term inflation, real growth in the economy, fixed income spreads and equity premiums consistent with our portfolio, with provision for active management and expenses paid from the trust. The discount rate assumption is based on a cash flow matching technique developed by our outside actuaries and current economic conditions. This technique matches the yields from high-quality (AA-graded, non-callable) corporate bonds to the company’s projected cash flows for the pension plan to develop a present value that is converted to a discount rate and this assumption is subject to change each year. The salary increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases. Holding all other assumptions constant, a 1% increase or decrease in the assumed rate of return on plan assets would decrease or increase, respectively, 2006 net periodic expense by approximately $4.4 million. Likewise, a 0.67% increase or a 0.42% decrease in the discount rate assumption would result in an approximately $3.4 million change in the 2006 net periodic pension expense. This $3.4 million change represents a 1-cent change in earnings-per-share.
Unrecognized actuarial gains and losses are being recognized over approximately a 15-year period, which represents the expected remaining service life of the employee group. Unrecognized actuarial gains and losses arise from several factors including experience and assumption changes in the obligations and from the difference between expected return and actual returns on plan assets. These unrecognized gains and losses will be systematically recognized in future net periodic pension expense in accordance with FAS 87, Employer’s Accounting for Pensions. Our policy is to fund the plan based on the required contribution determined by our actuaries within the guidelines set by the Employee Retirement Income Security Act of 1974 (ERISA), as amended.
In addition, we currently provide certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 who meet certain service requirements. The key assumptions used in determining the amount of obligation and expense recorded for postretirement benefits other than pension (OPEB), under FAS 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, include the assumed discount rate and the assumed rate of increases in future health care costs. The discount rate used to determine the obligation for these benefits has matched the discount rate used in determining our pension obligation in each year presented. In estimating the health care cost trend rate, we consider our actual health care cost experience, future benefit structures, industry trends, and advice from our outside actuaries. We assume that the relative increase in health care cost will trend downward over the next several years, reflecting assumed increases in efficiency in the health care system and industry-wide cost containment initiatives. In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was enacted. The Act established a prescription drug benefit under Medicare, known as Medicare Part D, and a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription benefit, which is at least actuarially equivalent to Medicare Part D. In May 2004, the FASB issued FASB Staff Position No. FSP 106-2 which required 1) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and 2) certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits.
We adopted FSP 106-2 retroactive to the second quarter of 2004 for benefits provided that we believe to be actuarially equivalent to Medicare Part D. The expected subsidy reduced the accumulated postretirement benefit obligations (ABPO) at Dec. 31, 2006 by $25.8 million and net periodic cost for 2006 by $3.8 million. In 2006, we filed and received a Part D subsidy of $0.6 million.
The assumed health care cost trend rate for medical costs was 9.5% in 2006 and decreases to 5.00% in 2016 and thereafter. A 1% increase in the health care trend rates would produce a 4% ($1.0 million) increase in the aggregate service and interest cost for 2006 and a 4% ($7.4 million) increase in the accumulated postretirement benefit obligation as of Sep. 30, 2006, the measurement date.
A 1% decrease in the health care trend rates would produce a 3% ($0.7 million) decrease in the aggregate service and interest cost for 2006 and a 3% ($6.0 million) decrease in the accumulated postretirement benefit obligation as of Sept. 30, 2006, the measurement date.
The actuarial assumptions we used in determining our pension and OPEB retirement benefits may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, or longer or shorter life spans of participants. While we believe that the assumptions used are appropriate, differences in actual experience or changes in assumptions may materially affect our financial position or results of operations.
See further discussion of Employee Postretirement Benefits in Note 5 to the TECO Energy Consolidated Financial Statements
Accounting for Contingencies
In accordance with FAS 5, Accounting for Contingencies, we make estimates at the end of each reporting period to record the probable loss related to contingent liabilities. Examples of such expected losses and respective contingent liabilities would include environmental and legal contingencies and incurred but unreported medical and general liability claims. We consider these estimates of liabilities to be critical since the company must first determine the likelihood that the known claims or legal events will result in a future loss to the company. Then we must determine if the future amount of expected loss can be reasonably estimated.
For a known claim, if the company determines that it is probable that future events will result in a loss and that loss can be reasonably estimated, the expected loss and respective liability are recorded. If we determine that the likelihood is remote that those future events will develop in a manner that will result in a loss to the company, no loss or liability is recorded. If there is more than a remote possibility but it is less than likely that future events will result in a loss to the company, we disclose the specific claim or situation if it is material.
For medical and general liability claims that have been incurred but not reported, we rely on a third-party actuary to advise us as to probable liabilities that will become known in the future but were incurred in the current reporting period, and we record the expected loss and liability accordingly.
Many of the material claims that have been made or could be made against the company in the future are covered by insurance. Accounting for the expected loss and liability under FAS 5 has different recognition criteria than expected insurance recoveries. As a result, it is possible that the company could have to report a loss and respective liabilities in accounting periods before the offsetting proceeds from the insurance recovery and potential gain could be reported.
While the company carefully evaluates all known claims and cases to record the most probable outcome, future events could develop in an unexpected manner that could have a material impact on future financial statements. See Note 12 to the TECO Energy Consolidated Financial Statements for a complete discussion of certain legal contingencies that existed at Dec. 31, 2006.
Long-Lived Assets
In accordance with FAS 144, Accounting for the Impairment or Disposal of Long- Lived Assets, we assess whether there has been an other than temporary impairment of our long-lived assets and certain intangibles held and used by us when such indicators exist. We annually review all long-lived assets in the last quarter of each year to ensure that any gradual change over the year and the seasonality of the markets are considered when determining which assets require an impairment analysis. We believe the accounting estimates related to asset impairments are critical estimates for the following reasons: (1) the estimates are highly susceptible to change, as management is required to make assumptions based on expectations of the results of operations for significant/indefinite future periods and/or the then current market conditions in such periods; (2) markets can experience significant uncertainties; (3) the estimates are based on the ongoing expectations of management regarding probable future uses and holding periods of assets; and (4) the impact of an impairment on reported assets and earnings could be material. Our assumptions relating to future results of operations or other recoverable amounts are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. Our expectations regarding uses and holding periods of assets are based on internal long-term budgets and projections, which give consideration to external factors and market forces, as of the end of each reporting period. The assumptions made are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities.
At the end of the 2006 fiscal year impairment tests were conducted on our long-lived assets. At the conclusion of the analyses, it was determined that all asset carrying values were recoverable based on the reasonable estimates used. No impairment adjustments were necessary.
During 2005, we reduced our fair market value assumption for the McAdams power project, based on a strategic review of the options to dispose of that investment, which resulted in a further impairment charge related to additional asset retirement obligations (see Note 15 to the TECO Energy Consolidated Financial Statements). All the remaining assets associated with the McAdams power project we sold in 2006 (see Note 16 to the TECO Energy Consolidated Financial Statements).
During the fourth quarter of 2004, as a part of its annual impairment review, management conducted a review of the prospects for long-term power prices, as well as opportunities for actual sales of assets. As a result of this review, we sold the Frontera project and determined it was appropriate to reduce the probability that the Dell, McAdams, and Commonwealth Chesapeake projects would be held for use for the overall economic life of those projects. The first step in the impairment testing was weighted more toward an ultimate recovery of the investment. In each case, the testing resulted in a determination that the carrying value of each project was not recoverable. This recoverability test is conducted by comparing the probability weighted undiscounted cash flows for the asset to its carrying value. If the test is not passed, a second step is required. Each of the projects
listed above required the second step, in which the difference between the fair market value of the projects and the carrying value was estimated in order to determine and record appropriate impairment charges. Critical estimates are also inherent in determining the fair market value. We based the fair market values on probability weighted values. To the extent actual fair market value should vary from the probability weighted average values, future impairment charges or gains on disposition could occur (see Note 18 to the TECO Energy Consolidated Financial Statements).
Regulatory Accounting
Tampa Electric’s and PGS’ retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the Federal Energy Regulatory Commission (FERC). As a result, the regulated utilities qualify for the application of FAS 71, Accounting for the Effects of Certain Types of Regulation. This statement recognizes that the actions of a regulator can provide reasonable assurance of the existence of an asset or liability. Regulatory assets and liabilities arise as a result of a difference between generally accepted accounting principles and the accounting principles imposed by the regulatory authorities. Regulatory assets generally represent incurred costs that have been deferred, as their future recovery in customer rates is probable. Regulatory liabilities generally represent obligations to make refunds to customers from previous collections for costs that are not likely to be incurred.
We periodically assess the probability of recovery of the regulatory assets by considering factors such as regulatory environment changes, recent rate orders to other regulated entities in the same jurisdiction, the current political climate in the state, and the status of any pending or potential deregulation legislation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. A change in these assumptions may result in a material impact on reported assets and the results of operations (see the Regulation section and Notes 1 and 3 to the TECO Energy Consolidated Financial Statements).
RECENTLY ISSUED ACCOUNTING STANDARDS
Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans
In September 2006, the FASB issued FAS No.158, Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R). The company adopted FAS 158 on Dec. 31, 2006. This statement of financial accounting standards requires the recognition in the statement of financial position the over-funded or under-funded status of a defined benefit postretirement plan, measured as the difference between the fair value of plan assets and the benefit obligation in the case of a defined benefit plan, or the accumulated postretirement benefit obligation in the case of other postretirement benefit plans. As a result of this standard, the company reported as of Dec. 31, 2006, a $125.8 million increase in benefit liability on the balance sheet and a $21.8 million accumulated other comprehensive loss, net of estimated tax benefits. In addition, as a result of the application of FAS 71 to the impacts of FAS 158, Tampa Electric Company recorded $91.9 million in both benefit liabilities and regulatory assets. This standard does not affect the results of operations.
Accounting for Uncertainty in Income Taxes
In June 2006, the FASB issued FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109 (FIN 48). FIN 48 prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. Application involves a two-step approach where recognition occurs if the position exceeds a “more likely than not” threshold and the measurement is based on the tax benefit being greater than 50 percent likely of being realized upon settlement with the tax agencies involved. FIN 48 is effective for fiscal years beginning after Dec. 15, 2006. Based on the company’s assessment to date of the tax positions as of Jan. 1, 2007, the company believes that the implementation of FIN 48 during the first quarter of 2007 will have an immaterial impact on retained earnings. In addition, as a result of reaching a favorable conclusion with a taxing authority during the first quarter of 2007, the company expects to record during the first quarter of 2007 a previously unrecognized gain in Discontinued Operations in the range between $12 and $15 million related to the disposition of the Union and Gila River power stations.
Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in the Current Year Financial Statements
In September 2006, the Securities and Exchange Commission staff issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in the Current Year Financial Statements (SAB 108). SAB 108 addresses the diversity in practice by registrants when quantifying the effect of an error on the financial statements and provides guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements. SAB No. 108 was adopted on Dec. 31, 2006 and did not have an impact on the company’s consolidated financial statements.
OTHER ITEMS IMPACTING NET INCOME
OTHER INCOME (EXPENSE)
In 2006, Other income or (expense) of $153.6 million reflected the $46.6 million from the installment sale of the 98% interest in the synthetic fuel production facilities at TECO Coal, $58.6 million of pretax income from the Guatemalan operations, which are accounted for as equity investments, $34.8 million of pretax interest income on invested cash balances and $6.0 million of pretax gains on the smaller assets sold in 2006 partially offset by the debt reduction charges. Income from the sale of the interests in TECO Coal’s synthetic fuel production facilities was reduced in 2006 by the 35% limitation on the tax credits due to high oil prices and lower production in 2006 (see the TECO Coal section). The debt reduction charges were $2.5 million in 2006, compared to $74.2 million in 2005.
In 2005, Other Income (expense) of $157.8 million reflected the installment sale of the 98% interest in the synthetic fuel production facilities at TECO Coal, income from the Guatemalan operations, which are on equity investment accounting, and gains on the smaller assets sold in 2005 partially offset by the debt extinguishment charges associated with our 2005 debt retirement program.
In 2004, Other Income (expense) of $23.1 million reflected the income related to the gain on the sale of the Hamakua Power Station, the sale of our interest in the propane business, the installment sale of the 90% interest in the synthetic fuel production facilities at TECO Coal, and income from the deconsolidated Guatemalan operations, largely offset by a $152.3 million pretax impairment charge related to our investment in the Texas Independent Energy (TIE) projects.
AFUDC equity at Tampa Electric, which is included in Other Income (expense), was $2.7 million in 2006 and $0.7 million in 2004, and there was no AFUDC recorded in 2005. AFUDC is expected to increase in 2007 due to the installation of NOx control at Tampa Electric’s Big Bend Station (see the Environmental Compliance and Liquidity, Capital Resources sections).
INTEREST EXPENSE
Total interest expense was $278.3 million in 2006 compared to $288.7 million in 2005 and $322.9 million in 2004. In 2006, interest expense was reduced by the repayment in June 2005 of $380 million of 10.5% notes and the December 2005 repayment of $100 million of 8.5% trust preferred securities. Interest expense also reflects Tampa Electric’s issuance of $250 million of 6.55% notes in May 2006 and use of proceeds to reduce short-term borrowings. In 2005, interest expense was reduced by the retirement of $391.6 million of trust preferred securities in late 2004, and the repayment in June 2005 of $380 million of 10.5% notes, partially offset by interest associated with $200 million of fixed-rate notes issued in May 2005 and $100 million of floating-rate notes issued in June 2005 (see the Financing Activity section), and higher short-term borrowings under credit facilities at Tampa Electric Company.
Interest expense is expected to decrease in 2007 due to the full-year benefits from the December 2006 retirement of the remaining 8.5% TruPS outstanding, the January 2007 retirement of $57 million of 5.93% junior subordinated notes and the planned retirement of the $300 million of 6.125% notes due in May 2007, partially offset by Tampa Electric Company’s increased borrowings to support its capital spending program (see the Liquidity, Capital Resources section).
INCOME TAXES
The provision for income taxes increased in 2006 from higher operating income primarily due to lower debt extinguishment costs and lower interest expense. The provision for income taxes increased in 2005 as a result of more-normal operations and fewer write-offs of merchant generating assets. In 2004 the provision for income taxes was a benefit as we incurred net operating losses primarily as a result of losses on the disposition of merchant power generating assets. Income tax expense as a percentage of income from continuing operations before taxes was 32.7% in 2006, 32.6% in 2005, and 40.8% in 2004. For 2007, 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 Alternative Minimum Tax Rules (AMT), state income taxes and payments related to prior years’ audits was $10.4 million, $27.4 million and $22.4 million in 2006, 2005 and 2004, respectively.
Due to the generation of deferred income tax assets related to the net operating loss (NOL) carry-forward from disposition of the merchant generating assets, we expect future cash tax payments for income taxes to be limited to approximately 10% of the AMT rate and various state taxes. We currently expect to utilize these NOLs through 2010. Beyond 2010, we expect to use more than $190 million of AMT carry-forward to limit future cash tax payments for federal income taxes to the level of AMT. Our current projection of cash income tax payments in 2007 is about $14 million, including amounts for refunds of foreign tax credits carried back to prior years and amounts owed to jurisdictions where we do not have NOLs. For the 2008-2010 period, we estimate tax payments to be in the range of $7 to $12 million annually.
Total income tax expense in years prior to 2004 was reduced by the federal tax credits related to the production of non-conventional fuels. We recognized no tax credits in 2004 and $73.0 million in 2003. These tax credits are generated annually on qualified production at TECO Coal through Dec. 31, 2007, subject to changes in the law, regulation or administration that could impact the qualification for non-conventional fuel tax credits. We were unable to utilize any of these tax credits in both 2005 and 2004 due to our net tax loss position for the years. Under the Energy Policy Act of 2005 that was signed into law on Aug. 8, 2005,
effective Jan. 1, 2006 tax credits from the production of synthetic fuels generated in 2006 and 2007 that could not be utilized in those years will be carried forward for 20 years.
The synthetic fuel tax credit is determined annually and is estimated to be $1.19 per million Btu for 2006 before phase-out, and was $1.17 per million Btu in 2005 and $1.13 per million Btu in 2004. This rate escalates with inflation but could be limited by domestic oil prices. (See the Synthetic Fuel discussion in the Outlook section and the discussion of the reference oil price in the TECO Coal Outlook section. )
In 2006, 2005 and 2004, income tax expense also reflected a decrease due to the impact of increased overseas operations with deferred U.S. tax structures. The decrease related to these deferrals was $9.2 million, $9.4 million and $10.5 million for 2006, 2005 and 2004, respectively.
The income tax effect of gains and losses from discontinued operations is shown as a component of results from discontinued operations.
DISCONTINUED OPERATIONS
Discontinued Operations
In 2006 net income from discontinued operations was $1.9 million, reflecting primarily the recovery of receivables and adjustments for estimates for businesses that had been previously written off. In 2005, net income from discontinued operations was $63.5 million, compared to a loss of $196.5 million in 2004. The 2005 results include the operating results from the Union and Gila River power stations through the end of May 2005 and the $76.5 million after-tax gain recorded upon the final disposition of the plants. Discontinued operations also include results for the Commonwealth Chesapeake Power Station until its sale in April 2005 and adjustments to estimates for impairments on previously divested assets.
Discontinued Operations/Asset Dispositions
TECO Energy completed a number of asset dispositions in 2006, 2005 and 2004 as part of a revised business strategy to focus on the electric and gas utilities and long-term profitable unregulated businesses and to reduce exposure to the merchant power sector. This process was completed with the sale of TECO Thermal in 2006 and the uncompleted McAdams Power Station. In 2005, TWG Merchant sold its membership interest in Commonwealth Chesapeake Power Station (CCC) in Virginia and substantially all the assets of the Dell Power Station in Arkansas. BCH Mechanical, Inc. (BCH Mechanical) was also sold in 2005. In 2004, TWG Merchant completed both the sale of its 50% indirect interest in TIE and the sale of Frontera Generation Limited Partnership (Frontera), the owner of the Frontera Power Station in Texas. In 2004, TECO Guatemala sold its 50% indirect interest in the Hamakua Power Station (Hamakua) in Hawaii. TECO BGA, Inc. (TECO BGA), TECO AGC, Ltd. (TECO AGC), and substantially all the assets of Prior Energy were also sold in 2004. In addition, TECO Energy completed the sale of its general and limited partnership interests in Heritage Propane Partners, L.P. as part of a larger transaction that involved the merging of privately held Energy Transfer Company with Heritage Propane Partners in 2004. Results for CCC, BCH Mechanical, TECO Thermal, Frontera, Prior Energy, TECO BGA, and TECO AGC have been accounted for as discontinued operations for all periods reported. Revenues from these discontinued operations were $10.6 million and $141.7 million in 2005 and 2004, respectively (see Notes 16 and 21 to the TECO Energy Consolidated Financial Statements). Included in continuing operations prior to their respective sales were the results from our interests in the Dell and McAdams power stations, TIE, Hamakua and Heritage Propane Partners.
TWG Merchant’s interests in the Union and Gila River project companies, which owned merchant generation plants in Arkansas and Arizona, respectively, were held by an indirect wholly owned subsidiary of TWG Merchant, TECO-Panda Generating Company, L.P. (TPGC). TPGC was part of the TWG Merchant operating segment until designated as assets held for sale in December 2003. In 2005, TECO Energy completed the sale and transfer of the Union and Gila River project companies (see Notes 16 and 21 to the TECO Energy Consolidated Financial Statements). TPGC’s results are accounted for as discontinued operations for all periods reported. Revenues from the discontinued operations of TPGC in 2005 and 2004 were $109.1 million and $510.7 million, respectively. Net income (loss) from the discontinued operations of TPGC were $65.1 million and $(96.0) million in 2005 and 2004, respectively.
INFLATION
The effects of inflation on our results have not been significant for the past several years. The annual rate of inflation, as measured by the Consumer Price Index (CPI-U), all items, all urban consumers as reported by the U.S. Department of Labor, was 2.5%, 3.4% and 3.3% in 2006, 2005 and 2004, respectively. Published forecasts by economists and by several agencies of the U.S. government indicate that inflation is expected to be relatively modest again in 2007, with a 2.8% increase expected.
Prices for certain products and services used by TECO Energy’s operating companies increased at rates above the CPI in 2006, including prices for concrete, steel and copper products and petroleum-based products used extensively in all of our operating companies, and for subcontracted services used by Tampa Electric and subcontracted mining services used by TECO Coal. These prices moderated in late 2006 and are expected to rise in 2007, but at a rate slower than in 2006. In the case of TECO Transport, a portion of the increased cost of petroleum products is passed through to its contract customers through fuel adjustment clauses while other costs are covered by inflation adjustment clauses, and Tampa Electric and PGS are eligible to recover the cost of commodity fuel through the respective FPSC-approved fuel-adjustment clauses. In those cases where the higher costs can not be passed directly to the customers, higher costs could reduce the profit margins at the operating companies.
ENVIRONMENTAL COMPLIANCE
Environmental Matters
Our commitment to environmental compliance is an important element of our culture. Each of our operating companies has an environmental compliance plan tailored to its industry and location, each of which is part of our overall corporate compliance plan.
Among our companies, Tampa Electric has the most significant number of stationary sources with air emissions impacts and material Clean Water Act implications. Tampa Electric has taken significant steps to dramatically reduce its air emissions through a series of voluntary actions, including technology selection (including IGCC and natural-gas fired combined cycle); a responsible fuel mix taking into account price and reliability impacts to its customers; a significant capital expenditure program to add Best Available Control Technology (BACT) emissions controls; 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, including the installation of IGCC technology, BACT and repowering from coal to natural gas, represent an investment in excess of $2 billion since 1994.
Through these actions, Tampa Electric has achieved significant reductions of all air pollutants, including CO2 while maintaining a reasonable fuel mix through the clean use of coal for the economic benefit of its customers. The early CO2 reductions and pioneering use of IGCC technology positions us and Tampa Electric well for new laws and rules which may be enacted to address climate change related issues, including carbon reductions.
We believe that any government adopted carbon reduction program should: (1) apply across all sectors of the economy and address all sources of greenhouse gases (GHG); (2) recognize and give credit for early action and be based on a market driven “cap-and-trade” program with allocations based on the status of emissions and reductions to date, much like the program applicable to SO2; and (3) include mechanisms for the development and deployment of new technologies, including the removal of regulatory and economic barriers or the inclusion of incentives for the use of those technologies for low emission generation, carbon capture, storage, wind, solar and other renewable energy resources, as well as cost effective development of demand-side management technologies and conservation incentives.
Air Quality Control
IGCC Technology - Polk Power Station
In 2006, Tampa Electric celebrated its tenth year of commercial operation of the Polk Power Station, originally a 260-megawatt Integrated Gasification Combined Cycle (IGCC) power plant, which was the first of its kind commercially available in operation. The IGCC unit was constructed in cooperation with the U.S. Department of Energy (DOE) as a part of its Clean Coal Program. DOE contributed approximately $140 million to assist in the commercialization of this technology to enable the clean burning of coal. This technology converts coal into a synthesis gas and removes 95% of the SO2 from the gas prior to combustion and coupled with efficient combined-cycle technology uses approximately 10% less fuel for the same level of power output. The emission rates of this unit are very similar to a natural gas combined-cycle unit of the same size.
Polk Power Station Unit 1 has been recognized as the best example of IGCC technology in the United States and the cleanest coal-burning generating plant in North America. Tampa Electric is a leader in operations and maintenance experience and enhancement techniques for clean-coal burning technology. Operational improvements and the low cost of fuel make the Polk IGCC the most economical unit on Tampa Electric’s system and it dispatches ahead of the Big Bend conventional coal-fired units.
The Energy Policy Act of 2005 encourages the development of clean-coal technologies. It authorized almost $1.1 billion over three years to fund the U. S. Department of Energy’s (DOE) clean coal research and development programs. In 2006 the Internal Revenue Service and DOE awarded Tampa Electric $133 million of tax credits for its proposed 630 megawatt IGCC plant to be built at the Polk Power Station as contained in its 10-year site plan, which is expected to be in service after 2012 (see the Tampa Electric and Liquidity, Capital Resources and Capital Expenditures sections).
Consent Decree
Tampa Electric, through voluntary negotiations with the Environmental Protection Agency (EPA) and the U.S. Department of Justice and the Florida Department of Environmental Protection (FDEP), signed a Consent Decree, which became effective Feb. 29, 2000, and a Consent Final Judgment, which became effective Dec. 6, 1999, as settlement of federal and state litigation. Pursuant to these agreements, allegations of violations of New Source Review requirements of the Clean Air Act were resolved, 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 efforts on Big Bend Units 1 through 4, and the repowering of the coal-fired Gannon Power Station to natural gas. The commercial operation dates for the two repowered units, renamed as the H. L. Culbreath Bayside Power Station (Bayside), were Apr. 24, 2003 and Jan. 15, 2004. The completed station has total station capacity of about 1,800 megawatts (nominal) of efficient, natural gas-fueled, combined-cycle electric generation, which uses 10% less fuel for the same amount of power output. The repowering has reduced the facility’s NOx and SO2 emissions by approximately 99% and particulate matter emissions have decreased approximately 92% from 1998 levels.
In 2004, Tampa Electric made its NOx reduction technology selection and decided to install SCRs for NOx control on Big Bend Unit 4, with an expected in-service date by Jun. 1, 2007. Tampa Electric has also decided to install SCR technology on Big Bend Units 1, 2 and 3 with in-service dates for Unit 3 by May 1, 2008, Unit 2 by May 1, 2009 and Unit 1 by May 1, 2010. The engineering, design and construction of the SCR system are currently in progress. Tampa Electric’s capital investment forecast includes amounts in the 2007 through 2011 period for compliance with the NOx, SO2 and particulate matter (PM) reduction requirements (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 Station and pre-SCR projects on Big Bend Units 1-3 (which are early plant improvements to reduce NOx emissions prior to installing the SCRs) through the Environmental Cost Recovery Clause (ECRC) (see the Regulation section). The first SCR (Big Bend Unit 4) is scheduled to enter service by Jun. 1, 2007 and cost recovery for the capital investment, which is dependent on filings related to the prudence of actual expenditures to be made in 2007, is expected to start in 2008.
Emission Reductions
Projects committed to under the Consent Decree and Consent Final Judgment have resulted in significant reductions in emissions. Since 1998, Tampa Electric has reduced annual SO2, NOx and PM from its facilities by 160,000 tons, 41,000 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 Station remove more than 95% of the SO2 emissions from the flue gas streams.
The repowering of Gannon Station to Bayside Station has resulted in a significant reduction in emissions of all pollutant types. We expect that Tampa Electric’s actions to install additional NOx emissions controls on all Big Bend units will result in the further reduction of emissions and that by 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 Electric’s emission reduction initiatives will result in the reduction of SO2, NOx and PM emissions by 89%, 90%, and 72%, respectively, below 1998 levels by 2010. With these improvements in place, Tampa Electric’s facilities meet the same standards required of new power generating facilities and help to significantly enhance the quality of the air in the community. As a result of all its already completed emission reduction actions, and upon completion of the SCR projects, we expect that Tampa Electric will have achieved emission reduction levels called for in Phase I of the Clean Air Interstate Rule (CAIR) when it is implemented in 2009.
Due to pollution control benefits from the environmental improvements, reductions in mercury emissions have occurred due to the repowering of Gannon Station to Bayside Station. At Bayside, where mercury levels have decreased 99% below 1998 levels, there are virtually zero mercury emissions. Additional mercury reductions are also anticipated from the installation of NOx controls at Big Bend Station, which would lead to a reduction of mercury emissions of more than 70% from 1998 levels by 2010. Tampa Electric expects to be in compliance with the Clean Air Mercury Rule (CAMR) Phase I requirements when they are implemented in 2010 without additional capital investment. The stricter standards required in 2018 by Phase II of CAMR may require additional control equipment.
The EPA has recently proposed modifications to the 24-hour coarse and fine particulate matter standards. Based on the reduced emissions of 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.
Carbon Reductions
We have historically supported voluntary efforts to reduce carbon emissions and have taken significant steps to reduce overall emissions at Tampa Electric’s facilities. Since 1998, Tampa Electric has reduced its system-wide emissions of CO2 by approximately 19%, bringing emissions to near 1990 levels. Tampa Electric expects that emissions of CO2 should remain near 1990 levels until the addition of the next baseload unit, which is expected after 2012. Tampa Electric estimates that the repowering to natural gas and the shut-down of coal-fired units resulted in a decrease in CO2 emissions of approximately 4.0 million tons below 1998 levels. During this same timeframe, the numbers of retail customers and retail energy sales have risen by approximately 25%.
We believe new legislative and regulatory efforts to reduce CO2 emissions will be more effective if any proposed Legislation or Rules recognize the early, voluntary steps some have taken to dramatically improve their emissions profiles (to provide an incentive to continue doing so before new legislation or regulations take effect), focus on technology development, and provide a regulatory structure that supports advanced clean coal IGCC technology or other similar technologies. As a result of Tampa Electric’s already dramatic reductions in CO2 emissions, it is well-positioned to engage in the carbon reduction debate. Many states, including California, and Congress have made proposals to reduce greenhouse gas emissions over an extended period. There are several means to address reductions in greenhouse gas emissions, including energy efficiency initiatives, more efficient automobiles, such as plug-in hybrids, and advanced clean coal technology such as Tampa Electric’s IGCC facility Polk Power Station.
We stand by our commitment to achieve emissions reductions and technologies that provide a viable future for coal. We are a supporter of coal as a plentiful, cost-effective and reliable source of energy. We believe that the environmental controls in place at Tampa Electric’s facilities and the successful operation of coal gasification for the production of electricity Tampa Electric have demonstrated that advanced clean coal is an environmentally sound, economic and reliable electric generation fuel source that will continue to have a viable future.
We believe that the important elements of CO2 emissions reduction efforts include: (1) research and development efforts aimed at technology development for carbon capture and sequestration; (2) financial support for IGCC, such as the tax credits awarded to Tampa Electric in 2006; and (3) innovative regulatory mechanisms to address the higher capital costs of these clean technologies.
Tampa Electric belongs to the U.S. Department of Energy’s Climate Challenge program and participates in the Chicago Climate Exchange, a voluntary but legally binding cap-and-trade program dedicated to reducing greenhouse gas emissions. Because of Tampa Electric’s membership in the Chicago Climate Exchange, its CO2 emissions are measured through the use of emissions monitoring equipment and audited annually by the National Association of Securities Dealers, which has certified the results thus far.
Florida has an Energy Commission charged with developing a comprehensive energy policy for the state. By statute the final report of the Commission is due on Dec. 31, 2007, a portion of which must include an action plan on climate change. Specifically, the legislation requires the Commission to “recommend consensus-based public-involvement processes that evaluate greenhouse gas emissions in this state and make recommendations regarding related economic, energy, and environmental benefits. The report must include recommended steps and a schedule for the development of a comprehensive state climate action plan with greenhouse gas reduction through a public-involvement process, including transportation and land use, generation; residential, commercial and industrial activities, waste management, agriculture and forestry; emissions-reporting systems; and public education.” The Commission’s organizational meeting was held in mid-February, 2007, subcommittees (including one on climate change) were formed, and meetings with opportunities for public input will be held throughout the remainder of the year.
Several states have proposed or enacted legislation to limit CO2 emissions, and there is proposed legislation at the federal level that would limit CO2 emissions. The timing of passage of any federal legislation is uncertain as is the period over which CO2 emissions reductions would be required. Several bills have been introduced in Congress but none are on a fast track for action. Most of these bills contain some type of cap-and-trade system. Several of them focus on the power sector only but others are economy-wide and all of focus on some reductions from a baseline year; however, none of the details are defined.
In the case of Tampa Electric, we expect that the costs to comply with new environmental regulations would be eligible for recovery through the Environmental Cost Recovery Clause. If approved as prudent, the costs required to comply with CO2 emissions reductions would be reflected in customers’ bills.
In the case of TECO Coal, it is unclear if the requirements for CO2 emissions reductions would impact it as a carbon-based fuel provider or the user. In either case, it could make the use of coal more expensive or less desirable, which could impact TECO Coal’s margins and profitability.
Tampa Electric currently emits approximately 15 million tons of CO2 per year. With a projected annual growth of electricity demand of 2.5%, Tampa Electric estimates an approximately 30% increase to approximately 20 million tons in 2020 due to planned additional generation to meet customer growth. This level would be substantially the same as, or slightly below 1998 levels.
If legislation is adopted to require mandatory reductions in CO2, the company favors recognition for early action and a cap-and-trade program in which allocations of allowances would be made based on performance against a baseline year supported by verifiable data. Currently the several proposals at the federal level have not yet received public input in a formal way so that the details of what might emerge are uncertain.
Because there is no specific defined congressional proposal, we cannot reasonably predict the economic impact to the company of any adopted legislation. We will participate in the debate in an effort to include provisions for credit for early reductions, such as those already achieved by Tampa Electric, and for future percentage reductions that are reasonable.
In its ten-year site plan filed in 2006, Tampa Electric identified preliminary plans to build a 630-megawatt IGCC unit in 2013, in addition to two 180-megawatt natural gas-fired peaking units in 2007. The company would continue to run its existing coal- and natural gas-fired capacity.
Water Quality
Tampa Electric uses water from Tampa Bay at its Bayside and Big Bend facilities for cooling water. Both plants use mesh screens to reduce the adverse impacts to aquatic organisms. Big Bend units 3 and 4 use proprietary fine-mesh screens, the best available technology, to further reduce impacts to aquatic organisms. Water recycling and beneficial reuse programs are widely employed on the fresh water systems at both plants. Numerous methods are used to prevent storm water, and other water discharges protecting ground water and the waters of Tampa Bay.
Renewable Energy
Tampa Electric’s renewable energy program uses energy from several sources to support customer demand for its Renewable Program. The majority of renewable energy comes from sources that include:
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Biomass, which is organic plant material from yard clippings and other vegetation. Tampa Electric has tested bahia grass as a fuel to generate electricity at the Polk Power Station. More than 60 tons of bahia grass, grown on the 4,300 acre plant site, were ground and mixed with the pulverized coal slurry used in the plant’s gasifier.
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Photovoltaic panels have been installed at two schools, the Museum of Science and Industry and the Manatee Viewing Center to harness energy from the sun.
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Methane gas from a landfill is used to drive a microturbine at the Hillsborough Heights landfill.
Through the end of 2006, the environmental impacts of customers’ participation in the program have been significant:
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More than 2 million kwhs of renewable energy have been produced to support participating customer requirements,
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Approximately 1,400 tons of coal have been offset with energy from renewable resources, and
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CO2 reductions from using renewable resources are the equivalent of planting more than 5,800 acres of trees or removing almost 1,700 cars from the streets.
Conservation
Energy conservation is becoming increasingly important in a period of volatile energy prices and in the greenhouse gas emissions reduction debate. Tampa Electric offers customers a number of programs to conserve energy. These programs are designed to reduce peak energy demand which allows Tampa Electric to delay construction of future generation facilities. Since 1981, the conservation programs have reduced the summer peak demand by 251 megawatts, and the winter peak demand by 731 megawatts. These programs and their costs are approved annually by the FPSC with the costs recovered through a clause on the customer’s bill. PGS also offers programs that enable customers to reduce their energy consumption with the costs recovered through customers’ bills.
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, 2006, Tampa Electric Company has estimated its ultimate financial liability to be approximately $12.3 million (primarily related to PGS), and this amount has been reflected in the company’s financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices. The amounts represent only the estimated portion of the cleanup costs attributable to Tampa Electric Company. The estimates to perform the work are based on actual estimates obtained from contractors or Tampa Electric Company’s experience with similar work, adjusted for site specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.
Allocation of the responsibility for remediation costs among Tampa Electric Company and other PRPs is based on each party’s relative ownership interest in or usage of a site. Accordingly, Tampa Electric Company’s share of remediation costs varies with each site. In virtually all instances where other PRPs are involved, those PRPs are considered credit worthy.
Factors that could impact these estimates include the ability of other PRPs to pay their pro rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. These additional costs would be eligible for recovery through customer rates.
REGULATION
The retail operations of Tampa Electric are regulated by the FPSC, which has jurisdiction over retail rates, quality of service and reliability, issuances of securities, planning, siting and construction of facilities, accounting and depreciation practices, and other matters.
In general, the FPSC’s pricing objective is to set rates at a level that allows the utility to collect total revenues (revenue requirements) equal to its cost of providing service, plus a reasonable return on invested capital.
The costs of owning, operating and maintaining the utility system, other than fuel, purchased power, conservation and certain environmental costs, are recovered through base rates. These costs include operation and maintenance expenses, depreciation and taxes, as well as a return on Tampa Electric’s investment in assets used and useful in providing electric service (rate base). The rate of return on rate base, which is intended to approximate Tampa Electric’s weighted cost of capital, primarily includes its costs for debt, deferred income taxes at a zero cost rate and an allowed return on common equity. Base rates are determined in FPSC rate setting hearings which occur at irregular intervals at the initiative of Tampa Electric, the FPSC or other parties.
Tampa Electric is also subject to regulation by the Federal Energy Regulatory Commission (FERC) in various respects, including wholesale power sales, certain wholesale power purchases, transmission services, and accounting practices.
Federal, state and local environmental laws and regulations cover air quality, water quality, land use, power plant, substation and transmission line siting, noise and aesthetics, solid waste and other environmental matters (see Environmental Compliance section above).
Tampa Electric Rates
Tampa Electric’s rates and allowed return on equity (ROE) range of 10.75% to 12.75%, with a midpoint of 11.75%, are in effect until such time as changes are occasioned by an agreement approved by the FPSC or other FPSC actions as a result of rate or other proceedings initiated by Tampa Electric, FPSC staff or other interested parties.
Tampa Electric has not sought a base rate increase since 1992. Since that last rate proceeding it has earned within its allowed ROE range while adding almost 190,000 customers and making significant investments in facilities and infrastructure including baseload and peaking generating capacity additions to serve the growing customer base. Over time, current base rates may not support the additional transmission and distribution system reliability capital spending, storm hardening capital and operations and maintenance spending, other recurring capital expenditures and generally higher non-fuel operations and maintenance expenditures and still earn a return within its allowed ROE range.
Cost Recovery Clauses - Tampa Electric
Fuel, purchased power, conservation and certain environmental costs are recovered through levelized monthly charges established pursuant to the FPSC’s cost recovery clauses. These charges, which are reset annually in an FPSC proceeding, are based on estimated costs of fuel, environmental compliance, conservation programs and purchased power and estimated customer usage for a specific recovery period, with a true-up adjustment to reflect the variance of actual costs from the projected costs. The FPSC may disallow recovery of any costs that it considers imprudently incurred.
In September 2006, Tampa Electric filed with the FPSC for approval of cost recovery rates for fuel and purchased power, capacity, environmental and conservation costs for the period January through December 2007. In November 2006, the FPSC approved Tampa Electric’s requested rates. The rates include the cost for natural gas and coal expected in 2007, the collection of approximately $51 million of underestimated fuel and purchased power expenses in 2006, the collection of approximately $107 million for previously unrecovered 2005 fuel and purchased power expenses and the operating cost for and a return on the capital invested in the first SCR project to enter service on Big Bend Unit 4 as well as the operations and maintenance expense associated with the Big Bend Units 1-3 pre-SCR projects as required by the EPA Consent Decree and FDEP Consent Final Judgment (see the Environmental Compliance section). The rates were partially offset by actual and projected proceeds from the sale of approximately $105.8 million excess SO2 emissions allowances in 2006 and 2007. Accordingly, Tampa Electric’s residential customer rate per 1,000 kilowatt-hours increased $4.93 from $109.61 in 2006, when $100 million of proceeds from the sale of SO2 emissions allowances were returned to customers, to $114.54 in 2007.
The FPSC determined that it was appropriate for Tampa Electric to recover SCR operating costs through the ECRC as well as earn a return on its SCR investment installed on Big Bend Unit 4 and Big Bend Units 1-3 in October 2004 and May 2005, respectively, for NOx control in compliance with the environmental consent decree. The SCR for Big Bend Unit 4 is scheduled to enter service by Jun. 1, 2007. The SCRs for Big Bend Units 3, 2, and 1 are scheduled to enter service by May 1, 2008, 2009 and 2010, respectively. Cost recovery for the capital investment for each unit, which is dependent on filings made in the year each SCR enters service, is expected to start in 2008, 2009 and 2010, respectively.
Coal Transportation Contract
Tampa Electric’s contract for coal transportation and storage services with TECO Transport expired on Dec. 31, 2003. TECO Transport had been providing river and cross-gulf transportation services and storage services under that contract since 1999 and under a series of contracts for more than 40 years. Following a RFP process, Tampa Electric executed a new five-year contract with TECO Transport, effective Jan. 1, 2004, for waterborne coal transportation and storage services at market rates supported by the results of the RFP and an independent expert in maritime transportation matters. Hearings regarding the prudence of the RFP process and final contract were held in the first half of 2004 and a final order on the matter was issued in October 2004, which
reduced the annual amount Tampa Electric can recover from its customers through the fuel adjustment clause for the water transportation services for coal and petroleum coke provided by TECO Transport. The annual after-tax disallowance is estimated to be $8 million to $10 million, depending on the volumes and origination points of the coal shipments, for as long as the contract is in effect.
Tampa Electric expects to issue a RFP for solid fuel transportation services on a schedule that will facilitate having a new contract for these services in place at the expiration of the current contract. The FPSC October 2004 order established the parameters for a bid process that would be acceptable to it. Tampa Electric plans to structure the RFP to comply with the FPSC order.
Storm Damage Cost Recovery
Following Hurricane Andrew in 1992, Florida’s investor owned utilities (IOUs) were unable to obtain transmission and distribution insurance coverage for hurricanes, tornados or other damage due to destructive acts of nature. Tampa Electric and other IOUs were permitted to implement a self-insurance program effective Jan. 1, 1994 for such costs of restoration, and the FPSC authorized Tampa Electric to accrue $4 million annually to grow its unfunded storm damage reserve. Tampa Electric had never utilized its reserve before the 2004 hurricane season. The final costs for restoration associated with hurricanes Charley, Frances and Jeanne in 2004 were approximately $74 million.
In June 2005, the FPSC approved a stipulation entered into by Tampa Electric, the Office of Public Counsel and the Florida Industrial Power Users Group regarding the treatment of Tampa Electric’s 2004 hurricane costs. Under the stipulation, Tampa Electric agreed to reclassify approximately $39 million of the hurricane restoration costs as plant in service (rate base). With this adjustment and the normal $4 million annual storm accrual, Tampa Electric’s storm reserve, which had a $30 million deficit balance, had a positive balance of about $14 million at the June start of the 2006 hurricane season and a $16 million balance at Dec. 31, 2006.
In the 2005 legislative session, the Florida Legislature passed a bill that would allow IOUs in Florida to “securitize” storm damage costs. Under this bill, IOUs would have the opportunity to recover hurricane restoration costs and establish a higher storm reserve fund through the sale of bonds that would be repaid by an FPSC-approved surcharge on customer bills. Tampa Electric elected to forego securitizing its 2004 hurricane costs following the approval of the stipulation discussed above. However, Tampa Electric continues to evaluate securitization and other options as possible means of funding for future storms.
Hardening of Transmission and Distribution Facilities
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, the FPSC initiated a proceeding to explore methods of designing and building transmission and distribution systems that would minimize long-term outages and restoration costs. Following a series of FPSC workshops to review 2004 and 2005 hurricane damage, restoration practices and activities, and plans for the 2006 hurricane season, the FPSC issued an order that required utilities to inspect wooden distribution poles every eight years and report the results of the inspections to the FPSC annually. For many years, Tampa Electric has routinely inspected its wooden poles and adjusted its inspection schedule to comply with the FPSC’s order.
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. In addition to a wood pole inspection program instituted separately, the plans address vegetation management, audits of pole attachments, transmission structure inspections and hardening, data gathering and analysis, natural disaster planning, coordination with local governmental agencies and collaborative research. In October 2006, the FPSC approved Tampa Electric’s plan to comply with the directive. Tampa Electric is implementing its plan and estimates that the average incremental non-fuel operations and maintenance expense of this plan to be approximately $15 million annually.
The FPSC also modified its rule regarding the design standards for new and replacement transmission and distribution line construction, including certain critical circuits in a utility’s system. Beyond employing accepted engineering practices and complying with the applicable edition of the National Electric Safety Code (NESC), the new design standard requires adoption of the NESC extreme wind loading standards for distribution facilities. The new design standards also encourage the placement of new or modified facilities underground when feasible. These new requirements are expected to increase the capital expenditures required to expand the system to meet growing customer demand and to maintain system reliability by approximately $20 million annually.
Florida’s Energy Plan
The Florida Department of Environmental Protection has produced an energy plan for the state that, among other initiatives, encourages fuel diversity for electric generation, streamlining of the power plant siting review process, conservation by state agencies and consumers, educational programs for residential and business customers regarding energy conservation, expansion of the use of hydrogen and additional grants to study alternative energy supplies.
Utility Competition - Electric
Tampa Electric’s retail electric business is substantially free from direct competition with other electric utilities, municipalities and public agencies. At the present time, the principal form of competition at the retail level consists of self-generation available to larger users of electric energy. Such users may seek to expand their alternatives through various initiatives,
including legislative and/or regulatory changes that would permit competition at the retail level. Tampa Electric intends to retain and expand its retail business by managing costs and providing high quality service to retail customers.
Presently there is competition in Florida’s wholesale power markets, increasing largely as a result of the Energy Policy Act of 1992 and related federal initiatives. However, the state’s Power Plant Siting Act, which sets the state’s electric energy and environmental policy and governs the building of new generation involving steam capacity of 75 megawatts or more, requires that applicants demonstrate that a plant is needed prior to receiving construction and operating permits.
In 2003, the FPSC modified rules from 1994 that required IOUs to issue RFPs prior to filing a petition for Determination of Need for construction of a power plant with a steam cycle greater than 75 megawatts. The modified 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. The new rules became effective prospectively for RFPs for applicable capacity additions.
Market Based Rate Authority
As previously disclosed, in 2005 the FERC determined that Tampa Electric had market power within its own service territory and within the area served by Reedy Creek (Walt Disney World). At that time, Tampa Electric agreed to limit itself to only conducting wholesale cost-based transactions in those two parts of Florida.
In 2006, through the filing of additional market analysis, Tampa Electric was successful in convincing the FERC that it did not have market power in the Reedy Creek area. As a result, Tampa Electric is once again able to transact with Reedy Creek at market-determined prices, which is expected to provide benefits for both entities.
PGS Rates
PGS’ current rates were agreed to in a settlement with all parties involved, and a final FPSC order was granted on Dec. 17, 2002 and rates were effective after Jan. 16, 2003. PGS’ authorized rates provide an allowed ROE range from 10.25% to 12.25% with an 11.25% midpoint, and a capital structure with 57.43% equity.
PGS Cost Recovery Clauses
PGS recovers the costs it pays for gas supply and interstate transportation for system supply through the purchased gas adjustment clause. This charge is designed to recover the costs incurred by PGS for purchased gas, and for holding and using interstate pipeline capacity for the transportation of gas it sells to its customers. These charges 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 2006, the FPSC approved rates under PGS’ PGA for the period January 2007 through December 2007 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 for system supply customers, 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, expenditures made in connection with these programs if it demonstrates that the programs are cost effective for its ratepayers.
Utility Competition - Gas
Although PGS is not in direct competition with any other regulated distributors of natural gas for customers within its service areas, there are other forms of competition. At the present time, the principal form of competition for residential and small commercial customers is from companies providing other sources of energy, including electricity.
In Florida, gas service is unbundled for all non-residential customers. In November 2000, PGS implemented its “NaturalChoice” program, offering unbundled transportation service to all eligible customers. This means that non-residential customers can purchase commodity gas from a third party but continue to pay PGS for the transportation of the gas. 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 12,600 transportation customers as of Dec. 31, 2006 out of approximately 29,400 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 services at discounted rates.
In general, PGS faces competition from other energy source suppliers offering fuel oil, electricity and, in some cases, propane. PGS has taken actions to retain and expand its commodity and transportation business, including managing costs and providing high quality service to customers.
CORPORATE GOVERNANCE
CEO and CFO Certifications
The most recent certifications by our Chief Executive Officer and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 are filed as exhibits to TECO Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2006. The certification of TECO Energy’s Chief Executive Officer regarding compliance with the New York Stock Exchange (NYSE) corporate governance listing standards required by NYSE will be filed with NYSE following the 2007 Annual Meeting of Shareholders. Last year, we filed this certification with the NYSE after the 2006 Annual Meeting of Shareholders, in compliance with NYSE rules.
Item 7a.
Item 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Risk Management Infrastructure
We are subject to various types of market risk in the course of daily operations, as discussed below. We have adopted an enterprise-wide approach to the management and control of market and credit risk. Middle Office risk management functions, including credit risk management and risk control, are independent of each transacting entity (Front Office).
Our Risk Management Policy (Policy) governs all energy transacting activity at the TECO Energy group of companies. The Policy is approved by our Board of Directors and administered by a Risk Authorizing Committee (RAC) that is comprised of senior management. Within the bounds of the Policy, the RAC approves specific hedging strategies, new transaction types or products, limits, and transacting authorities. Transaction activity is reported daily and measured against limits. For all commodity risk management activities, derivative transaction volumes are limited to the anticipated volume for customer sales or supplier procurement activities.
The RAC administers the risk management policy with respect to interest rate risk exposures. Under the policy for interest rate risk management, the RAC operates and oversees transaction activity. Interest rate derivative transaction activity is directly correlated to borrowing activities.
Risk Management Objectives
The Front Office is responsible for reducing and mitigating the market risk exposures which arise from the ownership of physical assets and contractual obligations, such as debt instruments and firm customer sales contracts. The primary objectives of the risk management organization, the Middle Office, are to quantify, measure, and monitor the market risk exposures arising from the activities of the Front Office and the ownership of physical assets. In addition, the Middle Office is responsible for enforcing the limits and procedures established under the approved risk management policies. Based on the policies approved by the company’s Board of Directors and the procedures established by the RAC, from time to time, members of the TECO Energy group of companies enter into futures, forwards, swaps and option contracts to limit the exposure to:
•
Price fluctuations for physical purchases and sales of natural gas in the course of normal operations at Tampa Electric and PGS;
•
Interest rate fluctuations on debt at TECO Energy and its affiliates;
•
Price fluctuations for physical purchases of fuel at TECO Transport and TECO Coal.
•
Price fluctuations for crude oil and the resulting reduction of synthetic fuel proceeds if crude oil prices exceed phase-out threshold levels.
The TECO Energy companies use derivatives only to reduce normal operating and market risks, not for speculative purposes. Our primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers. For unregulated operations, the companies use derivative instruments primarily to mitigate the price uncertainty related to commodity inputs, such as diesel fuel.
Derivatives and Hedge Accounting
FAS 133, Accounting for Derivative Instruments and Hedging Activities, as subsequently amended and interpreted requires us and our affiliates to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value, and to reflect the changes in the fair value of those instruments as components of other comprehensive income, depending on the designation of those instruments.
Designation of a hedging relationship requires management to make assumptions about the future probability of the timing and amount of the hedged transaction and the future effectiveness of the derivative instrument in offsetting the change in fair value or cash flows of the hedged item or transaction. The determination of fair value is dependent upon certain assumptions and judgments, as described more fully below (see the Unregulated Operating Companies section and Note 21 to the TECO Energy Consolidated Financial Statements).
Credit Risk
We have a rigorous process for the establishment of new trading counterparties. This process includes an evaluation of each counterparty’s financial statements, with particular attention paid to liquidity and capital resources; establishment of counterparty specific credit limits; optimization of credit terms; and execution of standardized enabling agreements. Our Credit Guidelines require transactions with counterparties below investment grade to be collateralized.
Contracts with different legal entities affiliated with the same counterparty are consolidated and managed as appropriate, considering the legal structure and any netting agreements in place. The Credit Guidelines are administered and monitored within the Middle Office, independent of the Front Office.
Credit exposures are calculated, compared to limits and reported to management on a daily basis. Contracts with different legal entities affiliated with the same counterparty are consolidated and managed as appropriate, considering the legal structure and any netting agreements in place.
Interest Rate Risk
We are exposed to changes in interest rates, primarily as a result of our borrowing activities. We may enter into futures, swaps and option contracts, in accordance with the approved risk management policies and procedures, to moderate this exposure to interest rate changes and achieve a desired level of fixed and variable rate debt. As of Dec. 31, 2006 and 2005, a hypothetical 10% increase in the consolidated group’s weighted average interest rate on its variable rate debt during the subsequent year, would not result in a material impact on pretax earnings. This is driven by the very low amounts of variable rate debt at either TECO Energy or Tampa Electric Company.
These amounts were determined based on the variable rate obligations existing on the indicated dates at TECO Energy and its subsidiaries. A hypothetical 10% decrease in interest rates would increase the fair market value of our long-term debt by approximately 3.2% and 2.8% at Dec. 31, 2006 and 2005, respectively (see the Financing Activity section and Notes 6 and 7 to the TECO Energy Consolidated Financial Statements). The above sensitivities assume no changes to our financial structure and could be affected by changes in our credit ratings, changes in general economic conditions or other external factors (see the Risk Factors section).
Commodity Risk
We and our affiliates face varying degrees of exposure to commodity risks including coal, natural gas, fuel oil, and other energy commodity prices. Any changes in prices could affect the prices these businesses charge, their operating costs and the competitive position of their products and services. We assess and monitor risk using a variety of measurement tools. Management uses different risk measurement and monitoring tools based on the degree of exposure of each operating company to commodity risks.
Regulated Utilities
Historically, Tampa Electric’s fuel costs used for generation have been affected primarily by the price of coal and, to a lesser degree, the cost of natural gas and fuel oil. With the repowering of the Bayside Power Station, the use of natural gas, with its more volatile pricing, has increased substantially. PGS has exposure related to the price of purchased gas and pipeline capacity.
Currently, Tampa Electric’s and PGS’ commodity price risk is largely mitigated by the fact that increases in the price of fuel and purchased power are recovered through cost recovery clauses, with no anticipated effect on earnings. However, increasing fuel cost recovery has the potential to affect total energy usage and the relative attractiveness of electricity and natural gas to consumers. To moderate the impacts of fuel price changes on customers, both PGS and Tampa Electric manage commodity price risk by entering into long-term fuel supply agreements, prudently operating plant facilities to optimize cost, and entering into derivative transactions designated as cash flow hedges of anticipated purchases of wholesale natural gas. At Dec. 31, 2006 and 2005, a change in commodity prices would not have a material impact on earnings for Tampa Electric or PGS, but could have an impact on the timing of the cash recovery of the cost of fuel (see the Tampa Electric and Regulation sections).
Unregulated Operating Companies
Most of the unregulated subsidiaries at TECO Energy are subject to significant commodity risk. These include TECO Coal, TECO Transport and TECO Guatemala. The unregulated companies do not speculate using derivative instruments. However, not all derivative instruments receive hedge accounting treatment due to the strict requirements and narrow applicability of the accounting rules to dynamic transactions.
TECO Coal is exposed to commodity price risk through coal sales as a part of its daily operations. Where possible and economical, TECO Coal enters into fixed price sales transactions to mitigate variability in coal prices. Based on the uncontracted tons subject to market price variation at Dec. 31, 2006 and 2005, a hypothetical 10% increase in the average annual market price of coal for each year would have resulted in an increase in pretax earnings of approximately $7.1 million and $3.5 million, respectively. TECO Coal is also exposed to variability in operating costs as a result of periodic purchases of diesel oil in its operations. At Dec. 31, 2006, TECO Coal had utilized derivative instruments to reduce the price variability for approximately 50% of its anticipated 2007 diesel oil purchases. These derivative instruments qualify for cash flow hedge accounting treatment, and as such, variations in the value of the hedges would offset the price variation in diesel oil, reducing any impact to earnings.
TECO Coal is also indirectly exposed to changes in the price of crude oil. Under the rules governing synthetic fuel tax credits, those credits can be phased out in the event that the price of crude oil reaches a certain threshold. The synthetic fuel tax credit is determined annually and is estimated to be $1.21 per million Btu for 2006, and was $1.17 per million Btu in 2005 and $1.13 per million Btu in 2004. This rate escalates with inflation but could be limited by domestic oil prices. If the oil price limitation is reached, the level of the tax credits starts to decline. In 2006, average annual domestic oil prices, as measured by the DOE index, would have had to exceed $55 per barrel for this limitation to have been effective, and it was estimated that the tax credit would have
been eliminated at an average oil price of $69 per barrel. The DOE index is based on the “Domestic First Purchase Price” not the NYMEX-quoted oil futures prices, which in 2006 averaged 90% of the NYMEX price per barrel. The synthetic fuel tax credit phase-out range for 2007 based on the DOE oil prices is expected to be $57 to $71 per barrel, which would be the equivalent of a NYMEX price of approximately $63 to $79 per barrel (see the Synthetic Fuel discussion in the Outlook section).
In January 2007, TECO Coal entered into oil price hedge instruments that protect against the risk of high oil prices reducing the value of the tax credits related to the production of synthetic fuel in 2007. When combined with the hedges entered into in October 2006, the additional instruments protect approximately $195 million of the gross cash benefits expected from the third-party investors for the production of synthetic fuel over the full expected average annual oil price range of $63 to $79 per barrel on a NYMEX basis. The oil price range between $63 and $79 per barrel is the expected phase-out range for synthetic fuel benefits for 2007. The hedges in place provide approximately a dollar-for-dollar recovery of lost synthetic fuel revenues in the event of a phase out over the estimated phase-out range. The total cost of the hedges was approximately $37 million (see the Synthetic Fuel discussion in the Outlook section).
Commodity price risk exists at TECO Transport as a result of periodic purchases of fuel oil. Haulage and freight agreements often include fuel price adjustments to transfer the risk of market fuel price movements to the customer. TECO Transport also utilizes derivative instruments to reduce the risk of price variability for anticipated fuel purchases in excess of purchases subject to fuel adjustment clauses. As of Dec. 31, 2006, nearly all of the potential fuel price variability for 2007 was removed via price adjustment clauses and derivative instruments. As a result, a hypothetical 10% increase in the price of fuel would not result in a material impact on pretax earnings as of Dec. 31, 2006.
Like Tampa Electric and PGS, TECO Guatemala has commodity price risk that is largely mitigated by the fact that increases in the price of fuel are passed through to the power purchasing distribution utility.
The following tables summarize the changes in and the fair value balances of energy derivative assets (liabilities) for the year ended Dec. 31, 2006:
Changes in Fair Value of Energy Derivatives (millions)
Roll-Forward of Energy Derivative Net Assets (Liabilities) (millions)
When available, the company uses quoted market prices to record the fair value of energy derivative contracts. However, many energy derivative contracts are not traded in sufficient volume or with sufficient market transparency to establish a representative quotation. In those cases, we use industry-accepted valuation techniques based on pricing models or matrix pricing for energy derivative contracts. Prices, inputs, assumptions and the results of valuation techniques are validated by the Middle Office, independently of the Front Office, on a daily basis. Significant inputs and assumptions used by the company to determine the fair value of energy derivative contracts are: 1) the physical delivery location of the commodity; 2) the correlation between different basis points and/or different commodities; 3) rational, economic behavior in the markets and by counterparties; 4) on- and off-peak curve shapes and correlations; 5) observed market information; and 6) volatility forecasts and estimates for and between commodities. Mathematical approaches are applied on a frequent basis to validate and corroborate the results of valuation calculations.
For all unrealized energy derivative contracts, the valuation is an estimate based on the best available information at the date of valuation. Actual cash flows upon maturity could be materially different from the estimated value.
The following is a summary table of sources of fair value, by maturity period, for energy derivative contracts at Dec. 31, 2006.
Maturity and Source of Energy Derivative Contracts Net Assets (Liabilities) at Dec. 31, 2006
(1) Model prices are used for determining the fair value of energy derivatives where price quotes are infrequent or the market is illiquid. Significant inputs to the models are derived from market observable data and actual historical experience.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DAT A.
TECO ENERGY, INC.
All other financial statement schedules have been omitted since they are not required, are inapplicable or the required information is presented in the financial statements or notes thereto.
TECO ENERGY, INC.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. We conducted an evaluation of the effectiveness of our internal control over financial reporting as of Dec. 31, 2006 based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under this framework, our management concluded that our internal control over financial reporting was effective as of Dec. 31, 2006.
PricewaterhouseCoopers LLP, an independent registered certified public accounting firm, has audited management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of Dec. 31, 2006 as stated in their report below.
Report of Independent Registered Certified Public Accounting Firm
To the Board of Directors and Shareholders of TECO Energy, Inc.:
We have completed integrated audits of TECO Energy, Inc.’s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits are presented below.
Consolidated financial statements and financial statement schedules
In our opinion, the consolidated financial statements listed in the index appearing under Item 8 present fairly, in all material respects, the financial position of TECO Energy, Inc. and its subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 8 present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 2 to the financial statements, the Company changed its method of accounting for stock-based compensation as of January 1, 2006 and its method of accounting for its defined benefit pension and other postretirement plans as of December 31, 2006.
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8, that the Company maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP
Tampa, Florida
February 27, 2007
TECO ENERGY, INC.
Consolidated Balance Sheets
The accompanying notes are an integral part of the consolidated financial statements.
TECO ENERGY, INC.
Consolidated Balance Sheets - continued
The accompanying notes are an integral part of the consolidated financial statements.
TECO ENERGY, INC.
Consolidated Statements of Income
The accompanying notes are an integral part of the consolidated condensed financial statements.
TECO ENERGY, INC.
Consolidated Statements of Comprehensive Income
The accompanying notes are an integral part of the consolidated financial statements.
TECO ENERGY, INC.
Consolidated Statements of Cash Flows
(1) Included in interest paid during the year is interest paid on debt obligation for discontinued operations of $12.0 million and $51.5 million for 2005 and 2004, respectively. No interest was paid in 2006 for debt related to discontinued operations.
The accompanying notes are an integral part of the consolidated financial statements.
TECO ENERGY, INC.
Consolidated Statements of Capital
(1) TECO Energy had a maximum of 400 million shares of $1 par value common stock authorized as of Dec. 31, 2006, 2005 and 2004.
The accompanying notes are an integral part of the consolidated financial statements.
TECO ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Significant Accounting Policies
The significant accounting policies for both utility and diversified operations are as follows:
Principles of Consolidation
The consolidated financial statements include the accounts of TECO Energy, Inc. and its majority-owned subsidiaries (TECO Energy or the company). All significant inter-company balances and inter-company transactions have been eliminated in consolidation. Generally, the equity method of accounting is used to account for investments in partnerships or other arrangements in which TECO Energy or its subsidiary companies do not have majority ownership or exercise control.
TECO Energy adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation No. 46 (FIN 46), Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51, as of Oct. 1, 2003 with no material impact. Effective Jan. 1, 2004, the company adopted FASB Interpretation No. 46R, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 (FIN 46R), which impacted the consolidation principles applied to certain entities. For entities that are determined to meet the definition of a variable interest entity (VIE), the company obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If the company is determined to be the primary beneficiary, then the VIE is consolidated and a minority interest is recognized for any other third-party interests. If the company is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In certain circumstances this can result in the company consolidating entities in which it has less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest. FIN 46R impacted the consolidation policy for the subsidiaries that hold interests in San José and Alborada Power Stations in Guatemala, the funding companies involved in the issuance of the trust preferred securities, TECO AGC, Ltd., and Hernando Oaks, LLC (see Note 19).
Use of Estimates
The use of estimates is inherent in the preparation of financial statements in accordance with generally accepted accounting principles (GAAP). Actual results could differ from these estimates.
Segment Reporting
In the first quarter of 2005, the company revised internal reporting information used for decision making purposes by viewing the results and performance of TECO Guatemala, Inc. (TECO Guatemala) (formerly TWG Non-Merchant, Inc.) as a separate segment comprised of all Guatemalan operations. TECO Guatemala includes the equity investments in the San José and Alborada Power Stations, the equity investment in the Guatemalan distribution company, Empresa Eléctrica de Guatemala, S.A. (EEGSA), and the TECO Guatemala parent company. Results for TECO Guatemala were previously reported in the Other Unregulated segment. Following the sales of the larger energy services businesses, which were previously reported in the Other Unregulated segment, the remaining small operations of TECO Solutions, Inc. (TECO Solutions) are now reported within Other & Eliminations. Prior period segment results have been restated to reflect the revised segment structure (see Note 14).
In 2006, only historical data is presented for TWG Merchant as all merchant assets have been divested. Any residual results for 2006 are included in “Other and eliminations”.
Cash Equivalents
Cash equivalents are highly liquid, high-quality investments purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments.
Restricted Cash
Restricted cash at Dec. 31, 2006 and 2005 includes $30.0 million and $30.3 million, respectively, of cash held in escrow related to the 2003 sale of TECO Coal Corporation’s (TECO Coal) indirectly owned synthetic fuel production facilities (to provide credit support for the company’s current credit rating). The $30.0 million of cash from the synthetic fuel facility sale will be retained in escrow to support the company’s obligation under the sale agreement, until the expiration of the agreement or TECO Energy achieves an investment-grade credit rating. Restricted cash at Dec. 31, 2006 and 2005 also includes $7.1 million and $7.3 million, respectively, of cash held in escrow related to the 2003 sale of Hardee Power Partners (HPP). The $7.1 million will be released from escrow in 2012, upon maturity of debt financing currently held by the purchaser of HPP. Restricted cash also included other unrelated amounts totaling approximately $0.2 million at Dec. 31, 2006.
Cost Capitalization
Debt issuance costs - The company capitalizes the external costs of obtaining debt financing and amortizes such costs over the life of the related debt. These costs are included in “Deferred Charges and Other Assets” on TECO Energy’s Consolidated Balance Sheet.
Capitalized interest expense - Interest costs for the construction of non-utility facilities are capitalized and depreciated over the service lives of the related property. TECO Energy capitalized $0.1 million and $0.7 million of interest costs in 2005 and 2004, respectively. No interest costs were capitalized in 2006.
Planned Major Maintenance
TECO Energy accounts for planned maintenance projects by expensing the costs as incurred. Planned major maintenance projects that do not increase the overall life or value of the related assets are expensed. When the major maintenance materially increases the life or value of the underlying asset, the cost is capitalized. While normal maintenance outages covering various components of the plants generally occur on at least a yearly basis, major overhauls occur less frequently.
Tampa Electric and Peoples Gas System (PGS) expense major maintenance costs as incurred. For Tampa Electric and PGS, concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with Florida Public Service Commission (FPSC) and Federal Energy Regulatory Commission (FERC) regulations.
The San José and Alborada plants in Guatemala each have a long-term power purchase agreement (PPA) with EEGSA. A major maintenance revenue recovery component is explicit in the capacity payment portion of the PPA for each plant. Accordingly, a portion of each monthly fixed capacity payment is deferred to recognize the portion that reflects recovery of future planned major maintenance expenses. Actual maintenance costs are expensed when incurred with a like amount of deferred recovery revenue recognized at the same time.
Depreciation
TECO Energy computes depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage value, of depreciable property over its estimated service life. Unregulated electric generating, pipeline and transmission facilities are depreciated over the expected useful lives of the related equipment, a period of up to 40 years. Total depreciation expense for the years ended Dec. 31, 2006, 2005, and 2004 was $270.3 million, $267.6 million and $257.6 million, respectively. Total plant acquisition adjustments were $10.0 million as of Dec. 31, 2005. There were no acquisition adjustments in 2006. The provision for total regulated and unregulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.9% for 2006, 4.0% for 2005 and 3.9% for 2004.
The implementation of FAS No. 143, Accounting for Asset Retirement Obligations (FAS 143) in 2003 and FASB Interpretation No.47, Accounting for Conditional Asset Retirement Obligations, an Interpretation of FASB Statement No. 143 (FIN 47) in 2005 resulted in increases in the carrying amount of long-lived assets and the liabilities associated with those assets. In addition, the accumulated reserve for cost of removal was reclassified to “Regulatory liabilities”. The adjusted capitalized amount is depreciated over the remaining useful life of the asset. (See Note 15).
Allowance for Funds Used During Construction (AFUDC)
AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. The rate was 7.79% for 2006 and 2004. No projects qualified for AFUDC in 2005 while total AFUDC for 2006 and 2004 was $3.8 million and $1.0 million, respectively. The base on which AFUDC is calculated excludes construction work-in-progress which has been included in rate base.
Investments in Unconsolidated Affiliates
Investments in unconsolidated affiliates are accounted for using the equity method of accounting. The percentage ownership interests for each investment at Dec. 31, 2006 and 2005 are presented in the following table:
TECO Energy’s Percent Ownership in Unconsolidated Affiliates (5)
(1) TECO Energy can no longer consolidate CGESJ or TCAE (the project companies for the San José and Alborada power plants, respectively, in Guatemala), as a result of the application FIN 46R, Consolidation of Variable Interest Entities as it relates to long-term power purchase agreements with affiliated entities. See Notes 14 and 19 for additional details.
(2) In 2004, the assets of Litestream Technologies, LLC were sold in bankruptcy. The company still indirectly owned a 36% interest in Litestream Technologies, LLC as of Dec. 31, 2006 and 2005.
(3) As of Jan. 1, 2004, in accordance with the interpretation and application of the consolidation guidance established in FIN 46R, TECO Energy did not consolidate Capital Funding I or II. See Notes 7 and 19 for additional details.
(4) On Dec. 20, 2005, all outstanding subordinated notes held by TECO Funding Company I, LLC were redeemed and the LLC was subsequently dissolved. On Jan. 16, 2007, all outstanding subordinated notes held by TECO Funding Company II, LLC matured.
(5) TECO Energy, Inc. received $55.5 million, $24.5 million and $1.8 million during the years ended Dec. 31, 2006, 2005 and 2004, respectively, as dividends from unconsolidated affiliates.
Regulatory Assets and Liabilities
Tampa Electric and PGS are subject to the provisions of Financial Accounting Standard (FAS) No. 71, Accounting for the Effects of Certain Types of Regulation (FAS 71) (see Note 3 for additional details).
Deferred Income Taxes
TECO Energy uses the liability method to determine deferred income taxes. Under the liability method, the company estimates its current tax exposure and assesses the temporary differences resulting from differences in the treatment of items, such as depreciation, for financial statement and tax purposes. These differences are reported as deferred taxes, measured at current rates, in the consolidated financial statements. Management reviews all reasonably available current and historical information, including forward-looking information, to determine if it is more likely than not that some or all of the deferred tax asset will not be realized. If management determines that it is likely that some or all of a deferred tax asset will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized.
Investment Tax Credits
Investment tax credits have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.
Revenue Recognition
TECO Energy recognizes revenues consistent with the Securities and Exchange Commission’s (SEC’s) Staff Accounting Bulletin (SAB) 104, Revenue Recognition in Financial Statements. The interpretive criteria outlined in SEC’s SAB 104 are that 1) there is persuasive evidence that an arrangement exists; 2) delivery has occurred or services have been rendered; 3) the fee is fixed and determinable; and 4) collectibility is reasonably assured. Except as discussed below, TECO Energy and its subsidiaries recognize revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer. Revenues for any financial or hedge transactions that do not result in physical delivery are reported on a net basis.
The regulated utilities’ (Tampa Electric and PGS) retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by FERC. See Note 3 for a discussion of significant regulatory matters and the applicability of FAS 71 to the company.
Revenues for certain transportation services at TECO Transport are recognized using the percentage of completion method, which includes estimates of the distance traveled and/or the time elapsed, compared to the total estimated contract.
Revenues for energy marketing operations at TECO Gas Services are presented on a net basis in accordance with Emerging Issues Task Force No. (EITF) 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, and EITF
02-3, Recognition and Reporting of Gains and Losses on Energy Trading Contracts Under Issues No. 98-10 and 00-17, to reflect the nature of the contractual relationships with customers and suppliers. As a result, costs netted against revenues for the years ended Dec. 31, 2006, 2005 and 2004 were $0.8 million, $3.8 million and $3.9 million, respectively.
Other Income and Minority Interest
TECO Energy earns a significant portion of its income indirectly through the synthetic fuel operations at TECO Coal. At the end of 2006, 2005 and 2004, TECO Coal had sold ownership interests in the synthetic fuel facilities to unrelated third-party investors equal to 98%, 98% and 90%, respectively. These investors pay for the purchase of the ownership interests as synthetic fuel is produced. The payments are based on the amount of production and sales of synthetic fuel and the related, underlying value of the tax credit, which is subject to potential limitation based on the price of domestic crude oil. These payments are recorded in “Other income” in the Consolidated Statements of Income.
Additionally, the outside investors make payments towards the cost of producing synthetic fuel. These payments are reflected as a benefit under “Minority interest” in TECO Energy’s Consolidated Statements of Income and these benefits comprise the majority of that line item.
For the year ended Dec. 31, 2006, “Other income” reflected a phase-out of approximately 35% of the benefit of the underlying value of any 2006 tax credits based on an estimate of the average annual price of domestic crude oil during 2006. Should the Dec. 31, 2006 estimate of the average annual price of domestic crude oil be different than this estimate, the cash payments and the benefits recognized in “Other income” and “Minority interest” will be adjusted, either positively or negatively, in the first quarter of 2007. No phase-out of the benefit was recognized in 2005. (See the “Critical Accounting Policies and Estimates” section of Item 7, MD&A for a sensitivity evaluation regarding this estimate.)
Revenues and Fuel Costs
Revenues include amounts resulting from cost recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline capacity and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over-recovery or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as deferred credits, and under-recoveries of costs are recorded as deferred charges.
Certain other costs incurred by the regulated utilities are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide a closer matching of revenues and expenses (see Note 3).
As of Dec. 31, 2006 and 2005, unbilled revenues of $47.8 million and $52.3 million, respectively, are included in the “Receivables” line item on TECO Energy’s Consolidated Balance Sheets.
Purchased Power
Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. As a result of the sale of Hardee Power Partners, Ltd. (HPP) in October 2003, power purchases from HPP, subsequent to the sale, are reflected as non-affiliate purchases by Tampa Electric. Tampa Electric’s long-term power purchase agreement from HPP was not affected by the sale of HPP. Under the existing power purchase agreement, which has been approved by the FERC and the FPSC, Tampa Electric has full entitlement to the output of the CT2B unit at all times and full entitlement to the output of the remaining units at the Hardee power station at all times except when Seminole Electric Cooperative has entitlement due to outages and/or durations on a specified portion of its generating units. Tampa Electric purchased power from non-TECO Energy affiliates, including purchases from HPP, at a cost of $221.3 million, $269.7 million and $172.3 million, for the years ended Dec. 31, 2006, 2005 and 2004, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost recovery clause.
Accounting for Excise Taxes, Franchise Fees and Gross Receipts
TECO Coal and TECO Transport incur most of TECO Energy’s total excise taxes, which are accrued as an expense and reconciled to the actual cash payment of excise taxes. As general expenses, they are not specifically recovered through revenues. Excise taxes paid by the regulated utilities are not material and are expensed when incurred.
The regulated utilities are allowed to recover certain costs incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Statements of Income. These amounts totaled $104.2 million, $87.2 million and $83.8 million for the years ended Dec. 31, 2006, 2005 and 2004, respectively. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. For the years ended Dec. 31, 2006, 2005 and 2004, these totaled $104.0 million, $87.0 million and $83.6 million, respectively.
Asset Impairments
TECO Energy and its subsidiaries apply the provisions of Statement of Financial Accounting Standards (FAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. FAS 144 addresses accounting and reporting for the impairment or disposal of long-lived assets, including the disposal of a component of a business.
In accordance with FAS 144, the company assesses whether there has been an impairment of its long-lived assets and certain intangibles held and used by the company when such impairment indicators exist. Indicators of impairment existed for certain asset groups, triggering a requirement to ascertain the recoverability of these assets using undiscounted cash flows. See Note 18 for specific details regarding the results of these assessments.
Deferred Charges and Other Assets
Deferred charges and other assets consist primarily of mining development costs amortized on a per ton basis and offering costs associated with various debt offerings that are being amortized over the related obligation period as an increase in interest expense.
Deferred Credits and Other Liabilities
Other deferred credits primarily include the accrued post-retirement benefit liability, the pension liability, incurred but not reported medical and general liability claims, and deferred gains on sale-lease back transactions involving marine assets. The company and its subsidiaries’ have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. The company estimates its liabilities for auto, general, marine protection & indemnity, and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these liabilities at Dec. 31, 2006 and 2005 ranged from 4.00% to 4.75%.
Stock-based Compensation
Effective Jan. 1, 2006, TECO Energy accounts for its stock-based compensation in accordance with FAS No. 123 (revised 2004), Share-Based Payment (FAS 123R). Under the provisions of FAS 123R, share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s or director’s requisite service period (generally the vesting period of the equity grant). Prior to this, the company accounted for its share-based payments under Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees and its related interpretations and the disclosure requirements of FAS 123, Accounting for Stock-Based Compensation, as amended by FAS 148, Accounting for Stock-Based Compensation - Transition and Disclosure. The company elected to adopt the modified-prospective transition method as provided under FAS 123R and, accordingly, results for prior periods have not been restated. See Note 9, Common Stock, for more information on share-based payments.
Restrictions on Dividend Payments and Transfer of Assets
Dividends on TECO Energy’s common stock are declared and paid at the discretion of its Board of Directors. The primary sources of funds to pay dividends on TECO Energy’s common stock are dividends and other distributions from its operating companies. TECO Energy’s 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. In March 2004, Tampa Electric repaid $75 million of 7.75% first mortgage bonds issued under an indenture that included a limitation on dividends covenant. This covenant is no longer operative since there are no bonds outstanding under the indenture. 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 Transport and 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 Notes 6, 7 and 12 for additional information on significant financial covenants.
Foreign Operations
The functional currency of the company’s foreign investments is primarily the U.S. dollar. Transactions in the local currency are re-measured to the U.S. dollar for financial reporting purposes. The aggregate re-measurement gains or losses included in net income in 2006, 2005 and 2004 were not material. The foreign investments are generally protected from any significant currency gains or losses by the terms of the power sales agreements and other related contracts, in which payments are defined in U.S. dollars.
Reclassifications
Certain prior year amounts were reclassified to conform to the current year presentation. Results for all prior periods have been reclassified from continuing operations to discontinued operations as appropriate for each of the entities as discussed in Note 20.
2. New Accounting Pronouncements
Asset Retirement Obligations
FIN 47 was issued in March 2005 and became effective as of Dec. 31, 2005. FIN 47 clarifies the term “conditional asset retirement obligation” as a legal obligation to perform an asset retirement activity in which the timing and method of settlement are conditional on a future event that may or may not be within the control of the entity, and clarifies when an entity has sufficient information to reasonably estimate the fair value of an asset retirement obligation. The company implemented FIN 47 during the fourth quarter of 2005. See Note 15 for discussion of the effects of this implementation.
Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans
In September 2006, the FASB issued FAS No.158, Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R). This statement of financial accounting standards requires the recognition in the statement of financial position of the over-funded or under-funded status of a defined benefit postretirement plan, measured as the difference between the fair value of plan assets and the projected benefit obligation in the case of a defined benefit plan, or the accumulated postretirement benefit obligation in the case of other postretirement benefit plans. Compared to the current recognition of pension and other postretirement obligations on the balance sheet, this standard requires the recognition of: 1) the impact of future salary increases to the pension obligation and 2) the unamortized post-retirement benefit costs that are currently being expensed over the service lives of the participants. This standard also requires recognition in other comprehensive income certain benefit cost components that are not part of net periodic benefit cost, and that the defined benefit plan assets and obligations be measured as of the balance sheet date. For the regulated segments, amounts required to be recorded in “Other comprehensive income” are reflected as a regulatory asset, as pension obligations will be recovered through rates. FAS 158 is effective for publicly-held companies for fiscal years ending after Dec. 15, 2006. The company has adopted the balance sheet recognition provisions of FAS 158 at Dec. 31, 2006 and will adopt the year-end measurement date in 2008. This standard has increased benefit liabilities on the balance sheet by approximately $125.8 million and accumulated other comprehensive loss, net of estimated tax benefits, by approximately $21.8 million. This standard does not affect the company’s results of operations or cash flows.
Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in the Current Year Financial Statements
In September 2006, the Securities and Exchange Commission staff issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in the Current Year Financial Statements (SAB 108). SAB 108 addresses the diversity in practice by registrants when quantifying the effect of an error on the financial statements and provides guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements. The company has adopted the provisions of SAB No. 108 effective Dec. 31, 2006. The adoption of SAB 108 did not have an impact on the company’s consolidated financial statements.
Fair Value Measurements
In September 2006, the FASB issued FAS No. 157, Fair Value Measurements (FAS 157). FAS 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about fair value measurements. FAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and states that a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability. FAS 157 applies under other accounting pronouncements that require or permit fair value measurements. The effective date is for fiscal years beginning after Nov. 15, 2007. The company is currently assessing the implementation of FAS 157, however, does not believe it will be material to its results of operations, statement of position or cash flows.
Planned Major Maintenance
In September 2006, the FASB issued FASB Staff Position (FSP) AUG AIR-1 Accounting for Planned Major Maintenance Activities. This FSP effectively removes the accrual-in-advance method of accounting for future planned major maintenance activities. The FASB believes that the accrual-in-advance method results in the recognition of liabilities prior to the occurrence of a transaction or event that obligates the entity and that does not meet the definition of a liability in accordance with FASB Concept No. 6, Elements of Financial Statements. Entities are still permitted to use the built-in overhaul, deferral or direct expensing methods. This FSP is effective for the first fiscal year beginning after Dec. 15, 2006 and the company has adopted this FSP effective Jan. 1, 2007. Because the company has been applying the direct expensing method, the company does not believe adoption of this FSP will have an effect on its results of operations, statement of position or cash flows.
Determining the Variability of Variable Interest Entities
In April 2006, the FASB issued FSP FIN 46(R)-6, Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R). In this FSP, the FASB addresses how a reporting enterprise should determine the variability to be
considered in applying FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities. The FASB describes a number of risks that should be considered as well as the purpose for which the entities were created, in order to determine the variability of these entities. The company has reviewed this FSP and has incorporated it into its process for determining the variability for current and future entities. This FSP is not expected to materially impact the company’s results of operations, statement of position or cash flows.
Amendment to Derivatives Accounting
In February 2006, the FASB issued FAS No. 155, Accounting for Certain Hybrid Financial Instruments (FAS 155), which amends FAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and FAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. FAS 155 simplifies the accounting for certain derivatives embedded in other financial instruments by permitting fair value re-measurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation. This statement is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after Sep. 15, 2006. The company adopted FAS 155 effective Jan. 1, 2007, and it does not materially impact the company’s results of operations, statement of position or cash flows.
Accounting for Uncertainty in Income Taxes
In June 2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109 (FIN 48). FIN 48 prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. Application involves a two-step approach where recognition occurs if the position exceeds a “more likely than not” threshold and the measurement is based on the tax benefit being greater than 50 percent likely of being realized upon settlement with the tax agencies involved. FIN 48 is effective for fiscal years beginning after Dec. 15, 2006. Based on the company’s assessment to date of the tax positions as of Jan. 1, 2007, the company believes that the implementation of FIN 48 during the first quarter of 2007 will have an immaterial impact on retained earnings.
3. Regulatory
As discussed in Note 1, Tampa Electric’s and PGS’s retail businesses are regulated by the FPSC. Tampa Electric is subject to regulation by the Federal Energy Regulatory Commission (“FERC”) under the Public Utility Holding Company Act of 2005 (“PUHCA 2005”), which replaced the Public Utility Holding Company Act of 1935 which was repealed, however, pursuant to a waiver granted in accordance with FERC’s regulations, TECO Energy is not subject to certain of the accounting, record-keeping, and reporting requirements prescribed by FERC’s regulations under PUHCA 2005.
Base Rate - Tampa Electric
Tampa Electric’s rates and allowed return on equity (ROE) range of 10.75% to 12.75% with a midpoint of 11.75% and are in effect until such time as changes are occasioned by an agreement approved by the FPSC or other FPSC actions resulting from rate or other proceedings initiated by Tampa Electric, FPSC staff or other interested parties.
Tampa Electric has not sought a base rate increase to recover significant plant investment since 1992, including the Bayside Power Station, which entered service in 2003 and 2004.
Cost Recovery - Tampa Electric
In September 2006, Tampa Electric filed with the FPSC for approval of fuel and purchased power, capacity, environmental and conservation cost recovery rates for the period January 2007 through December 2007. In November 2006, the FPSC approved Tampa Electric’s requested changes. The rates include the costs of natural gas and coal prices expected in 2007, the collection of underestimated fuel and purchased power expenses in 2006, the collection of previously unrecovered 2005 fuel and purchased power expenses, the proceeds from the sale of sulfur dioxide (SO2) emissions allowances and the operating costs for and a return on the capital invested in the first SCR project to enter service on Big Bend Unit 4 as well as the O&M costs associated with the pre-SCR projects for Big Bend Units 1 - 3 as required by the Environmental Protection Agency (EPA) Consent Decree and Florida Department of Environmental Protection (FDEP) Consent Final Judgment (see Note 12 for additional details regarding projected environmental expenditures). In addition, the rates reflect the FPSC’s September 2004 decision to reduce the annual cost recovery amount for water transportation services for coal and petroleum coke provided under Tampa Electric’s contract with TECO Transport described below. As part of the regulatory process, it is reasonably likely that third parties may intervene on similar matters in the future. The company is unable to predict the timing, nature or impact of such future actions.
Base Rate - PGS
As a result of a base rate proceeding, effective Jan. 16, 2003, PGS’ allowable ROE range is 10.25% to 12.25% with an 11.25% midpoint. PGS expects to continue earning within its allowed ROE range for the foreseeable future.
Cost Recovery - PGS
In September 2006, PGS filed its annual request with the FPSC to change its Purchased Gas Adjustment (PGA) cap factor for 2007. The PGA rate can vary monthly due to changes in actual fuel costs but is not expected to exceed the FPSC approved annual cap. In November 2006, the FPSC approved the cap factor under PGS’ PGA for the period January 2007 through December 2007.
SO2 Emission Allowances
The Clean Air Act Amendments of 1990 established SO2 allowances to manage the achievement of SO2 emissions requirements. The legislation also established a market-based SO2 allowance trading component.
An allowance authorizes a utility to emit one ton of SO2 during a given year. The EPA allocates allowances to utilities based on mandated emissions reductions. At the end of each year, a utility must hold an amount of allowances at least equal to its annual emissions. Allowances are fully marketable and, once allocated, may be bought, sold, traded or banked for use currently or in future years. In addition, the EPA withholds a small percentage of the annual SO2 allowances it allocates to utilities for auction sales. Any resulting auction proceeds are then forwarded to the respective utilities. Allowances may not be used for compliance prior to the calendar year for which they are allocated. Tampa Electric accounts for these using an inventory model with a zero basis for those allowances allocated to the company. Tampa Electric recognizes a gain at the time of sale, approximately 95% of which accrues to retail customers through the environmental cost recovery clause.
Over the years, Tampa Electric has acquired allowances through EPA allocations. Also, over time, Tampa Electric has sold unneeded allowances based on compliance and allowances available. The SO2 allowances unneeded and sold in 2006 resulted from lower emissions at Tampa Electric brought about by environmental actions taken by the company under the Clean Air Act.
For the year ended Dec. 31, 2006, Tampa Electric sold approximately 44,500 allowances, resulting in proceeds of $45.0 million, the majority of which is included as a cost recovery clause regulatory liability. In the years ended Dec. 31, 2005 and 2004, approximately 100,000 and 13,000 allowances were sold for $79.7 million and $7.4 million in proceeds, respectively.
Other Items
Storm Damage Cost Recovery
Following Hurricane Andrew in 1992, Florida’s investor owned utilities (IOUs) were unable to obtain transmission and distribution insurance coverage in the event of hurricanes, tornados or other damage due to destructive acts of nature. Tampa Electric and other IOUs were permitted to implement a self-insurance program effective Jan. 1, 1994 for such costs of restoration, and the FPSC authorized Tampa Electric to accrue $4 million annually to grow its unfunded storm damage reserve.
The costs for restoration associated with hurricanes Charley, Frances and Jeanne in 2004 were approximately $75 million, which exceeded the storm damage reserve by $30 million. These excess costs over the reserve amounts were charged against the reserve and were reflected as a regulatory asset. The storm costs did not reduce earnings but did reduce cash flow from operations.
In June 2005, the FPSC approved a stipulation entered into by Tampa Electric, the OPC and the Florida Industrial Power Users group regarding the treatment of Tampa Electric’s 2004 hurricane costs. Under the stipulation, Tampa Electric agreed to reclassify approximately $39 million of the hurricane restoration costs as plant in service (rate base). With this adjustment and the normal $4 million annual storm accrual, Tampa Electric’s storm reserve is $16 million as of Dec. 31, 2006.
Coal Transportation Contract
In September 2004, the FPSC voted to disallow approximately $14 to $16 million (pretax) of the costs that Tampa Electric can recover from its customers for water transportation services. The decision allows, but does not require, Tampa Electric to rebid the water transportation and terminal service contract. In October 2004, Tampa Electric filed with the FPSC a motion for clarification and reconsideration of the disallowance of recovery of costs under its waterborne transportation contract with TECO Transport. On Mar. 1, 2005, the FPSC heard oral arguments on the motion and denied Tampa Electric’s request for reconsideration and clarification. The impact of the FPSC vote was fully recognized by Tampa Electric in 2004.
Regulatory Assets and Liabilities
Tampa Electric and PGS maintain their accounts in accordance with recognized policies of the FPSC. In addition, Tampa Electric maintains its accounts in accordance with recognized policies prescribed or permitted by the FERC. These policies conform with GAAP in all material respects.
Tampa Electric and PGS apply the accounting treatment permitted by FAS 71. Areas of applicability include deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel; purchased power, conservation and environmental costs; and deferral of costs as regulatory assets, when cost recovery is ordered over a period longer than a fiscal year, to the period that the regulatory agency recognizes them. Details of the regulatory assets and liabilities as of Dec. 31, 2006 and 2005 are presented in the following table:
Regulatory Assets and Liabilities
(1) Related to plant life and derivative positions.
(2) Amortized over the term of the related debt instrument.
(3) Amortized over a 5-year period with various ending dates.
(4) Related to the adoption of FAS 158. See Note 5.
All regulatory assets are being recovered through the regulatory process. The following table further details our regulatory assets and the related recovery periods:
Regulatory assets
(1) To be recovered through cost recovery clauses approved by the FPSC on a dollar for dollar basis in the next year.
(2) Primarily reflects allowed working capital, which is included in rate base and earns an 8.2 % rate of return as permitted by the FPSC.
(3) “Regulatory tax assets” and “Capital structure and other” regulatory assets have a recoverable period longer than a fiscal year and are recognized over the period authorized by the regulatory agency. Also included are unamortized loan costs which are amortized over the life of the related debt instruments. See footnotes 1 and 2 in the prior table for additional information.
4. Income Tax Expense
Income tax expense consists of the following components:
Income Tax Expense (Benefit)
As discussed in Note 1, TECO Energy uses the liability method to determine deferred income taxes. Based primarily on the reversal of deferred income tax liabilities and future earnings of the company’s core utility operations, management has determined that the net deferred tax assets recorded at Dec. 31, 2006 will be realized in future periods.
The principal components of the company’s deferred tax assets and liabilities recognized in the balance sheet are as follows:
Deferred Income Tax Assets and Liabilities
(1) Certain property related assets and liabilities have been netted.
Included in the “Property related” component of the deferred tax asset is the impact of the asset impairments discussed in Notes 18 and 20.
At Dec. 31, 2006, the company has cumulative unused federal and state (Florida) net operating losses of approximately $1,999.0 million and $1,158.6 million, respectively, expiring in 2025 and 2026 respectively. In addition, the company has available alternative minimum tax credit carryforwards for tax purposes of approximately $198 million which may be used indefinitely to reduce federal income taxes.
Effective Income Tax Rate
For the three years presented, we experienced a number of events that have impacted the overall effective tax rate on continuing operations. These events included permanent reinvestment of foreign income under APB Opinion No. 23, Accounting
for Taxes - Special Areas (APB 23), adjustment of deferred tax assets for the effect of an enacted change in state rates, depletion, repatriation of foreign source income to the United States, and reduction of income tax expense under the new “tonnage tax” regime.
At Dec. 31, 2006, the portion of cumulative undistributed earnings from our investments in EEGSA was approximately $72.1 million. With the exception of the earnings repatriated in 2005, these earnings have been and are intended to be indefinitely invested in foreign operations. Therefore, no provision has been made for U.S. taxes or foreign withholding taxes that may be applicable upon actual or deemed repatriation.
On Oct. 22, 2004, the President of the United States signed the American Jobs Creation Act of 2004 (the Act). The Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85% dividend received deduction for certain dividends from controlled foreign corporations. The company elected to apply Code Section 965 with respect to its 2005 dividends. For the twelve months ended Dec. 31, 2005, the company repatriated $38.9 million, resulting in $1.0 million of additional tax expense net of foreign tax credits. The tax savings related to the repatriation provision of the Act are reflected in the “Other” category in the effective income tax rate.
Code Section 248 of the Act also introduced a new “tonnage tax” which allows corporations to elect to exclude from gross income certain income from activities connected with the operation of a U.S. flag vessel in U.S. foreign trade and become subject to a tax imposed on the per-ton weight of the qualified vessel instead. The company elected to apply Code Section 248 for qualified vessels in 2006 and 2005.
The consolidated entity recorded a net state benefit in 2006, 2005 and 2004 to reflect state deferred balances at the expected realizable rate which is lower than in prior years and to record estimated state benefits from impairments. The total effective income tax rate differs from the federal statutory rate due to state income tax, net of federal income tax, the non-conventional fuels tax credit, and other miscellaneous items. The actual cash paid for income taxes as required for the alternative minimum tax, state income taxes, and prior year audit in 2006, 2005 and 2004 was $10.4 million, $27.4 million and $22.4 million, respectively.
5. Employee Postretirement Benefits
Pension Benefits
TECO Energy has a non-contributory defined benefit retirement plan that covers substantially all employees. Benefits are based on employees’ age, years of service and final average earnings.
Amounts disclosed for pension benefits also include the unfunded obligations for the supplemental executive retirement plan. This is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management.
TECO Energy reported other comprehensive income of $42.7 million in 2006 for adjustments to the minimum pension liability. The adjustments to other comprehensive income related to the minimum pension liability in 2006 are net of $35.1 million of after-tax charges that, for regulatory purposes proscribed by FAS 71, were recorded as regulatory assets for Tampa Electric and PGS. TECO Energy had recorded other comprehensive losses of $7.2 million in 2005 and other comprehensive income of $7.2 million in 2004 related to adjustments to the minimum pension liability associated with the pension plans; there were no impacts of FAS 71 in 2005 or 2004 related to the additional minimum pension liability adjustments (see Note 10).
Other Postretirement Benefits
TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 meeting certain service requirements. The company contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and Jun. 30, 2001 is limited to a defined dollar benefit based on service. The company contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after Jul. 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2007, the company expects to make a contribution of about $12.8 million to this program. Postretirement benefit levels are substantially unrelated to salary. The company reserves the right to terminate or modify the plans in whole or in part at any time.
On Dec. 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the MMA) was signed into law. Beginning in 2006, the new law added prescription drug coverage to Medicare, with a 28% tax-free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. TECO Energy’s current retiree medical program for those eligible for Medicare (generally over age 65) includes coverage for prescription drugs. The company has determined that prescription drug benefits available to certain Medicare-eligible participants under its defined-dollar-benefit postretirement health care plan are at least “actuarially equivalent” to the standard drug benefits that are offered under Medicare Part D.
On May 19, 2004, the FASB issued FSP 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (FSP 106-2). The guidance in FSP 106-2 requires (a) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and (b) certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits. TECO Energy adopted FSP 106-2 retroactive for the second quarter of 2004.
In 2006, the company received its first subsidy payment under Part D and has filed and is awaiting approval for its 2007 Part D subsidy application with the Centers for Medicare and Medicaid Services (CMS).
(1) The measurement date was Sept. 30, 2006 and 2005.
Amounts recognized in accumulated other comprehensive income consist of:
The accumulated benefit obligation for all defined benefit pension plans was $508.3 million and $509.7 million at Sep. 30, 2006 and 2005, respectively.
Information for pension plans with an accumulated benefit obligation in excess of plan assets
Components of Net Periodic Benefit Cost and Other Amounts Recognized in Other Comprehensive Income
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
(1) These balances exclude the pretax amounts recognized as Regulated Assets by Tampa Electric and Peoples Gas System as detailed as follows on a pretax basis:
The estimated net loss and prior service net cost for the defined benefit pension plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are $2.3 million and $0.1 million, respectively. The estimated prior service cost and transition obligation for the other postretirement benefit plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year is $1.3 million and $0.6 million, respectively.
In addition, the estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year totals &6.1 million. The estimated prior service cost and transition obligation for the other postretirement benefit plan that will be amortized from regulatory asset into net periodic benefit cost over the next fiscal year totals $3.8 million.
Additional Information
The following table presents the incremental effect of adopting SFAS 158 on individual line items on the Consolidated balance sheets as of Dec. 31, 2006:
Weighted-average assumptions used to determine benefit obligations at Sep. 30, the measurement date for the pension and other postretirement benefit plans
Weighted-average assumptions used to determine net periodic benefit cost for years ended Dec. 31,
The expected return on assets assumption was based on expectations of long-term inflation, real growth in the economy, fixed income spreads and equity premiums consistent with our portfolio, with provision for active management and expenses paid. The salary increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases. The discount rate assumption was based on a cash flow matching technique developed by our outside actuaries and a review of current economic conditions. This technique matches the yields from high-quality (Aa-graded, non-callable) corporate bonds to the company’s projected cash flows for the pension plan to develop a present value that is converted to a discount rate.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
Asset Allocation
Pension plan assets (plan assets) are invested in a mix of equity and fixed income securities. The company’s investment objective is to obtain above-average returns while minimizing volatility of expected returns over the long term. The target equities/fixed income mix is designed to meet investment objectives. The company’s strategy is to hire proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses.
Other Postretirement Benefit Plan Assets
There are no assets associated with TECO Energy’s postretirement benefit plan.
Contributions
On Aug. 17, 2006, the President signed the Pension Protection Act of 2006 (the Act). While the company expects the Internal Revenue Service to issue regulations clarifying various terms of the Act, it generally introduces new minimum funding requirements beginning Jan. 1, 2008. The company’s policy is to fund the plan at or above amounts determined by the company’s actuaries to meet ERISA guidelines for minimum annual contributions and minimize PBGC premiums paid by the plan. The company contributed $36.3 million to the plan in 2006, which included a $30 million contribution in addition to the $6.3 million minimum contribution required. TECO Energy expects to make a $30 million contribution in 2007 and average annual contributions of $22 million in 2008 - 2011.
The supplemental executive retirement plan is funded annually to meet the benefit obligations. In 2006, the company made a contribution of $1.6 million to this plan. In 2007, the company expects to make a contribution of about $1.4 million to this plan.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
Defined Contribution Plan
The company has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries (the Employers) that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. The company and its subsidiaries match up to 6% of the participant's payroll savings deductions. From Jan. 1, 2004 to Jun. 30, 2004, the company's matching contribution was 55% of eligible participant payroll savings deductions made in the form of the company's common stock. Effective Jul. 1, 2004, employer matching contributions were 30% of eligible participant contributions with additional incentive match of up to 70% of eligible participant contributions based on the achievement of certain operating company financial goals. For the years ended Dec. 31, 2006, 2005 and 2004, the company and its subsidiaries recognized expense totaling $9.0 million, $10.2 million and $6.6 million, respectively, related to the matching contributions made to this plan.
6. Short-Term Debt
At Dec. 31, 2006 and 2005, the following credit facilities and related borrowings existed:
(1) Borrowings outstanding are reported as notes payable.
These credit facilities require commitment fees ranging from 12.5 to 37.5 basis points. The weighted average interest rate on outstanding notes payable at Dec. 31, 2006 and 2005 was 5.45% and 4.45%, respectively.
TECO Energy Credit Facility
On Oct. 11, 2005, TECO Energy amended its $200 million bank credit facility, extending the maturity to Oct. 11, 2010 with optional extensions of up to two additional years with lenders’ consent. The amended facility also allows TECO Energy to increase the facility size by up to $50 million with lenders’ consent. The facility is secured by the stock of TECO Transport, which security will be released if TECO Energy achieves investment-grade ratings and stable outlooks from both Moody’s and Standard & Poor’s. This facility includes a $100 million sub-limit for letters of credit. The facility requires that at the end of each quarter the ratio of debt to earnings before interest, taxes, depreciation and amortization (EBITDA), as defined in the agreement, not exceed 5.25 times through Mar. 31, 2007, 5.00 times from Apr. 1, 2007 through Dec. 31, 2009 and 4.50 times from and after Jan. 1, 2010, and TECO Energy’s EBITDA to interest coverage ratio, as defined in the agreement, to be not less than 2.25 times through Dec. 30, 2005 and 2.60 times thereafter. As of Dec. 31, 2006, the company was in compliance with both requirements. The facility places certain limitations on the ability to sell core assets and limits the ability of TECO Energy and certain of its subsidiaries, excluding Tampa Electric Company, to issue additional indebtedness in excess of a calculated level (initially $100 million), unless the indebtedness refinances currently outstanding indebtedness or meets certain other conditions. The facility also provides that, in the event the aggregate quarterly dividend payments on TECO Energy common stock were to equal or exceed a calculated amount (initially $50 million), subject to increase in the event TECO Energy issues additional shares of common stock, TECO Energy would not be able to declare or pay cash dividends on the common stock or make certain other distributions unless it had previously delivered liquidity projections satisfactory to the administrative agent under the credit facility demonstrating that TECO Energy will have sufficient cash to pay such dividends and distributions and the three succeeding quarterly dividends. The limitations described above on the ability to sell core assets, issue additional indebtedness and pay cash dividends will be released if TECO Energy achieves investment grade ratings and stable outlooks from both Moody’s and Standard & Poor’s.
Tampa Electric Company Credit Facility
On Oct. 11, 2005, Tampa Electric Company amended its $150 million bank credit facility, increasing the facility size to $325 million and extending the maturity to Oct. 11, 2010 with optional extensions of up to two additional years with lenders’ consent. Tampa Electric Company terminated its $125 million 3-year bank credit facility. The amended facility also allows Tampa Electric Company to increase the facility size by up to $50 million with lenders’ consent; and includes a $50 million sub-limit for letters of credit. The financial covenants were also amended to eliminate the requirement that Tampa Electric Company maintain a specified ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) to interest, as defined in the agreement, and increase the permissible quarter-end debt to capital, as defined in the agreement, to 65%. As of Dec. 31, 2006, Tampa Electric Company was in compliance with this requirement.
Tampa Electric Company Accounts Receivable Facility
On Jan. 6, 2005, Tampa Electric Company and TEC Receivables Corp (TRC), a wholly-owned subsidiary of Tampa Electric Company, entered into a $150 million accounts receivable collateralized borrowing facility. The assets of TRC are not intended to be generally available to the creditors of Tampa Electric Company. Under the Purchase and Contribution Agreement entered into in connection with that facility, Tampa Electric Company sells and/or contributes to TRC all of its receivables for the sale of electricity or gas to its retail customers and related rights (the Receivables), with the exception of certain excluded receivables and related rights defined in the agreement, and assigns to TRC the deposit accounts into which the proceeds of such
Receivables are paid. The Receivables are sold by Tampa Electric Company to TRC at a discount. Under the Loan and Servicing Agreement among Tampa Electric Company as Servicer, TRC as Borrower, certain lenders named therein and Citicorp North America, Inc. as Program Agent, TRC may borrow up to $150 million to fund its acquisition of the Receivables under the Purchase Agreement. TRC has secured such borrowings with a pledge of all of its assets including the Receivables and deposit accounts assigned to it. Tampa Electric Company acts as Servicer to service the collection of the Receivables. TRC pays program and liquidity fees based on Tampa Electric Company’s credit ratings. The receivables and the debt of TRC are included in the consolidated financial statements of TECO Energy and Tampa Electric Company.
On Dec. 22, 2006, Tampa Electric and TRC extended the maturity of Tampa Electric’s $150 million accounts receivable collateralized borrowing facility from Jan. 5, 2006 to Dec. 21, 2007. As part of this extension, the EBITDA to interest covenant for Tampa Electric was eliminated. Tampa Electric’s debt to capital covenant was increased from 60% to 65%.
7. Long-Term Debt
At Dec. 31, 2006, total long-term debt, excluding amounts currently due, had a carrying amount of $3,212.6 million and an estimated fair market value of $3,336.8 million. The estimated fair market value of long-term debt was based on quoted market prices for the same or similar issues, on the current rates offered for debt of the same remaining maturities, or for long-term debt issues with variable rates that approximate market rates, at carrying amounts.
A substantial part of the tangible assets of Tampa Electric are pledged as collateral to secure its first mortgage bonds, and certain pollution control equipment is pledged to secure certain installment contracts payable. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture.
TECO Energy’s maturities and annual sinking fund requirements of long-term debt for 2007 through 2011 and thereafter are as follows:
Long-Term Debt Maturities For Continuing Operations
Debt Securities
TECO Energy - $100 million Senior Unsecured Floating Rate Notes
On Jun. 7, 2005, TECO Energy issued $100 million of senior unsecured Floating Rate Notes due 2010 through an institutional private placement. Net proceeds of $99.3 million were used to implement TECO Energy’s debt redemption, refinancing, and hedging strategy. On Oct. 14, 2005, TECO Energy completed an exchange offer related to the Floating Rate Notes, thereby satisfying its obligations under a registration rights agreement.
TECO Energy - $200 million Senior Unsecured 6.75% Notes
On May 26, 2005, TECO Energy issued $200 million of senior unsecured 6.75% Notes due 2015. Net proceeds of $198.5 million were used in TECO Energy’s debt redemption and refinancing plan. On Oct. 14, 2005, TECO Energy completed an exchange offer related to the 6.75% Notes, thereby satisfying its obligations under a registration rights agreement.
Tampa Electric - $250 million 6.55% Senior Unsecured Notes
On May 12, 2006, Tampa Electric Company issued $250 million aggregate principal amount of 6.55% Notes due May 15, 2036. The 6.55% Notes were sold at 99.375% of par to yield 6.598%. The offering resulted in net proceeds to Tampa Electric (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $246.0 million. Net proceeds were used to repay short-term debt and for general corporate purposes. Tampa Electric may redeem all or any part of the 6.55% Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of 6.55% Notes to be redeemed or (ii) the present value of the remaining payments of principal and interest on the 6.55% Notes to be redeemed, discounted at an applicable treasury rate (as defined in the applicable indenture), plus 25 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date.
Junior Subordinated Notes
Based on the provisions of FAS 150, the preferred securities issued by the company were reclassified and presented as long-term debt for external financial reporting purposes.
Effective Jan. 1, 2004, TECO Energy adopted FIN 46R. As a result, the company’s preferred securities were no longer recognized as a result of the deconsolidation of the funding companies established to issue the securities purchases by the trusts described below. As described below, the company issued junior subordinated notes to the funding companies in connection with the issuance of the trust preferred securities. The company has reflected the junior subordinated notes and the equity investment in the funding companies on the balance sheet. See Note 19 for additional discussion of the impact of FIN 46R.
Capital Trust I
In December 2000, TECO Capital Trust I, a trust established for the sole purpose of issuing Trust Preferred Securities (TRuPS) and purchasing company preferred securities, issued 8 million shares of $25 par, 8.5% TRuPS, due 2041, with an aggregate liquidation value of $200 million. Each TRuPS represents an undivided beneficial interest in the assets of the Trust. The TRuPS represent an indirect interest in a corresponding amount of the TECO Energy 8.5% junior subordinated notes due 2041. Distributions are payable quarterly in arrears on Jan. 31, Apr. 30, Jul. 31, and Oct. 31 of each year. Distributions were $18.2 million in 2005, and $17.0 million per year in 2004 and 2003. For 2005 and 2006, these distributions were reflected in interest expense.
On Dec. 20, 2005, TECO Energy completed the early redemption of $100 million aggregate liquidation amount of the 8.5% TRuPS of TECO Capital Trust I. On Dec. 20, 2006, TECO Energy completed the early redemption of the remaining outstanding $100 million aggregate liquidation amount of the 8.5% TRuPS of TECO Capital Trust I.
Capital Trust II
In January 2002, TECO Energy sold 17.965 million mandatorily convertible equity security units in the form of 9.5% equity units at $25 per unit resulting in $436 million of net proceeds. Each equity unit consisted of $25 in principal amount of a trust preferred security of TECO Capital Trust II, a Delaware business trust formed for the purpose of issuing these securities, with a stated liquidation amount of $25 and a contract to purchase shares of common stock of TECO Energy in January 2005 at a price per share of between $26.29 and $30.10 based on the market price at that time. The equity units represented an indirect interest in a corresponding amount of the TECO Energy 5.11% junior subordinated notes. The holders of these contracts were entitled to quarterly contract adjustment payments at the annualized rate of 4.39% of the stated amount of $25 per year through and including Jan. 15, 2005.
In August 2004, the company exchanged approximately 10.227 million common shares and $14.9 million in cash for 10.756 million units through an early settlement offer (see Note 9). After the acceptance of the early settlement offer, approximately 7.209 million units remained outstanding.
In October 2004, $162.7 million of TECO Capital Trust II trust preferred securities out of a total $180.2 million aggregate stated liquidation amount of such trust preferred securities outstanding were remarketed. The distribution rate on the trust preferred securities was reset to a coupon rate of 5.934% per annum, payable quarterly, effective on and after Oct. 16, 2004.
At the closing of the remarketing on Oct. 15, 2004, the company purchased approximately $122.7 million of the trust preferred securities that were remarketed and retired the trust preferred securities it purchased. The company funded its participation by borrowing $124.1 million under an unsecured bridge loan facility with JP Morgan Chase Bank and Merrill Lynch Bank USA. The company received the proceeds of this loan on Oct. 15, 2004 and repaid the loan on Dec. 23, 2004 with the proceeds from the sale of Frontera Generation Limited Partnership (see Note 16).
On Jan. 14, 2005, the final settlement rate was set for TECO Energy’s remaining outstanding 7.209 million equity security units that were not tendered in the early settlement offer completed in August 2004. On Jan. 18, 2005, each holder of the TECO Energy units purchased from TECO Energy 0.9509 shares of TECO Energy common stock per unit for $25 per share. The cash for the unit holders’ purchase obligation was satisfied from the proceeds received upon the maturity of a portfolio of U.S. Treasury securities acquired in connection with the October 2004 remarketing of the trust preferred securities of TECO Capital Trust II. As a result, TECO Energy issued 6.85 million shares of common stock on Jan. 18, 2005 and received approximately $180 million of proceeds from the settlement (see Note 22 for details regarding the redemption of these securities).
On Jan. 16, 2007, all $71.4 million outstanding trust preferred securities of TECO Capital Trust II were retired at maturity pursuant to their original terms.
At Dec. 31, 2006 and 2005, TECO Energy had the following long-term debt outstanding:
(1) These securities are subject to redemption in whole or in part, at any time, at the option of the company.
(2) These long-term debt agreements contain various restrictive financial covenants.
(3) These securities were redeemed on Dec. 20, 2006.
(4) Tax-exempt securities.
(5) The interest rate on these bonds was fixed for a five-year term on Aug. 5, 2002.
(6) Composite year-end interest rate.
(7) These notes were redeemed on Jan. 16, 2007.
(8) Certain pollution control equipment is pledged to secure these bonds.
8. Preferred Stock
Preferred stock of TECO Energy - $1 par
10 million shares authorized, none outstanding.
Preference stock (subordinated preferred stock) of Tampa Electric - no par
2.5 million shares authorized, none outstanding.
Preferred stock of Tampa Electric - no par
2.5 million shares authorized, none outstanding.
Preferred stock of Tampa Electric - $100 par
1.5 million shares authorized, none outstanding.
9. Common Stock
Stock-Based Compensation
On Jan. 1, 2006, TECO Energy adopted FAS 123R, requiring the company to recognize expense related to the fair value of its stock-based compensation awards. Prior to this, the company accounted for its share-based payments under APB 25 and related interpretations. The company adopted FAS 123R using the modified-prospective transition method. Under this transition method, compensation cost recognized beginning Jan. 1, 2006 includes compensation cost for all share-based payments granted prior to, but not yet vested as of, Dec. 31, 2005 (based on the grant-date fair market value estimated in accordance with the original provisions of FAS 123), and compensation cost for all share-based payments granted on or after Jan. 1, 2006 (based on the grant date fair market value estimated in accordance with the provisions of FAS 123R). Results for prior periods have not been restated.
TECO Energy has two share-based compensation plans (the Equity Plan and the Director Equity Plan), which are described below. The types of awards granted under these Plans include stock options, stock grants, time-vested restricted stock and performance-based restricted stock. Stock options are granted with an exercise price greater than or equal to the fair market value of the common stock on the date of grant and have a 10-year contractual term. Stock options for the Director Equity Plan vest immediately and stock options for the Equity Plan have graded vesting over a three-year period, with the first 33% becoming exercisable one year after the date of grant. Stock grants and time-vested restricted stock are granted at a price equal to the fair market value on the date of grant, with expense recognized over the vesting period, which is normally three years. Beginning in 2006, we granted time-vested restricted stock to directors that vests one-third each year. Performance-based restricted stock is granted with shares vesting after three years at 0% to 200% of the original grant, based on the total return of TECO Energy common stock compared to a peer group of utility stocks. Dividends are paid on all time-vested and performance-based restricted stock awards.
TECO Energy recognized total stock compensation expense for 2006 of $11.5 million pretax, or $7.1 million after-tax. Cash received from option exercises under all share-based payment arrangements was $7.3 million, $11.5 million and $5.7 million for the periods ended Dec. 31, 2006, 2005 and 2004 respectively. The aggregate intrinsic value of stock options exercised was $2.7 million, $5.5 million and $1.6 million for the periods ended Dec. 31, 2006, 2005 and 2004 respectively. The total fair market value of awards vesting during 2006 was $4.8 million, which includes stock grants, time-vested restricted stock and performance-based restricted stock. As of Dec. 31, 2006, there was $10.5 million of unrecognized compensation cost related to all non-vested awards that is expected to be recognized over a weighted average period of two years. Prior to the adoption of FAS 123R, TECO Energy presented all tax benefits of deductions resulting from the exercise of stock options as operating cash flows in the Consolidated Condensed Statement of Cash Flows. Beginning on Jan. 1, 2006, the company changed its cash flow presentation in accordance with FAS 123R, which requires the cash flows resulting from excess tax deductions on share-based payments to be classified as financing cash flows.
Previously under APB 25, the company recognized or disclosed expenses for retirement-eligible employees over the nominal vesting period. Beginning Jan. 1, 2006 under FAS 123R, any new awards made to retirement-eligible employees are recognized immediately or over the period from the grant date to the date of retirement eligibility (non-substantive approach). The impact on net income for 2006 and 2005 of applying the nominal vesting period approach versus the non-substantive vesting period approach to awards granted prior to Jan. 1, 2006, for retirement-eligible employees would not have been material.
The fair market value of stock options is determined using the Black-Scholes valuation model, and the company uses the following methods to determine its underlying assumptions: expected volatilities are based on the historical volatilities; the expected term of options granted is based on the Staff Accounting Bulletin No. 107 (SAB 107) simplified method of averaging the vesting term and the original contractual term; the risk-free interest rate is based on the U.S. Treasury implied yield on zero-coupon issues (with a remaining term equal to the expected term of the option); and the expected dividend yield is based on the current annual dividend amount divided by the stock price on the date of grant.
The fair market value of performance-based restricted stock awards is determined using the Monte-Carlo valuation model, and the company uses the following methods to determine its underlying assumptions: expected volatilities are based on the historical volatilities; the expected term of the awards is based on the performance measurement period (which is generally three years); the risk-free interest rate is based on the U.S. Treasury implied yield on zero-coupon issues (with a remaining term equal to the expected term of the award); and the expected dividend yield is based on the current annual dividend amount divided by the stock price on the date of grant, with continuous compounding.
The value of time-vested restricted stock and stock grants are based on the fair market value of TECO Energy common stock at the time of grant.
Stock-based compensation expense reduced the Company's results of operations as follows:
The following table illustrates the effect on net income and earnings per share as if the company had applied the fair-value recognition provisions of FAS 123 to all share-based payments, prior to the adoption of FAS 123R. As all share-based payments have been expensed in 2006 in accordance with FAS 123R, no pro forma is required.
Pro Forma Stock-Based Compensation Expense
(1) Unearned compensation expense reflects the compensation expense of time-vested and performance-based restricted stock awards, after-tax.
(2) Includes compensation expense for stock options and performance-based restricted stock, determined using a fair-value based method, after-tax, plus compensation expense associated with time-vested restricted stock awards, determined based on fair market value at the time of grant, after-tax.
Equity Plans
In April 2004, the company’s shareholders approved the 2004 Equity Incentive Plan (2004 Plan). The 2004 Plan superseded the 1996 Equity Incentive Plan (1996 Plan), and no additional grants will be made under the 1996 Plan. Under the 2004 Plan, the Compensation Committee of the Board of Directors authorized 10 million shares of TECO Energy common stock that may be awarded as stock grants, stock options and/or stock equivalents to officers, key employees and consultants of TECO Energy and its subsidiaries. The Compensation Committee has discretion to determine the terms and conditions of each award, which may be subject to conditions relating to continued employment, restrictions on transfer or performance criteria.
Under the 2004 Plan and the 1996 Plan (collectively referred to as the “Equity Plans”), 1.1 million, 0.9 million and 2.4 million stock options were granted to employees in 2006, 2005 and 2004, respectively, with weighted average fair values of $3.26, $3.93 and $2.80. In addition, 0.5 million, 0.4 million and 0.3 million shares of restricted stock were granted in 2006, 2005 and 2004, respectively, with weighted average fair values of $16.85, $21.57 and $14.80. In 2006, 17,962 shares of unrestricted common stock were granted with a weighted average fair value of $17.54. A summary of non-vested shares of restricted stock and stock options for 2006 under the Equity Plans are shown as follows:
Nonvested Restricted Stock and Stock Options-Equity Plans
(1) The weighted average remaining contractual term of restricted stock is 2 years.
Stock option transactions during 2006 under the Equity Plans are summarized as follows:
Stock Options - Equity Plans
(1) Option prices range from $11.09 to $31.58.
(2) Option prices range from $11.09 to $16.21.
As of Dec. 31, 2006, the 9.8 million options outstanding under the Equity Plans are summarized below:
Director Equity Plan
In April 1997, the company’s shareholders approved the 1997 Director Equity Plan (1997 Plan), as an amendment and restatement of the 1991 Director Stock Option Plan (1991 Plan). The 1997 Plan superseded the 1991 Plan, and no additional grants will be made under the 1991 Plan. The purpose of the 1997 Plan is to attract and retain highly qualified non-employee directors of the company and to encourage them to own shares of TECO Energy common stock. The 1997 Plan, administered by the Board of Directors, authorized 250,000 shares of TECO Energy common stock to be awarded as stock grants, stock options and/or stock equivalents.
Under the 1997 Plan, 26,875 shares of restricted stock were awarded in 2006, with a weighted average fair value of $16.30. Restricted stock transactions for the year ended Dec. 31, 2006 under the 1997 Plan are summarized as follows:
Nonvested Restricted Stock - Director Equity Plans
(1) The weighted average remaining contractual term is 2 years.
Under the 1997 Plan, 35,000 stock options were granted in each of the years 2005 and 2004, with weighted average fair values of $3.95 and $2.90, respectively. In addition, 5,000 shares of unrestricted common stock were granted in each of the years 2005 and 2004, with weighted average fair values of $16.21 and $13.56, respectively. Stock option transactions during the year ended Dec. 31, 2006 under the 1997 Plan are summarized as follows:
Stock Options - Director Equity Plans (1)
(1) Stock options granted under the Director Equity Plans vest immediately.
(2) Option prices range from $11.09 to $31.58 per share.
(3) Option prices range from $11.09 to $16.21 per share.
Dividend Reinvestment Plan
In 1992, TECO Energy implemented a Dividend Reinvestment and Common Stock Purchase Plan. TECO Energy raised $4.4 million, $4.9 million and $5.1 million of common equity from this plan in 2006, 2005 and 2004, respectively.
Common Stock
On Jan. 18, 2005, TECO Energy issued 6.85 million shares of common stock as part of the final settlement for the remaining outstanding equity security units of TECO Capital Trust II; receiving approximately $180 million of proceeds from the settlement (see Note 7).
On Aug. 25, 2004, the company completed an early settlement exchange offer of its TECO Capital Trust II equity security units for 10.2 million shares of common stock (see Note 7).
Shareholder Rights Plan
In accordance with the company’s Shareholder Rights Plan, a Right to purchase one additional share of the company’s common stock at a price of $90 per share is attached to each outstanding share of the company’s common stock. The Rights expire in May 2009, subject to extension. The Rights will become exercisable 10 business days after a person acquires 10% or more of the company’s outstanding common stock or commences a tender offer that would result in such person owning 10% or more of such stock. If any person acquires 10% or more of the outstanding common stock, the rights of holders, other than the acquiring person, become rights to buy shares of common stock of the company (or of the acquiring company if the company is involved in a merger or other business combination and is not the surviving corporation) having a market value of twice the exercise price of each Right.
The company may redeem the Rights at a nominal price per Right until 10 business days after a person acquires 10% or more of the outstanding common stock.
Employee Stock Ownership Plan
Effective Jan. 1, 1990, TECO Energy amended the TECO Energy Group Retirement Savings Plan, a tax-qualified benefit plan available to substantially all employees, to include an employee stock ownership plan (ESOP). During 1990, the ESOP purchased 7 million shares of TECO Energy common stock on the open market for $100 million. The share purchase was financed through a loan from TECO Energy to the ESOP. This loan was at a fixed interest rate of 9.3% and was repaid from dividends on ESOP shares and from TECO Energy’s contributions to the ESOP. Shares were released to provide employees with the company match in accordance with the terms of the TECO Energy Group Retirement Savings Plan and in lieu of dividends on allocated ESOP shares. At Dec. 31, 2004, the ESOP had no shares remaining to be allocated.
TECO Energy’s contributions to the ESOP were $2.1 million in 2004. TECO Energy’s annual contribution equals the interest accrued on the loan during the year plus additional principal payments needed to meet the matching allocation requirements under the plan, less dividends received on the ESOP shares. The components of net ESOP expense recognized for the prior years are as follows:
ESOP Expense
Compensation expense was determined by the shares allocated method.
For financial statement purposes, the unallocated shares of TECO Energy stock were reflected as a reduction of common equity, classified as unearned compensation. Dividends on all ESOP shares were recorded as a reduction of retained earnings, as are dividends on all TECO Energy common stock. The dividends received by the ESOP were used to pay debt service on the loan between TECO Energy and the ESOP.
The tax benefit related to dividends paid to the ESOP for allocated shares is a reduction of income tax expense and was $1.5 million for 2004. The tax benefit related to dividends paid to the ESOP for unallocated shares is an increase in retained earnings and was $0.1 million in 2004. All ESOP shares were considered outstanding for earnings per share computations.
10. Other Comprehensive Income
TECO Energy reported the following other comprehensive income (loss) (OCI) for the years ended Dec. 31, 2006, 2005 and 2004, related to changes in the fair value of cash flow hedges, foreign currency adjustments and adjustments to the minimum pension liability associated with the company’s pension plans:
(1) Amounts include interest rate swaps designated as cash flow hedges at TPGC, which was consolidated effective Apr. 1, 2003 as a result of the termination of the partnership. Prior to Apr. 1, 2003, only the company’s proportionate share of its equity investee’s comprehensive loss was included. See Note 21 for additional details regarding the OCI balances for cash flow hedges.
Accumulated Other Comprehensive Income
(1) Net of tax benefit of $32.5 million as of Dec. 31, 2005.
(2) Net of tax benefit of $13.9 million as of Dec. 31, 2006.
(3) Net of tax benefit of $5.5 million as of Dec. 31, 2006.
(4) Net of tax expense of $0.2 million and $0.4 million as of Dec. 31, 2006 and 2005, respectively.
(2) Net of tax expense of $0.2 million and $0.4 million as of Dec. 31, 2006 and 2005, respectively.
11. Earnings Per Share
For the years ended Dec. 31, 2006, 2005 and 2004, stock options for 7.0 million shares, 5.4 million shares and 10.6 million shares, respectively, were excluded from the computation of diluted earnings per share due to their anti-dilutive effect. Additionally, 1.9 million common shares issuable under the purchase contract associated with the mandatorily convertible equity units were also excluded from the computation of diluted earnings per share for the year ended Dec. 31, 2004 due to their anti-dilutive effect.
Earnings per Share
12. Commitments and Contingencies
Capital Investments
TECO Energy has made certain commitments in connection with its continuing capital expenditure program. These estimated capital investments total approximately $523 million for 2007.
For 2007, Tampa Electric expects to spend approximately $400 million, consisting of about $200 million to support system growth and generation reliability, approximately $14 million for distribution system reliability improvements, $13 million for transmission and distribution system storm hardening, $4 million for transmission system improvements to meet reliability requirements, $20 million for an additional natural gas pipeline to improve reliability of supply to the Bayside Power Station, $20 million for coal-fired generation capacity factor and availability improvements, $6 million to complete the addition of two combustion turbines at the Polk Power Station to meet its peaking generation capacity needs, $87 million for the addition of selective catalytic reduction (SCR) equipment at the Big Bend Station for NOx control, and $34 million for other environmental compliance programs. At the end of 2006, Tampa Electric had outstanding commitments of about $198 million, for long-term capitalized maintenance agreements for its combustion turbines, materials and contractors for the SCR projects and for major maintenance outages at Big Bend Station.
Capital expenditures for PGS are expected to be about $50 million in 2007. Included in these amounts is an average of approximately $30 million annually for projects associated with customer growth and system expansion. The remainder represents capital expenditures for ongoing renewal, replacement and system safety.
TECO Coal and TECO Transport expect to invest a combined $70 million in 2007. Included in these amounts are new mine development projects to replace higher cost of production mines and position TECO Coal to increase production when coal markets improve at TECO Coal. Also included is normal renewal and replacement capital, including coal mining equipment, normal steel replacements, shipyard periods for oceangoing vessels, and inland river transportation equipment. TECO Coal had outstanding commitments of approximately $27 million, primarily for replacement of coal mining equipment at Dec. 31, 2006. TECO Transport had an outstanding commitment of $21 million for the construction of 50 replacement river barges, which is not included in the capital spending forecast as the company expects to charter these barges under an operating lease.
Legal Contingencies
At Dec. 31, 2006, the ultimate resolution of the following specific proceedings is uncertain and no liability has been reserved or can be estimated. At this time, the ultimate outcome of these proceedings is not expected to have a material adverse effect on the company's results of operations or financial condition.
Tampa Electric Transmission Litigation
In 2003, Tampa Electric completed a transmission project which required the placement of 95 foot and 125 foot transmission structures on public right of way in parts of residential neighborhoods, near the Egypt Lake subdivision in Tampa, Florida, in order to move electricity to the growth areas in the north-west part of its service area. The lawsuits for private nuisance (the Shaw, Acosta, and Alvarez cases) were filed shortly thereafter.
The Shaw plaintiffs’ (39 parcels and approximately 55 individuals) appeal of the trial court’s summary judgment denying plaintiffs’ right to a mandatory injunction to remove the poles was decided in favor of the Company on Friday, Jan. 5, 2007. The Shaw case was set for trial on Jan. 8, 2007, but we were able to resolve the case and avoid the effect of a long and expensive trial. The legal principles in the Shaw case should apply to the remaining Acosta and Alvarez cases.
The Acosta plaintiffs are owners of 93 parcels and comprised of about 131 individuals. Many of these plaintiffs do not own property on the streets where the structures were placed. The case has been set for trial in May 2007.
There has been no activity in the Alvarez (substation) case, which involves only one parcel.
Grupo Arbitration
On Aug. 11, 2006, TPS International Power, Inc. (TPSI) received a favorable ruling from the Bogotá Chamber of Commerce Arbitration Tribunal in the Grupo-financed arbitration on behalf of itself and the Colombian trade union regarding a 1996 transaction that was never consummated related to the potential purchase and financing of a power plant. The Tribunal found no liability on the part of TPSI and found that it had no jurisdiction over TECO Energy or any of its subsidiaries. Accordingly, it did not become necessary to address the issue of damages.
Following the Arbitration Tribunal’s finding of “no liability” as to TPSI on Aug. 11, 2006, the union filed a petition for annulment in the Ordinary courts on Aug. 31, 2006. The Union was ordered to file its detailed petition citing the record to substantiate its annulment claim on Oct. 12, but it failed to do so. The court appointed Tribunal issued a confirmation that the matter was closed. However, in early December, the Union filed papers asking the Tribunal to set aside its determination, that the Union’s petition was barred due to the missed deadline, on the basis that the Tribunal’s “Notification of the Oct. 12 date” was technically deficient. TPSI’s counsel filed a reply on or about Dec. 14, 2006. There has not been any further activity.
Securities Class Action and Derivative Suits
Class Action Suit
After the consolidated Class Action Complaint brought by the “TECO Lead Plaintiff Group” in connection with TECO Energy’s Merchant power activities was dismissed without prejudice by the Court on Mar. 31, 2006, plaintiffs filed their further amended complaint to which TECO Energy and the individual defendants filed their motion to dismiss on Jul. 7, 2006 based on the same ground as raised in the prior motion, failure to plead loss causation. Defendants filed a renewed motion to dismiss, and on Oct. 10, 2006, the Court granted defendants' motion to dismiss in part, leaving only one remaining issue dealing with public statements relating to the status of the contracting plan for the approximately 6,000 MWs of merchant power then under construction in several states outside of Florida. On Oct. 30, 2006, the plaintiffs filed a Rule 54(b) motion asking the Court to enter a final judgment on the matters that were dismissed by its Oct. 10th order in order to appeal that portion of the order immediately, while maintaining the balance of the action in the district Court. The Court denied the Rule 54(b) motion. A mediation on the entire suit occurred on Feb. 16, 2007 whereby the company reached an agreement in principle to settle the shareholder securities class action lawsuit. See Note 22 for more details.
Derivative Suit
On Apr. 5, 2006, the Hillsborough Circuit Court dismissed the derivative complaint filed against two named officers and the named directors without prejudice. Subsequently, the parties stipulated to dismiss with prejudice directors Penn and Whiting who were not members of the board during the relevant time period. Quarterly status reports of the Special Litigation Committee have been filed commencing Aug. 1, 2006. A mediation on the entire suit occurred on Feb. 16, 2007 whereby the company reached an agreement in principle to settle the derivative lawsuit. See Note 22 for more details.
Other Issues
From time to time, TECO Energy and its subsidiaries are involved in various other legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with FAS No. 5, Accounting for Contingencies, to provide for matters that are probable of resulting in an estimable, material loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations or financial condition.
Superfund and Former Manufactured Gas Plant Sites
Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a potentially responsible party (PRP) for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Dec. 31, 2006, Tampa Electric Company has estimated its ultimate financial liability to be approximately $12.3 million, and this amount has been accrued in the company’s financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.
The estimated amounts represent only the estimated portion of the cleanup costs attributable to Tampa Electric Company. The estimates to perform the work are based on actual estimates obtained from contractors, or Tampa Electric Company’s experience with similar work adjusted for site specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.
Allocation of the responsibility for remediation costs among Tampa Electric Company and other PRPs is based on each party’s relative ownership interest in or usage of a site. Accordingly, Tampa Electric Company’s share of remediation costs varies with each site. In virtually all instances where other PRPs are involved, those PRPs are considered creditworthy.
Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. These costs are recoverable through customer rates established in subsequent base rate proceedings.
TECO Transport Storm Damage
In August and September 2005, TECO Transport subsidiaries sustained flood and wind damage, as well as business interruptions as a result of hurricanes Katrina and Rita. In 2006 and 2005, the company incurred $7.2 million pretax ($4.5 million after-tax) and $20.2 million pretax ($12.6 million after tax), respectively, of direct costs associated with these storms, including property damage, salvage, and cleanup expenses. The company carried wind and flood insurance for a majority of the property damaged and in 2006 and 2005, the company received $2.4 million pretax ($1.5 million after-tax) and $22.0 million pretax ($13.7 million after-tax), respectively, in insurance recoveries. As of Dec. 31, 2006, TECO Transport has settled all claims for terminal and marine damages related to the 2005 storms.
Long Term Commitments
TECO Energy has commitments under long-term operating leases, primarily for building space, office equipment and heavy equipment, and marine assets at TECO Transport.
Total rental expense for these operating leases, included in the Consolidated Statements of Income for the years ended Dec. 31, 2006, 2005 and 2004 was $30.0 million, $28.3 million and $32.3 million, respectively.
The following is a schedule of future minimum lease payments at Dec. 31, 2006 for all operating leases with non-cancelable lease terms in excess of one year:
Future Minimum Lease Payments of Operating Leases
In 1994, Tampa Electric bought out a long-term coal supply contract which would have expired in 2004 for a lump sum payment of $25.5 million. In February 1995, the FPSC authorized the recovery of this buy-out amount plus carrying costs through the Fuel and Purchased Power Cost Recovery Clause over the 10-year period beginning Apr. 1, 1995. In 2004, $2.7 million of buy-out costs were amortized to expense. It was fully amortized by the end of 2004.
Guarantees and Letters of Credit
TECO Energy accounts for guarantees in accordance with FASB Interpretation No. (FIN) 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (an interpretation of FASB Statements No. 5, 57 and 107 and rescission of FASB Interpretation No. 34). Upon issuance or modification of a guarantee the company determines if the obligation is subject to either or both of the following:
•
Initial recognition and initial measurement of a liability; and/or
•
Disclosure of specific details of the guarantee.
Generally, guarantees of the performance of a third party or guarantees that are based on an underlying (where such a guarantee is not a derivative subject to FAS 133) are likely to be subject to the recognition and measurement, as well as the disclosure provisions, of FIN 45. Such guarantees must initially be recorded at fair value, as determined in accordance with the interpretation.
Alternatively, guarantees between and on behalf of entities under common control or that are similar to product warranties are subject only to the disclosure provisions of the interpretation. The company must disclose information as to the term of the guarantee and the maximum potential amount of future gross payments (undiscounted) under the guarantee, even if the likelihood of a claim is remote.
A summary of the face amount or maximum theoretical obligation under TECO Energy’s letters of credit and guarantees as of Dec. 31, 2006 are as follows:
Letters of Credit and Guarantees
(1) These guarantees renew annually and are shown on the basis that they will continue to renew beyond 2011.
(2) The amounts shown are the maximum theoretical amount guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy under these agreements at Dec. 31, 2006. The obligations under these letters of credit and guarantees include net accounts payable and net derivative liabilities.
Financial Covenants
In order to utilize their respective bank facilities, TECO Energy and Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, Tampa Electric Company and other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Dec. 31, 2006, TECO Energy, Tampa Electric Company and the other operating companies were in compliance with all required financial covenants. See Liquidity, Capital Resources-Covenants in Financing Agreements in MD&A.
13. Related Parties
The company and its subsidiaries had certain transactions, in the ordinary course of business, with entities in which directors of the company had interests. The company paid legal fees of $1.2 million, $1.3 million and $1.4 million for the years ended Dec. 31, 2006, 2005 and 2004, respectively, to Ausley McMullen, P.A. of which Mr. Ausley (a director of TECO Energy) is an employee. Other transactions were not material for the years ended Dec. 31, 2006, 2005 and 2004. No material balances were payable as of Dec. 31, 2006 or 2005.
14. Segment Information
TECO Energy is an electric and gas utility holding company with significant diversified activities. Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. The management of TECO Energy reports segments based on each subsidiary’s contribution of revenues, net income and total assets, as required by FAS 131, Disclosures about Segments of an Enterprise and Related Information. All significant intercompany transactions are eliminated in the consolidated financial statements of TECO Energy, but are included in determining reportable segments.
As more fully described in Note 1, during the first quarter of 2005, the company revised internal reporting information for the purpose of evaluating, measuring and making decisions with respect to the components which previously comprised the “Other Unregulated” operating segment. The revised operating segment, “TECO Guatemala”, is comprised of all Guatemalan operations. The remaining components are now included in “Other & eliminations”. Prior period segment results have been restated to reflect the revised segment structure. In 2006, only historical data is presented for TWG Merchant as all merchant assets have been divested. Any residual results for 2006 are included in “Other and eliminations”.
The information presented in the following table excludes all discontinued operations. See Note 20 for additional details of the components of discontinued operations.
Segment Information (1)
(1) From continuing operations. All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for CCC and Frontera Generation Limited Partnership (Frontera) (formerly included in the TWG Merchant segment) and BCH Mechanical, Inc. (BCH) and other Energy Services operations (formerly included in the Eliminations & Other segment).
(2) Segment net income is reported on a basis that includes internally allocated financing costs. Internally allocated costs for 2006, 2005 and 2004 were at pretax rates of 8%, based on the average of each subsidiary’s equity and indebtedness to TECO Energy assuming a 50/50 debt/equity capital structure. Internally allocated interest charges are a component of total interest charges.
(3) Net income for 2006 includes after-tax gains of $8.1 million on the sale of McAdams and $5.7 million on the sale of two steam turbines (original impairment recorded on TECO Guatemala in 2004, see (5) below). Net income for 2005 includes $46.7 million after-tax of debt extinguishment charges at TECO Energy parent (including a $19.8 million non-cash charge). Net income for 2004 includes an after-tax gain of $12.0 million on the sale of TECO Energy’s interest in its propane business, partially offset by a non-cash $3.4 million after-tax asset impairment charge at TECO Solutions.
(4) Net income for 2004 includes a non-cash $12.8 million after-tax asset impairment charge related to certain steam turbines (see Note 18), $6.7 million after-tax charge related to the refinancing of the debt associated with the San José power station in Guatemala, and $17.4 million in after-tax charges associated with income taxes due to repatriation of cash from Guatemala following the refinancing.
(5) The carrying value of mineral rights as of Dec. 31, 2006, 2005, and 2004 was $20.6 million, $22.5 million and $25.0 million, respectively.
(6) Revenues for 2006, 2005 and 2004 are exclusive of entities deconsolidated as a result of FIN 46R and include only revenues for the consolidated Guatemalan entities.
(7) Included in other capital expenditures is a cash offset of $22.1 million, related to the sale of two combustion turbines by TPS McAdams to Tampa Electric. The corresponding capital expenditure is included in Tampa Electric’s capital expenditures for 2006.
Tampa Electric provides retail electric utility services to more than 660,000 customers in West Central Florida. PGS is engaged in the purchase and distribution of natural gas for more than 332,000 residential, commercial, industrial and electric power generation customers in the state of Florida.
TECO Coal, through its wholly-owned subsidiaries, owns mineral rights and owns or operates surface and underground mines and coal processing and loading facilities in Kentucky, Tennessee and Virginia. TECO Coal acquired and began operating two synthetic fuel facilities in 2000, whose production qualifies for the nonconventional fuels tax credit. In 2003, these synthetic fuel operations were transferred into a newly formed LLC for the purpose of continuing growth in the production and sale of synthetic fuel. In April 2003, TECO Coal sold 49.5% interest in this entity, with another 40.5% being sold in 2004, and an additional 8% sold in 2005.
TECO Transport, through its wholly-owned subsidiaries, transports, stores and transfers coal and other dry bulk commodities for third parties and Tampa Electric. TECO Transport’s subsidiaries operate on the Mississippi, Ohio and Illinois rivers, in the Gulf of Mexico and worldwide.
TECO Guatemala includes the equity investments in the San José and Alborada power plants, TEMSA, the equity investment in the Guatemalan distribution company, EEGSA, and the TECO Guatemala parent company. See below for further information on the deconsolidated Guatemala investments.
TWG Merchant’s assets were entirely divested by the end of 2006.
Foreign Operations
TECO Guatemala, through its subsidiaries, owns independent power operations and other electric related investments in Guatemala. TECO Energy, through its equity investments, has a 100% ownership interest in the 120-megawatt San José power station and in transmission facilities in Guatemala. The plant provides capacity and energy under a U.S. dollar-denominated power sales agreement to EEGSA. TECO Energy, through its equity investments, also has a 96% ownership interest and operates the 78-megawatt Alborada power station that supplies capacity and energy to EEGSA, under a U.S. dollar-denominated power sales agreement. Prior to 2004, the subsidiaries that hold interests in the San José and Alborada power stations in Guatemala were consolidated entities. Subsequent to 2004, in accordance with the interpretation and application of the consolidation guidance established in FIN 46R regarding long-term power purchase agreements, TECO Energy could no longer consolidate these project companies and they are accounted for as equity investments (see Notes 1 and 19 for additional details).
TECO Energy, through its subsidiaries, owns a 30% interest in a three member consortium that also includes Iberdrola, an electric utility in Spain, and Electricidad de Portugal, an electric utility in Portugal. The consortium, called Distribución Electrica Centroamericana Dos, S.A. owns an 80.9% interest in Empresa Electrica de Guatemala, S.A. - EEGSA, the largest electric distribution company in Central America, Inversiones Electricas Centroamericanas, S.A.-INVELCA, (the holding company for Guatemalan-based electric transmission, services and unregulated distribution companies) and Inmobiliaria y Desarrolladora Empresarial de America, S.A.-IDEAMSA, a real estate company, a 55% interest in Navega.com and subsidiaries in Central America, a telecommunications and data transmission carrier, and a 99.7% interest in Almacenaje y Manejo de Materiales Eléctricos, S.A., a company that manages, controls and sells electrical supplies and inventory materials.
The information presented in the following table provides select condensed financial information for the unconsolidated operations of the San José and Alborada power stations and the DECA II/EEGSA project.
TECO Guatemala Selected Financial Data
(1) 2006 information is based on management’s estimates, derived from information provided by EEGSA and its related affiliates. Final 2006 income statement information for the DECA II/EEGSA project will be received during the first quarter of 2007 and true-up adjustments will be made at that time. These adjustments are not expected to be material.
(2) EEGSA and its related affiliates had not provided balance sheet information prior to the company’s filing date.
(3) Total net income from the entire Guatemalan segment was $37.6 million, $40.4 million and $5.7 million for 2006, 2005 and 2004, respectively. The above selected income information includes only the project level information as stated above and does not include certain parent-based oversight costs and U.S. taxes.
15. Asset Retirement Obligations
TECO Energy accounts for asset retirement obligations under FAS 143. An asset retirement obligation (ARO) for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under an existing or enacted law or statute, a written or oral contract, or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.
When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The liability must be revalued each period based on current market prices.
TECO Energy has recognized asset retirement obligations for reclamation and site restoration obligations principally associated with coal mining, storage and transfer facilities. The majority of obligations arise from environmental remediation and restoration activities for coal-related operations. Prior to the adoption of FAS 143, TECO Coal accrued reclamation costs for such activities. For TECO Coal, the adoption of FAS 143 modified the valuation and accrual methods used to estimate the fair value of asset retirement obligations.
In the fourth quarter of 2005, Tampa Electric recorded an increase to net property, plant and equipment of $3.6 million (net of accumulated depreciation of $0.4 million), an increase to regulatory assets of $2.7 million and an increase to asset retirement obligations of $18.3 million (including $12.1 million reclassified from a regulatory liability), in accordance with FIN 47.
For the years ended Dec. 31, 2006, 2005 and 2004, TECO Energy recognized $1.5 million, $1.6 million, and $2.0 million of accretion expense, respectively, associated with asset retirement obligations.
Reconciliation of beginning and ending carrying amount of asset retirement obligations:
(1) Accretion expense reclassed as a deferred regulatory asset.
During 2006, estimated cash flows used in determining the recognized asset retirement obligations were adjusted by $7.3 million at Tampa Electric Company. The amount is related to the increased cost of removal of materials used for the generation and transmission of power.
As regulated utilities, Tampa Electric and PGS must file depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components-a salvage factor and a cost of removal or dismantlement factor. The company uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation.
For Tampa Electric and PGS, the original cost of utility plant retired or otherwise disposed of and the cost of removal, or dismantlement, less salvage value is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively.
16. Mergers, Acquisitions and Dispositions
Sale of Properties
During the year ended Dec. 31, 2006, the company sold two lots adjacent to the corporate office in downtown Tampa, Florida to third party real estate developers. The sales included total proceeds of $15.0 million and resulted in pretax gains of $6.4 million. Included in each sale agreement were the ability to lease the properties until construction commenced and options to repurchase the properties after a certain period of time in the event the lots were not developed. As a result of this continuing involvement, the total gain is being deferred until such time as the continuing involvement terminates.
Sale of Steam Turbines
In July of 2006, the company sold a steam turbine generator located in Maricopa County, Arizona to a third party for a net after-tax gain of $2.6 million. In December of 2006, the company sold a second steam turbine generator also located in Maricopa County, Arizona to a third party for a net after-tax gain of $3.1 million
Sale of TPS McAdams, LLC
On Jun. 23, 2006, TPS McAdams, LLC, an indirect subsidiary of TECO Energy was sold to Von Boyett Corporation for $1.2 million in cash. The assets of TPS McAdams, LLC had been impaired in 2004 to an estimate of salvage value, which included allowances for potential future site restoration costs. In the first quarter of 2006, TPS McAdams, LLC sold the combustion turbines at the site to Tampa Electric Company at the book value contemplated in the salvage estimate. The sale and transfer of TPS McAdams, LLC, including its remaining assets and any potential site restoration costs at terms better than contemplated in the salvage estimate, resulted in a pretax gain of $10.7 million ($8.1 million after-tax) being recognized in continuing operations.
Sale of TECO Thermal
In May of 2006, the company sold the assets of TECO Thermal, an indirect subsidiary of TECO Energy, to a third party. Total proceeds of the sale were $8.1 million and resulted in an after-tax gain of $0.5 million.
Dell Power Station
On Aug. 16, 2005, an indirect subsidiary of TECO Energy completed the sale of substantially all of its assets, including the Dell Power Station, to Associated Electric Cooperative, Inc., a Missouri electric cooperative, for $75 million. The sale resulted in a pretax gain of $23.2 million ($14.9 million after-tax). TECO Energy retained certain other operating liabilities totaling $11.0 million pretax ($7.1 million after-tax). The net after-tax impact of $7.8 million is included in continuing operations.
Union and Gila River Project Companies
On Jun. 1, 2005, the company completed the sale and transfer of ownership of its indirect subsidiaries, Union Power Partners, L.P., Panda Gila River, L.P., Trans-Union Interstate Pipeline, L.P., and UPP Finance Co., LLC, owners of the Union and Gila River power stations in Arkansas and Arizona, respectively (collectively, the Projects) to an entity owned by the Projects’ lenders in the manner set forth in the Projects’ confirmed Joint Plan of Reorganization (the Plan). In connection with the transfer and the related release of liability, the company and its indirect subsidiaries paid an aggregate of $31.8 million, consisting of $30.0 million to the Project’s lenders as consideration for release of liability and $1.8 million as reimbursement of legal fees for two non-consenting lenders in the recently concluded Chapter 11 proceeding.
BCH Mechanical, Inc.
On Jan. 7, 2005, an indirect subsidiary of TECO Energy completed the disposal of its 100% interest in BCH Mechanical, Inc. (BCH) pursuant to a Stock Purchase Agreement dated as of Dec. 31, 2004. The purchaser of BCH was BCH Holdings, Inc., majority owned at that time by Daryl W. Blume, who was a Vice President of BCH and one of the owners of BCH when it was purchased by a subsidiary of TECO Energy in September 2000. Under the transaction, TECO Energy retained BCH’s net working capital determined as of Dec. 31, 2004, and certain other existing obligations. During the third quarter of 2005, terms of the sale were modified from a sale of assets to a sale of stock. This modification resulted in an additional after-tax loss of $1.4 million on tax-related assets. The results of BCH are reflected in discontinued operations for all periods presented (see Note 20).
PLC/TIE
On Aug. 30, 2004, a TWG Merchant subsidiary completed the sale of its 50% indirect interest in TIE to PSEG Americas Inc., for $0.5 million. The company recorded a $152.3 million pretax impairment ($99.0 million after tax) to write off the value of the investment as a result of the sale.
Frontera
On Dec. 22, 2004, subsidiaries of TWG Merchant completed the sale of their respective interests in Frontera Generation Limited Partnership (Frontera), the owner of the Frontera Power Station in Texas, to a subsidiary of Centrica plc for $133.7 million, consisting of $128.5 million of cash and assumption of $5.2 million of liabilities. As a result of the sale, a pretax loss of $42.1 million ($27.0 million after tax) was recorded. See Note 20 for additional details related to this transaction.
Commonwealth Chesapeake
In August 2004, the company entered into an agreement with NCP of Virginia, LLC (NCP), the non-equity member in Commonwealth Chesapeake Company (CCC), under which TECO Energy and a subsidiary agreed to purchase NCP’s interest in CCC for $30 million in cash plus shares of TECO Energy common stock having a value of $10 million, and NCP released all claims against the company and its subsidiaries. The funds and shares were released from escrow upon receipt of FERC approval on Sep. 30, 2004.
On Apr. 19, 2005, an indirect subsidiary of TECO Energy completed the sale of its membership interests in CCC, the owner of the Commonwealth Chesapeake Power Station in Virginia, to an affiliate of Tenaska Power Fund, L.P. Net proceeds from the sale were $90.2 million after consideration for the value of working capital less transaction-related expenses. As a result of asset impairments recorded in the fourth quarter 2004, the sale transaction resulted in a pretax gain of $0.9 million ($0.6 million after-tax) upon close. The transaction terms provided for certain ordinary and customary post-closing adjustments to working capital items, which were completed as expected with no material adjustments in the third quarter of 2005. CCC’s results are reflected in discontinued operations for all periods presented (see Note 20).
TECO Propane Ventures
In the first quarter of 2004, US Propane, LLC, in which TECO Propane Ventures owned an interest, sold a majority of its assets, consisting of direct and indirect equity investments in Heritage Propane Partners, L.P., and the remaining indirect investment was sold in the second quarter of 2004. The sales resulted in cash proceeds of $53 million and after-tax gains totaling $12.0 million.
Hamakua Power Station
On Jul. 15, 2004, TECO Wholesale Generation’s 50% indirect interest in the Hamakua Power Station in Hawaii was sold to an affiliate of Black River Energy, an affiliate of Energy Investors Funds’ US Power Fund, L.P. Via its ownership of Black River Energy, which already owns 50% of the plant, Energy Investors Funds became the sole owner of Hamakua. Cash proceeds from the sale were approximately $12 million, and resulted in an immaterial gain. As a result of the transaction, TECO Energy was also relieved of certain financial guarantees related to the facility.
Prior Energy
Effective Feb. 1, 2004, a subsidiary of TECO Energy completed the sale of Prior Energy for net proceeds of approximately $30 million. This sale did not result in a material gain or loss to the company.
BGA
Effective Jan. 1, 2004, the company completed the sale of TECO BGA to an entity owned by an employee group for a loss on disposal of $12.2 million ($7.5 million after tax). This loss was recorded as part of the asset impairment charge reported in the income statement for the year ended Dec. 31, 2003.
Synthetic Fuel Facilities
Effective Apr. 1, 2003, TECO Coal sold a 49.5% indirect interest in Pike Letcher Synfuel, LLC (PLS), which owns synthetic fuel production facilities located at TECO Coal’s operations in eastern Kentucky. In May 2004, TECO Coal sold an additional 40.5% of its membership interest in the synthetic fuel facilities and another 8% in July 2005, under similar terms as the first transaction. On Dec. 29, 2005, the agreements with the investors were amended to permit the curtailment of synthetic fuel production when oil prices are above certain thresholds and to allow TECO the right, but not the obligation, to cause PLS to reduce or halt synthetic fuel production should estimates for crude oil prices reach certain levels. This amendment also allowed for the release of $20 million of the $50 million restricted cash that has been held in escrow. Generally, revenue is recognized as the monthly installments are received. Because the purchase price for this sale, as well as the other sales of ownership interests, is related to the value of tax credits generated through December 2007, it is subject to a reduction to the extent the credit is limited due to the average domestic oil price for a particular year exceeding the benchmark designated for that year by the Department of Energy. In addition to retaining a 2% membership interest in the facilities, TECO Coal has continued to supply the feedstock and operate the facilities.
17. Goodwill and Other Intangible Assets
FAS 141 Business Combinations, requires all business combinations be accounted for using the purchase method of accounting. Under FAS 142 Goodwill and Other Intangible Assets, goodwill is not subject to amortization. Rather, goodwill and intangible assets, with an indefinite life, are subject to an annual assessment for impairment by applying a fair-value-based test. Intangible assets with a measurable useful life are required to be amortized.
As required under FAS 142, TECO Energy reviews recorded goodwill and intangible assets at least annually during the fourth quarter, for each reporting unit. Reporting units are generally determined as one level below the operating segment level; reporting units with similar characteristics are grouped for the purpose of determining the impairment, if any, of goodwill and other intangible assets. The fair value for the reporting units evaluated is generally determined using discounted cash flows appropriate for the business model of each significant group of assets within each reporting unit. The models incorporate assumptions relating to future results of operations that are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. Management periodically reviews and adjusts the assumptions, as necessary, to reflect current market conditions and observable activity. If a sale is expected in the near term or a similar transaction can be readily observed in the marketplace, then this information is used by management to estimate the fair value of the reporting unit.
At Dec. 31, 2006, the company has $59.4 million of goodwill on its balance sheet, which is reflected in the TECO Guatemala segment. In conducting its annual impairment assessment, the company determined the fair value of the Guatemalan reporting unit supported the goodwill. The balance of goodwill arose from the purchase of multiple entities as a result of the company’s investment in its operations in Guatemala. The amount remained unchanged from Dec. 31, 2005.
In December 2004, the company recognized an $11.8 million pretax charge ($8.4 million after tax) to write off the value of the remaining goodwill associated with BCH Mechanical. This charge is reflected in discontinued operations. See Note 20 for additional details.
In December 2004, as a result of its annual impairment assessment, the company recognized a pretax impairment charge of $4.8 million ($3.1 million after tax) to write off the value of an intangible asset associated with the acquisition of the Commonwealth Chesapeake power station (see Note 18 for additional details). For the year ended Dec. 31, 2004, the company recognized amortization expense of $0.2 million.
18. Asset Impairments
The company accounts for asset impairments in accordance with FAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets (FAS 144). FAS 144 requires that long-lived assets be tested for recoverability whenever events or changes in circumstances indicate that its carrying value may not be recoverable. As of Dec. 31, 2006, the carrying value of all long lived assets was determined to be recoverable. No adjustments for asset impairments were necessary.
Following major investments in merchant power, during 2001 and 2002, conditions in merchant energy markets changed dramatically, reducing prospects for profitability and leading to cessation of new merchant development activities in 2003. During 2003, the company announced that it would re-focus on its regulated utilities and its profitable unregulated businesses, and reduce its exposure to the merchant power sector. This led to the decision in 2003 to exit the Union and Gila River power stations (see Note 20 for additional details). During 2004, wholesale power prices remained weak and prospects for price recovery for the next several
years remained poor. While management monitored these events throughout 2004, there were no specific triggering events prior to the fourth quarter that warranted a SFAS 142 or 144 impairment analysis. In the fourth quarter of 2004, management conducted a review of prospects for long-term price recovery as well as opportunities for sales of the assets. This review led to the sale of the company’s investment in the Frontera power station in December 2004 (see Note 16). Also as a result of this review, management determined as of Dec. 31, 2004 there existed a lower probability that the remaining merchant investments would be held for the long term resulting in the impairments to the Dell, McAdams, and Commonwealth Chesapeake power stations described below. During 2005, an additional impairment was made to McAdams, also discussed below.
In the fourth quarter of 2005, a pretax impairment charge of $3.2 million ($2.1 million after tax) was recognized related to the company’s investment in the McAdams power station. The reduction in fair value resulted from an updated strategic review of the potential salvage options (including asset retirement obligations as a result of exiting the facility) following the decision to sell the combustion turbines and certain ancillary equipment to Tampa Electric.
In December 2004, a pretax impairment charge of $609.5 million ($390.7 million after tax) was recognized related to the company’s investments in the Dell and McAdams power stations. Under a probability analysis weighted toward short-term recovery, the investments failed the recoverability test of FAS 144. As a result, the assets were written down to fair market value based on a probability weighting of potential sales of the assets and salvage value, which represented the best estimate of fair market value.
In December 2004, the company recognized a pretax impairment charge of $81.3 million ($52.1 million after tax) related to its investment in the Commonwealth Chesapeake power station. Under a probability analysis weighted toward short-term recovery, the investments failed the recoverability test of FAS 144. As a result, the assets were written down to fair market value based on a probability weighting of potential sales of the assets, which represented the best estimate of fair market value. Of the $81.3 million charge, $4.8 million ($3.1 million after tax) was recorded as an impairment of an intangible asset related to the acquisition of the membership interest in the project and is included in “goodwill and intangible asset impairment” on TECO Energy’s Consolidated Statements of Income.
On Aug. 30, 2004, a TWG Merchant subsidiary completed the sale of its 50% indirect interest in TIE. In the second quarter of 2004 the company recorded a $151.9 million pretax impairment ($98.7 million after tax) to record the estimated write-off of the investment reflecting the anticipated sale. This estimate was finalized resulting in an additional $0.4 million pretax impairment ($0.3 million after tax) being recorded in the third quarter of 2004. See Note 16 for additional details.
In December 2004, a pretax impairment charge of $8.2 million ($5.9 million after tax) was recognized related to the company’s interests in BCH Mechanical. The impairment charge and results of operations are reflected in discontinued operations (see Note 20).
In December 2004, as part of its annual impairment review, pretax impairment charges of $21.1 million ($12.8 million after tax) were recognized to write off the remaining value of steam turbines originally planned for use in a cogeneration project. Based on management’s review of the market for steam turbines and its refocus on its core businesses, it was determined that the turbines should be written down to fair market value. In December 2003, pretax asset impairment charges of $27.8 million ($17.4 million after tax) were recognized primarily related to the steam turbines and licenses that were also planned for use in a cogeneration project. Although the steam turbine impairment charges were not directly related to TECO Guatemala, they are reflected in the TECO Guatemala segment for accounting purposes, due to the revised segment reporting described in Note 1.
In the first quarter of 2004, Litestream Technologies, LLC, an entity in which TECO Fiber, a subsidiary of TECO Solutions, held an equity investment, was placed into bankruptcy by creditors. As a result of the bankruptcy, the company recognized a pretax loss of $5.5 million ($3.4 million after tax). The loss on the equity investment in Litestream was determined using the estimated fair value of the company’s claims to net assets. The charge is reflected in the Other and eliminations segment.
Additional impairment charges recognized in 2004 included a $2.4 million pretax ($1.5 million after tax) valuation adjustment at TECO Solutions related to a district cooling plant, which is reflected in discontinued operations, and a pretax impairment of $0.9 million ($0.6 million after tax) on ocean-going barges at TECO Transport.
19. Variable Interest Entities
The equity method of accounting is generally used to account for significant investments in arrangements in which we or our subsidiary companies do not have a majority ownership interest or exercise control. A new approach for determining if a reporting entity should consolidate certain legal entities, including partnerships, limited liability companies, or trusts, among others, collectively defined as variable interest entities (VIEs) was developed and later revised under FIN 46 (FIN 46R), Consolidation of Variable Interest Entities, an interpretation of ARB No. 51.
A legal entity is considered a VIE, with some exemptions if specific criteria are met, if it does not have sufficient equity at risk to finance its own activities without relying on financial support from other parties. Additional criteria must be applied to determine if this condition is met or if the equity holders, as a group, lack any one of three stipulated characteristics of a controlling financial interest. If the legal entity is a VIE, then the reporting entity determined to be the primary beneficiary of the VIE must consolidate it. Even if a reporting entity is not obligated to consolidate a VIE, then certain disclosures must be made about the VIE if the reporting entity has a significant variable interest.
TECO Energy adopted the provisions of FIN 46 in 2003 without material impact. As of Jan. 1, 2004, FIN 46R was adopted for the remaining VIEs as described below.
Prior to the adoption of FIN 46, the company formed TCAE to own and construct the Alborada Power Station and the company formed CGESJ to own and construct the San José Power Station. Both power stations are located in Guatemala and both
projects obtained long-term power purchase agreements (PPA) with EEGSA, a distribution utility in Guatemala. The terms of the two separate PPAs include EEGSA’s right to the full capacity of the plants for 15 years, U.S. dollar based capacity payments, certain terms for providing fuel, and certain other terms including the right to extend the Alborada and San José contracts. Management believes that EEGSA is the primary beneficiary of the variable interests in TCAE and CGESJ due to the terms of the PPAs. Accordingly, both entities were deconsolidated as of Jan. 1, 2004. The TCAE deconsolidation resulted in the initial removal of $25 million of debt and $15.1 million of net assets from TECO Energy’s Consolidated Balance Sheet. The San José deconsolidation resulted in the initial removal of $65.5 million of debt and $106.6 million of net assets from TECO Energy’s Consolidated Balance Sheet. The results of operations for the two projects are classified as “Income (loss) from Equity Investments” in TECO Energy’s Consolidated Statements of Income since the date of deconsolidation. TECO Energy’s estimated maximum loss exposure is its equity investment of approximately $118.5 million in these entities. (See Note 14 for additional financial information related to these projects).
Pike Letcher Synfuel, LLC was established as part of the Apr. 1, 2003, sale of TECO Coal’s synthetic fuel production facilities. While TECO Energy’s maximum loss exposure in this entity is its investment of approximately $8.2 million, the company could lose potential earnings and could incur losses related to the production costs for the future production of synthetic fuel, in the event that such production creates non-conventional fuel tax credits in excess of TECO Energy’s or the other buyers’ capacity to generate sufficient taxable income to use such credits or fuel tax credits are reduced or eliminated due to high oil prices. Management believes that the company is the primary beneficiary of this VIE and continues to consolidate the entity under the guidance of FIN 46R.
TECO Transport entered into two separate sale leaseback transactions for certain vessels which were recognized as sales in December 2001 and December 2002, and are currently recognized as operating leases for use of the assets. The sale leaseback transactions were entered into with separate third parties that the company believes meet the definition of a VIE. TECO Transport currently leases two ocean going tugboats, four ocean going barges, five river towboats and 49 river barges through these two trusts. The estimated maximum loss exposure faced by TECO Transport is the incremental cost of obtaining suitable replacement equipment to meet the company’s contractual shipping obligations. In accordance with the guidance of FIN 46R, management has concluded that the company is not the primary beneficiary of the lessor trusts and continues to report only the impacts of the operating leases and any other required cash contributions.
In 1992, a subsidiary of the company, Hardee Power Partners, Ltd. commenced construction of the Hardee Power Station in central Florida. HPP obtained dual 20-year PPAs with Tampa Electric and another Florida utility company to provide peaking capacity. The company sold its interest in HPP to an affiliate of Invenergy LLC and GTCR Golder Rauner LLC in 2003. Under FIN 46R, the company is required to make an exhaustive effort to obtain sufficient information to determine if HPP is a VIE and which holder of the variable interests is the primary beneficiary. The new owners of HPP are not willing to provide the information necessary to make these determinations and have no obligation to do so. The information is not available publicly. As a result, the company is unable to determine if HPP is a VIE and if so, which variable interest holder, if any, is the primary beneficiary. The maximum exposure for the company is the ability to purchase electricity under terms of the PPA with HPP at rates unfavorable to the wholesale market. For a description and measure of the purchases of electricity under the HPP PPA, see Note 1 - Purchased Power.
TECO Properties formed a limited liability company (Hernando Oaks, LLC) with a project developer to buy and develop land in Hernando County, Florida into a residential golf community. Hernando Oaks, LLC met the definition of a VIE, due to subordinated financial support in the form of a guarantee by the company on behalf of Hernando Oaks, LLC. The company consolidated Hernando Oaks, LLC as of Jan. 1, 2004, resulting in an increase in assets of $18.5 million and a corresponding increase in liabilities. Hernando Oaks, LLC was sold during 2005.
A subsidiary of TECO Solutions formed a partnership to construct, own and operate a water cooling plant to produce and distribute chilled water to customers via a local distribution loop primarily for use in air conditioning systems. The partnership, TECO AGC, Ltd., met the definition of a VIE due to subordinated financing of $3.3 million provided to the partnership as of Dec. 31, 2003, in addition to the company’s equity investment. The company consolidated TECO AGC, Ltd. as of Jan. 1, 2004 with no material increase in assets or liabilities. TECO AGC, Ltd was sold in 2004.
20. Discontinued Operations and Assets Held for Sale
Union and Gila River Project Companies (TPGC)
On Jun. 1, 2005, the company completed the previously announced sale and transfer of ownership of its indirect subsidiaries Union Power Partners, L.P., Panda Gila River, L.P., Trans-Union Interstate Pipeline, L.P., and UPP Finance Co., LLC, owners of the Union and Gila River power stations in Arkansas and Arizona, respectively (collectively, the Projects) to an entity owned by the Projects’ lenders in the manner set forth in the Projects’ confirmed Joint Plan of Reorganization. In connection with the transfer and the related release of liability, the company and its indirect subsidiaries paid an aggregate of $31.8 million, consisting of $30.0 million to the Project’s lenders as consideration for the release of liability and $1.8 million as reimbursement of legal fees for two non-consenting lenders in the Chapter 11 proceeding. As a result of the transaction, the company recorded a non-cash, pretax gain of $117.7 million ($76.5 million after tax), which is reflected in discontinued operations. Through the May 31, 2005 effective date of the transfer to the lending group, the net equity of the Projects was reduced by accumulated unfunded operating losses primarily related to unpaid accrued interest expense on the Projects. As a result of the recognition of these subsequent losses, the book value of the assets was less than the book value of non-recourse project financing at the effective date of
the sale and transfer to the lending group. Accordingly, the gain on the disposition represents the transfer of equity in the projects and the related non-recourse debt and other liabilities in excess of the asset value of the projects.
As an asset held for sale, the assets and liabilities that were expected to be transferred as part of the sale, as of Dec. 31, 2004, were reclassified in the balance sheet. The results from operations and the gain on sale have been reflected in discontinued operations for all periods presented. The following table provides selected components of discontinued operations for the Union and Gila River project companies.
Components of income from discontinued operations -
Union and Gila River Project Companies
Interest Expense
In accordance with the Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code (SOP 90-7), and the provisions of the U.S. bankruptcy code and the Joint Plan, interest expense on the Project entities’ non-recourse debt subsequent to the bankruptcy filing was not to be paid and was therefore not recorded. Had the bankruptcy proceeding not occurred, the Project entities would have recorded additional pretax interest expense of $44.3 million during 2005, which would have been reported in income (loss) from discontinued operations.
Other transactions
Components of income from discontinued operations include CCC (sold in 2005), BCH Mechanical (sold in 2005), Frontera (sold in 2004), Prior Energy (sold in 2004), TECO BGA (sold in 2004) and TECO AGC (sold in 2004). See Note 16 for additional details related to these sales. Results for 2004 include a $2.4 million pretax ($1.5 million after-tax) asset impairment charge at TECO Solutions related to a district cooling plant.
At Dec. 31, 2005, assets and liabilities held for sale includes TECO Thermal, an investment of TECO Solutions. For all periods presented, the results from operations of each of these entities are presented as discontinued operations on the income statement. There are no assets held for sale as of Dec. 31, 2006.
The following table provides selected components of discontinued operations for transactions other than the Union and Gila River projects (TPGC) transaction:
Components of income from discontinued operations - Other
(1) Results for BCH, TECO Thermal, TECO BGA and Prior Energy include internal financing costs, allocated prior to discontinued operations designation. Internally allocated costs for 2004 were at a pretax rate of 8%, based on the average investment in each subsidiary. There were no internally allocated financing costs to discontinued operations in 2006 or 2005.
Revenues
Discontinued operations for 2005 and 2004 include revenues for energy marketing operations at Prior Energy, which are presented on a net basis in accordance with Emerging Issues Task Force No. (EITF) 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, and EITF 02-3, Recognition and Reporting of Gains and Losses on Energy Trading Contracts Under Issues No. 98-10 and 00-17, to reflect the nature of the contractual relationships with customers and suppliers. As a result, costs netted against revenues for the years ended Dec. 31, 2005 and 2004 were ($0.1) million and $128.0 million, respectively. There were no revenues for Prior Energy in 2006.
(Loss) Gain on sale
As a result of the sale of Frontera in December 2004, the company recognized a pretax loss of $42.1 million ($27.0 million after tax). The sales of Prior Energy and TECO AGC, Ltd. in 2004 did not result in a material gain or loss to the company.
Assets and Liabilities
The following table provides a summary of the carrying amounts of the significant assets and liabilities reported in the combined current and non-current “Assets held for sale” and “Liabilities associated with assets held for sale” line items for all other transactions described above:
Assets held for sale
Liabilities associated with assets held for sale
21. Derivatives and Hedging
From time to time, TECO Energy and its affiliates enter into futures, forwards, swaps and option contracts for the following purposes:
•
To limit the exposure to price fluctuations for physical purchases and sales of natural gas in the course of normal operations at Tampa Electric and PGS;
•
To limit the exposure to interest rate fluctuations on debt securities at TECO Energy and its affiliates;
•
To limit the exposure to electricity, natural gas and fuel oil price fluctuations related to the operations of natural gas-fired and fuel oil-fired power plants at TWG Merchant, prior to the transfer of the Union & Gila power plants in June 2005;
•
To limit the exposure to price fluctuations for physical purchases of fuel at TECO Transport and TECO Coal; and
•
To limit the exposure to synthetic fuel tax credits from TECO Coal’s synthetic fuel produced as a result of changes to the reference price of domestically produced oil.
TECO Energy and its affiliates use derivatives only to reduce normal operating and market risks, not for speculative purposes. The company’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers.
The risk management policies adopted by TECO Energy provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group which is independent of all operating companies.
The company applies the provisions of FAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended by FAS 138, Accounting for Certain Derivative Instruments and Certain Hedging Activity and FAS 149, Amendment on Statement 133 on Derivative Instruments and Hedging Activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value, and to reflect the changes in the fair value of those instruments as either components of OCI or in net income, depending on the designation of those instruments. The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or the loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the instruments’ settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the amount paid or received on the underlying physical transaction.
At Dec. 31, 2006 and 2005, respectively, TECO Energy and its affiliates had derivative assets (current and non-current) totaling $7.2 million and $68.9 million, and liabilities (current and non-current) totaling $74.0 million and $0.3 million. At Dec. 31, 2006 and 2005, accumulated other comprehensive income (AOCI) included $0.1 million and $0.4 million, respectively, of unrealized after-tax gains, representing the fair value of cash flow hedges whose underlying transactions will occur within the next 12 months. Amounts recorded in AOCI reflect the estimated fair value of derivative instruments designated as hedges, based on market prices as of the balance sheet date. These amounts are expected to fluctuate with movements in market prices and may or may not be realized as a loss upon future reclassification from OCI.
For the years ended Dec. 31, 2006, 2005 and 2004, TECO Energy and its affiliates reclassified amounts from OCI (excluding certain reclassifications for interest rate swaps described below) and recognized net pretax gains (losses) of $0.5 million, $5.7 million and $1.2 million, respectively. Amounts reclassified from OCI were primarily related to cash flow hedges for physical
purchases of fuel oil at TECO Transport. For these types of hedge relationships, the gain on the derivative at settlement is reclassified from OCI to earnings, which is offset by the increased cost of spot purchases for fuel oil.
As a result of 1) the suspension of construction on the Dell and McAdams power plants at TWG in 2003 and 2) the maintenance activity on the Frontera Power Station at TWG in early 2003, the company discontinued hedge accounting for purchases of natural gas and sales of electricity which were no longer anticipated to take place within two months of the originally designated time period for delivery. The discontinuation of hedge accounting resulted in a reclassification of a pretax gain of $0.2 million from OCI to earnings, reflecting the fair value of the related derivatives as of the discontinuation date. In addition, as a result of the designation of TPGC as an asset held for sale in 2003, the company concluded that the hedged interest expense for periods beyond the expected disposition date were no longer probable. As a result, the company reclassified pretax losses of $24.0 million ($15.6 million after tax) from OCI to income from discontinued operations in 2004 (see Note 20). Gains and losses on these derivative instruments, subsequent to the discontinuation of hedge accounting treatment, were recorded in earnings.
At Dec. 31, 2006, TECO Energy subsidiaries had derivative assets totaling $7.0 million for transactions related to crude oil options that were not designated as either a cash flow or fair value hedge. These derivatives are marked-to-market with fair value gains and losses recognized through earnings. For the years ended Dec. 31, 2006, 2005 and 2004, the company recognized gains on marked-to-market derivatives of $2.9 million, $0.5 million and $0.8 million, respectively.
22. Subsequent Events
TECO Capital Trust II
On Jan. 16, 2007, all $71.4 million outstanding subordinated notes were retired by TECO Energy pursuant to their original terms. This caused the retirement of $57.5 million trust preferred securities of TECO Capital Trust II, pursuant to their original terms.
Settlement of the Securities Class Action and Derivative Suits
During the scheduled mediation on Feb. 16, 2007, the company reached an agreement in principle to settle the shareholder securities class action lawsuit (“class action suit”) and, at the same time, the company’s officers and directors reached a similar agreement to settle the shareholder derivative lawsuit (“derivative suit”) pending in the Federal District Court in Tampa, Florida and the Florida State Circuit Court for the 13th Circuit in Tampa, respectively, both relating to merchant power activities during 2001 and 2002. The settlement in the class action suit will resolve all issues in the case against the company and the two individual defendants, including the one remaining category of claims that was not dismissed by the federal court’s order issued on Oct. 10, 2006, in response to the company’s motion to dismiss. The settlement in the derivative suit will also reserve all claims against the directors and officers. Under the terms of the settlements, the company’s primary insurance carrier will pay the settlement amount of $17.4 million to completely resolve the class action suit. In the derivative suit, the company will institute certain corporate governance changes along with those previously instituted since the pendency of the suit and the company’s insurance carrier will pay the plaintiff’s attorney’s fees in the amount of $400,000. All defendants in both cases will receive releases of all claims, and both lawsuits will be dismissed with prejudice. The settlement is subject to various conditions, including the execution of definitive agreements and releases, approval by the applicable federal or state court and the appropriate shareholder notices. See Note 12.
23. Quarterly Data (unaudited)
Financial data by quarter is as follows:
(1) Trading prices for common shares
(2) Second quarter 2005 results include a debt extinguishment charge.
(3) Fourth quarter 2005 results include an impairment charge as described in Note 18.
TAMPA ELECTRIC COMPANY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
All other financial statement schedules have been omitted since they are not required, are inapplicable or the required information is presented in the financial statements or notes thereto.
Report of Independent Registered Certified Public Accounting Firm
To the Board of Directors and Shareholders of Tampa Electric Company:
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Tampa Electric Company and its subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 2 to the financial statements, the Company changed its method of accounting for its defined benefit pension and other postretirement plans as of December 31, 2006.
/s/ PricewaterhouseCoopers LLP
Tampa, Florida
February 27, 2006
TAMPA ELECTRIC COMPANY
Consolidated Balance Sheets
The accompanying notes are an integral part of the consolidated financial statements.
TAMPA ELECTRIC COMPANY
Consolidated Balance Sheets (continued)
The accompanying notes are an integral part of the consolidated financial statements.
TAMPA ELECTRIC COMPANY
Consolidated Statements of Income
The accompanying notes are an integral part of the consolidated financial statements.
TAMPA ELECTRIC COMPANY
Consolidated Statements Of Cash Flows
The accompanying notes are an integral part of the consolidated financial statements.
TAMPA ELECTRIC COMPANY
Consolidated Statements Of Retained Earnings
Consolidated Statements of Capitalization
(1) Quarterly dividends paid on Feb. 15, May 15, Aug. 15 and Nov. 15.
(2) Not meaningful
The accompanying notes are an integral part of the consolidated financial statements.
TAMPA ELECTRIC COMPANY
Consolidated Statements of Capitalization (continued)
(1) Tax-exempt securities.
(2) Composite year-end interest rate.
(3) Certain pollution control equipment is pledged to collateralize these bonds.
(4) The interest rate on these bonds was fixed for a five-year term on Aug. 5, 2002
(5) These securities are subject to redemption in whole or in part, at any time, at the option of the company.
(6) These long-term debt agreements contain various restrictive financial covenants.
TAMPA ELECTRIC COMPANY
Consolidated Statements Of Capitalization (continued)
At Dec. 31, 2006, total long-term debt, excluding amounts currently due, had a carrying amount of $1,601.4 million and an estimated fair market value of $1,673.0 million. The estimated fair market value of long-term debt was based on quoted market prices for the same or similar issues, on the current rates offered for debt of the same remaining maturities, or for long-term debt issues with variable rates that approximate market rates, at carrying amounts. The carrying amount of long-term debt due within one year approximated fair market value because of the short maturity of these instruments.
A substantial part of the tangible assets of Tampa Electric is pledged as collateral for the first mortgage bonds issued under Tampa Electric’s first mortgage bond indentures, and certain pollution control equipment is pledged as collateral for the installment contracts payable. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture, and Tampa Electric could cause the lien associated with this indenture to be released at any time. If the lien under the first mortgage bond indenture were released, the terms of the liens on the pollution control equipment would permit Tampa Electric to cause these liens to be discharged, as well. Maturities and annual sinking fund requirements of long-term debt for the years 2007 through 2011 and thereafter are as follows:
Long-Term Debt Maturities
The accompanying notes are an integral part of the consolidated financial statements.
TAMPA ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Significant Accounting Policies
The significant accounting policies are as follows:
Principles of Consolidation
Tampa Electric Company is a wholly-owned subsidiary of TECO Energy, Inc, and is comprised of the Electric division, generally referred to as Tampa Electric, and the Natural Gas division, generally referred to as Peoples Gas System (PGS). All significant intercompany balances and intercompany transactions have been eliminated in consolidation.
The use of estimates is inherent in the preparation of financial statements in accordance with generally accepted accounting principles (GAAP). Actual results could differ from these estimates.
Planned Major Maintenance
Tampa Electric and PGS expense major maintenance costs as incurred. Concurrent with a planned major maintenance outage, the cost of adding or replacing retirement units-of-property is capitalized in conformity with Florida Public Service Commission (FPSC) and Federal Energy Regulatory Commission (FERC) regulations.
Depreciation
Tampa Electric computes depreciation expense by applying composite, straight-line rates (approved by the state regulatory agency) to the investment in depreciable property. Total depreciation expense for the years ended Dec. 31, 2006, 2005 and 2004 was $217.4 million, $215.0 million and $207.5 million, respectively. Total plant acquisition adjustments were $10.0 million as of Dec. 31, 2005. No acquisition adjustments were made in 2006. The provision for total regulated and unregulated utility plant in service, expressed as a percentage of the original cost of depreciable property, was 3.9% for 2006, 4.0% for 2005 and 3.9% for 2004 as approved by the FPSC. Construction work-in progress is not depreciated until the asset is completed or placed in service.
The implementation of FAS 143 in 2003 and FIN 47 in 2005 resulted in increases in the carrying amount of long-lived assets and the reclassification of the accumulated reserve for cost of removal as “Regulatory liabilities” for all periods presented. The adjusted capitalized amount is depreciated over the remaining useful life of the asset. See Note 11.
Allowance for Funds Used During Construction (AFUDC)
AFUDC is a non-cash credit to income with a corresponding charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa Electric’s cost of capital. The rate was 7.79% for 2006 and 2004. Total AFUDC for 2006 and 2004 was $3.8 million and $1.0 million, respectively. No projects qualified for AFUDC in 2005. The base on which AFUDC is calculated excludes construction work-in-progress which has been included in rate base.
Deferred Income Taxes
Tampa Electric Company utilizes the liability method in the measurement of deferred income taxes. Under the liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at current tax rates. Tampa Electric and PGS are regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to customers through future rates.
Investment Tax Credits
Investment tax credits have been recorded as deferred credits and are being amortized as reductions to income tax expense over the service lives of the related property.
Revenue Recognition
Tampa Electric Company recognizes revenues consistent with the Securities and Exchange Commission’s Staff Accounting Bulletin (SAB) 104, Revenue Recognition in Financial Statements. The interpretive criteria outlined in SAB 104 are that 1) there is persuasive evidence that an arrangement exists; 2) delivery has occurred or services have been rendered; 3) the fee is fixed and determinable; and 4) collectibility is reasonably assured. Except as discussed below, Tampa Electric Company recognizes revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer.
The regulated utilities’ (Tampa Electric and PGS) retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by FERC. See Note 3 for a discussion of significant regulatory matters and the applicability of Financial Accounting Standard No. (FAS) 71, Accounting for the Effects of Certain Types of Regulation, to the company.
Revenues and Fuel Costs
Revenues include amounts resulting from cost recovery clauses which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline capacity and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over-recovery or under-recovery of costs plus an interest factor are taken into account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as deferred credits, and under-recoveries of costs are recorded as deferred charges.
Certain other costs incurred by Tampa Electric and PGS are allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. Tampa Electric and PGS accrue base revenues for services rendered but unbilled to provide a closer matching of revenues and expenses. See Note 3.
As of Dec. 31, 2006 and 2005, unbilled revenues of $47.8 million and $52.3 million, respectively, are included in the “Receivables” line item on the balance sheet.
Purchased Power
Tampa Electric purchases power on a regular basis primarily to meet the needs of its retail customers. As a result of the sale of Hardee Power Partners, Ltd. (HPP) in October 2003, power purchases from HPP, subsequent to the sale, are reflected as non-affiliate purchases by Tampa Electric. Tampa Electric’s long-term power purchase agreement from HPP was not affected by the sale of HPP. Under the existing agreement, which has been approved by the FERC and FPSC, Tampa Electric has full entitlement to the output of the CT2B unit at all times and full entitlement to the output of the remaining units at the Hardee power station at all times except when Seminole Electric Cooperative has entitlement due to outages and/or durations on a specified portion of its generating units. Tampa Electric purchased power from non-TECO Energy affiliates, including HPP, at a cost of $221.3 million, $269.7 million and $172.3 million, respectively, for the years ended Dec. 31, 2006, 2005 and 2004. The prudently incurred purchased power costs are recoverable through an FPSC-approved cost recovery clause.
Accounting for Excise Taxes, Franchise Fees and Gross Receipts
Tampa Electric Company is allowed to recover certain costs incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Statements of Income. These amounts totaled $104.2 million, $87.2 million and $83.8 million, for the years ended Dec. 31, 2006, 2005 and 2004, respectively. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. For the years ended Dec. 31, 2006, 2005 and 2004, these totaled $104.0 million, $87.0 million and $83.6 million, respectively.
Excise taxes paid by the regulated utilities are not material and are expensed as incurred.
Asset Impairments
Tampa Electric Company has adopted FAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which supersedes FAS 121, Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of. FAS 144 addresses accounting and reporting for the impairment or disposal of long-lived assets, including the disposal of a component of a business.
In accordance with FAS 144, the company assesses whether there has been impairment of its long-lived assets and certain intangibles held and used by the company when such impairment indicators exist. As of Dec. 31, 2006, the carrying value of all long lived assets was determined to be recoverable. No adjustments for asset impairments were necessary. There were no asset impairments recorded in the years ended Dec. 31, 2005 or 2004.
Restrictions on Dividend Payments and Transfer of Assets
Certain long-term debt at PGS contains restrictions that limit the payment of dividends and distributions on the common stock of Tampa Electric. See Note 9 for additional information on significant financial covenants.
Receivables and Allowance for Uncollectible Accounts
Receivables consist of services billed to residential, commercial, industrial and other customers. An allowance for doubtful accounts is established based on Tampa Electric’s and PGS’s collection experience. Circumstances that could affect Tampa Electric’s and PGS’s estimates of uncollectible receivables include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible.
Reclassifications
Certain prior year amounts, primarily related to income taxes, were reclassified to conform to the current year presentation.
2. New Accounting Pronouncements
Asset Retirement Obligations
FASB Interpretation No. 47 (FIN 47), Accounting for Conditional Asset Retirement Obligation, an Interpretation of FASB Statement No. 143, was issued in March 2005 and became effective as of Dec. 31, 2005. FIN 47 clarifies the term “conditional asset retirement obligation” as a legal obligation to perform an asset retirement activity in which the timing and method of settlement are conditional on a future event that may or may not be within the control of the entity, and clarifies when an entity has sufficient information to reasonably estimate the fair value of an asset retirement obligation. The company implemented FIN 47 during the fourth quarter of 2005. See Note 11 for discussion of the effects of this implementation.
Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans
In September 2006, the Financial Accounting Standards Board (FASB) issued FAS No.158, Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R). This statement of financial accounting standards requires the recognition in the statement of financial position the over-funded or under-funded status of a defined benefit postretirement plan, measured as the difference between the fair value of plan assets and the projected benefit obligation in the case of a defined benefit plan, or the accumulated postretirement benefit obligation in the case of other postretirement benefit plans. Compared to the current recognition of pension and other postretirement obligations on the balance sheet, this standard requires the recognition of: 1) the impact of future salary increases to the pension obligation and 2) the unamortized post-retirement benefit costs that are currently being expensed over the service lives of the participants. This standard also requires recognition in other comprehensive income certain benefit cost components that are not part of net periodic benefit cost, and that the defined benefit plan assets and obligations be measured as of the balance sheet date. For Tampa Electric Company, amounts required to be recorded in “Other comprehensive income” are reflected as a regulatory asset, as pension obligations will be recovered through rates. FAS 158 is effective for publicly-held companies for fiscal years ending after Dec. 15, 2006. The company has adopted the balance sheet recognition provisions of FAS 158 at Dec. 31, 2006 and will adopt the year-end measurement date in 2008. This standard has increased benefit liabilities on the balance sheet by approximately $91.9 million and regulatory assets by approximately $91.9 million. This standard does not affect the results of operations.
Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in the Current Year Financial Statements
In September 2006, the Securities and Exchange Commission staff issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in the Current Year Financial Statements (SAB 108). SAB 108 addresses the diversity in practice by registrants when quantifying the effect of an error on the financial statements and provides guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements. The company has adopted the provisions of SAB No. 108 effective Dec. 31, 2006. The adoption of SAB 108 did not have an impact on the company’s consolidated financial statements.
Fair Value Measurements
In September 2006, the FASB issued FAS No. 157, Fair Value Measurements (FAS 157). FAS 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles, and expands disclosures about fair value measurements. FAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and states that a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability. FAS 157 applies under other accounting pronouncements that require or permit fair value measurements. The effective date is for fiscal years beginning after Nov. 15, 2007. The company is currently assessing the implementation of FAS 157, however, it does not believe it will be material to its results of operations, statement of position or cash flows.
Planned Major Maintenance
In September 2006, the FASB issued FASB Staff Position (FSP) AUG AIR-1 Accounting for Planned Major Maintenance Activities. This FSP effectively removes the accrual-in-advance method of accounting for future planned major maintenance activities. The FASB believes that the accrual-in-advance method results in the recognition of liabilities prior to the occurrence of a transaction or event that obligates the entity and that does not meet the definition of a liability in accordance with FASB Concept No. 6, Elements of Financial Statements. Entities are still permitted to use the built-in overhaul, deferral or direct expensing methods. This FSP is effective for the first fiscal year beginning after Dec. 15, 2006 and the company has adopted this FSP effective Jan. 1, 2007. Because the company has been applying the direct expensing method, the adoption of this FSP did not have a material affect on its results of operations, statement of position or cash flows.
Income Statement Presentation of Taxes Collected on Behalf of Governmental Authorities
In June 2006, the FASB ratified EITF Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (EITF 06-3). EITF 06-3 provides guidance on disclosing the accounting policy for the income statement presentation of any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer on either a gross (included in revenues and costs) or a net (excluded from
revenues) basis. In addition, EITF 06-3 requires disclosure of any such taxes that are reported on a gross basis as well as the amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented. EITF 06-3 will be effective for the company as of Jan. 1, 2007. As EITF 06-3 provides only disclosure requirements, the adoption of this standard will not have an impact on the results of operations, statement of position or cash flows.
Amendment to Derivatives Accounting
In February 2006, the FASB issued FAS No. 155, Accounting for Certain Hybrid Financial Instruments (FAS 155), which amends FAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and FAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. FAS 155 simplifies the accounting for certain derivatives embedded in other financial instruments by permitting fair value re-measurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation. This statement is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after Sep. 15, 2006. The company adopted FAS 155 effective Jan. 1, 2007 and it does not materially impact the company.
Accounting for Uncertainty in Income Taxes
In June 2006, the FASB issued FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109 (FIN 48). FIN 48 prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. Application involves a two-step approach where recognition occurs if the position exceeds a “more likely than not” threshold and the measurement is based on the tax benefit being greater than 50 percent likely of being realized upon settlement with the tax agencies involved. FIN 48 is effective for fiscal years beginning after Dec. 15, 2006. Based on the company’s assessment to date of the tax positions as of Jan. 1, 2007, the company believes that the implementation of Fin 48 during the first quarter of 2007 will have no impact on retained earnings.
3. Regulatory
As discussed in Note 1, Tampa Electric’s and PGS’s retail business are regulated by the FPSC. Tampa Electric is subject to regulation by the Federal Energy Regulatory Commission (“FERC”) under the Public Utility Holding Company Act of 2005 (“PUHCA 2005”), which replaced the Public Utility Holding Company Act of 1935 which was repealed, however, pursuant to a waiver granted in accordance with FERC’s regulations, TECO Energy is not subject to certain of the accounting, record-keeping, and reporting requirements prescribed by FERC’s regulations under PUHCA 2005.
Base Rate - Tampa Electric
Tampa Electric’s rates and allowed return on equity (ROE) range of 10.75% to 12.75% with a midpoint of 11.75% are in effect until such time as changes are occasioned by an agreement approved by the FPSC or other FPSC actions as a result of rate or other proceedings initiated by Tampa Electric, FPSC staff or other interested parties.
Tampa Electric has not sought a base rate increase to recover significant plant investment since 1992, including the Bayside Power Station, which entered service in 2003 and 2004.
Cost Recovery - Tampa Electric
In September 2006, Tampa Electric filed with the FPSC for approval of fuel and purchased power, capacity, environmental and conservation cost recovery rates for the period January 2007 through December 2007. In November, the FPSC approved Tampa Electric’s requested changes. The rates include the costs of natural gas and coal prices expected in 2007, the collection of underestimated fuel and purchased power expenses in 2006, the collection of previously unrecovered 2005 fuel and purchased power expenses, the proceeds from the sale of sulfur dioxide (SO2) emissions allowances and the operating costs for and a return on the capital invested in the first SCR project to enter service on Big Bend Unit 4 as well as the O&M costs associated with the Pre-SCR projects for Big Bend Units 1 - 3 as required by the Environmental Protection Agency (EPA) Consent Decree and Florida Department of Environmental Protection (FDEP) Consent Final Judgment (see Note 8 for additional details regarding projected environmental expenditures). In addition, the rates reflect the FPSC’s September 2004 decision to reduce the annual cost recovery amount for water transportation services for coal and petroleum coke provided under Tampa Electric’s contract with TECO Transport described below (see Note 9). As part of the regulatory process, it is reasonably likely that third parties may intervene on similar matters in the future. The company is unable to predict the timing, nature or impact of such future actions.
Base Rate - PGS
As a result of a base rate proceeding, effective Jan. 16, 2003, PGS’ allowable ROE range is 10.25% to 12.25% with an 11.25% midpoint.
Cost Recovery - PGS
In September 2006, PGS filed its annual request with the FPSC to change its Purchased Gas Adjustment (PGA) cap factor for 2007. The PGA rate can vary monthly due to changes in actual fuel costs but is not expected to exceed the FPSC approved annual cap. In November 2006, the FPSC approved the cap factor under PGS’s PGA for the period January 2007 through December 2007.
SO2 Emission Allowances
The Clean Air Act Amendments of 1990 established SO2 allowances to manage the achievement of SO2 emissions requirements. The legislation also established a market-based SO2 allowance trading component.
An allowance authorizes a utility to emit one ton of SO2 during a given year. The EPA allocates allowances to utilities based on mandated emissions reductions. At the end of each year, a utility must hold an amount of allowances at least equal to its annual emissions. Allowances are fully marketable and, once allocated, may be bought, sold, traded or banked for use currently or in future years. In addition, the EPA withholds a small percentage of the annual SO2 allowances it allocates to utilities for auction sales. Any resulting auction proceeds are then forwarded to the respective utilities. Allowances may not be used for compliance prior to the calendar year for which they are allocated. Tampa Electric accounts for these using an inventory model with a zero basis for those allowances allocated to the company. Tampa Electric recognizes a gain at the time of sale, approximately 95% of which accrues to retail customers through the environmental cost recovery clause.
Over the years, Tampa Electric has acquired allowances through EPA allocations. Also, over time, Tampa Electric has sold unneeded allowances based on compliance and allowances available. The SO2 allowances unneeded and sold in 2006 resulted from lower emissions at Tampa Electric brought about by environmental actions taken by the company under the Clean Air Act.
For the year ended Dec. 31 2006, Tampa Electric sold approximately 44,500 allowances, resulting in proceeds of $45.0 million, the majority of which is included as a cost recovery clause regulatory liability. In the years ended Dec. 31 2005 and 2004, approximately 100,000 and 13,000 allowances were sold for $79.7 million and $7.4 million in proceeds, respectively.
Other Items
Storm Damage Cost Recovery
Following Hurricane Andrew in 1992, Florida’s investor owned utilities (IOUs) were unable to obtain transmission and distribution insurance coverage in the event of hurricanes, tornados or other damage due to destructive acts of nature. Tampa Electric and other IOUs were permitted to implement a self-insurance program effective Jan. 1, 1994 for such costs of restoration, and the FPSC authorized Tampa Electric to accrue $4 million annually to grow its unfunded storm damage reserve.
The costs for restoration associated with hurricanes Charley, Frances and Jeanne in 2004 were approximately $75 million, which exceeded the storm damage reserve by $30 million. These excess costs over the reserve amounts were charged against the reserve and were reflected as a regulatory asset. The storm costs did not reduce earnings but did reduce cash flow from operations. Tampa Electric filed for and received approval from the FPSC to defer prudently incurred storm damage restoration costs to the reserve until alternative accounting treatment is sought.
In June 2005, the FPSC approved a stipulation entered into by Tampa Electric, the OPC and the Florida Industrial Power Users group regarding the treatment of Tampa Electric’s 2004 hurricane costs. Under the stipulation, Tampa Electric agreed to reclassify approximately $39 million of the hurricane restoration costs as plant in service (rate base). With this adjustment and the normal $4 million annual storm accrual, Tampa Electric’s storm reserve is $16 million as of Dec. 31, 2006.
Coal Transportation Contract
In September 2004, the FPSC voted to disallow approximately $14 to $16 million (pretax) of the costs that Tampa Electric can recover from its customers for water transportation services. The decision allows, but does not require, Tampa Electric to rebid the water transportation and terminal service contract. In October 2004, Tampa Electric filed with the FPSC a motion for clarification and reconsideration of the disallowance of recovery of costs under its waterborne transportation contract with TECO Transport. On Mar. 1, 2005, the FPSC heard oral arguments on the motion and denied Tampa Electric’s request for reconsideration and clarification. The impact of the FPSC vote was fully recognized by Tampa Electric in 2004.
Regulatory Assets and Liabilities
Tampa Electric and PGS maintain their accounts in accordance with recognized policies of the FPSC. In addition, Tampa Electric maintains its accounts in accordance with recognized policies prescribed or permitted by the FERC. These policies conform with GAAP in all material respects.
Tampa Electric and PGS apply the accounting treatment permitted by FAS 71, Accounting for the Effects of Certain Types of Regulation. Areas of applicability include deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost recovery clauses that provide for monthly billing charges to reflect increases or decreases in fuel; purchased power, conservation and environmental costs; and deferral of costs as regulatory assets, when cost recovery is ordered over a period longer than a fiscal year, to the period that the regulatory agency recognizes them. Details of the regulatory assets and liabilities as of Dec. 31, 2006 and 2005 are presented in the following table:
Regulatory Assets and Liabilities
(1) Related to plant life and derivative positions.
(2) Amortized over the term of the related debt instrument.
(3) Amortized over a 5-year period with various ending dates.
(4) Related to the adoption of FAS 158. See Note 5.
All regulatory assets are being recovered through the regulatory process. The following table further details our regulatory assets and the related recovery periods:
Regulatory assets
(1) To be recovered through cost recovery clauses approved by the FPSC on a dollar for dollar basis within approximately one year.
(2) Primarily reflects allowed working capital, which is included in rate base and earns an 8.2 % rate of return as permitted by the FPSC.
(3) “Regulatory tax assets” and “Capital structure and other” regulatory assets have a recoverable period longer than a fiscal year and are recognized over the period authorized by the regulatory agency. Also included are unamortized loan costs which are amortized over the life of the related debt instruments. See footnotes 1 and 2 in the prior table for additional information.
4. Income Tax Expense
Tampa Electric Company is included in the filing of a consolidated federal income tax return with TECO Energy and its affiliates. Tampa Electric Company’s income tax expense is based upon a separate return computation. Income tax expense consists of the following components:
Income Tax Expense
Deferred taxes result from temporary differences in the recognition of certain liabilities or assets for tax and financial reporting purposes. The principal components of the company’s deferred tax assets and liabilities recognized in the balance sheet are as follows:
Deferred Income Tax Assets and Liabilities
Deferred income tax assets and liabilities above are included in the balance sheet as follows:
(1) Certain property related assets and liabilities have been netted.
The total income tax provisions differ from amounts computed by applying the federal statutory tax rate to income before income taxes for the following reasons:
Effective Income Tax Rate
5. Employee Postretirement Benefits
Pension Benefits
Tampa Electric Company is a participant in the comprehensive retirement plans of TECO Energy (multi-employer plans), including a non-contributory defined benefit retirement plan which covers substantially all employees. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses allocable to Tampa Electric Company are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy retirement plans. Benefits are based on employees’ age, years of service and final average earnings. In 2006, Tampa Electric Company made contributions totaling $24.8 million to this non-contributory defined benefit plan.
Amounts disclosed for pension benefits also include the unfunded obligations for the supplemental executive retirement plans. These are non-qualified, non-contributory defined benefit retirement plans available to certain members of senior management. In 2006, Tampa Electric Company made a contribution of $1.3 million to these plans.
Tampa Electric Company recorded regulated assets totaling $57.0 million related to the additional minimum pension liability adjustment at Dec. 31, 2006 and $42.1 million for the unfunded pension liability related to the adoption of FAS 158. There were no additional minimum pension liability adjustments recorded at Tampa Electric Company in 2005 or 2004.
Components of net pension expense, reconciliation of the funded status and the accrued pension liability for TECO Energy, Inc. are presented below.
TECO Energy Consolidated
Pension Benefits
Obligations and Funded Status
Tampa Electric Company
(1) The measurement date was Sept. 30, 2006 and 2005.
The accumulated benefit obligation for all defined benefit pension plan was $508.3 million and $509.7 million at Sept. 30, 2006 and 2005 (the measurement dates), respectively.
Information for the TECO Energy consolidated pension plans with an accumulated benefit obligation in excess of plan assets
Components of TECO Energy consolidated Net Periodic Benefit Cost
Tampa Electric Company’s portion of the net periodic benefit costs was $13.6 million, $9.7 million and $5.2 million for 2006, 2005 and 2004, respectively.
The estimated net loss and prior service net (benefits) for the defined benefit pension plans that will be amortized by Tampa Electric Company from regulatory assets into net periodic benefit cost over the next fiscal year total $6.1 million.
Other Postretirement Benefits
TECO Energy and its subsidiaries currently provide certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 meeting certain service requirements. Tampa Electric Company’s contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and Jun. 30, 2001 is limited to a defined dollar benefit based on service. The company contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after Jul. 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2007, the company expects to make a contribution of about $10.1 million to this program. Postretirement benefit levels are substantially unrelated to salary. The company reserves the right to terminate or modify the plans in whole or in part at any time.
On Dec. 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the MMA) was signed into law. Beginning in 2006, the new law added prescription drug coverage to Medicare, with a 28% tax-free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. TECO Energy’s current retiree medical program for those eligible for Medicare (generally over age 65) includes coverage for prescription drugs. The company has determined that prescription drug benefits available to certain Medicare-eligible participants under its defined-dollar-benefit postretirement health care plan are at least “actuarially equivalent” to the standard drug benefits to be offered under Medicare Part D.
On May 19, 2004, the FASB issued FSP 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (FSP 106-2). The guidance in FSP 106-2 requires (a) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and (b) certain disclosures for employers that sponsor postretirement health care plans that provide prescription drug benefits. TECO Energy and its subsidiaries adopted FSP 106-2 retroactive for the second quarter of 2004.
In 2006, the company received its first subsidy payment under Part D and has filed and is awaiting approval for its 2007 Part D subsidy application with the Centers for Medicare and Medicaid Services (CMS).
The following charts summarize the income statement and balance sheet impact for Tampa Electric Company, as well as the benefit obligations, assets, funded status.
Obligations and Funded Status-Other Postretirement Benefits
Components of Net Periodic Other Postretirement Benefit Cost
Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets
The estimated prior service cost and transition obligation for the other postretirement benefit plans that will be amortized at Tampa Electric Company from regulatory assets into net periodic benefit cost over the next fiscal year is $3.8 million.
Other Postretirement Benefit Plan Assets
There are no assets associated with Tampa Electric’s other postretirement benefit plan.
Additional Information for Pensions and Other Postretirement Benefits
The following table presents the incremental effect of adopting SFAS 158 on individual line items on Tampa Electric Company’s consolidated balance sheets as of Dec. 31, 2006:
Weighted-average assumptions used to determine benefit obligations at Sep. 30, (the measurement date)
Weighted-average assumptions used to determine net periodic benefit cost for years ended Dec. 31,
The expected return on assets assumption was based on expectations of long-term inflation, real growth in the economy, fixed income spreads and equity premiums consistent with our portfolio, with provision for active management and expenses paid. The salary increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases. The discount rate assumption was based on a cash flow matching technique developed by our outside actuaries and a review of current economic conditions. This technique matches the yields from high-quality (Aa-graded, non-callable) corporate bonds to the company’s projected cash flows for the pension plan to develop a present value that is converted to a discount rate.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
Contributions
On Aug. 17, 2006, the President signed the Pension Protection Act of 2006 (the Act). While TECO Energy expects the Internal Revenue Service to issue regulations clarifying various terms of the Act, it generally introduces new minimum funding requirements beginning Jan. 1, 2008. TECO Energy’s policy is to fund the plan at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions and minimize PBGC premiums paid by the plan. TECO Energy contributed $36.3 million to the plan in 2006, which included a $30 million contribution in addition to the $6.3 million minimum contribution required. TECO Energy expects to make a $30 million contribution in 2007 and average annual contributions of $22 million in 2008 - 2011. Tampa Electric Company’s portion of the pension contribution in 2007 is estimated at $20.5 million.
Information about TECO Energy’s expected benefit payments for the pension and postretirement benefit plans follows:
Defined Contribution Plan
The company has a defined contribution savings plan covering substantially all employees of TECO Energy and its subsidiaries (the Employers) that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. The company and its subsidiaries match up to 6% of the participant's payroll savings deductions. From Jan. 1, 2004 to Jun. 30, 2004, the company's matching contribution was 55% of eligible participant payroll savings deductions made in the form of the company's common stock. Effective Jul. 1, 2004, employer matching contributions were 30% of eligible participant contributions with additional incentive match of up to 70% of eligible participant contributions based on the achievement of certain operating company financial goals. For the years ended Dec. 31, 2006, 2005 and 2004, Tampa Electric Company recognized expense totaling $4.5 million, $6.3 million and $4.6 million, respectively, related to the matching contributions made to this plan.
6. Short-Term Debt
At Dec. 31, 2006 and 2005, the following credit facilities and related borrowings existed:
(1) Borrowings outstanding are reported as notes payable.
(2) A 3-year facility as of Dec. 31, 2004 (as discussed below).
These credit facilities require commitment fees ranging from 12.5 - 17.5 basis points. The weighted average interest rate on outstanding notes payable at Dec. 31, 2006 and 2005 was 5.45% and 4.45%, respectively.
Tampa Electric Credit Facility
On Oct. 11, 2005, Tampa Electric amended its $150 million bank credit facility, increasing the facility size to $325 million and extending the maturity to Oct. 11, 2010 with optional extensions of up to two additional years with lenders’ consent. Tampa Electric terminated its $125 million 3-year bank credit facility. The amended facility also allows Tampa Electric to increase the facility size by up to $50 million with lenders’ consent; and includes a $50 million sub-limit for letters of credit. The financial covenants were also amended to eliminate the requirement that Tampa Electric maintain a specified ratio of earnings before interest, taxes, depreciation and amortization (EBITDA) to interest, as defined in the agreement, and increase the permissible quarter-end debt to capital, as defined in the agreement, to 65%. As of Dec. 31, 2006, Tampa Electric was in compliance with this requirement.
Tampa Electric Company Accounts Receivable Facility
On Jan. 6, 2005, Tampa Electric Company and TEC Receivables Corp (TRC), a wholly-owned subsidiary of Tampa Electric Company, entered into a $150 million accounts receivable collateralized borrowing facility. The assets of TRC are not intended to be generally available to the creditors of Tampa Electric Company. Under the Purchase and Contribution Agreement entered into in connection with that facility, Tampa Electric Company sells and/or contributes to TRC all of its receivables for the sale of electricity or gas to its retail customers and related rights (the Receivables), with the exception of certain excluded receivables and related rights defined in the agreement, and assigns to TRC the deposit accounts into which the proceeds of such Receivables are paid. The Receivables are sold by Tampa Electric Company to TRC at a discount. Under the Loan and Servicing Agreement among Tampa Electric Company as Servicer, TRC as Borrower, certain lenders named therein and Citicorp North America, Inc. as Program Agent, TRC may borrow up to $150 million to fund its acquisition of the Receivables under the Purchase Agreement. TRC has secured such borrowings with a pledge of all of its assets including the Receivables and deposit accounts assigned to it. Tampa Electric Company acts as Servicer to service the collection of the Receivables. TRC pays program and liquidity fees based on Tampa Electric Company’s credit ratings. The receivables and the debt of TRC are included in the consolidated financial statements of TECO Energy and Tampa Electric Company.
On Dec. 22, 2006, Tampa Electric and TRC extended the maturity of Tampa Electric’s $150 million accounts receivable collateralized borrowing facility from Jan. 5, 2006 to Dec. 21, 2007. As part of this extension, the EBITDA to interest covenant for Tampa Electric was eliminated. Tampa Electric’s debt to capital covenant was increased from 60% to 65%.
7. Common Stock
Tampa Electric Company is a wholly owned subsidiary of TECO Energy, Inc.
(1) TECO Energy, Inc. made an equity contribution to Tampa Electric for $51.8 million in 2006 to support capital generation expansion and environmental projects.
8. Commitments and Contingencies
Capital Investments
For 2007, Tampa Electric expects to spend $400 million, consisting of about $200 million to support system growth and generation reliability, approximately $14 million for distribution system reliability improvements, $13 million for transmission and distribution system storm hardening, $4 million for transmission system improvements to meet reliability requirements, $20 million for an additional natural gas pipeline to improve reliability of supply to the Bayside Power Station, $20 million for coal-fired generation capacity factor and availability improvements, $6 million to complete the addition of two combustion turbines at the Polk Power Station to meet its peaking generation capacity needs, $87 million for the addition of selective catalytic reduction (SCR) equipment at the Big Bend Station for NOx control, and $34 million for other environmental compliance programs. At the end of 2006, Tampa Electric had outstanding commitments of about $198 million, for long-term capitalized maintenance agreements for its combustion turbines, materials and contractors for the SCR projects and for major maintenance outages at Big Bend Station.
Capital expenditures for PGS are expected to be approximately $50 million in 2007. Included in these amounts is an average of approximately $30 million annually for projects associated with customer growth and system expansion. The remainder represents capital expenditures for ongoing renewal, replacement and system safety.
Legal Contingencies
At Dec. 31, 2006, the ultimate resolution of the following specific proceedings is uncertain and no liability has been reserved or can be estimated. At this time, the ultimate outcome of these proceedings is not expected to have a material adverse effect on the company’s results of operations or financial condition.
Tampa Electric Transmission Litigation
In 2003, Tampa Electric completed a transmission project which required the placement of 45 foot and 125 foot transmission structures on public right of way in parts of residential neighborhoods, near the Egypt Lake subdivision in Tampa, Florida, in order to move electricity to the growth areas in the north-west part of its service area. The lawsuits for private nuisance, the Shaw, Acosta, and Alvarez cases were filed shortly thereafter.
The Shaw plaintiffs’ (39 parcels and approximately 55 individuals) appeal of the trial court’s summary judgment denying plaintiffs’ right to a mandatory injunction to remove the poles was decided in favor of the Company on Friday, Jan. 5, 2007. The Shaw case was set for trial on Jan. 8, 2007, but we were able to resolve the case and avoid the effect of a long and expensive trial. The legal principles in the Shaw case should apply to the remaining Acosta and Alvarez cases.
The Acosta plaintiffs are owners of 93 parcels and comprised of about 131 individuals. Many of these plaintiffs do not own property on the streets where the structures were placed. The case has been set for trial in May 2007.
There has been no activity in the Alvarez (substation) case, which involves only one parcel.
Other Issues
From time to time, Tampa Electric Company is involved in various other legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with FAS No. 5, Accounting for Contingencies, to provide for matters that are probable of resulting in an estimable, material loss. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the company’s results of operations or financial condition.
Superfund and Former Manufactured Gas Plant Sites
Tampa Electric Company, through its Tampa Electric and Peoples Gas divisions, is a potentially responsible party (PRP) for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Dec. 31, 2006, Tampa Electric Company has estimated its ultimate financial liability to be approximately $12.3 million, and this amount has been accrued in the company’s financial statements. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.
The estimated amounts represent only the estimated portion of the cleanup costs attributable to Tampa Electric Company. The estimates to perform the work are based on actual estimates obtained from contractors, or Tampa Electric Company’s experience with similar work adjusted for site specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.
Allocation of the responsibility for remediation costs among Tampa Electric Company and other PRPs is based on each party’s relative ownership interest in or usage of a site. Accordingly, Tampa Electric Company’s share of remediation costs varies with each site. In virtually all instances where other PRPs are involved, those PRPs are considered creditworthy.
Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. These costs are recoverable through customer rates established in subsequent base rate proceedings.
Long Term Commitments
Tampa Electric Company has commitments under long-term operating leases, primarily for building space, office equipment and heavy equipment. Total rental expense included in the Consolidated Statements of Income for the years ended Dec. 31, 2006, 2005 and 2004 was $4.2 million, $2.1 million and $6.7 million, respectively.
The following table is a schedule of future minimum lease payments at Dec. 31, 2006 for all operating leases with noncancelable lease terms in excess of one year:
Future Minimum Lease Payments for Operating Leases
In 1994, Tampa Electric bought out a long-term coal supply contract which would have expired in 2004 for a lump sum payment of $25.5 million. In February 1995, the FPSC authorized the recovery of this buy-out amount plus carrying costs through the Fuel and Purchase Power Cost Recovery Clause over the 10-year period beginning Apr. 1, 1995. In 2004, $2.7 million of buy-out costs were amortized to expense. It was fully amortized by the end of 2004.
Guarantees and Letters of Credit
On Jan. 1, 2003, Tampa Electric Company adopted the prospective initial measurement provisions for certain types of guarantees, in accordance with FASB Interpretation No. (FIN) 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34). Upon issuance or modification of a guarantee after Jan. 1, 2003, the company must determine if the obligation is subject to either or both of the following:
•
Initial recognition and initial measurement of a liability; and/or
•
Disclosure of specific details of the guarantee.
Generally, guarantees of the performance of a third party or guarantees that are based on an underlying (where such a guarantee is not a derivative subject to FAS 133) are likely to be subject to the recognition and measurement, as well as the disclosure provisions, of FIN 45. Such guarantees must initially be recorded at fair value, as determined in accordance with the interpretation.
Alternatively, guarantees between and on behalf of entities under common control or that are similar to product warranties are subject only to the disclosure provisions of the interpretation. The company must disclose information as to the term of the guarantee and the maximum potential amount of future gross payments (undiscounted) under the guarantee, even if the likelihood of a claim is remote.
At Dec. 31, 2006, Tampa Electric was not obligated under guarantees or letters of credit for the benefit of third parties, including entities under common control. At Dec. 31, 2006, TECO Energy had provided a fuel purchase guarantee on behalf of Tampa Electric and had outstanding letters of credit on behalf of Tampa Electric in the face amounts of $20.0 million and $0.3 million, respectively.
Financial Covenants
In order to utilize its bank credit facilities, Tampa Electric Company must meet certain financial tests as defined in the applicable agreements. In addition, Tampa Electric Company has certain restrictive covenants in specific agreements and debt instruments. At Dec. 31, 2006, Tampa Electric Company was in compliance with required financial covenants. See Liquidity, Capital Resources-Covenants in Financing Agreements in MD&A.
9. Related Party Transactions
In January 2006, Tampa Electric purchased two 150-megawatt combustion turbines and other ancillary equipment from TPS McAdams for $20.6 million. This has been included in capital expenditures on the Tampa Electric Company Consolidated Statements of Cash Flows for the period ended Dec. 31, 2006.
In October 2003, Tampa Electric signed a five-year contract renewal with an affiliate company, TECO Transport, for integrated waterborne fuel transportation services effective Jan. 1, 2004. The contract calls for inland river and ocean transportation along with river terminal storage and blending services for up to 5.5 million tons of coal annually through 2008.
A summary of activities between Tampa Electric Company and its affiliates follows:
Net transactions with affiliates:
Amounts due from or to affiliates of the company at Dec. 31,
(1) Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.
10. Segment Information
Tampa Electric Company is a public utility operating within the state of Florida. Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to more than 661,000 customers in West Central Florida. Its Peoples Gas System division is engaged in the purchase, distribution and marketing of natural gas for more than 332,000 residential, commercial, industrial and electric power generation customers in the state of Florida.
Segment Information
11. Asset Retirement Obligations
Tampa Electric Company accounts for asset retirement obligations under FAS 143, Accounting for Asset Retirement Obligations. An asset retirement obligation (ARO) for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under an existing or enacted law or statute, a written or oral contract, or by legal construction under the doctrine of promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset.
When the liability is initially recorded, the carrying amount of the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The liability must be revalued each period based on current market prices.
For year ended Dec. 31, 2006, significant revisions to estimated cash flows used in determining the recognized asset retirement obligations were adjusted by $7.3 million at Tampa Electric Company. The amount is related to the increased cost of removal of materials used in the generation and transmission of electricity. For years ended Dec. 31, 2005 and 2004, accretion expense was immaterial and no significant revisions to estimated cash flows were necessary.
In the fourth quarter of 2005, Tampa Electric recorded an increase to net property, plant and equipment of $3.6 million (net of accumulated depreciation of $0.4 million), an increase to regulatory assets of $2.7 million and an increase to asset retirement obligations of $18.3 million (including $12.1 million reclassified from a regulatory liability) as a result of the adoption of FIN 47.
Reconciliation of beginning and ending carrying amount of asset retirement obligations:
(1) Accretion expense recorded as a deferred regulatory asset.
As regulated utilities, Tampa Electric and PGS must file depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as a percentage. The net salvage factor is principally comprised of two components - a salvage factor and a cost of removal or dismantlement factor. The company uses current cost of removal or dismantlement factors as part of the estimation method to approximate the amount of cost of removal in accumulated depreciation.
12. Derivatives and Hedging
Tampa Electric Company enters into futures, forwards, swaps and option contracts to limit the exposure to interest on variable rate debt and price fluctuations for physical purchases and sales of natural gas in the course of normal operations. The company uses derivatives only to reduce normal operating and market risks, not for speculative purposes. The company’s primary objective is to reduce the impact of market price volatility on ratepayers, and uses derivative instruments primarily to optimize the value of physical assets, including generation capacity and natural gas delivery.
The risk management policies adopted by the company provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group which is independent of all operating companies.
The company applies the provisions of FAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended by FAS 138, Accounting for Certain Derivative Instruments and Certain Hedging Activity and FAS 149, Amendment on Statement 133 on Derivative Instruments and Hedging Activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value, and to reflect the changes in the fair value of those instruments as either components of other comprehensive income (OCI) or in net income, depending on the designation of those instruments. The changes in fair value that are recorded in OCI are not immediately recognized in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or the loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of its reclassification. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the amount paid or received on the underlying physical transaction. Additionally, amounts deferred in OCI related to an effective designated cash flow hedge must be reclassified to current earnings if the anticipated hedged transaction is no longer probable of occurring.
As a result of applying the provisions of FAS 71, the change in value of these derivatives is recorded as regulatory assets or liabilities to reflect the impact in the fuel recovery clause and not OCI as is the case with non-regulated entities (see Note 3). At Dec. 31, 2006 and 2005, respectively, the company had net derivative (liabilities) assets of $(73.8) million and $62.8 million. For the years ended Dec. 31, 2006, 2005 and 2004, after-tax gains of $42.6 million, $40.1 million and $5.4 million, respectively, were reclassed from regulatory liabilities.
Based on the fair values of derivatives at Dec. 31, 2006, pretax losses of $70.2 million are expected to be reversed from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months. However, these gains and other future reclassifications from regulatory assets or liabilities will fluctuate with movements in the underlying market price of the derivative instruments. The company does not currently have any cash flow hedges for transactions forecasted to take place in periods subsequent to 2008.
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
Item 9A.
Item 9A. CONTROLS AND PROCEDURES.
TECO Energy, Inc.
Conclusions Regarding Effectiveness of Disclosure Controls and Procedures.
TECO Energy’s management, with the participation of its principal executive officer and principal financial officer, has evaluated the effectiveness of TECO Energy’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this annual report (the “Evaluation Date”). Based on such evaluation, TECO Energy’s principal executive officer and principal financial officer have concluded that, as of the Evaluation Date, TECO Energy’s disclosure controls and procedures are effective.
Management’s Report on Internal Control over Financial Reporting.
Management’s Report on Internal Control Over Financial Reporting is on page 79 of this report.
Management’s assessment of the effectiveness of TECO Energy, Inc.’s internal control over financial reporting as of Dec. 31, 2006 has been audited by PricewaterhouseCoopers LLP, an independent registered certified public accounting firm, as stated in their report which is on pages 79 and 80 of this report.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. A control system, no matter how well designed and operated, can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Changes in Internal Control over Financial Reporting.
There was no change in TECO Energy’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) identified in connection with the evaluation of TECO Energy’s internal controls that occurred during TECO Energy’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, such controls.
Tampa Electric Company
Conclusions Regarding Effectiveness of Disclosure Controls and Procedures.
Tampa Electric Company’s management, with the participation of its principal executive officer and principal financial officer, has evaluated the effectiveness of Tampa Electric Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this annual report (the “Evaluation Date”). Based on such evaluation, Tampa Electric Company’s principal executive officer and principal financial officer have concluded that, as of the Evaluation Date, Tampa Electric Company’s disclosure controls and procedures are effective.
Changes in Internal Control over Financial Reporting.
There was no change in Tampa Electric Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) identified in connection with the evaluation of Tampa Electric Company’s internal controls that occurred during Tampa Electric Company’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, such controls.
Item 9B.
Item 9B. OTHER INFORMATION.
None.
PART III
Item 10.
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
(a) The information required by Item 10 with respect to the directors of the registrant is included under the caption “Election of Directors” in TECO Energy’s definitive proxy statement for its Annual Meeting of Shareholders to be held on May 2, 2007 (Proxy Statement) and is incorporated herein by reference.
(b) The information required by Item 10 concerning executive officers of the registrant is included under the caption “Executive Officers of the Registrant” on page 32 of this report.
(c) The information required by Item 10 concerning Section 16(a) Beneficial Ownership Reporting Compliance is included under that caption in the Proxy Statement and is incorporated herein by reference.
(d) Information regarding TECO Energy’s Audit Committee, including the committee’s financial experts, is included under the caption “Committees of the Board” in the Proxy Statement, and is incorporated herein by reference.
(e) TECO Energy has adopted a code of ethics applicable to all of its employees, officers and directors. The text of the Standards of Integrity is available in the Investors section of the company’s website at www.tecoenergy.com. Any amendments to or waivers of the Standards of Integrity for the benefit of any executive officer or director will also be posted on the website.
Item 11.
Item 11. EXECUTIVE COMPENSATION.
The information required by Item 11 is included in the Proxy Statement beginning with the caption “Compensation Discussion and Analysis” and ending with “Post-Termination Benefits” just above the caption “Ratification of Appointment of Auditor”, and under the caption “Compensation of Directors” and is incorporated herein by reference.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The information required by Item 12 is included under the caption “Share Ownership” in the Proxy Statement, and is incorporated herein by reference.
Equity Compensation Plan Information
(1) The reported amount for the 2004 Equity Incentive Plan excludes performance shares which have been issued or may potentially be issued due to performance, subject to a performance-based vesting schedule. Because of the nature of these awards, these shares have also not been taken into account in calculating the weighted-average exercise price under column (b) of this table.
(2) The reported amount for the 2004 Equity Incentive Plan includes shares which may be issued as restricted stock, performance shares, performance-accelerated restricted stock, bonus stock, phantom stock, performance units, dividend equivalents and other forms of award available for grant under the plan.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
The information required by Item 13 is included under the captions “Certain Relationships and Related Person Transactions” and “Director Independence” in the Proxy Statement, and is incorporated herein by reference.
Item 14.
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.
The information required by Item 14 for TECO Energy is included under the caption “Item 2 - Ratification of Appointment of Auditor” in the Proxy Statement and is incorporated herein by reference.
Tampa Electric Company incurred $0.8 million and $1.0 million in audit related fees rendered by PricewaterhouseCoopers in 2006 and 2005, respectively, including $0.3 million and $0.4 million in 2006 and 2005, respectively, related to Sarbanes-Oxley. No other fees were incurred at Tampa Electric Company in those years, for services rendered by PricewaterhouseCoopers.
PART IV
Item 15.
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.
(a) Certain Documents Filed as Part of this Form 10-K
1. Financial Statements
TECO Energy, Inc. Financial Statements - See index on page 78
Tampa Electric Company Financial Statements - See index on page 128
2. Financial Statement Schedules
Condensed Parent Company Financial Statements Schedule I - pages 160-163
TECO Energy, Inc. Schedule II - page 164
Tampa Electric Company Schedule II - page 165
3. Exhibits - See index beginning on page 169
(b) The exhibits filed as part of this Form 10-K are listed on the Exhibit Index immediately preceding such Exhibits. The Exhibit Index is incorporated herein by reference.
(c) The financial statement schedules filed as part of this Form 10-K are listed in paragraph (a)(2) above, and follow immediately.
SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS
TECO ENERGY, INC.
PARENT COMPANY ONLY
Condensed Balance Sheets
The accompanying notes are an integral part of the condensed financial statements.
SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS
TECO ENERGY, INC.
PARENT COMPANY ONLY
Condensed Statements of Income
The accompanying notes are an integral part of the condensed financial statements.
SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS
TECO ENERGY, INC.
PARENT COMPANY ONLY
Condensed Statements of Cash Flows
The accompanying notes are an integral part of the condensed financial statements.
SCHEDULE I - CONDENSED PARENT COMPANY FINANCIAL STATEMENTS
TECO ENERGY, INC.
PARENT COMPANY ONLY
NOTES TO CONDENSED FINANCIAL STATEMENTS
1. Basis of Presentation
TECO Energy, Inc., on a stand alone basis, (the parent company) has accounted for majority-owned subsidiaries using the equity basis of accounting. These financial statements are presented on a condensed basis. Additional disclosures relating to the parent company financial statements are included under the TECO Energy Notes to Consolidated Financial Statements, which information is hereby incorporated by reference.
The use of estimates is inherent in the preparation of financial statements in accordance with generally accepted accounting principles. Actual results could differ from those estimates.
2. Long-term Obligations
See Note 7 to the TECO Energy Consolidated Financial Statements for a description and details of long-term debt obligations of the parent company.
3. Commitments and Contingencies
See Note 12 to the TECO Energy Consolidated Financial Statements for a description of all material contingencies and guarantees outstanding of the parent company.
4. Subsequent Events
Settlement of the Securities Class Action and Derivative Suits
During the scheduled mediation on Feb. 16, 2007, the company reached an agreement in principle to settle the shareholder securities class action lawsuit (“class action suit”) and, at the same time, the company’s officers and directors settled the shareholder derivative lawsuit (“derivative suit”) pending in the Federal District Court in Tampa, Florida and the Florida State Circuit Court for the 13th Circuit in Tampa, respectively, both relating to merchant power activities during 2001 and 2002. See Note 22 to the TECO Energy Consolidated Financial Statements for further discussion of this subsequent event.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
TECO ENERGY, INC.
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended Dec. 31, 2006, 2005 and 2004
(millions)
(1) Write-off of individual bad debt accounts
(2) Includes $3.1 million charged to discontinued operations for asset impairments for BCH
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
TAMPA ELECTRIC COMPANY
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended Dec. 31, 2006, 2005 and 2004
(millions)
(1) Write-off of individual bad debt accounts
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on February 28, 2007:
Signature
Title
/s/ S. W. HUDSON
S. W. HUDSON
Chairman of the Board,
Director and Chief Executive Officer
(Principal Executive Officer)
/s/ G. L. GILLETTE
G. L. GILLETTE
Executive Vice President
and Chief Financial Officer
(Principal Financial Officer)
/s/ S. W. CALLAHAN
S. W. CALLAHAN
Vice President-Treasury and Risk
Management
(Principal Accounting Officer)
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities indicated on February 28, 2007:
Signature
Title
/s/ S. W. HUDSON
S. W. HUDSON
Chairman of the Board,
Director and Chief Executive Officer
(Principal Executive Officer)
/s/ G. L. GILLETTE
G. L. GILLETTE
Senior Vice President-Finance
and Chief Financial Officer
(Principal Financial Officer)
/s/ P. L. BARRINGER
P. L. BARRINGER
Chief Accounting Officer
(Principal Accounting Officer)
Supplemental Information to Be Furnished With Reports Filed Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered Securities Pursuant to Section 12 of the Act
No annual report or proxy material has been sent to Tampa Electric Company’s security holders because all of its equity securities are held by TECO Energy, Inc.
INDEX TO EXHIBITS
(1) This certification accompanies the Annual Report on Form 10-K and is not filed as part of it.
* Indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. Exhibits filed with periodic reports of TECO Energy, Inc. and Tampa Electric Company were filed under Commission File Nos. 1-8180 and 1-5007, respectively.
Certain instruments defining the rights of holders of long-term debt of TECO Energy, Inc. and its consolidated subsidiaries authorizing in each case a total amount of securities not exceeding 10% of total assets on a consolidated basis are not filed herewith. TECO Energy, Inc. will furnish copies of such instruments to the Securities and Exchange Commission upon request.
Certain instruments defining the rights of holders of long-term debt of Tampa Electric Company authorizing in each case a total amount of securities not exceeding 10% of total assets on a consolidated basis are not filed herewith. Tampa Electric Company will furnish copies of such instruments to the Securities and Exchange Commission upon request.
Executive Compensation Plans and Arrangements
Exhibits 10.1 through 10.17 above are management contracts or compensatory plans or arrangements in which executive officers or directors of TECO Energy, Inc. participate.