Item 1. BUSINESS.
T a m p a Electric Company (Tampa Electric or the company) was incorporated in Florida in 1899 and was reincorporated in 1949. As a result of restructuring in 1981, the company became a subsidiary of TECO Energy, Inc. (TECO Energy), a diversified energy-related holding company. The company is a public utility operating wholly within the state of Florida and 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 substantially all of Hillsborough County and parts of Polk, Pasco and Pinellas Counties, and has an estimated population of over one million. The principal communities served are Tampa, Winter Haven, Plant City and Dade City. In addition, the company engages in wholesale sales to other utilities which consist of broker economy, requirements and other types of service of varying duration and priority. The company has three electric generating stations in or near Tampa and two electric generating stations located near Sebring, a city located in Highlands County in South Central Florida. The company had 2,828 employees as of Jan. 1, 1995, of which 1,154 were represented by the International Brotherhood of Electrical Workers (IBEW) and 333 by the Office and Professional Employees International Union. In 1994, approximately 46 percent of the company's total operating revenue was derived from residential sales, 29 percent from commercial sales, 10 percent from industrial sales and 15 percent from other sales including bulk power sales for resale. No material part of the company's business is dependent upon a single customer or a few customers, the loss of any one or more of whom would have a materially adverse effect on the company, except that 8 customers in the phosphate industry accounted for 5 percent of operating revenues in 1994. The company's business is not a seasonal one, but winter peak loads are experienced due to fewer daylight hours and colder temperatures, and summer peak loads are experienced due to use of air conditioning and other cooling equipment.
Regulation
The retail operations of the company are regulated by the Florida Public Service Commission (FPSC), which has jurisdiction over retail rates, the quality of service, issuances of securities, planning, siting and construction of facilities, accounting and depreciation practices and other matters. The company 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. Federal, state and local environmental laws and regulations cover air quality, water quality, land use, power plant, substation and transmission line siting, noise and aesthetics, solid waste and other environmental matters. See Environmental Matters on page 6.
TECO Transport & Trade Corporation (TECO Transport) and TECO Coal Corporation (TECO Coal), subsidiaries of TECO Energy, sell transportation services and coal to the company and to third parties. The transactions between the company and these affiliates and the prices paid by the company are subject to regulation by the FPSC and FERC, and any charges deemed to be imprudently incurred may not be allowed to be billed to the company's customers. See Utility Regulation on pages 15 and 16.
Competition
The company's retail 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 the self-generation option available to larger industrial users of electric energy. The company anticipates that such users, and possibly commercial and residential customers as well, may seek to expand their options through legislative and/or regulatory initiatives that would permit competition at the retail level. The company intends to take all appropriate actions to retain and expand its retail business and to continue its efforts to reduce costs and provide high quality service to retail customers. There is presently active competition in the wholesale power markets, and this is increasing, largely as a result of the Energy Policy Act of 1992 and related federal initiatives. This Act removed certain regulatory barriers to independent power producers under the Public Utility Holding Company Act of 1935 and required utilities to transmit power from such producers, utilities and others to wholesale customers under certain circumstances. In a related development, the two largest electric utilities in Florida have filed new transmission tariffs with FERC. The company is challenging various aspects of these tariffs on the grounds that they have anti-competitive effects which adversely affect wholesale power markets and the company's ability to compete for wholesale power sales. In addition to these initiatives, the company continues its efforts to increase its wholesale business by reducing costs and maintaining competitive prices.
Retail Pricing
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, including a reasonable return on invested capital. The basic costs, other than fuel and purchased power, of providing electric service are recovered through base rates, which are designed to recover the costs of owning, operating and maintaining the utility system. These costs include operation and maintenance expenses, depreciation and taxes, as well as a return on the company'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 the company's weighted cost of capital, includes its costs for debt and preferred stock, deferred income taxes at a zero cost rate and an allowed return on common equity. Base prices are determined in FPSC price setting hearings that occur at irregular intervals at the initiative of the company, the FPSC or other parties.
Fuel and certain purchased power costs are recovered through levelized monthly charges established pursuant to the FPSC's fuel adjustment and cost recovery clauses. These charges, which are reset semi-annually in an FPSC hearing, are based on estimated costs of fuel and purchased power and estimated customer usage for a specific recovery period, with a true-up adjustment to reflect the variance of actual costs from the projected charges for prior periods. The FPSC may disallow recovery of any costs that it considers imprudently incurred. Certain non-fuel costs and the accelerated recovery of the costs of conversion from oil-fired to coal-fired generation at the company's Gannon Station are recovered through the FPSC's oil backout clause. Accelerated r e c overy of this project's costs is obtained through accelerated depreciation, which is permitted in an amount equal to two-thirds of the net fuel savings of the project. The remaining one-third of the savings is realized on a current basis by customers through the fuel adjustment clause. See further discussion in Note A on page 26.
Fuel
About 99 percent of the company's generation for 1994 was from its coal-fired units. The same level is anticipated for 1995. The company's average fuel cost per million BTU and average cost per ton of coal burned have been as follows:
Average cost per million BTU: 1994 1993 1992 1991 1990
Coal $ 2.22 $ 2.26 $ 2.23 $ 2.22 $ 2.11 Oil $ 2.49 $ 2.69 $ 2.76 $ 3.21 $ 5.21 Gas -- $ 3.52 $ 2.43 $ 1.98 -- Composite $ 2.22 $ 2.27 $ 2.24 $ 2.25 $ 2.14 Average cost per ton of coal burned $53.39 $54.55 $53.65 $53.87 $51.07
The company's generating stations burn fuels as follows: Gannon Station burns low-sulfur coal; Big Bend Station burns coal of a somewhat higher sulfur content; Hookers Point Station burns low-sulfur oil; Phillips Station burns oil of a somewhat higher sulfur content; and Dinner Lake Station, which was placed on long-term reserve standby in March 1994, burns natural gas and oil. Coal. The company burned approximately 6.8 million tons of coal during 1994 and estimates that its coal consumption will be 6.9 million tons for 1995. During 1994, the company purchased approximately 76 percent of its coal under long-term contracts with seven suppliers, including TECO C o a l, and 24 percent of its coal in the spot market or under intermediate-term purchase agreements. About 28 percent of the company's 1994 coal requirements were supplied by TECO Coal. During December 1994, the average delivered cost of coal (including transportation) was $52.40 per ton, or $2.18 per million BTU. The company expects to obtain approximately 69 percent of its coal requirements in 1995 under long-term contracts with six suppliers, including TECO Coal, with the remaining 31 percent in the spot market. The company's long-term coal contracts provide for revisions in the base price to reflect changes in a wide range of cost factors and for suspension or reduction of deliveries if environmental
regulations should prevent the company from burning the coal supplied, provided that a good faith effort has been made to continue burning such coal. The company estimates that about 23 percent of its 1995 coal requirements will be supplied by TECO Coal. For information concerning transactions with affiliated companies, see Note I. on page 33. In 1994, about 85 percent of the company's coal supply was deep-mined and approximately 15 percent was surface-mined. Federal surface-mining laws and regulations have not had any material adverse impact on the company's coal supply or results of its operations. The company, however, cannot predict the effect on the market price of coal of any future mining laws and regulations. Although there are reserves of surface-mineable coal dedicated by suppliers to the company's account, high-quality coal reserves in Kentucky that can be economically surface-mined are being depleted and in the future more coal will be deep-mined. This trend is not expected to result in any significant additional costs to the company. Oil. The company has supply agreements through Dec. 31, 1995 for No. 2 fuel oil and No. 6 fuel oil for its four combustion turbine units, Hookers Point Station and Phillips Station at prices based on Gulf Coast Cargo spot prices. The price for No. 2 fuel oil deliveries taken in December 1994 was $23.00 per barrel, or $3.96 per million BTU. The price for No. 6 fuel oil deliveries taken in August 1994 was $15.10 per barrel, or $2.39 per million BTU. There were no No. 6 fuel oil deliveries taken from September through December 1994.
Franchises
The company holds franchises and other rights that, together with its charter powers, give it the right to carry on its retail business in the localities it serves. The franchises are irrevocable and are not subject to amendment without the consent of the company, although, in certain events, they are subject to forfeiture. Florida municipalities are prohibited from granting any franchise for a term exceeding 30 years. If a franchise is not renewed by a municipality, the franchisee has the statutory right to require the municipality to purchase any and all property used in connection with the franchise at a v a l u ation to be fixed by arbitration. In addition, all of the municipalities except for the cities of Tampa and Winter Haven have reserved the right to purchase the company's property used in the exercise of its franchise, if the franchise is not renewed. T h e c o mpany has franchise agreements with 13 incorporated municipalities within its retail service area. These agreements have various expiration dates ranging from December 2005 to September 2021, including the agreement with the city of Tampa, which expires in August 2006. The company has no reason to believe that any of these franchises will not be renewed. Franchise fees payable by the company, which totaled $19.9 million in 1994, are calculated using a formula based primarily on electric revenues.
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 county rights-of-way granted by the county commissioners of such counties. There is no law limiting the time for which such permits may be granted by counties. There are no fixed expiration dates for the Hillsborough County and Pinellas County agreements. The agreements covering electric operations in Pasco and Polk counties expire in September 2033 and March 2005, respectively.
Environmental Matters
The company's operations are subject to county, state and federal environmental regulations. The Hillsborough County Environmental Protection C o mmission and the Florida Environmental Regulation Commission are responsible for promulgating environmental regulations and coordinating most of the environmental regulation functions performed by the various departments of state government. The Florida Department of Environmental Protection (FDEP) is responsible for the administration and enforcement of the state regulations. The U.S. Environmental Protection Agency (EPA) is the primary federal agency with environmental responsibility. The company has all required environmental permits. In addition, a monitoring program is in place to assure compliance with permit conditions. The company has been identified as one of numerous potentially responsible parties (PRP) with respect to nine Superfund Sites. While the total costs of remediation at these sites may be significant, the company shares potential liability with other PRPs, many of which have substantial assets. The company expects that its liability in connection with these sites will not be significant.
Expenditures. During the five years ended Dec. 31, 1994, the company s p e n t $98.6 million on capital additions to meet environmental requirements, including $45.7 million for the Polk Power Station project. Environmental expenditures are estimated at $69 million for 1995 and $58 million in total for 1996-1999, including, respectively, $65 million and $48 million for the planned Polk Power Station. These totals exclude amounts required to comply with Phase II of the 1990 amendments to the Clean Air Act. The company is complying with the Phase I emission limitations imposed by the Clean Air Act which became effective Jan. 1, 1995 by using blends of lower-sulfur coal and the use of a small quantity of purchased sulfur dioxide allowances. In support of its Phase I compliance plan, the company has entered into two long-term contracts effective in late 1994 for the purchase of low-sulfur coal. To comply with Phase II emission standards set for 2000, the company would likely use blends of low-sulfur coal and flue gas scrubbing. The company expects to spend $35 million of capital to comply with Phase II of the Clean Air Act as described in the Capital Expenditures section on page 14. The aggregate effect of Phase I and Phase II compliance on the utility's price structure is estimated to be 2 percent or less.
In addition to recovering prudently incurred environmental costs through base rates, the company can petition the FPSC for such recoveries on a current basis pursuant to a statutory environmental cost recovery procedure.
Item 2.
Item 2. PROPERTIES.
The company believes that its physical properties are adequate to carry on its business as currently conducted. The properties are generally subject to liens securing long-term debt. The company had four electric generating plants and four combustion turbine units in service with a total net generating capability at Dec. 31, 1994 of 3,393 MWs, including Big Bend (1,747-MW capability for four coal units), Gannon (1,196-MW capability for six coal units), Hookers Point (212-MW capability for five oil units), Phillips (34-MW capability for two diesel units) and four combustion turbine units located at the Big Bend and Gannon stations (204 MWs). Capability as used herein represents the demonstrable dependable load carrying abilities of the generating units during peak periods as proven under actual operating conditions. Units at Hookers Point went into service from 1948 to 1955, at Gannon from 1957 to 1967, and at Big Bend from 1970 to 1985. In 1991, Tampa Electric purchased two power plants (Dinner Lake and Phillips) from the Sebring Utilities Commission (Sebring). Dinner Lake (11-MW capability for one natural gas unit) and Phillips were placed in service by Sebring in 1966 and 1983, respectively. In March 1994, Dinner Lake Station was placed on long-term reserve standby. The company owns approximately 4,350 acres of previously mined phosphate land located in Polk County, Florida. This site will accommodate the planned Polk Unit One electric power plant and additional generating capacity in the future. Polk Unit One is discussed further under Capital Expenditures on pages 14 and 15. The company owns 176 substations having an aggregate transformer c a p a city of 15,231,497 KVA. The transmission system consists of approximately 1,183 pole miles of high voltage transmission lines, and the distribution system consists of 6,791 pole miles of overhead lines and 2,357 trench miles of underground lines. As of Dec. 31, 1994, there were 491,101 meters in service. All of the foregoing property is located within Florida. All plants and important fixed assets are held in fee except that title to some of the properties are subject to easements, leases, contracts, covenants and similar encumbrances and minor defects, of a nature common to properties of the size and character of those of the company. T h e company 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. The company has a long-term lease for the office building in downtown Tampa, Florida, that serves as its headquarters.
Item 3.
Item 3. LEGAL PROCEEDINGS.
None.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matter was submitted during the fourth quarter of 1994 to a vote of the company's security holders through the solicitation of proxies or otherwise.
PART II
Item 5.
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
All of the company's common stock is owned by TECO Energy and, therefore, there is no market for the stock.
The company pays dividends substantially equal to its net income applicable to common stock to TECO Energy. Such dividends totaled $115.8 million for 1994 and $102.4 million for 1993. See Note C on page 28 for a description of restrictions on dividends on the company's common stock.
Item 6.
Item 6. SELECTED FINANCIAL DATA.
(millions of dollars) Year ended Dec. 31, 1994 1993 1992 1991 1990
Operating revenues $1,094.9 $1,041.3 $1,005.7 $ 987.5 $ 939.8 Net income (1) $ 110.1 $ 106.6 $ 110.8 $ 107.4 $ 108.2 Total assets $2,417.8 $2,267.5* $2,104.7* $1,994.5 $1,918.8 Long-term debt $ 607.3 $ 606.6* $ 591.5* $ 513.7 $ 513.9
*These balances have been restated to reflect current year presentation.
( 1 ) 1994 net income includes the effect of a one-time corporate restructuring charge of $13 million, after tax.
Item 7.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
EARNINGS SUMMARY
Tampa Electric's net income for 1994 of $110 million was 3 percent higher than 1993's primarily due to higher revenues partially offset by higher operating and maintenance expenses, and the restructuring charge described below. In 1993, net income was 4 percent lower than in 1992 primarily due to a $10 million non-recurring coal settlement charge in 1993 described in the Other Income (Expense) section on page 13. The company recorded a one-time $21 million pretax restructuring charge ($13 million after tax) in the fourth quarter of 1994. The restructuring program included almost a 10-percent reduction in staffing levels and other cost reductions. Approximately 70 percent of the charge represents costs associated with retirement benefits. See Note F on page 31.
OPERATING RESULTS
The company's operating income before the restructuring charge increased 9 percent in 1994. Higher base revenues from retail customer growth, increased retail energy usage and a retail price increase effective in January were partially offset by higher operating expenses. The company's 1993 operating income was even with 1992's as increased operating income from nearly 2-percent customer growth and a retail price increase were offset by higher operating expenses.
1994 Change 1993 Change 1992 (millions of dollars) Revenues $1,094.9 5.1% $1,041.3 3.5% $1,005.7 Operating expenses 926.5 4.4% 887.2 4.1% 852.5 Operating income before restructuring charge 168.4 9.3% 154.1 .5% 153.2
Restructuring charge 21.3 - - - -
Operating income $ 147.1 -4.5% $ 154.1 .5% $ 153.2
Operating Revenues The company's revenues rose in 1994 with retail customer growth of 2 percent and increased retail energy sales of almost 4 percent. In 1993 customer growth of almost 2 percent and higher long-term contract sales to other utilities increased operating revenues. Retail price increases of $16 million and $12 million became effective January 1994 and February 1993, respectively.
Retail megawatt-hour sales declined slightly in 1993 from 1992, the result of the significant reduction in energy demand from industrial phosphate customers. This industry experienced a sharp recession in 1993. The economy in the company's service area showed significant strength in 1994 after slow growth in 1993 and 1992. As a result residential and commercial energy sales were up by 4 percent in 1994. Sales to the phosphate industry also grew, up by more than 3 percent in 1994 as these companies recovered from their industry-wide recession. With continued economic recovery, total retail energy sales are expected to remain strong. Energy sales growth in the residential and commercial sectors are expected to be 2.5-3.0 percent for the next five years. Energy sales to industrial customers are expected to represent a smaller percentage of total energy sales over the same period. This is primarily due to the depletion of phosphate reserves and the resulting movement of mining activities out of the company's service area. Non-fuel revenues from sales to other utilities were $33 million in 1994, $34 million in 1993 and $33 million in 1992. Energy sold to other utilities declined in 1994 because of lower-priced oil and gas-fired generation available on other systems. By shifting to higher-margin longer-term power sales agreements, the 10-percent decline in sales to other utilities in 1994 resulted in only a 3-percent decline in non-fuel revenues. Signing of longer-term wholesale power sales agreements remains a priority. Within the last three years, the company has added seven bulk power sales contracts of varying capacities and terms. Low-cost, coal- fired generation has allowed the company to market its available capacity successfully.
1994 Change 1993 Change 1992 Megawatt-hour sales (thousands) Residential 5,947 4.2% 5,706 2.6% 5,560 Commercial 4,583 3.4% 4,432 2.3% 4,333 Industrial 2,278 1.9% 2,236 -14.8% 2,625 Other 1,124 4.7% 1,073 3.8% 1,034 Total retail 13,932 3.6% 13,447 -.8% 13,552 Sales for resale 2,102 -9.8% 2,330 -14.0% 2,710 Total energy sold 16,034 1.6% 15,777 -3.0% 16,262
Retail customers 485,698 1.8% 477,010 1.7% 468,997 (average)
Operating Expenses Effective cost management and efficiency improvements continued to be principal objectives at the company. Total operating expenses in 1994 included the restructuring charge discussed in the Earnings Summary section on page 9, the $4-million annual charge to develop a transmission and distribution property storm-damage reserve in accordance with regulatory directives described in the Utility Regulation section on pages 15 and 16 and the effects of accounting for fuel expense in accordance with FPSC requirements. Continued emphasis on cost containment limited growth in operating expenses in 1994 to 4 percent, excluding the amounts recovered
through FPSC-approved cost recovery clauses, the $21-million restructuring charge and the $4-million annual accrual for the storm damage reserve. Certain fuel, purchased capacity, conservation and oil backout costs were fully recovered and had no impact on earnings.
1994 Change 1993 Change 1992 (millions of dollars) Fuel $389.3 7.2% $363.2 -4.0% $378.2 Purchased power 33.4 -14.4% 39.0 98.0% 19.7 Total fuel cost 422.7 5.1% 402.2 1.1% 397.9 Other operating expenses 171.6 8.8% 157.7 9.8% 143.6 Maintenance 72.9 2.1% 71.4 4.2% 68.5 Depreciation 115.1 2.9% 111.9 9.6% 102.1 Taxes, federal and state income 57.4 -5.0% 60.5 -2.1% 61.8 Taxes, other than income 86.8 3.9% 83.5 6.2% 78.6 Operating expenses 926.5 4.4% 887.2 4.1% 852.5 Restructuring charge 21.3 - - - - Total operating expenses 947.8 6.8% 887.2 4.1% 852.5
Less: recoverable fuel, purchased capacity, conservation, and oil backout expenses 437.1 3.7% 421.6 3.7% 406.4
Net operating expenses $510.7 9.7% $465.6 4.4% $446.1
Other operating expenses increased 5 percent, excluding amounts recovered through FPSC-approved cost recovery clauses and the $4-million accrual for the storm damage reserve. Included in the increase were higher employee-related expenses, higher accruals for self-insurance liability reserves and increased expenses for regulatory activity. The largest employee-related increase in expense was the pay-at-risk program for all employees. This program, which began in 1992, places a percentage of all employees' pay at risk subject to the company achieving or surpassing various annual goals. The program is strongly linked to operating results; good results in 1994 produced a higher payout than in 1993. This program will continue with an increasing pay-at-risk component for all employees in 1995. The restructuring actions taken in 1994 will help mitigate future increases in other operating expenses. The company expects to recover the $ 2 1 -million corporate restructuring charge through lower operating expenses within two years.
The increase in other operating expense in 1993 included $6 million related to changes in accounting for postemployment benefits. Higher medical coverage costs and other employee-related expenses and greater regulatory activity also increased 1993 expenses. Continued efforts at cost control reduced maintenance expense in many areas of the company in 1994 and helped partially offset increased scheduled generating unit maintenance expenses during the year. Ongoing work redesign efforts and equipment modifications and enhancements will help moderate maintenance expense increases in the future. Maintenance expense in 1993 was unchanged from 1992, excluding $2.5 million of oil backout costs which are recovered through a specific FPSC- approved recovery clause. Depreciation expense increased both years because of normal additions to plant and equipment. A large increase in 1993 was due primarily to the transfer of the assets of the Gannon Project Trust to the company. Taxes, other than those on income, were up each year, mainly reflecting higher gross receipts taxes and franchise fees which were included in customer bills. Property taxes also contributed to the increase in 1993. Total fuel cost and purchased power expense was 5 percent higher in 1994 due to the accounting for deferred fuel expense consistent with the FPSC-approved fuel clause. Actual system fuel cost incurred was in line with 1993 due to the mix in operating generating units and the company's success in using lower-priced coals. In 1993 the average fuel price increased due to an unavailability of lower-priced spot coal caused by the United Mine Workers' strike. The company purchased less energy in 1994 because its generating units performed at higher levels of availability. Substantially all fuel and purchased power expenses were recovered through the Fuel and Purchased Power Cost Recovery Clause. Nearly all of the company's generation in the last three years has been from coal, and the fuel mix will continue to be substantially coal. Coal prices are expected to remain stable during the next few years compared with either oil or gas prices, and the company continues to work to reduce its fuel costs.
Coal Contract Buyout In December 1994 the company bought out an existing long-term coal supply contract which would have expired in 2004 for a lump sum payment of $25.5 million and entered into two new contracts with the supplier. The price of the coal supplied under the new contracts was competitive in price with coals of comparable quality. The new contracts will allow the company to increase its participation in a more favorable coal market. At the same time, the company customers will benefit from anticipated net fuel savings of more than $40 million through the year 2004. The company requested and the FPSC authorized it to recover the buy- out cost plus carrying costs through the Fuel and Purchased Power Cost Recovery Clause over the next ten years.
NON-OPERATING ITEMS
Other Income (Expense) Allowance for funds used during construction (AFUDC) in 1994 more than doubled from 1993 levels. AFUDC will continue to increase in 1995 and 1996 with the construction of the company's Polk Unit One. In 1993, the company recorded as other expense a one-time $10-million pretax charge, or 5 cents per share, associated with an FPSC-approved settlement agreement between the company and the Office of Public Counsel, described in the Utility Regulation section on page 15.
Interest Charges Interest charges were $39 million in 1994, 7 percent lower than in 1993 primarily due to the savings from refinancing of long-term debt accomplished in 1993, which substantially offset the impact of rising short-term interest rates in 1994. Interest charges in 1993 were level with 1992. Interest costs in 1993 were affected by lower interest rates and savings from the refinancings as discussed in the Financing Activity section on pages 16 and 17, which offset higher average debt balances.
Income Taxes Total income tax expense for 1994, as described in Note G on pages 31 and 32, was 3 percent higher than in 1993 primarily due to higher pretax income. Effective Jan. 1, 1993, the federal corporate income tax rate increased from 34 percent to 35 percent. This rate increase lowered 1993 earnings by $1.7 million.
ACCOUNTING STANDARDS
Income Tax Accounting Effective Jan. 1, 1993, the company adopted Financial Accounting Standards (FAS) 109, Accounting for Income Taxes, which requires the use of the liability method in accounting for income taxes. The adoption of FAS 109 had no effect on net income or common equity, but did result in certain adjustments to accumulated deferred income taxes and the establishment of corresponding regulatory tax liability and asset accounts reflecting the amounts payable to or recoverable from customers through future rates. The FPSC adopted a rule for accounting for deferred income taxes under FAS 109 requiring that deferred tax adjustments and the related regulatory tax liability be treated the same as accumulated deferred income taxes had been treated in the past. Based on the FPSC rule, the company believes that there will not be any changes in the computation of income tax expense for rate making purposes and thus, no change in its revenue requirements or earnings due to the adoption of FAS 109.
Postemployment Benefits The company adopted FAS 106, Accounting for Postretirement Benefits Other than Pensions, effective Jan. 1, 1993. The rates approved by the FPSC f o r the company in 1993 and 1994 reflect full cost accrual of postretirement benefits as required by FAS 106. The company also adopted FAS 112, Accounting for Postemployment Benefits, in 1993.
Investments in Securities I n 1994 the company adopted FAS 115, Accounting for Certain Investments in Debt and Equity Securities, which requires fair value accounting for these securities. Adopting this standard did not have a significant impact on the company's financial position or results of operations.
CAPITAL EXPENDITURES
Capital expenditures for 1994 were $231 million, which included $6 million of AFUDC. The company spent $97 million in 1994 for construction of Polk Unit One, a 250-megawatt coal-gasification plant. The cash cost of the plant is estimated at about $450 million, net of $110 million in construction funding from the U.S. Department of Energy under its Clean Coal Technology Program. Site preparation and construction began in mid- 1994 with commercial operation expected in the fourth quarter of 1996. In addition, the company spent $128 million for equipment and facilities to serve the growing customer base and provide for generating equipment improvements. The company expects to spend $320 million in 1995 and $570 million during the 1996-1999 period, mainly for distribution facilities to meet customer growth and for construction of Polk Unit One. An estimated $205 million will be spent on this project in 1995, and $60 million in 1996. At the end of 1994, the company had outstanding commitments of about $175 million for the construction of Polk Unit One. Included in the company's expected capital expenditures is $35 million in the 1995 to 1999 period to comply with Phase II of the Clean Air Act, primarily for nitrogen oxide emission reductions, emissions monitoring equipment and sulfur dioxide emission reductions through scrubbing. This amount excludes the capital expenditures that may be required for an additional new scrubber, if required, to comply with the Clean Air Act.
Construction Requirements (millions of dollars)
1994 1995 Actual Estimated Generation expansion $ 97 $205 Production 41 29 Transmission 17 21 Distribution 53 49 General 17 16 225 320 AFUDC 6 20 Total $231 $340
ENVIRONMENTAL COMPLIANCE
The company is complying with the Phase I emission limitations imposed by the Clean Air Act which became effective Jan. 1, 1995 by using blends of lower-sulfur coal and the use of a small quantity of purchased sulfur dioxide allowances. In connection with its Phase I compliance plan, the company has entered into two long-term contracts effective in late 1994 for the purchase of low-sulfur coal. To comply with Phase II emission standards set for 2000, the company would likely use blends of low-sulfur coal and flue gas scrubbing. The aggregate effect of Phase I and Phase II compliance on the utility's price structure is estimated to be 2 percent or less. The company expects to spend $35 million of capital to comply with Phase II of the Clean Air Act as described in the Capital Expenditures section on page 14.
UTILITY REGULATION
Price Increase The FPSC granted the company a $1.2 million base revenue increase and a $10.3 million revenue increase primarily associated with recovery of purchased power capacity payments effective in early February 1993. The utility received an additional base revenue increase of $16 million effective Jan. 1, 1994. The FPSC decision reflected overall allowed regulatory rates of return of 8.20 percent in 1993 and 8.34 percent in 1994, which include an allowed regulatory rate of return on common equity of 12 percent, the midpoint of a range of 11 percent to 13 percent. The FPSC approved for inclusion in rate base $19 million of construction work in progress in 1993 and $55 million in 1994. On March 25, 1994 the FPSC issued an order that changed Tampa Electric's authorized regulatory rate of return on common equity to an 11.35 percent midpoint with a range of 10.35 percent to 12.35 percent, while leaving in effect the rates it had previously established. The FPSC also ordered a $4-million annual accrual to establish an unfunded storm damage reserve for transmission and distribution property and ordered the company to prepare a study of the appropriate annual accrual and the appropriate balance for this reserve. The company filed this study with
the FPSC in September 1994. In February 1995 the FPSC approved the accrual of $4 million annually and a total amount to be reserved of $55 million as supported by the study. The $55 million total amount is subject to review in future years. On July 18, 1994 the FPSC issued an order approving an agreement between its staff and the company to cap the utility's authorized regulatory rate of return on common equity at 12.45 percent for calendar year 1994 only. Any earnings above that amount would be used to increase the storm damage reserve. The company did not exceed the 12.45 percent cap in 1994 and, therefore, accrued only the $4 million to the storm damage reserve. The company expects to file for inclusion of the Polk Unit One in the rate base in 1996. The company is exploring a number of alternatives in addition to its cost reduction efforts to mitigate the impact of any base price change on the total bill that customers pay.
Coal Settlement In February 1993, the FPSC approved an agreement between the company and Public Counsel that resolved all issues relating to prices for coal purchased in the years 1990 through 1992 by the company from its affiliate, Gatliff Coal, a subsidiary of TECO Coal. The company agreed to refund $10 million plus interest to its customers through the fuel adjustment clause over a 12-month period beginning April 1, 1993. In 1993, the company refunded $7.6 million to its customers and refunded the remaining $2.4 million in 1994.
FERC Transmission/Interchange Proceedings The company is one of several utilities that have intervened in Florida Power & Light's (FPL) proceeding before the Federal Energy Regulatory Commission (FERC) in which FPL has requested to change substantially the terms for providing interchange power and transmission services. In addition to challenging the reasonableness and fairness of many provisions of FPL's filing, the company maintains that aspects of the t r a n smission tariffs are anti-competitive and violate FERC's new comparability standard governing open access to transmission. By order of the FERC, evidentiary hearings on the reasonableness of FPL's filing commenced before an administrative law judge in January 1995. Final resolution of the matters at issue is not expected until 1996 or 1997. In response to a transmission tariff filing by Florida Power Corporation (FPC), the company filed with the FERC, on March 16, 1995 a protest and request for hearing claiming ambiguities regarding the availability of transmission services, the lack of support for the tariff rates and charges, the anti-competitive effects of the tariff and lack of compliance with the FERC's comparability standard. The company has requested that FPC be required to clarify the ambiguities in the tariff and provide cost support. Additionally, the company has requested that the FERC set for hearing the comparability issues and competitive impacts of the filing.
FINANCING ACTIVITY
The company's 1994 year-end capital structure was 41 percent debt, 56 percent common equity and 3 percent preferred stock. The company's objective is to maintain a capital structure over time that will support its current credit ratings.
Credit Ratings/Senior Debt Duff & Phelps Moody's(1) Standard & Poor's AA+ Aa1 AA
(1) Credit rating under review, March 1995.
In June 1993, the Hillsborough County Industrial Development Authority issued $20 million of Pollution Control Revenue Bonds for the benefit of the company to finance the cost of waste disposal facilities. The bonds bear interest at a floating rate set daily. At Dec. 31, 1994, $3.7 million remained on deposit with the trustee to finance future expenditures for qualified facilities. In July 1993, the company entered into a forward refunding arrangement for $85.95 million of outstanding Pollution Control Revenue Bonds. Under this arrangement, $85.95 million of new tax-exempt bonds due Dec. 1, 2034 were issued on Dec. 1, 1994 at a 6.25 percent interest rate. The proceeds were used on Feb. 1, 1995 to refund the original series having a 9.9 percent interest rate. For accounting and rate-making purposes, the company recorded interest expense using a blended rate for the original and refunding bonds from July 1993 and will continue to use this blended rate through the maturity dates of the original bonds.
LIQUIDITY, CAPITAL RESOURCES
The company met its cash needs during 1994 largely with internally generated funds and capital contributions from its parent, with the balance from debt. At Dec. 31, 1994, the company had bank credit lines of $140 million available. The company expects to meet its capital requirements for ongoing operations in 1995-1999 substantially from internally generated funds. The company anticipates some capital contributions from its parent and debt financing, primarily in 1995 and 1996.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page No.
Report of Independent Accountants 19
Balance Sheets, Dec. 31, 1994 and 1993 20
Statements of Income for the years ended Dec. 31, 1994, 1993 and 1992 21
Statements of Cash Flows for the years ended Dec. 31, 1994, 1993 and 1992 22
Statements of Retained Earnings for the years ended Dec. 31, 1994, 1993 and 1992 23
Statements of Capitalization, Dec. 31, 1994 and 1993 23-25
Notes to Financial Statements 26-33
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 ACCOUNTANTS
To the Board of Directors of Tampa Electric Company,
We have audited the balance sheets of Tampa Electric Company, (a wholly owned subsidiary of TECO Energy, Inc.) as of Dec. 31, 1994 and 1993, and the related statements of income, cash flows, retained earnings and capitalization for each of the three years in the period ended Dec. 31, 1994. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. 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, e v i dence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Tampa Electric Company as of Dec. 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended Dec. 31, 1994, in conformity with generally accepted accounting principles.
As discussed in Note A to the financial statements, effective Jan. 1, 1993 the company adopted Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes."
COOPERS & LYBRAND L.L.P. Certified Public Accountants
Tampa, Florida Jan. 16, 1995
BALANCE SHEETS (thousands of dollars) Assets Dec. 31, 1994 1993 Property, Plant and Equipment, At Original Cost Utility plant in service $2,854,240 $2,773,652 Construction work in progress 246,089 151,311 3,100,329 2,924,963 Accumulated depreciation (1,115,167) (1,052,979) 1,985,162 1,871,984 Other property 194 201 1,985,356 1,872,185 Current Assets Cash and cash equivalents 7,071 4,499 Short-term investments -- 216 Receivables, less allowance for uncollectibles 103,508 97,997 Inventories, at average cost Fuel 95,831 77,438 Materials and supplies 38,465 37,726 Prepayments 2,675 10,062 247,550 227,938 Deferred Debits Unamortized debt expense 19,782 21,242 Deferred fuel expense 13 13,721 Deferred income taxes 86,514 78,642 Regulatory asset-tax related 30,791 30,859 Other 47,815 22,961 184,915 167,425 $2,417,821 $2,267,548
Liabilities and Capital Capital Common stock $ 775,956 $ 664,631 Retained earnings 173,299 182,939 949,255 847,570 Preferred stock, redemption not required 54,956 54,956 Long-term debt, less amount due within one year 607,270 606,606 1,611,481 1,509,132 Current Liabilities Long-term debt due within one year 1,260 1,245 Notes payable 91,800 81,500 Accounts payable 113,759 87,791 Customer deposits 49,457 47,358 Interest accrued 11,166 10,522 Taxes accrued 2,152 6,151 269,594 234,567 Deferred Credits Deferred income taxes 327,646 334,170 Investment tax credits 63,265 66,033 Regulatory liability-tax related 88,291 92,832 Other 57,544 30,814 536,746 523,849 $2,417,821 $2,267,548 The accompanying notes are an integral part of the financial statements.
STATEMENTS OF INCOME (thousands of dollars)
Year ended Dec. 31, 1994 1993 1992
Operating Revenues Residential $ 505,491 $ 464,096 $ 444,961 Commercial 316,772 298,281 287,422 Industrial-Phosphate 58,282 55,116 70,175 Industrial-Other 49,946 48,906 46,497 Sales for resale 70,433 76,055 72,957 Other 93,941 98,850 83,770 1,094,865 1,041,304 1,005,782 Operating Expenses Operation Fuel 389,333 363,250 378,234 Purchased power 33,437 38,961 19,671 Other 171,589 157,701 143,624 Restructuring charge 21,299 -- -- Maintenance 72,831 71,397 68,501 Depreciation 115,111 111,866 102,081 Taxes-Federal and state income 57,468 60,559 61,809 Taxes-Other than income 86,735 83,513 78,626 947,803 887,247 852,546
Operating Income 147,062 154,057 153,236
Other Income (Expense) Allowance for other funds used during construction 3,541 1,585 -- Other income (expense), net (1,138) (6,676) 186 2,403 (5,091) 186
Income before interest charges 149,465 148,966 153,422
Interest Charges Interest on long-term debt 36,957 39,281 36,896 Other interest 4,590 5,133 6,845 Allowance for borrowed funds used during construction (2,134) (2,096) (1,104) 39,413 42,318 42,637
Net Income 110,052 106,648 110,785 Preferred dividend requirements 3,568 3,568 3,567
Balance Applicable to Common Stock $ 106,484 $ 103,080 $ 107,218
The accompanying notes are an integral part of the financial statements.
STATEMENTS OF CASH FLOWS (thousands of dollars)
Year ended Dec. 31, 1994 1993 1992 Cash Flows from Operating Activities Net income $110,052 $106,648 $110,785 Adjustments to reconcile net income to net cash Depreciation 115,111 111,866 102,081 Deferred income taxes (14,080) 10,793 6,087 Restructuring charge and other cost reductions 21,299 -- -- Investment tax credits, net (5,432) (4,913) (4,139) Allowance for funds used during construction (5,675) (3,681) (1,104) Deferred fuel cost 19,101 (10,018) 2,030 Fuel cost settlement -- 10,000 -- Peabody coal contract buyout (25,500) -- -- Refund to customers (2,428) (7,572) -- Receivables, less allowance for uncollectibles (5,512) (3,941) 2,502 Inventories (18,393) 8,443 15,022 Taxes accrued (10,201) 2,121 2,556 Accounts payable 27,776 6,088 16,757 Other 18,966 (306) 5,528 225,084 225,528 258,105 Cash Flows from Investing Activities Capital expenditures (230,777) (205,642) (156,307) Allowance for funds used during construction 5,675 3,681 1,104 Short-term investments 216 1,718 (1,727) (224,886) (200,243) (156,930) Cash Flows from Financing Activities Proceeds from contributed capital from parent 111,000 37,000 14,000 Proceeds from long-term debt 686 15,636 75,000 Repayment of long-term debt (245) (48,000) (235) Net increase (decrease) in short-term debt 10,300 52,300 (60,100) Dividends (119,367) (105,982) (109,947) 2,374 (49,046) (81,282) Net increase (decrease) in cash and cash equivalents 2,572 (23,761) 19,893 Cash and cash equivalents at beginning of year 4,499 28,260 8,367 Cash and cash equivalents at end of year $ 7,071 $ 4,499 $ 28,260
Supplemental Disclosure of Cash Flow Information Cash paid during the year for: Interest $ 39,808 $ 43,540 $ 42,257 Income taxes $ 83,888 $ 51,426 $ 55,781
The accompanying notes are an integral part of the financial statements.
STATEMENTS OF RETAINED EARNINGS (thousands of dollars)
Year ended Dec. 31, 1994 1993 1992 Balance, Beginning of Year (1) $182,614 $182,273 $181,435 Add-Net income 110,052 106,648 110,785 292,666 288,921 292,220 Deduct-Cash dividends on capital stock Preferred 3,568 3,568 3,567 Common 115,799 102,414 106,380 119,367 105,982 109,947 Balance, End of Year $173,299 $182,939 $182,273
(1) The Retained Earnings balance at Jan. 1, 1994 has been restated to reflect a net $325,000 reclassification of stock issuance expense and additional paid in capital in accordance with a FERC audit recommendation. See Note B on page 28.
STATEMENTS OF CAPITALIZATION Capital Stock Outstanding Cash Dividends Dec.31, 1994 Paid in 1994(1) Current Redemption Per Price Shares Amount(2) Share Amount(2)
Common stock-Without par value 25 million shares authorized N/A 10 $775,956 N/A $115,799
Preferred Stock-$100 Par Value 1.5 million shares authorized 4.32% Cumulative, Series A $103.75 49,600 $ 4,960 $4.32 $ 214 4.16% Cumulative, Series B $102.875 50,000 5,000 $4.16 208 4.58% Cumulative, Series D $101.00 100,000 10,000 $4.58 458 8.00% Cumulative, Series E $102.00 149,960 14,996 $8.00 1,200 7.44% Cumulative, Series F $101.00 200,000 20,000 $7.44 1,488
549,560 $54,956 $3,568 Preferred Stock - No Par 2.5 million shares authorized, none outstanding. Preference Stock - No Par 2.5 million shares authorized, none outstanding. _________________ (1) Quarterly dividends paid on Feb. 15, May 15, Aug. 15 and Nov. 15. (2) Thousands of dollars.
At Dec. 31, 1994, preferred stock had a carrying amount of $55.0 million and an estimated fair market value of $44.3 million. The estimated fair market value of preferred stock was based on quoted market prices.
The accompanying notes are an integral part of the financial statements.
STATEMENTS OF CAPITALIZATION (continued)
(thousands of dollars) Long-Term Debt Outstanding at Dec. 31, Due 1994 1993 First mortgage bonds (issuable in series) 5 1/2% 1996 25,000 25,000 7 3/4% 2022 75,000 75,000 5 3/4% 2000 80,000 80,000 6 1/8% 2003 75,000 75,000 Installment contracts payable(2) 5 3/4% 2007 24,675 24,920 7 7/8% Refunding bonds(3) 2021 25,000 25,000 8% Refunding bonds(3) 2022 100,000 100,000 9.9%(4) 2011-2014 85,950 85,950 Variable rate: 4.10% for 1994 and 2.12% for 1993(1) 2025 51,605 51,605 Variable rate: 4.02% for 1994 and 2.12% for 1993(1) 2018 54,200 54,200 Variable rate: 4.23% for 1994 and 2.28% for 1993(1)(5) 2020 16,322 15,636 Unamortized debt premium/(discount) (4,222) (4,460) 608,530 607,851 Less amount due within one year(6) (1,260) (1,245) Total Long-Term Debt $607,270 $606,606
Maturities and annual sinking fund requirements of long-term debt for the years 1996, 1997, 1998 and 1999 are $26.0 million, $1.0 million, $1.1 million, and $1.1 million, respectively. Of these amounts $0.8 million per year for 1996 through 1999 may be satisfied by the substitution of property in lieu of cash payments. Substantially all of the property, plant and equipment of the company is pledged as collateral. ___________________________ (1) Composite year-end interest rate. (2) Tax-exempt securities. (3) Proceeds of these bonds were used to refund bonds with interest rates of 11 5/8% - 12 5/8%. For accounting purposes, interest expense has been recorded using blended rates of 8.28%-8.66% on the original and refunding bonds, consistent with regulatory treatment. (4) Under a financing arrangement entered into in July 1993, new tax- exempt bonds were issued in December 1994, the proceeds of which were used to refund this outstanding series when they became eligible for refunding on Feb. 1, 1995. At year-end 1994, the proceeds of the new bonds were on deposit with the trustee. The new refunding series bears an interest rate of 6.25%. For accounting purposes, interest expense has been recorded using a blended rate of 6.52% from July 1993 forward, consistent with regulatory treatment. (5) This amount is recorded net of $3.7 million and $4.4 million at Dec. 31, 1994 and Dec. 31, 1993, respectively on deposit with the trustee. (6) Of the amount due in 1995, $1.0 million may be satisfied by the substitution of property in lieu of cash payments.
The accompanying notes are an integral part of the financial statements.
STATEMENTS OF CAPITALIZATION (continued)
At Dec. 31, 1994, total long-term debt had a carrying amount of $607.3 million and an estimated fair market value of $601.8 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. The carrying amount of long-term debt due within one year approximated fair market value because of the short maturity of these instruments.
The company entered into an interest rate exchange agreement to reduce the cost of $100 million of fixed rate long-term debt. The debt has been refinanced but the exchange agreement will remain in effect until January 1996. The benefit derived from the exchange agreement could range up to $2.3 million depending on floating rate levels. The benefits of this agreement are at risk only in the event of nonperformance by the other party to this agreement or if the floating rate reaches 12.55%. The company does not anticipate nonperformance by the other party. The benefit of the interest rate exchange is used to reduce interest expense. The reduction was $2.3 million per year in 1994, 1993 and 1992.
At Dec. 31, 1994, this interest rate exchange agreement had an estimated fair market value of $2.3 million. Estimated fair market value was based on the expected realizable value to the company upon termination of the agreement.
The accompanying notes are an integral part of the financial statements.
NOTES TO FINANCIAL STATEMENTS
A. Summary of Significant Accounting Policies
Basis of Accounting The company maintains its accounts in accordance with recognized policies prescribed or permitted by the Florida Public Service Commission (FPSC) and the Federal Energy Regulatory Commission (FERC). These policies conform with generally accepted accounting principles in all material respects.
The impact of Financial Accounting Standard (FAS) No. 71, Accounting for the Effects of Certain Types of Regulation, has been minimal in the company's experience, but when cost recovery is ordered over a longer period than a fiscal year, costs are recognized in the period that the regulatory agency recognizes them in accordance with FAS 71.
The company's retail and wholesale businesses are regulated by the FPSC and the FERC, respectively. Prices allowed by both agencies are generally based on recovery of prudent costs incurred plus a reasonable return on invested capital.
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 capacity, oil backout and conservation costs. These adjustment factors are based on costs projected by the company for a specific recovery period. Any over-recovery or under-recovery of costs plus an interest factor are refunded or billed to customers during the subsequent recovery period. Over-recoveries of costs are recorded as deferred credits and under-recoveries of costs are recorded as deferred debits.
Certain other costs incurred by the company 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 company accrues base revenues for services rendered but unbilled to provide a closer matching of revenues and expenses.
On Oct. 27, 1992, pursuant to FPSC approval, the Gannon Project Trust was terminated and the Trust's net assets and debt were placed on the company's balance sheet. At that time, the net assets of the Trust totaled $54.2 million, which included $140.3 million of property, plant and equipment, $87.6 million of accumulated depreciation and $1.5 million of other assets a n d liabilities. Concurrently, the Hillsborough County Industrial Development Authority issued $54.2 million of variable-rate Pollution Control Revenue Refunding Bonds due May 15, 2018 for the benefit of Tampa Electric, the proceeds of which were used to redeem all of the outstanding debt of the Gannon Project Trust. The effect of this non-cash transaction has been netted to arrive at capital expenditures and proceeds from long- term debt in the Statements of Cash Flows.
In February 1993, the FPSC approved an agreement between the company and the Office of Public Counsel that resolved all issues relating to prices for coal purchased in the years 1990 through 1992 by the company from its affiliate, Gatliff Coal, a subsidiary of TECO Coal. The company recognized a $10-million liability in February 1993 and agreed to return this amount plus interest during the 12-month period effective April 1, 1993. The $10- million charge related to this agreement is classified in "Other income (expense)" on the income statement.
Depreciation The company provides for depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage, of depreciable property over its estimated service life. The provision for utility plant in service, expressed as a percentage of the original cost of depreciable property, was 4.2% for 1994, 1993 and 1992.
The original cost of utility plant retired or otherwise disposed of and the cost of removal less salvage are charged to accumulated depreciation.
Deferred Income Taxes Effective Jan.1, 1993, the company adopted FAS 109, which changed the requirements for accounting for income taxes. Although FAS 109 retains the concept of comprehensive interperiod income tax allocation, it adopts the liability method in the measurement of deferred income taxes rather than the deferred method. 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. Since the company is a regulated enterprise and reflects the approved regulatory treatment, the adoption of FAS 109 resulted in 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 and had no effect on earnings.
In 1994, the company reclassed certain deferred tax items on the balance sheet to comply with FERC interpretations of FAS 109 requirements.
Investment Tax Credits Investment tax credits have been recorded as deferred credits and are being amortized to income tax expense over the service lives of the related property.
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 the company's cost of capital. The rate was 7.28% for the final 10 months of 1994, 7.70% for the first two months of 1994 and for all of 1993, and 7.93% for 1992. The base on which AFUDC is calculated excludes construction work in progress which has been included in rate base.
Cash and Cash Equivalents and Short-Term Investments Included in cash and cash equivalents at Dec. 31, 1994 is $3.4 million of securities classified as available-for-sale. Securities classified as a v ailable-for-sale are highly liquid, high-quality debt instruments purchased with a maturity of three months or less.
Short-term investments at Dec. 31, 1993 consisted of various equity investments, stated at lower of aggregate cost or market. Net unrealized gains are not recognized until they are realized. Realized gains and losses are determined on the specific identification cost basis. The carrying amount of these investments approximated fair market value because of their short holding period.
In 1994 the company adopted FAS 115, Accounting for Certain Investments in Debt and Equity Securities, which requires fair value accounting for debt and equity securities. No short-term investments existed at Dec. 31, 1994 and the change in net unrealized gains and losses on trading securities included in earnings in 1994 was not significant.
Reclassifications Certain 1993 and 1992 amounts were reclassified to conform with current year presentation.
B. Common Stock
The company is a wholly owned subsidiary of TECO Energy, Inc.
Common Stock Issue Shares Amount Expense (thousands of dollars) Balance Dec. 31, 1991 10 $615,323 $(1,692) Contributed capital from parent 14,000 -- Balance Dec. 31, 1992 10 629,323 (1,692) Contributed capital from parent 37,000 -- Balance Dec. 31, 1993 10 666,323 (1,692) Contributed capital from parent 111,000 -- Reclassification to other capital accounts(1) (28) 353 Balance Dec. 31, 1994 10 $777,295 $(1,339)
(1) In 1994, a FERC audit recommended that $325,000 of net costs be reclassified from common stock issuance expense and additional paid in capital, to retained earnings. The issuance expense, which totaled $353,000, related to a retired series of preferred stock.
C. Retained Earnings
The company's Restated Articles of Incorporation and certain series of the company's first mortgage bond issues contain provisions that limit the dividend payment on the company's common stock and the purchase or retirement of the company's capital stock. At Dec. 31, 1994, substantially all of the company's retained earnings were available for dividends on its common stock.
D. Retirement Plan
The company is a participant in the comprehensive retirement plan of TECO Energy, which has a non-contributory defined benefit retirement plan which covers substantially all employees. Benefits are based on employees' years of service and average final salary. TECO Energy's policy is to fund the plan within the guidelines set by ERISA for the minimum annual contribution and the maximum allowable as a tax deduction by the IRS. The company's share of net pension expense, excluding the restructuring charge, was $0.9 million for 1994, $1.1 million for 1993 and $1.8 million for 1992. The company's portion of pension expense related to the restructuring charge in 1994 was $12.7 million. About 65 percent of plan assets were invested in common stocks and 35 percent in fixed income investments at Dec. 31, 1994. Components of net pension expense, reconciliation of the funded status and the accrued pension prepayment are presented below for TECO Energy consolidated.
Components of Net Pension Expense (thousands of dollars) 1994 1993 1992 Service cost (benefits earned during the period) $ 8,787 $ 7,665 $ 7,347
Interest cost on projected benefit obligations 15,840 15,052 14,063 Less: Return on plan assets Actual (3,711) 30,495 25,896 Less net amortization of unrecognized transition asset and deferred return (25,811) 10,284 7,696 Net return on assets 22,100 20,211 18,200 Net pension expense 2,527 2,506 3,210 Effect of restructuring charge 13,272 -- -- Net pension expense recognized in the Consolidated Statements of Income $15,799 $ 2,506 $ 3,210
Reconciliation of the Funded Status of the Retirement Plan and the Accrued Pension Prepayment/(Liability) (thousands of dollars) Dec. 31, Dec. 31, 1994 1993 Fair market value of plan assets $239,179 $254,253 Projected benefit obligation (217,993) (207,282) Excess of plan assets over projected benefit obligation 21,186 46,971 Less unrecognized net gain from past experience different from that assumed 23,792 36,426 Less unrecognized prior service cost (7,649) (8,858) Less unrecognized net transition asset (being amortized over 19.5 years) 10,474 11,472 Accrued pension prepayment/(liability) $ (5,431) $ 7,931
Accumulated benefit obligation (including vested benefits of $163,801 for 1994 and $151,213 for 1993) $183,432 $169,212
Assumptions Used in Determining Actuarial Valuations 1994 1993 Discount rate to determine projected benefit obligation 8.25% 7.75% Rates of increase in compensation levels 3.3-5.3% 3.3-5.3% Plan asset growth rate through time 9% 9%
E. Postretirement Benefit Plan
The company currently provides certain postretirement health care benefits for substantially all employees retiring after age 55 meeting certain service requirements. The company contribution toward health care coverage for most employees retiring after Jan. 1, 1990 is limited to a defined dollar benefit based on years of service. Postretirement benefit levels are substantially unrelated to salary. The company reserves the right to terminate or modify the plan in whole or in part at any time.
In 1993, the company adopted FAS 106 that requires postretirement benefits be recognized as earned by employees rather than recognized as paid. Prior to 1993, the cost of these benefits was recognized as benefits were paid and amounted to $2.2 million for eligible retirees in 1992.
Components of Postretirement Benefit Cost (thousands of dollars) 1994 1993
Service cost (benefits earned during the period) $ 1,536 $1,207 Interest cost on projected benefit obligations 4,148 3,616 Amortization of transition obligation (straight line over 20 years) 2,063 2,063 Amortization of actuarial (gain)/loss 214 -- Net periodic postretirement benefit expense 7,961 6,886 Effect of restructuring charge 2,569 -- Net periodic postretirement benefit expense recognized in the statements of Income $10,530 $6,886
Reconciliation of the Funded Status of the Postretirement Benefit Plan and the Accrued Liability (thousands of dollars)
Dec. 31, Dec. 31, 1994 1993 Accumulated postretirement benefit obligation Active employees eligible to retire $ (9,407) $(8,324) Active employees not eligible to retire (19,865) (18,232) Retirees and surviving spouses (32,999) (20,699) (62,271) (47,255) Less unrecognized net gain/(loss) from past experience (14,129) (3,497) Less unrecognized transition obligation (35,880) (39,199) Liability for accrued postretirement benefit $(12,262) $ (4,559)
Assumptions used in Determining Actuarial Valuations
Discount rate to determine projected benefit obligation 8.25% 7.75%
The assumed health care cost trend rate for medical costs prior to age 65, and for certain retirees after age 65, was 11.5% in 1994 and decreases to 5.5% in 2002 and thereafter. The assumed health care cost trend rate for medical costs after age 65 was 8.0% in 1994 and decreases to 5.5% in 2002 and thereafter.
A 1 percent increase in the medical trend rates would produce an 11 percent ($0.5 million) increase in the aggregate service and interest cost for 1994 and a 7 percent ($3.9 million) increase in the accumulated postretirement benefit obligation as of Dec. 31, 1994.
F. Restructuring Charge
In 1994, the company implemented a corporate restructuring program which resulted in a $21 million charge ($13 million after tax). The cost of this r e s t ructuring program, which included 225 early retirements, the elimination of other positions and other cost control initiatives, is expected to be recovered within the next two years through reduced operating expenses. Approximately $1.7 million of this charge was paid in 1994. The impact on pension cost resulting from the restructuring as determined under the provisions of FAS 88, "Accounting for Settlements and C u rtailments of Defined Benefit Pension Plans and for Termination Benefits," was approximately $13.0 million. The impact on postretirement benefits as determined under FAS 106, "Accounting for Postretirement Benefits Other Than Pensions," was approximately $2.6 million. These amounts are included as part of the total charge of $21 million. See Note D on pages 29 and 30, and Note E on pages 30 and 31.
G. Income Tax Expense
The company is included in the filing of a consolidated Federal income tax return with its parent and affiliates. The company's income tax expense is based upon a separate return computation. Income tax expense consists of the following components:
(thousands of dollars) Federal State Total Currently payable $ 68,288 $ 9,948 $ 78,236 Deferred (11,055) (3,026) (14,081) Investment tax credits (569) - (569) Amortization of investment tax credits (4,861) - (4,861) Total income tax expense $ 51,803 $ 6,922 $ 58,725 Included in other income, net 1,257 Included in operating expenses $ 57,468
Currently payable $ 43,616 $ 7,647 $ 51,263 Deferred 9,368 1,425 10,793 Amortization of investment tax credits (4,912) -- (4,912) Total income tax expense $ 48,072 $ 9,072 57,144 Included in other income, net (3,415) Included in operating expenses $ 60,559
(thousands of dollars) Federal State Total Currently payable $ 50,851 $ 8,930 $ 59,781 Deferred 5,187 900 6,087 Investment tax credits (2) -- (2) Amortization of investment tax credits (4,138) -- (4,138) Total income tax expense $ 51,898 $ 9,830 61,728 Included in other income, net (81) Included in operating expenses $ 61,809
The company adopted FAS 109 as of Jan. 1, 1993 and elected not to restate the prior years financial statements. 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:
Dec. 31, Dec. 31, 1994 1993 Deferred tax assets(1) Property related $ 69,798 $ 67,363 Leases 5,200 5,306 Insurance reserves 5,415 2,485 Early capacity payments 2,223 2,565 Other 3,878 923 Total deferred income tax assets 86,514 78,642 Deferred income tax liabilities(1) Property related (336,597) (326,889) Other 8,951 (7,282) Total deferred income tax liabilities (327,646) (334,171) Accumulated deferred income taxes $(241,132) $(255,528) _________________ (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: 1994 1993 1992 Net income $110,052 $106,648 $110,785 Total income tax provision 58,725 57,144 61,728 Income before income taxes $168,777 $163,792 $172,513
Income taxes on above at federal statutory rate (35% for 1994 and 1993 and 34% for 1992) $ 59,072 $ 57,327 $ 58,654 Increase (decrease) due to State income tax, net of federal income tax 4,515 5,921 6,515 Amortization of investment tax credits (4,861) (4,912) (4,138) Other (1) (1,192) 697 Total income tax provision $ 58,725 $ 57,144 $ 61,728 Provision for income taxes as a percent of income before income taxes 34.8% 34.9% 35.8%
H. Short-Term Debt
Notes payable at Dec. 31, 1994 consisted exclusively of commercial paper with weighted average interest rates of 5.92% and 3.31%, respectively, at Dec. 31, 1994 and Dec. 31, 1993. The carrying amount of notes payable approximated fair market value because of the short maturity of these instruments. Unused lines of credit at Dec. 31, 1994 were $140 million. Certain lines of credit require commitment fees of .15% on the unused balances.
I. Related Party Transactions (thousands of dollars)
Net transactions with affiliates are as follows:
1994 1993 1992 Fuel and interchange related, net $180,016 $189,543 $190,085 Administrative and general, net $ 9,038 $ 15,462 $ 10,358
Amounts due from or to affiliates of the company at year-end are as follows:
1994 1993 Accounts receivable $ 1,601 $ 1,720 Accounts payable $ 17,270 $ 20,693
Accounts receivable and accounts payable were incurred in the ordinary course of business and do not bear interest.
J. Commitments and Contingencies
The company has made certain commitments in connection with its continuing capital improvements program. Capital expenditures are estimated to be $320 million for 1995 and $570 million for 1996 through 1999 for equipment and facilities to meet customer growth and for construction of additional generating capacity to be placed in service in 1996. The company is building a 250-MW coal-gasification plant (Polk Unit One) with a capital cost of about $450 million, net of $110 million in construction funding from the Department of Energy under its Clean Coal Technology Program. The company spent $97 million on this project in 1994 and expects to spend $205 million in 1995, and $60 million in 1996. At the end of 1994, the company h a d outstanding commitments of approximately $175 million for the construction of Polk Unit One.
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
During the period from Jan. 1, 1993 to the date of this report, the company has not had and has not filed with the Commission a report as to any changes in or disagreements with accountants, accounting principles or practices, financial statement disclosure, or auditing scope or procedure.
PART III
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
(a) Information concerning Directors of Tampa Electric is as follows: Principal Occupation During Last Five Years and Director Name Age Other Directorships Held Since
Girard F. Anderson 63 President and Chief Operating 1994 Officer, TECO Energy, Inc.; formerly Executive Vice President -Utility Operations, TECO Energy, Inc. and President and Chief Operating Officer, Tampa Electric Company
DuBose Ausley 57 Chairman, Macfarlane, Ausley, 1992 Ferguson & McMullen (attorneys), Tallahassee, Florida; formerly President, Ausley, McMullen, McGehee, Carothers & Proctor, P.A. (attorneys), Tallahassee, Florida; also a director Sprint Corporation and Capital City Bank Group Inc.
Sara L. Baldwin 63 Private Investor; formerly 1980 Vice President, Baldwin and Sons, Inc. (insurance agency), Tampa, Florida
Hugh L. Culbreath 73 Retired; Formerly Chairman of 1971 the Board of TECO Energy, Inc. and Tampa Electric Company
James L. Ferman, Jr. 51 President, Ferman Motor Car 1985 Company, Inc. (automobile dealerships), Tampa, Florida
Edward L. Flom 65 Retired; Formerly Chairman 1980 of the Board and Chief Executive Officer, Florida Steel Corporation (production and fabrication of steel products), Tampa, Florida; also a director of Outback Steakhouse, Inc.
Henry R. Guild, Jr. 66 President and Director, Guild, 1980 Monrad & Oates, Inc. (private trustees and family investment advisers), Boston, Massachusetts
Timothy L. Guzzle 58 Chairman of the Board and 1988 Chief Executive Officer, Tampa Electric Company and TECO Energy, Inc., 1991 to date; and prior thereto, President and Chief Operating Officer of TECO Energy, Inc.; also a director of NationsBank Corporation
Robert L. Ryan 51 Senior Vice President and 1991 Chief Financial Officer, Medtronic, Inc. (medical devices manufacturer), Minneapolis, Minnesota; formerly Vice President-Finance, Union Texas Petroleum Holdings, Inc. (independent oil and gas exploration and production), Houston, Texas; also a director of Riverwood International Corporation and Inter-Regional Financial Group, Inc.
J. Thomas Touchton 56 Managing Partner, The 1987 Witt-Touchton Company (private investment partnership), Tampa, Florida; also a director of 19 Merrill Lynch-sponsored mutual funds
John A. Urquhart 66 President, John A. Urquhart 1991 Associates (management consultants), Fairfield, Connecticut; formerly Senior Vice President, G. E. Industrial & Power Systems, General Electric Company; also a director of Enron Corp., Hubbell, Inc. and Aquarion Company
James O. Welch, Jr. 63 Retired; formerly Vice Chairman, 1976 RJR Nabisco, Inc. and Chairman, Nabisco Brands, Inc.; also a director of Vanguard Group of Investment Companies
The term of office of each director extends to the next annual meeting of shareholders, scheduled to be held on April 19, 1995, and until a successor is elected and qualified. At present, all the directors of the company are also directors of TECO Energy.
(b) Information concerning the current executive officers of the company is as follows: Current Positions and Principal Occupations Name Age During Last Five Years
Timothy L. Guzzle 58 Chairman of the Board and Chief Executive Officer, 1991 to date; also Chairman of the Board and Chief Executive Officer of TECO Energy, Inc., 1991 to date; and prior thereto, President and Chief Operating Officer of TECO Energy, Inc.
Keith S. Surgenor 47 President and Chief Operating Officer, 1994 to date; and prior thereto, Vice President-Human Resources; also Vice President- Human Resources of TECO Energy, Inc.,
William N. Cantrell 42 Vice President-Energy Supply, 1994 to date; Vice President- Energy Resource Planning, 1991 to 1994; and prior thereto, Vice President- Regulatory Affairs.
Gordon L. Gillette 35 Vice President-Regulatory Affairs, 1994 to date; Director-Project Services, TECO Power Services Corporation, 1991 to 1994; and prior thereto, Manager-Project Services, TECO Power Services Corporation.
Lester L. Lefler 54 Vice President-Controller.
Alan D. Oak 48 Vice President, Treasurer and Chief Financial Officer 1992 to date; and prior thereto Chief Financial Officer; also Senior Vice President-Finance, Treasurer and Chief Financial Officer of TECO Energy, Inc.
John B. Ramil 39 Vice President-Energy Services and Planning, 1994 to date; Vice President-Energy Services and Bulk Power, 1994; Director-Resource Planning, 1993 to 1994; and prior thereto, Director-Power Resource Planning.
Harry I. Wilson 56 Vice President-Transmission and Distribution.
There is no family relationship between any of the persons named in response to Item 10. The term of office of each officer extends to and expires at the meeting of the Board of Directors following the next annual meeting of shareholders, scheduled to be held on April 19, 1995, and until a successor is elected and qualified.
Item 11.
Item 11. EXECUTIVE COMPENSATION.
The following tables set forth certain compensation information for the Chief Executive Officer of the company and each of the five other most highly compensated executive officers of the company. The share amounts reported below have been restated to reflect the two-for-one stock split on Aug. 30, 1993.
Aggregated Option/SAR Exercises In Last Fiscal Year and Fiscal Year-End Option/SAR Value
Number of Shares Value of Underlying Unexercised Unexercised In-The-Money Options/SARs Options/SARs at Year-End(#) at Year-End Value Shares Acquired Realized Exercisable/ Exercisable/ Name On Exercise(#) ($) Unexercisable Unexercisable
Timothy L. Guzzle 0 0 160,000/0 $203,750/0 Girard F. Anderson 0 0 96,000/0 $172,375/0 Keith S. Surgenor 0 0 66,000/0 $172,375/0 Alan D. Oak 0 0 52,000/0 $ 66,219/0 William N. Cantrell 0 0 51,600/0 $294,862/0 Harry I. Wilson 0 0 14,200/0 $ 10,769/0
Pension Table
The following table shows estimated annual benefits payable under the company's pension plan arrangements for the named executive officers other than Mr. Guzzle.
Final Three Years of Service Years Average Earnings 5 10 15 20 or more
$100,000 $ 15,000 $ 30,000 $ 45,000 $ 60,000 150,000 22,500 45,000 67,500 90,000 200,000 30,000 60,000 90,000 120,000 250,000 37,500 75,000 112,500 150,000 300,000 45,000 90,000 135,000 180,000 350,000 52,500 105,000 157,500 210,000 400,000 60,000 120,000 180,000 240,000 450,000 67,500 135,000 202,500 270,000 500,000 75,000 150,000 225,000 300,000 550,000 82,500 165,000 247,500 330,000 600,000 90,000 180,000 270,000 360,000 650,000 97,500 195,000 292,500 390,000 700,000 105,000 210,000 315,000 420,000 750,000 112,500 225,000 337,500 450,000
The annual benefits payable to each of the named executive officers are equal to a stated percentage of such officer s average earnings for the three years before his retirement multiplied by his number of years of service, up to a stated maximum. The amounts shown in the table are based on 3% of such earnings and a maximum of 20 years of service. The amounts payable to Mr. Guzzle are based on 6% of earnings and a maximum of 10 years of service.
The earnings covered by the pension plan arrangements are the same as those reported as salary and bonus in the summary compensation table above. Years of service for the named executive officers are as follows: Mr. Guzzle (7 years), Mr. Anderson (35 years), Mr. Surgenor (6 years), Mr. Oak (21 years), Mr. Cantrell (19 years) and Mr. Wilson (32 years). The pension benefit is computed as a straight-life annuity commencing at age 62 and is reduced by an officer s Social Security benefits. The pension plan arrangements also provide death benefits to the surviving spouse of an officer equal to 50% of the benefit payable to the officer. If the officer dies during employment before reaching age 62, the benefit is based on the officer's service as if his employment had continued until age 62. The death benefit is payable for the life of the spouse. If Mr. Guzzle's employment is terminated by the Corporation without cause or by Mr. Guzzle for good reason (as such terms are defined in Mr. Guzzle's employment agreement referred to below), his age and service for purposes of determining benefits under the pension plan arrangements are increased by two years.
Employment and Severance Agreements
TECO Energy has severance agreements with 28 officers of TECO Energy and its subsidiaries, including the executive officers named in the Summary Compensation Table, under which payments will be made under certain circumstances following a change in control of TECO Energy (as defined in the severance agreements). Each officer is required, subject to the terms of the severance agreements, to remain in the employ of TECO Energy or its subsidiaries for one year following a potential change in control (as defined) unless a change in control earlier occurs. The severance agreements provide that in the event employment is terminated by the company or TECO Energy without cause (as defined) or by the officer for good reason (as defined) following a change in control, TECO Energy will make a lump sum severance payment to the officer of two times (three times in the cases of Mr. Guzzle, Mr. Surgenor and Mr. Oak) annual salary and bonus. Upon such termination, the severance agreements also provide for: (i) a cash payment equal to the additional retirement benefit which would have been earned under TECO Energy's retirement plans if employment had continued for two years (three years in the cases of Mr. Guzzle, Mr. Surgenor and Mr. Oak) following the date of termination, and (ii) participation in the life, disability, accident and health insurance plans of TECO Energy for such period except to the extent such benefits are provided by a subsequent employer. Any benefit payable to the officer in connection with a change in control or termination of employment will be reduced to the extent that such payment, taking into account any other compensation provided by TECO Energy, would not be deductible by TECO Energy pursuant to Section 280G of the Internal Revenue Code of 1986. TECO Energy has an employment agreement with Mr. Guzzle providing that if his employment is terminated by TECO Energy without cause or by Mr. Guzzle for good reason, he will receive benefits similar to those provided under the severance agreements described above based upon a level of two times annual salary and bonus and a two-year benefit continuation period. Consistent with his employment agreement, Mr. Guzzle's 1994 option grant provides for a two-year exercise extension period in the event of such a termination.
Compensation of Directors
Directors of TECO Energy and the company who are not employees or former employees of the company, TECO Energy or any of its subsidiaries are paid a combined annual retainer of $20,000 and a fee of $1,000 for attendance at each meeting of the Board of Directors and $500 ($600 for the Committee Chairman) for attendance at each meeting of a Committee of the Board. Directors may elect to defer these amounts with earnings credited at either the 90-day U.S. Treasury bill rate or a rate equal to the total return on TECO Energy's common stock.
TECO Energy has an agreement with Mr. Culbreath under which he will provide consulting services to TECO Energy through December 31, 2000 for compensation at a rate of $175,000 per year. Mr. Culbreath served as Chief Executive Officer of TECO Energy until April 1989 and retired as an employee in April 1990 at which time the consulting relationship commenced. The agreement provides severance benefits (in the event of termination of Mr. Culbreath s consultancy following a change in control) similar to the benefits described under "Executive Compensation--Employment and Severance Agreements" on the preceding page, including a lump sum cash payment of three times annual compensation, except that the amount of such payment is limited to the total of all consulting fees that would have become due under the agreement.
1991 Director Stock Option Plan. TECO Energy has a Director Stock Option Plan in which all non-employee directors of the company and TECO Energy participate. The plan provides automatic annual grants of options to purchase shares of TECO Energy common stock to each non-employee director serving on the TECO Energy Board at the time of grant. The exercise price is the fair market value of the common stock on the date of grant, payable in whole or in part in cash or TECO Energy common stock. The plan provides for an initial grant of options for 10,000 shares for each new director following election to the Board and an annual grant of options for 2,000 shares for each continuing director. Annual grants are made on the first trading day of TECO Energy common stock after its annual meeting. The options are exercisable immediately and expire ten years after grant or earlier as provided in the plan following termination of service on the Board.
Directors' Retirement Plan. All directors who have completed 60 months of service as a director of TECO Energy and who are not employees or former employees of TECO Energy or any of its subsidiaries are eligible to participate in a Directors' Retirement Plan. Under this plan, a retired director or his or her surviving spouse will receive a monthly retirement benefit equal to the monthly retainer last paid to such director for services as a director of TECO Energy or any of its subsidiaries. Such payments will continue for the lesser of the number of months the director served as a director or 120 months, but payments will in any event cease upon the death of the director or, if the director's spouse survives the director, the death of the spouse.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
All outstanding shares of Tampa Electric's common stock are owned by TECO Energy. As of Jan. 31, 1995, none of the directors or executive officers of Tampa Electric or TECO Energy owned any shares of the preferred stock of Tampa Electric.
The following table sets forth the shares of TECO Energy common stock beneficially owned as of Jan. 31, 1995 by directors and nominees, the executive officers named in the summary compensation table and Tampa Electric's directors and executive officers as a group. Except as otherwise noted, such persons have sole investment and voting power over the shares. The number of shares of TECO Energy's common stock beneficially owned by any director or executive officer or by all directors and executive officers as a group does not exceed 1% of such shares outstanding at Jan. 31, 1995.
Name Shares (1) Girard F. Anderson 128,095(2)(3) DuBose Ausley 19,322 Sara L. Baldwin 18,918(4) Hugh L. Culbreath 73,850(5) James L. Ferman, Jr. 24,163(6) Edward L. Flom 18,784(7) Henry R. Guild, Jr. 124,373(8) Timothy L. Guzzle 183,445(2)(9) Robert L. Ryan 18,000(10) J. Thomas Touchton 20,000(11) John A. Urquhart 17,301(12) James O. Welch, Jr. 24,600(13) Keith S. Surgenor 76,614(2)(14) Alan D. Oak 81,349(2)(15) William N. Cantrell 71,825(2)(16) Harry I. Wilson 25,361(2) 19 directors and executive officers as a group (including those named above) 946,318(2)(17) __________________
(1) The amounts listed include the following shares that are subject to options granted under the TECO Energy s stock option plans: Mr. Anderson, 96,000 shares; Mr. Ausley, 14,000 shares; Mrs. Baldwin and Messrs. Culbreath, Ferman, Flom, Guild, Ryan, Touchton and Welch, 16,000 shares each; Mr. Urquhart, 13,200 shares; Mr. Guzzle, 160,000 shares; Mr. Surgenor, 66,000 shares; Mr. Oak, 52,000 shares; Mr. Cantrell, 51,600 shares; Mr. Wilson, 14,200 shares; and all directors and executive officers as a group, 636,000 shares. (2) The amounts listed include the following shares that are held by benefit plans of TECO Energy for an officer s account: Mr. Guzzle, 1,445 shares; Mr. Anderson, 8,175 shares; Mr. Surgenor, 1,938 shares; Mr. Oak, 9,219 shares; Mr. Cantrell, 6,420 shares; Mr. Wilson, 11,161 shares; and all directors and executive officers as a group, 49,947 shares. (3) Includes 800 shares owned by Mr. Anderson s wife, as to which shares he disclaims any beneficial interest. (4) Includes 350 shares held by a trust of which Mrs. Baldwin is a trustee.
(5) Includes 8,000 shares owned by Mr. Culbreath s wife, as to which shares he disclaims any beneficial interest. (6) Includes 2,584 shares owned jointly by Mr. Ferman and his wife. Also includes 859 shares owned by Mr. Ferman s wife, as to which shares he disclaims any beneficial interest. (7) Includes 1,596 shares owned by Mr. Flom s wife, as to which shares he disclaims any beneficial interest. (8) Includes 105,973 shares held by trusts of which Mr. Guild is a trustee. Of these shares, 49,850 are held for the benefit of Mr. Culbreath and are also included in the number of shares beneficially owned by him. (9) Includes 20,000 shares owned by a Revocable Living Trust of which Mr. Guzzle is a trustee. (10) Includes 2,000 shares owned jointly by Mr. Ryan and his wife. (11) Includes 4,000 shares owned by a Revocable Living Trust of which Mr. Touchton is the sole trustee. (12) Includes 1,000 shares owned by Mr. Urquhart's wife, as to which shares he disclaims any beneficial interest. (13) Includes 2,000 shares owned by a charitable foundation of which Mr. Welch is a trustee. (14) Includes 8,580 shares owned jointly by Mr. Surgenor and his wife. (15) Includes 20,130 shares owned jointly by Mr. Oak and his wife. (16) Includes 9,600 shares owned jointly by Mr. Cantrell and his wife, and 4,205 shares held by a trust of which Mr. Cantrell is trustee. (17) Includes a total of 42,894 shares owned jointly with spouses and 1,169 shares owned jointly with parent and sibling. Also includes a total of 12,255 shares owned by spouses, as to which shares beneficial interest is disclaimed.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
TECO Energy paid $915,888 for legal services rendered during 1994 by Macfarlane, Ausley, Ferguson & McMullen, of which Mr. Ausley is the chairman.
In addition, reference is made to Note I on page 33.
PART IV
Item 14.
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) 1. Financial Statements - See index on page 18.
2. Financial Statement Schedules - See index on page 18. 3. Exhibits *3.1 Articles of Incorporation (Exhibit 3.1 to Registration Statement No. 2-70653). *3.2 Bylaws as amended on April 16, 1991 (Exhibit 3, Form 10-Q for quarter ended March 31, 1991 of Tampa Electric Company). *4.1 Indenture of Mortgage among Tampa Electric Company, State Street Trust Company and First Savings & Trust Company of T a mpa, dated as of Aug. 1, 1946 (Exhibit 7-A to Registration Statement No. 2-6693). *4.2 Ninth Supplemental Indenture, dated as of April 1, 1966, to Exhibit 4.1 (Exhibit 4-k, Registration Statement No. 2-28417). *4.3 Thirteenth Supplemental Indenture, dated as of Jan. 1, 1 9 7 4, to Exhibit 4.1 (Exhibit 2-g-l, Registration Statement No. 2-51204). *4.4 Sixteenth Supplemental Indenture, dated as of Oct. 30, 1992, to Exhibit 4.1 (Exhibit 4.1, Form 10-Q for the quarter ended Sept. 30, 1992 of Tampa Electric Company). *4.5 Eighteenth Supplemental Indenture, dated as of May 1, 1993, to Exhibit 4.1 (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 1993). *4.6 Installment Purchase and Security Contract between the Hillsborough County Industrial Development Authority and Tampa Electric Company, dated as of March 1, 1972 (Exhibit 4.9, Form 10-K for 1986 of Tampa Electric Company). *4.7 First Supplemental Installment Purchase and Security Contract, dated as of Dec. 1, 1974 (Exhibit 4.10, Form 10-K for 1986 of Tampa Electric Company). *4.8 Third Supplemental Installment Purchase Contract, dated as of May 1, 1976 (Exhibit 4.12, Form 10-K for 1986 of Tampa Electric Company). *4.9 Installment Purchase Contract between the Hillsborough County Industrial Development Authority and Tampa Electric Company, dated as of Aug. 1, 1981 (Exhibit 4.13, Form 10-K for 1986 of Tampa Electric Company). *4.10 Amendment to Exhibit A of Installment Purchase Contract, dated as of April 7, 1983 (Exhibit 4.14, Form 10-K for 1989 of Tampa Electric Company). 4.11 Second Supplemental Installment Purchase Contract, dated as of June 1, 1983. *4.12 Third Supplemental Installment Purchase Contract, dated as of Aug. 1, 1989 (Exhibit 4.16, Form 10-K for 1989 of Tampa Electric Company).
*4.13 Installment Purchase Contract between the Hillsborough County Industrial Development Authority and Tampa Electric Company, dated as of Jan. 31, 1984 (Exhibit 4.13, Form 10-K for 1993 of Tampa Electric Company). 4.14 First Supplemental Installment Purchase Contract, dated as of Aug. 2, 1984. *4.15 Second Supplemental Installment Purchase Contract, dated as of July 1, 1993 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 1993). *4.16 Loan and Trust Agreement among the Hillsborough County Industrial Development Authority, Tampa Electric Company and NCNB National Bank of Florida, dated as of Sept. 24, 1990 (Exhibit 4.1, Form 10-Q for the quarter ended Sept. 30, 1990 of Tampa Electric Company). *4.17 Loan and Trust Agreement, dated as of Oct. 26, 1992 among the Hillsborough County Industrial Development Authority, Tampa Electric Company and NationsBank of Florida, N.A., as trustee (Exhibit 4.2, Form 10-Q for the quarter ended Sept. 30, 1992 of Tampa Electric Company). *4.18 Loan and Trust Agreement, dated as of June 23, 1993, among the Hillsborough County Industrial Development Authority, Tampa Electric Company and NationsBank of Florida, N.A., as trustee (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 1993 of Tampa Electric Company). *10.1 1980 Stock Option and Appreciation Rights Plan, as amended on July 18, 1989 (Exhibit 28.1, Form 10-Q for quarter ended June 30, 1989 of TECO Energy, Inc.). *10.2 Directors' Retirement Plan, dated as of Jan. 24, 1985 (Exhibit 10.23, Form 10-K for 1986 of Tampa Electric Company). 10.3 Supplemental Executive Retirement Plan, as amended on July 18, 1989 (Exhibit *10.14, Form 10-K for 1989 of Tampa Electric Company), as further amended by the First Amendment to TECO Energy Group Supplemental Executive Retirement Plan, effective as of Oct. 1, 1994. *10.4 TECO Energy, Inc. Group Supplemental Retirement Benefits Trust Agreement Amendment and Restatement, dated as of April 27, 1989 (Exhibit 10.15, Form 10-K for 1989 of Tampa Electric Company) with Exhibit A as amended Dec. 1, 1989 (Exhibit 10.2, Form 10-Q for the quarter ended March 31, 1990 of TECO Energy, Inc.), as further amended by First Amendment to 1989 Restatement dated as of July 20, 1993 (Exhibit 10.5, Form 10-Q for the quarter ended Sept. 30, 1993 of Tampa Electric Company). *10.5 Annual Incentive Compensation Plan for Tampa Electric Company, as amended on April 27, 1989 (Exhibit 28.1, Form 10-Q for quarter ended March 31, 1989 of Tampa Electric Company). *10.6 TECO Energy, Inc. Group Supplemental Disability Income Plan, dated as of March 20, 1989 (Exhibit 10.19, Form 10-K for 1988 of Tampa Electric Company).
*10.7 Forms of Severance Agreements between TECO Energy, Inc. and certain senior executives, dated as of various dates in 1989 (Exhibit 10.18, Form 10-K for 1989 of Tampa Electric Company). *10.8 TECO Energy, Inc. 1990 Equity Incentive Plan (Exhibit 10.1, Form 10-Q for the quarter ended March 31, 1990 of TECO Energy, Inc.). *10.9 TECO Energy, Inc. 1991 Director Stock Option Plan as amended on Jan. 21, 1992 (Exhibit 10.20, Form 10-K for 1991 of Tampa Electric Company). 10.10 Supplemental Executive Retirement Plan for T.L. Guzzle, as amended on July 20, 1993 (Exhibit *10.1, Form 10-Q for the quarter ended Sept. 30, 1993 of Tampa Electric Company), as further amended by the First Amendment to TECO Energy Group Supplemental Executive Retirement Plan for T.L. Guzzle, effective as of Oct. 1, 1994. *10.11 Terms of R. H. Kessel's Employment, dated as of Dec. 1, 1989 (Exhibit 10.20, Form 10-K for 1989 of TECO Energy, Inc.). 10.12 Supplemental Executive Retirement Plan for R.H. Kessel, dated as of Dec. 4, 1989 (Exhibit *10.16, Form 10-K for 1989 of TECO Energy, Inc.), as amended by the First Amendment to TECO Energy Group Supplemental Executive Retirement Plan for R.H. Kessel, effective as of Oct. 1, 1994. *10.13 Supplemental Executive Retirement Plan for H.L. Culbreath, as amended on April 27, 1989 (Exhibit 10.14, Form 10-K for 1989 of TECO Energy, Inc.). 10.14 Supplemental Executive Retirement Plan for A.D. Oak, dated as amended on July 20, 1993 (Exhibit *10.2, Form 10-Q for the quarter ended Sept. 30, 1993 of Tampa Electric Company), as further amended by the First Amendment to TECO Energy Group Supplemental Executive Retirement Plan for A.D. Oak, effective as of Oct. 1, 1994. 10.15 Supplemental Executive Retirement Plan for K.S. Surgenor, as amended on July 20, 1993 (Exhibit *10.3, Form 10-Q for the quarter ended Sept. 30, 1993 of Tampa Electric Company), as further amended by the First Amendment to TECO Energy Group Supplemental Executive Retirement Plan for K.S. Surgenor, effective as of Oct 1, 1994. *10.16 Terms of T.L. Guzzle's employment, dated as of July 20, 1993 (Exhibit 10, Form 10-Q for the quarter ended June 30, 1993 of Tampa Electric Company). 10.17 Supplemental Executive Retirement Plan for G.F. Anderson (Exhibit *10.4, Form 10-Q for the quarter ended Sept. 30, 1993 of Tampa Electric Company), as amended by the First Amendment to TECO Energy Group Supplemental Executive Retirement Plan for G.F. Anderson, effective as of Oct. 1, 1994. *10.18 TECO Energy Directors' Deferred Compensation Plan, as amended and restated effective April 1, 1994 (Exhibit 10.1, Form 10-Q for the quarter ended March 31, 1994 of Tampa Electric Company).
*10.19 TECO Energy, Inc. Annual Incentive Compensation Plan, revised January 1993 (Exhibit 10.2, Form 10-Q for the quarter ended March 31, 1994 of Tampa Electric 10.20 TECO Energy Group Retirement Savings Excess Benefit Plan, as amended and restated effective Aug. 1, 1994. *10.21 Severance Agreement between TECO Energy, Inc. and H. L. Culbreath, dated as of April 28, 1989 (Exhibit 10.24, Form 10-K for 1989 of TECO Energy, Inc.). 12 Ratio of earnings to fixed charges. 23 Consent of Independent Accountants. 24.1 Power of Attorney. 24.2 C e r tified copy of resolution authorizing Power of Attorney. 27 Financial Data Schedule (EDGAR filing only) _____________ * Indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. Exhibits filed with periodic reports of Tampa Electric Company and TECO Energy, Inc. were filed under Commission File Nos. 1-5007 and 1-8180, respectively.
Executive Compensation Plans and Arrangements
Exhibits 10.1 through 10.21 above are management contracts or compensatory plans or arrangements in which executive officers or directors of TECO Energy, Inc. and its subsidiaries participate.
(b) The company filed no reports on Form 8-K during the last quarter of 1993.
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 on the 29th day of March, 1995.
TAMPA ELECTRIC COMPANY By T. L. GUZZLE* T. L. GUZZLE, Chairman of the Board and Chief Executive Officer
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 March 29, 1995:
Signature Title
T. L. GUZZLE* Chairman of the Board, T. L. GUZZLE Director and Chief Executive Officer (Principal Executive Officer)
A. D. OAK* Vice President, Treasurer A. D. OAK and Chief Financial Officer (Principal Financial Officer)
/s/ L. L. LEFLER Vice President-Controller L. L. LEFLER
G. F. ANDERSON* Director G. F. ANDERSON
C. D. AUSLEY* Director C. D. AUSLEY
S. L. BALDWIN* Director S. L. BALDWIN
H. L. CULBREATH* Director H. L. CULBREATH
J. L. FERMAN, JR.* Director J. L. FERMAN, JR.
E. L. FLOM* Director E. L. FLOM H. R. GUILD, JR.* Director H. R. GUILD, JR.
R. L. RYAN* Director R. L. RYAN
J. T. TOUCHTON* Director J. T. TOUCHTON
J. A. URQUHART* Director J. A. URQUHART J. O. WELCH, JR.* Director J. O. WELCH, JR.
*By: /s/ L. L. LEFLER L. L. LEFLER, Attorney-in-fact
INDEX TO EXHIBITS
Exhibit Page No. Description No.
3.1 Articles of Incorporation (Exhibit 3.1 to * Registration Statement No. 2-70653). 3.2 Bylaws as amended on April 16, 1991 * (Exhibit 3, Form 10-Q for quarter ended March 31, 1991 of Tampa Electric Company). 4.1 Indenture of Mortgage among Tampa Electric * Company, State Street Trust Company and First Savings & Trust Company of Tampa, dated as of Aug. 1, 1946 (Exhibit 7-A to Registration Statement No. 2-6693). 4.2 Ninth Supplemental Indenture, dated as of * April 1, 1966, to Exhibit 4.1 (Exhibit 4-k, Registration Statement No. 2-28417). 4.3 Thirteenth Supplemental Indenture, dated as of * Jan. 1, 1974, to Exhibit 4.1 (Exhibit 2-g-l, Registration Statement No. 2-51204). 4.4 Sixteenth Supplemental Indenture, dated as of * Oct. 30, 1992, to Exhibit 4.1 (Exhibit 4.1, Form 10-Q for the quarter ended Sept. 30, 1992 of Tampa Electric Company). 4.5 Eighteenth Supplemental Indenture, dated as of May 1, * 1993, to Exhibit 4.1 (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 1993). 4.6 Installment Purchase and Security Contract * between and the Hillsborough County Industrial Development Authority and Tampa Electric Company, dated as of March 1, 1972 (Exhibit 4.9, Form 10-K for 1986 of Tampa Electric Company). 4.7 First Supplemental Installment Purchase and * Security Contract, dated as of Dec. 1, 1974 (Exhibit 4.10, Form 10-K for 1986 of Tampa Electric Company). 4.8 Third Supplemental Installment Purchase Contract, * dated as of May 1, 1976 (Exhibit 4.12, Form 10-K for 1986 of Tampa Electric Company). 4.9 Installment Purchase Contract between the * Hillsborough County Industrial Development Authority and Tampa Electric Company, dated as of Aug. 1, 1981 (Exhibit 4.13, Form 10-K for 1986 of Tampa Electric Company). 4.10 Amendment to Exhibit A of Installment Purchase * Contract, dated as of April 7, 1983 (Exhibit 4.14, Form 10-K for 1989 of Tampa Electric Company). 4.11 Second Supplemental Installment Purchase Contract, 55 dated as of June 1, 1983. 4.12 Third Supplemental Installment Purchase Contract, * dated as of Aug. 1, 1989 (Exhibit 4.16, Form 10-K for 1989 of Tampa Electric Company). 4.13 Installment Purchase Contract between the * Hillsborough County Industrial Development Authority and Tampa Electric Company, dated as of Jan. 31, 1984 (Exhibit 4.13, Form 10-K for 1993 of Tampa Electric Company).
4.14 First Supplemental Installment Purchase Contract, 79 dated as of Aug. 2, 1984. 4.15 Second Supplemental Installment Purchase Contract, * dated as of July 1, 1993 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 1993). 4.16 Loan and Trust Agreement among the Hillsborough * County Industrial Development Authority, Tampa Electric Company and NCNB National Bank of Florida, dated as of Sept. 24, 1990 (Exhibit 4.1, Form 10-Q for the quarter ended Sept. 30, 1990 of Tampa Electric Company). 4.17 Loan and Trust Agreement, dated as of * Oct. 26, 1992 among the Hillsborough County Industrial Development Authority, Tampa Electric Company and NationsBank of Florida, N.A., as trustee (Exhibit 4.2, Form 10-Q for the quarter ended Sept. 30, 1992 of Tampa Electric Company). 4.18 Loan and Trust Agreement, dated as of June 23, * 1993, among the Hillsborough County Industrial Development Authority, Tampa Electric Company and NationsBank of Florida, N.A., as trustee (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 1993 of Tampa Electric Company). 10.1 1980 Stock Option and Appreciation Rights Plan, * as amended on July 18, 1989 (Exhibit 28.1, Form 10-Q for quarter ended June 30, 1989 of TECO Energy, Inc.). 10.2 Directors' Retirement Plan, dated as of * Jan. 24, 1985 (Exhibit 10.23, Form 10-K for 1986 of Tampa Electric Company). 10.3 Supplemental Executive Retirement Plan, as amended 98 on July 18, 1989 (Exhibit *10.14, Form 10-K for 1989 of Tampa Electric Company), as further amended by the First Amendment to TECO Energy Group Supplemental Executive Retirement Plan, effective as of Oct. 1, 1994. 10.4 TECO Energy, Inc. Group Supplemental Retirement * Benefits Trust Agreement Amendment and Restatement, dated as of April 27, 1989 (Exhibit 10.15, Form 10-K for 1989 of Tampa Electric Company) with Exhibit A as amended Dec. 1, 1989 (Exhibit 10.2, Form 10-Q for the quarter ended March 31, 1990 of TECO Energy, Inc.), as further amended by First Amendment to 1989 Restatement dated as of July 20, 1993 (Exhibit 10.5,
Form 10-Q for the quarter ended Sept. 30, 1993 of Tampa Electric Company). 10.5 Annual Incentive Compensation Plan for Tampa * Electric Company, as amended on April 27, 1989 (Exhibit 28.1, Form 10-Q for quarter ended March 31, 1989 of Tampa Electric Company). 10.6 TECO Energy, Inc. Group Supplemental Disability * Income Plan, dated as of March 20, 1989 (Exhibit 10.19, Form 10-K for 1988 of Tampa Electric Company). 10.7 Forms of Severance Agreement between TECO Energy, Inc. * and certain senior executives, dated as of various dates in 1989 (Exhibit 10.18, Form 10-K for 1989 of Tampa Electric Company). 10.8 TECO Energy, Inc. 1990 Equity Incentive Plan * (Exhibit 10.1, Form 10-Q for the quarter ended March 31, 1990 of TECO Energy, Inc.).
10.9 TECO Energy, Inc. 1991 Director Stock Option Plan * as amended on Jan. 21, 1992 (Exhibit 10.20, Form 10-K for 1991 of Tampa Electric Company). 10.10 Supplemental Executive Retirement Plan for 99 T.L. Guzzle, as amended on July 20, 1993 (Exhibit *10.1, Form 10-Q for the quarter ended Sept. 30, 1993 of Tampa Electric Company), as further amended by the First Amendment to TECO Energy Group Supplemental Executive Retirement Plan for T.L. Guzzle, effective as of Oct. 1, 1994. 10.11 Terms of R. H. Kessel's Employment, dated as of * Dec. 1, 1989 (Exhibit 10.20, Form 10-K for 1989 of TECO Energy, Inc.). 10.12 Supplemental Executive Retirement Plan for 100 R.H. Kessel, dated as of Dec. 4, 1989 (Exhibit *10.16, Form 10-K for 1989 of TECO Energy, Inc.), as amended by the First Amendment to TECO Energy Group Supplemental Executive Retirement Plan for R.H. Kessel, effective as of Oct. 1, 1994. 10.13 Supplemental Executive Retirement Plan for * H.L. Culbreath, as amended on April 27, 1989 (Exhibit 10.14, Form 10-K for 1989 of TECO Energy, Inc.). 10.14 Supplemental Executive Retirement Plan for 101 A.D. Oak, as amended on July 20, 1993 (Exhibit *10.2, Form 10-Q for the quarter ended Sept. 30, 1993 of Tampa Electric Company), as further amended by the First Amendment to TECO Energy Group Supplemental Executive Retirement Plan for A. D. Oak, effective as of Oct. 1, 1994. 10.15 Supplemental Executive Retirement Plan for 102 K.S. Surgenor, as amended on July 20, 1993 (Exhibit *10.3, Form 10-Q for the quarter ended Sept. 30, 1993 of Tampa Electric Company), as further amended by the First Amendment to TECO Energy Group Supplemental Executive Retirement Plan for K.S. Surgenor, effective as of Oct. 1, 1994. 10.16 Terms of T.L. Guzzle's employment, dated * as of July 20, 1993 (Exhibit 10, Form 10-Q for the quarter ended June 30, 1993 of Tampa Electric Company). 10.17 Supplemental Executive Retirement Plan for 103 G.F. Anderson (Exhibit *10.4, Form 10-Q for the quarter ended Sept. 30, 1993 of Tampa Electric Company), as amended by the First Amendment to TECO Energy Group Supplemental Executive Retirement Plan for G.F. Anderson, effective as of Oct. 1, 1994. 10.18 TECO Energy Directors' Deferred Compensation Plan, * as amended and restated effective April 1, 1994 (Exhibit 10.1, Form 10-Q for the quarter ended March 31, 1994 of Tampa Electric Company). 10.19 TECO Energy, Inc. Annual Incentive Compensation Plan, * revised January 1993 (Exhibit 10.2, Form 10-Q for the quarter ended March 31, 1994 of Tampa Electric Company). 10.20 TECO Energy Group Retirement Savings Excess Benefit 104 Plan, as amended and restated effective Aug. 1, 1994.
10.21 Severance Agreement between TECO Energy, Inc. and * H.L. Culbreath, dated as of April 28, 1989 (Exhibit 10.24, Form 10-K for 1989 of TECO Energy, Inc.). 12 Ratio of earnings to fixed charges. 111 23 Consent of Independent Accountants. 112 24.1 Power of Attorney. 113 24.2 Certified copy of resolution authorizing Power 115 of Attorney. 27 Financial Data Schedule (EDGAR filing only) _____________
* Indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference. Exhibits filed with periodic reports of Tampa Electric Company and TECO Energy, Inc. were filed under Commission File Nos. 1-5007 and 1-8180, respectively.