FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
(Mark One)
X Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended December 31, 1994
OR
Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the transition period from _________ to ________
Commission File Number 1-5007
TAMPA ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
FLORIDA 59-0475140
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
TECO Plaza
702 N. Franklin Street
Tampa, Florida 33602
(Address of principal (Zip Code)
executive offices)
Registrant's telephone number, including area code: (813)228-4111
Securities registered pursuant to Section 12(b) of the Act: NONE
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
YES X NO
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. X
The aggregate market value of the voting stock held by nonaffiliates of the
registrant as of February 28, 1995 was zero.
As of February 28, 1995, there were 10 shares of the registrant's common
stock issued and outstanding, all of which were held, beneficially and of
record, by TECO Energy, Inc.
DOCUMENTS INCORPORATED BY REFERENCE
None
PART I
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.
2
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.
3
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
4
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.
5
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.
6
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. 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.
7
Item 3. LEGAL PROCEEDINGS.
None.
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. 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. 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.
8
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.
9
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
10
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.
11
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.
12
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.
13
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.
14
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
15
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.
16
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.
17
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.
18
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
19
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.
20
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.
21
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.
22
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.
23
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.
24
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.
25
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.
26
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.
27
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.
28
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
29
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%
30
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
1994
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
1993
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
31
(thousands of dollars) Federal State Total
1992
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%
32
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.
33
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. 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.
34
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
35
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.
36
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. 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.
37
Summary Compensation Table
Long-Term
Compensation
Annual Awards All Other
Name an Compensation Shares Underlying Compensation
Principal Position Year Salary Bonus Options/SARs(#)(1) (2)
Timothy L. Guzzle(3) 1994 $468,750 $384,000 40,000 $28,703
Chairman of the Board 1993 443,750 194,000 40,000 $28,267
Chief Executive Officer 1992 421,250 176,000 40,000 26,248
Girard F. Anderson(3)(4) 1994 320,461 275,000 24,000 25,076
President and Chief 1993 284,750 110,000 24,000 23,290
Operating Officer of 1992 258,750 100,000 24,000 21,333
TECO Energy, Inc.
Keith S. Surgenor(3)(5) 1994 215,376 225,000 12,000 13,728
President and Chief 1993 179,500 60,000 12,000 11,986
Operating Officer 1992 170,500 53,000 12,000 11,175
Alan D. Oak(3) 1994 201,750 130,000 13,000 12,905
Vice President, 1993 192,875 74,000 13,000 12,843
Treasurer and Chief 1992 184,875 68,000 13,000 12,039
Financial Officer
William N. Cantrell 1994 129,917 50,000 4,600 8,902
Vice President- 1993 121,500 28,000 4,600 8,204
Energy Supply 1992 115,750 29,000 5,000 8,078
Harry I. Wilson 1994 136,750 45,000 4,600 6,832
Vice President- 1993 131,500 30,000 4,600 6,368
Transmission and 1992 126,000 29,000 5,000 6,367
Distribution
_________________
(1) Limited stock appreciation rights were awarded in tandem with options granted. See Footnote
(2) under "Option/SAR Grants In Last Fiscal Year" below.
(2) The reported amounts for 1994 consist of $924 of premiums paid by the company to the Executive
Supplemental Life Insurance Plan for each of the named executive officers, with the balance in
each case being employer contributions under the TECO Energy Group Retirement Savings Plan and
Retirement Savings Excess Benefit Plan.
(3) Includes compensation for services as an officer of TECO Energy.
(4) Mr. Anderson served as President and Chief Operating Officer of Tampa Electric Company until
July 19, 1994.
(5) Prior to July 19, 1994, Mr. Surgenor served as Vice President-Human Resources.
38
The Compensation Committee of the TECO Energy Board of Directors may award options to purchase
common stock of TECO Energy and stock appreciation rights (SARs) to officers and key employees of TECO
Energy and its subsidiaries, including the company. Information for 1994 with respect to stock options
and stock appreciation rights granted or exercised by the executive officers named in the "Summary
Compensation Table" is set forth in the following two tables.
Option/SAR Grants In Last Fiscal Year
Individual Grants
Number of % of Total
Shares Options/SARs Exercise Grant
Underlying Granted To or Base Date
Options/SARs Employees In Price Expiration Present
Name Granted(#)(1)(2) Fiscal Year Per Share Date Value(3)
Timothy L. Guzzle 40,000 9.99% $19.4375 4/18/2004 $137,307
Girard F. Anderson 24,000 5.99% $19.4375 4/18/2004 $ 82,384
Keith S. Surgenor 12,000 3.00% $19.4375 4/18/2004 $ 41,192
Alan D. Oak 13,000 3.25% $19.4375 4/18/2004 $ 44,625
William N. Cantrell 4,600 1.15% $19.4375 4/18/2004 $ 15,790
Harry I. Wilson 4,600 1.15% $19.4375 4/18/2004 $ 15,790
_________________
(1) The options are exercisable beginning on the date of grant, April 18, 1994.
(2) An equal number of stock appreciation rights which can only be exercised during limited periods
following a change in control of TECO Energy ( LSAR s) were awarded in tandem with the options
granted in 1994. Upon exercise of an LSAR, the holder is entitled to an amount based upon the
highest price paid or offered for TECO Energy Common Stock during the 30-day period preceding a
change in control of TECO Energy, as defined under "Employment and Severance Agreements" below.
The exercise of an option or an LSAR results in a corresponding reduction in the other.
(3) The values shown are based on the Binomial Option Pricing Model (a variant of the Black-Scholes
model) and are stated in current annualized dollars on a present value basis. The key assumptions
used in the Binomial Option Pricing Model for purposes of this calculation include the following:
(a) a 7% discount rate; (b) a volatility factor based upon the average TECO Energy Common Stock
trading price for the 40-month period ending December 31, 1993; (c) a dividend factor based upon
the 5-year average dividend paid by TECO Energy for the period ending December 31, 1993; (d) the
10-year option term; and (e) the closing price of TECO Energy's Common Stock on December 31, 1993.
The present value of the options reported has been calculated by multiplying $19.4375, the share
price on the date of grant, by 0.1766, the Binomial Option Pricing Model ratio, and by the number
of shares underlying the options granted. The actual value an executive may realize will depend
upon the extent to which the stock price exceeds the exercise price on the date the option is
exercised. Accordingly, the value, if any, realized by an executive will not necessarily be the
value determined by the Binomial Option Pricing Model.
39
Aggregated Option/SAR Exercises In Last Fiscal Year and
Fiscal Year-End Option/SAR Value
Number of
Shares Value of
Underlying Unexercised
Unexercised In-The-Money
Options/SARs Options/SARs
at Year-End(#) at Year-End
Value
Shares Acquired Realized Exercisable/ Exercisable/
Name On Exercise(#) ($) 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.
40
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.
41
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.
42
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.
43
(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. 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.
44
PART IV
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).
45
*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).
46
*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).
47
*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.
48
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
49
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
50
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).
51
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,
52
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.).
53
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.
55
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.
56