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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, 1995
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 29, 1996 was zero.
As of February 29, 1996, 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.
Tampa Electric Company (Tampa Electric or the company) was
incorporated in Florida in 1899 and was reincorporated in 1949. As a
result of a 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 2,836 employees as of Dec. 31, 1995, of which
1,164 were represented by the International Brotherhood of Electrical
Workers (IBEW) and 308 by the Office and Professional Employees
International Union.
In 1995, approximately 48 percent of the company's total
operating revenue was derived from residential sales, 29 percent from
commercial sales, 10 percent from industrial sales and 13 percent from
other sales including bulk power sales for resale.
The sources of operating revenue for the years indicated were as
follows:
(millions) 1995 1994 1993
Residential $ 523.3 $ 505.5 $ 464.1
Commercial 316.1 316.8 298.3
Industrial-Phosphate 61.7 58.3 55.1
Industrial-Other 45.0 50.0 48.9
Sales for resale 80.0 70.4 76.1
Deferred revenues (50.8) -- --
Other 117.0 93.9 98.8
$1,092.3 $1,094.9 $1,041.3
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 significantly adverse effect on the company, except
that 8 customers in the phosphate industry accounted for 6 percent of
operating revenues in 1995.
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.
2
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 pages 6 and 7.
TECO Transport & Trade Corporation (TECO Transport), TECO Coal
Corporation (TECO Coal) and TECO Power Services Corporation (TECO
Power Services), subsidiaries of TECO Energy, sell transportation
services, coal, and generating capacity and energy, respectively, 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 through 17.
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 natural gas for residences and businesses and the self-generation
option available to larger users of electric energy. 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, to control costs, and provide high
quality service to retail customers.
There is presently active competition in the wholesale power markets in
Florida, 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 and required utilities to transmit power
from such producers, utilities and others to wholesale customers under certain
circumstances. The company continues its cost reduction efforts to increase its
wholesale business, which is dependent in part on access to transmission systems
owned by others.
In March 1995 the FERC issued its Notice Of Proposed Rulemaking on Open
Access Transmission Services (NOPR). The NOPR would require open access to
transmission systems and utilities owning transmission facilities (including the
company) to provide services to wholesale transmission customers comparable to
those they provide to themselves on comparable terms and conditions, including
price. Among other things the NOPR would unbundle transmission services from
power sales and require owners of transmission systems to take service under
their own transmission tariffs.
In November 1995 the FERC accepted for filing the company s
open access transmission tariffs, which conform to the pro forma
tariffs contained in the NOPR, subject to refund and the outcome of
the final rule under the NOPR.
Retail Pricing
In general, the FPSC's pricing objective is to set rates at a
3
level that allows the utility to collect total revenues (revenue
requirements) equal to its cost of providing service, including a
reasonable return on invested capital.
The basic costs, other than fuel and purchased power, of
providing electric service are recovered through base rates, which are
designed to recover the costs of owning, operating and maintaining the
utility system. These costs include operation and maintenance
expenses, depreciation and taxes, as well as a return on the company's
investment in assets used and useful in providing electric service
(rate base). The rate of return on rate base, which is intended to
approximate the company's weighted cost of capital, includes its costs
for debt and preferred stock, deferred income taxes at a zero cost
rate and an allowed return on common equity. Base prices are
determined in FPSC price setting hearings that occur at irregular
intervals at the initiative of the company, the FPSC or other parties.
Fuel, Clean Air Act allowances, 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, Clean Air Act allowances 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.
Fuel
About 99 percent of the company's generation for 1995 was from
its coal-fired units. About the same level is anticipated for 1996.
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: 1995 1994 1993 1992 1991
Coal $ 2.15 $ 2.22 $ 2.26 $ 2.23 $ 2.22
Oil $ 2.76 $ 2.49 $ 2.69 $ 2.76 $ 3.21
Gas -- -- $ 3.52 $ 2.43 $ 1.98
Composite $ 2.16 $ 2.22 $ 2.27 $ 2.24 $ 2.25
Average cost per ton
of coal burned $50.97 $53.39 $54.55 $53.65 $53.87
4
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 7.4 million tons of coal
during 1995 and estimates that its coal consumption will be
7.3 million tons for 1996. During 1995, the company purchased
approximately 68 percent of its coal under long-term contracts with
six suppliers, including TECO Coal, and 32 percent of its coal in the
spot market or under intermediate-term purchase agreements. About 23
percent of the company's 1995 coal requirements were supplied by TECO
Coal. During December 1995, the average delivered cost of coal
(including transportation) was $47.99 per ton, or $2.01 per million
BTU. The company expects to obtain approximately 51 percent of its
coal requirements in 1996 under long-term contracts with five
suppliers, including TECO Coal, and the remaining 49 percent in the
spot market. The company's long-term coal contracts provide for
revisions in the base price to reflect changes in a wide range of cost
factors and for suspension or reduction of deliveries if environmental
regulations should prevent the company from burning the coal supplied,
provided that a good faith effort has been made to continue burning
such coal. The company estimates that about 19 percent of its 1996
coal requirements will be supplied by TECO Coal. For information
concerning transactions with affiliated companies, see Note I. on page
34.
In 1995, about 81 percent of the company's coal supply was
deep-mined, approximately 18 percent was surface-mined and 1 percent
was a processed oil by-product known as petroleum coke. 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, 1996 for
No. 2 fuel oil and No. 6 fuel oil for its four combustion turbine
units, Polk Station, 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 1995 was $24.91 per barrel, or $4.29
per million BTU. The price for No. 6 fuel oil deliveries taken in
December 1995 was $17.53 per barrel, or $2.77 per million BTU.
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
5
the franchise at a valuation 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.
The company 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.
The company has no reason to believe that any of these franchises will
not be renewed.
Franchise fees payable by the company, which totaled
$20.0 million in 1995, are calculated using a formula based primarily
on electric revenues.
Utility operations in Hillsborough, Pasco, Pinellas and Polk
Counties outside of incorporated municipalities are conducted in each
case under one or more permits to use county rights-of-way granted by
the county commissioners of such counties. There is no law limiting
the time for which such permits may be granted by counties. There are
no fixed expiration dates for the Hillsborough County and Pinellas
County agreements. The agreements covering electric operations in
Pasco and Polk counties expire in September 2033 and March 2004,
respectively.
Environmental Matters
The company's operations are subject to county, state and federal
environmental regulations. The Hillsborough County Environmental
Protection Commission 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,
monitoring programs are in place to assure compliance with permit
conditions. The company has been identified as one of numerous
potentially responsible parties (PRP) with respect to seven 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, 1995, the
company spent $171.4 million on capital additions to meet
environmental requirements, including $117.7 million for the Polk
Power Station project. Environmental expenditures are estimated at $73
million for 1996, including $66 million for the Polk Power Station,
and $9 million in total for 1997-2000. These totals exclude amounts
required to comply with the 1990 amendments to the Clean Air Act.
The company is complying with the Phase I emission limitations
imposed by the Clean Air Act Amendments which became effective Jan. 1,
1995 by using blends of lower-sulfur coal, controlling stack emissions
and using emission allowances.
In 1995 the company successfully integrated Big Bend Unit Three
into the existing scrubber on Big Bend Unit Four. This resulted in an
additional scrubbed unit at a fraction of the cost of a new scrubber.
Also as part of its Phase I compliance plan, the company has a long-
term contract for the purchase of low-sulfur coal.
6
To comply with Phase II emission standards set for 2000 the
company would potentially have to scrub additional capacity and is
evaluating equipment and technologies to accomplish compliance in the
most cost-effective manner. Absent capital expenditures for additional
scrubbing, the company expects to spend $30 million of capital to
comply with Phase II of the Clean Air Act Amendments for nitrogen
oxide reductions and emissions monitoring equipment. The cost of
compliance with Phase I and Phase II is expected to have little impact
on the company's prices.
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.
At Dec. 31, 1995, the company had four electric generating plants and four
combustion turbine units in service with a total net winter generating
capability of 3,404 MWs, including Big Bend (1,748-MW capability from four coal
units), Gannon (1,206-MW capability from six coal units), Hookers Point (212-MW
capability from five oil units), Phillips (34-MW capability from 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 winter 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, the company purchased two power plants (Dinner Lake
and Phillips) from the Sebring Utilities Commission (Sebring). Dinner Lake (11-
MW capability from 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 land in Polk County,
Florida. This site accommodates Polk Unit One, a 250-MW coal gasification
generating plant currently being constructed, and can accommodate additional
generating capacity in the future. Polk Unit One is discussed further under
Capital Expenditures on page 14.
The company owns 178 substations having an aggregate transformer capacity
of 15,777,966 KVA. The transmission system consists of approximately 1,197 pole
miles of high voltage transmission lines, and the distribution system consists
of 6,822 pole miles of overhead lines and 2,444 trench miles of underground
lines. As of Dec. 31, 1995, there were 501,909 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.
The company has easements for rights-of-way adequate for the maintenance
and operation of its electrical transmission and distribution lines that are not
constructed upon public highways, roads and streets. It has the power of eminent
domain under Florida law for the acquisition of any such rights-of-way for the
operation of transmission and distribution lines. Transmission and distribution
lines located in public ways are maintained under franchises or permits.
The company has a long-term lease for the office building in downtown
Tampa, Florida, that serves as its headquarters.
Item 3. LEGAL PROCEEDINGS.
7
None.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matter was submitted during the fourth quarter of 1995 to a
vote of the company's security holders, through the solicitation of
proxies or otherwise.
8
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
$115.2 million for 1995 and $115.8 million for 1994. See Note C on
page 29 for a description of restrictions on dividends on the
company's common stock.
Item 6. SELECTED FINANCIAL DATA.
(millions)
Year ended
Dec. 31, 1995 1994 1993 1992 1991
Operating
revenues $1,092.3(1) $1,094.9 $1,041.3 $1,005.7 $ 987.5
Net income $ 133.7 $ 110.1(2) $ 106.7 $ 110.8 $ 107.4
Total assets $2,639.2 $2,417.8 $2,267.5* $2,104.7* $1,994.5
Long-term debt $ 583.1 $ 607.3 $ 606.6* $ 591.5* $ 513.7
* T h e se balances have been restated to reflect current year
presentation.
(1) 1995 revenues were net of $50.8 million of revenues deferred
under a plan described in the Utility Regulation section on page
16.
(2) 1994 net income includes the effect of a corporate restructuring
charge of $13.1 million, after tax.
9
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.
EARNINGS SUMMARY
The company's net income for 1995 of $133.7 million was 22
percent higher than 1994's even after the deferral of $50.8 million of
revenues in 1995. Two-percent customer growth and favorable weather
increased retail energy sales 5 percent. In addition, non-fuel
operations and maintenance expenses were 5 percent below last year s
level as the company benefited from the 1994 restructuring efforts.
Allowance for funds used during construction (AFUDC) of $19.3 million
was up from $5.6 million in 1994 and $3.7 million in 1993 due to the
additional investment in Polk Unit One discussed in the Capital
Expenditures section on page 14.
Net income for 1994 of $110.1 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.
The company recorded a one-time $21.3 million pretax
restructuring charge ($13.1 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.
Net income for 1993 of $106.7 million included a $10 million
pretax non-recurring coal settlement charge described in the Other
Income (Expense) section on page 13.
OPERATING RESULTS
The company's operating income, after the deferral of $50.8
million in 1995, increased 11 percent as a result of higher retail
energy sales and favorable variances in non-fuel operations and
maintenance expenses.
The company's 1994 operating income, after the $21.3-million
pretax restructuring charge, decreased 5 percent from 1993. Higher
base revenues from retail customer growth, increased retail energy
usage from an improved economy and a retail price increase effective
in January 1994 were more than offset by higher operating expenses and
the restructuring charge.
(millions) 1995 Change 1994 Change 1993
Revenues $1,092.3(1) -.2% $1,094.9 5.1% $1,041.3
Operating expenses 929.0 .3% 926.5 4.4% 887.2
Operating income
before 1994
restructuring charge 163.3 -3.0% 168.4 9.3% 154.1
Restructuring charge - - 21.3 - -
Operating income $ 163.3 11.0% $ 147.1 -4.5% $ 154.1
(1) 1995 revenues were net of $50.8 million of revenues deferred
under a plan as described in the Utility Regulation section on page
16.
Operating Revenues
The company s 1995 revenues decreased slightly to $1,092.3
million reflecting the deferral of $50.8 million of revenues. The
company's revenues rose in 1994 with retail customer growth of almost
2 percent, increased retail energy sales of almost 4 percent and a
10
$16-million retail price increase effective in January 1994.
The economy in the company's service area continued to strengthen
in 1995. The combined residential and commercial energy sales grew by
more than 5 percent in 1995. Sales to the phosphate industry grew by
almost 11 percent in 1995 as these companies continued to experience
strong prices and demand for their product. Non-phosphate industrial
sales declined in 1995 due to the closure of a steel-making facility
in the service area.
Total retail energy sales are projected to increase almost 2
percent annually over the next five years based on continued growth in
the local economy. Annual energy sales growth in the residential and
commercial sectors is projected at 2 percent to 3 percent for the next
five years. Growth in energy sales to non-phosphate industrial
customers is projected to be less after a possible decline in 1996.
In 1996 the company service area economy is expected to grow
moderately, but at rates higher than the country as a whole. The local
economy continues to benefit from a good labor market, available land
and good access through airport and port facilities.
Energy sales to the phosphate industry are expected to decline
from increased self-generation and as mining activity slowly moves out
of the company's service area. In 1995 sales to the phosphate customer
group represented less than 6 percent of total operating revenues.
Non-fuel revenues from sales to other utilities in 1995 were
$33.7 million, $32.8 million in 1994 and $34.0 million in 1993. Energy
sold to other utilities increased in 1995 due to generating unit
availability and lower fuel cost.
In 1994 energy sold to other utilities declined because of
lower-priced oil and gas-fired generation available on other systems.
A shift to higher-margin, longer-term wholesale power sales agreements
resulted in only a 3-percent decline in 1994 non-fuel revenues despite
the 10-percent decline in energy sales to other utilities.
Securing additional longer-term wholesale power sales agreements
remains a priority. In the past three years, the company has added
nine bulk power sales contracts of varying size and duration.
Competitive pricing of coal-fired generation has allowed the company
to market available capacity successfully.
Energy Sales:
Megawatt-hour sales 1995 Change 1994 Change 1993
(thousands)
Residential 6,352 6.8% 5,947 4.2% 5,706
Commercial 4,710 2.8% 4,583 3.4% 4,432
Industrial 2,362 3.7% 2,278 1.9% 2,236
Other 1,176 4.6% 1,124 4.7% 1,073
Total retail 14,600 4.8% 13,932 3.6% 13,447
Sales for resale 2,706 28.7% 2,102 -9.8% 2,330
Total energy sold 17,306 7.9% 16,034 1.6% 15,777
Retail customers 495,198 2.0% 485,698 1.8% 477,010
(average)
11
Operating Expenses
Effective cost management and improved efficiency continue to be
principal objectives at the company. Operating expenses declined in
1995 from the restructuring actions taken in 1994 and continuing
efforts to control costs in all areas of the company.
Operating Expenses:
1995 Change 1994 Change 1993
(millions)
Fuel $384.3 -1.3% $389.3 7.2% $363.2
Purchased power 44.4 32.9% 33.4 -14.4% 39.0
Total fuel cost 428.7 1.4% 422.7 5.1% 402.2
Other operating expenses 163.3 -4.8% 171.6 8.8% 157.7
Maintenance 69.6 -4.5% 72.9 2.1% 71.4
Depreciation 113.3 -1.6% 115.1 2.9% 111.9
Taxes, federal and
State income 66.2 15.3% 57.4 -5.1% 60.5
Taxes, other than income 87.9 1.3% 86.8 3.9% 83.5
Operating expenses 929.0 .3% 926.5 4.4% 887.2
Restructuring charge - - 21.3 - -
Total operating expenses $929.0 -2.0% $947.8 6.8% $887.2
In 1995 non-fuel operations and maintenance expenses declined
almost 5 percent from 1994 levels before the restructuring charge. The
$11.6-million reduction was primarily from lower payroll and employee-
related expenses as a result of 217 fewer positions than in 1994.
In both 1994 and 1995 the company achieved savings from work
redesign efforts and equipment redesign and enhancements. In 1995
operating areas of the company achieved lower costs through technology
improvements, the streamlining of maintenance programs, and the
sharing of manpower resources in power generation facilities.
The savings realized from these efforts will partially offset
increased operations and maintenance expenses expected in 1996 from
Polk Unit One. During the first two years of operations, when domestic
coals will be evaluated for use in the gasifier, the company will
receive $20 million from the U. S. Department of Energy for
operations, maintenance and fuel expenses.
Total operating expenses in 1994 included the restructuring
charge discussed in the Earnings Summary section, a $4-million annual
charge to establish a transmission and distribution property storm-
damage reserve in accordance with regulatory directives described in
the Utility Regulation section, and the effects of accounting for fuel
expense in accordance with Florida Public Service Commission (FPSC)
requirements. Absent these three items, total operating expense
increased only 4 percent over 1993 principally as a result of higher
employee-related expenses, higher accruals for self-insurance
liability reserves and increased expenses for regulatory activity.
Depreciation expense in 1995 decreased as certain shorter-lived
assets were fully amortized. The decrease more than offset the impact
of normal additions to plant and equipment. The company s efforts to
reduce capital investment in recent years have limited additions to
all asset classes, particularly shorter-life asset classes. The
increased depreciation expense in 1994 from normal additions to plant
and equipment was minimized by these cost-control efforts.
Depreciation expense is projected to increase in 1996 as a result of
the start of commercial operation of Polk Unit One.
Taxes other than those on income increased each year primarily
from higher gross receipts taxes and franchise fees.
12
Actual system fuel cost was only 4 percent higher than in 1994
despite an 8-percent increase in generation. The success in
controlling fuel cost is a result of the company's use of lower-priced
coals and the mix in operating generating units. Average coal cost, on
a cents-per-million BTU basis, declined 3 percent in 1995 after a 2-
percent drop in 1994.
Fuel and purchased power cost rose only 1 percent in 1995 despite
a 9-percent increase in coal burned to meet increased generation. This
cost increase was partially offset by the normal effects of accounting
for deferred fuel expense consistent with the FPSC-approved fuel
adjustment clause. Fuel and purchased power cost was 5 percent higher
in 1994 than in 1993 primarily from the normal effects of accounting
for deferred fuel expense consistent with the fuel adjustment clause.
In 1995 the company purchased more power from both TECO Power
Services Hardee Power Station and cogenerators than in 1994,
primarily to meet weather-related demand. In 1994 the company
purchased less energy from other utilities than in 1993 because of the
combination of mild weather and higher levels of availability of its
own generating units. Substantially all fuel and purchased power
expenses were recovered through the fuel adjustment 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 relatively unchanged during
the next few years compared to oil or gas prices. The company
continues to work to reduce its fuel cost.
Coal Contract Buyout:
In December 1994, the company bought out a long-term coal supply
contract which would have expired in 2004 for a payment of $25.5
million and entered into two new contracts with the supplier. The coal
supplied under the new contracts is competitive in price with coals of
comparable quality.
As a result of this buyout the company s customers will benefit
from anticipated savings of more than $40 million, net of the buyout
costs, through the year 2004. The FPSC has authorized the recovery of
the buyout costs plus carrying costs through the fuel adjustment
clause during the years 1995 through 2004.
NON-OPERATING ITEMS
Other Income (Expense)
Other income in 1995 consisted mostly of AFUDC which increased to
$13.7 million from $3.5 million in 1994 and $1.6 million in 1993.
AFUDC will increase again in 1996 with the additional investment in
the construction of the company's Polk Unit One and is expected to
decline to minimal amounts for several years after the completion of
this unit, scheduled for the fourth quarter of 1996.
Other income (expense) in 1993 included a one-time $10-million
pretax charge associated with an FPSC-approved settlement agreement
between the company and the Office of Public Counsel as described in
the Utility Regulation section.
Interest Charges
Interest charges were $42.9 million in 1995, up 9 percent from
1994 due to higher short-term debt balances and rates. In 1995
interest expense included $1.5 million of interest accrued on the
company s $50.8 million of deferred revenues. Savings from long-term
debt refinancings accomplished in 1993 substantially offset the impact
of rising short-term interest rates in 1994.
13
Income Taxes
Total income tax expense, as described in Note G on pages 32
through 34, of $66.0 million increased from $58.7 million in 1994 and
$57.1 million in 1993 primarily due to higher pretax income.
CAPITAL EXPENDITURES
The company's 1995 capital expenditures were $334.5 million,
which included $19.3 million of AFUDC. In 1995, the company spent $199
million on construction of Polk Unit One, a 250-megawatt coal-
gasification plant. The capital cost of the plant is estimated at
about $450 million, net of the construction funding from the U.S.
Department of Energy under its Clean Coal Technology Program. An
estimated $70 million will be spent in 1996 to complete this project,
with commercial operation expected in the fourth quarter of 1996.
The company spent an additional $117 million in 1995 for
equipment and facilities to meet the company's growing customer base
and for generation equipment improvements.
The company expects to spend $178 million in 1996 and $569
million during the 1997-2000 period, excluding AFUDC, mainly for
distribution facilities to meet customer growth and for Polk Unit One
in 1996. At the end of 1995, the company had outstanding commitments
of about $72 million for capital programs including the construction
of Polk Unit One.
The company s capital expenditure projections include about $30
million over the 1996 to 2000 period to comply with Phase II of the
Clean Air Act Amendments for nitrogen oxide reductions and emissions
monitoring equipment as described in the Environmental Compliance
section.
Capital Expenditures
(millions)
1995 1996
Actual Estimated
Generation expansion $199 $ 74
Production 23 25
Transmission 33 16
Distribution 48 48
General 13 15
316 178
AFUDC 19 25
Total $335 $203
14
ENVIRONMENTAL COMPLIANCE
The company is complying with the Phase I emission limitations
imposed by the Clean Air Act Amendments which became effective Jan. 1,
1995 by using blends of lower-sulfur coal, controlling stack emissions
and emission allowances.
In 1995 the company successfully integrated Big Bend Unit Three
into the existing scrubber on Big Bend Unit Four. This resulted in an
additional scrubbed unit at a fraction of the cost of a new scrubber.
In connection with its Phase I compliance plan, the company
entered into two long-term contracts effective in mid-1994 for the
purchase of low-sulfur coal. In December 1995, one of the sellers
ceased operations at the mine supplying this coal. The company
believes that there will be no negative impact on its operations
because of the availability of alternative sources of supply and the successful
scrubber integration of Big Bend Units Three and Four.
To comply with Phase II emission standards set for 2000 the
company would potentially have to scrub additional capacity and is
evaluating equipment and technologies to accomplish compliance in the
most cost effective manner. Absent capital expenditures for additional
scrubbing, the company expects to spend $30 million of capital to
comply with Phase II of the Clean Air Act Amendments for nitrogen
oxide reductions and emissions monitoring equipment. The cost of
compliance with Phase I and Phase II is expected to have little impact
on the company's prices.
UTILITY REGULATION
Price Increase
1993 and 1994
The FPSC granted the company a $1.2-million permanent base revenue
increase and a $10.3-million revenue increase primarily associated
with recovery of purchased power capacity payments effective in
February 1993. The utility received an additional base revenue
increase of $16 million effective Jan. 1, 1994. The FPSC s decision
reflected overall allowed regulatory rates of return of 8.20 percent
in 1993 and 8.34 percent in 1994, which included an allowed regulatory
rate of return on common equity (ROE) of 12 percent, the midpoint of
a range of 11 percent to 13 percent.
Return on Equity Agreements
1994
In March 1994 the FPSC issued an order which changed the
company s authorized ROE 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.
In July 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 1994
only with any earnings above that amount to 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 $4.0 million to the storm
damage reserve.
15
1995
The company s objective is to place Polk Unit One in service
without increasing the total price that its customers pay for electric
service. A number of actions, discussed in the Operating Expenses
section, have been taken to reduce costs. A component of the strategy
to accomplish this objective has been the deferral of certain
revenues.
In 1995 the FPSC approved a plan submitted by the company to
defer certain revenues for 1995. Under this plan the company s allowed
ROE increased to an 11.75-percent midpoint with a range of 10.75
percent to 12.75 percent and the company deferred revenues under
certain financial circumstances related to these returns. For 1995 a
minimum of $15 million of revenues was deferred as well as 50 percent
of actual revenues in excess of an ROE of 11.75 percent up to a net
earned ROE of 12.75 percent and all actual revenues above an ROE of
12.75 percent. In 1995 the company deferred $50.8 million of revenues
under this plan. The deferred revenues accrue interest at the 30-day
commercial paper rate specified in the Florida Administrative Code.
Also as part of this plan the FPSC eliminated the company s oil
backout tariff effective Jan. 1, 1996, a reduction of about $12
million of annual revenues.
1996
On Jan. 3, 1996 the FPSC in a proposed agency action approved a
plan by Tampa Electric relating to the deferral in 1996 of revenues
under certain circumstances defined by ROE levels. As a result of
protests by the Office of Public Counsel and the Florida Industrial
Power Users Group, this action did not become effective and there
became operative a provision of the order that required the company to
hold subject to the FPSC s jurisdiction any revenues in 1996
contributing to an ROE in excess of 12.75 percent.
On March 25, 1996 the company filed with the FPSC an agreement
between the company and the two intervenors protesting the January 3
proposed order. If approved by the FPSC in a proposed agency action
proceeding and if no protests are filed, the agreement would replace
the Jan. 3, 1996 order. This agreement addresses, among other things,
the company s base rate levels, ROE levels for 1996 through 1998, and
the regulatory treatment of all accumulated deferred revenues through
the period ending Dec. 31, 1998. It provides for the company s
existing base rates to be frozen at current levels through Dec. 31,
1998; a refund to customers of $25 million ($15 million from 1996
operations and $10 million from the 1995 deferred revenues) plus
interest over a period of one year commencing on Oct. 1, 1996; and for
the possibility of an additional refund in 1999.
Under the agreement, for the years 1996 through 1998 the company
will keep in each year all revenues contributing to an ROE up to
11.75 percent. Any additional revenues will be allocated according to
the following formula.
In 1996, 40 percent of any actual revenues that contribute to an
ROE in excess of 11.75 percent will be included in 1996 revenues and
the remaining 60 percent will be deferred for use in 1997 and 1998.
There will also be available for use in 1997 and 1998 about
$41 million of the revenues deferred from 1995, after deducting from
1995 deferred revenues the $10-million portion of the $25-million
refund.
16
In 1997, 40 percent of any revenues that contribute to an ROE in
excess of 11.75 percent up to 12.75 percent will be included in the
company s 1997 revenues. The remaining 60 percent will be deferred for
use in 1998. Any revenues contributing to an ROE exceeding
12.75 percent will be deferred for use during 1998.
The same 40 percent allocation of revenues will be made in 1998
after taking into account any accumulated deferred revenues not used
in previous years. The remaining 60 percent, as well as all revenues
contributing to an ROE in excess of 12.75 percent, if any, will be
refunded to customers in 1999. No refunds resulting from the 1998
portion of the agreement will commence until a final, non-appealable
order has been issued resolving all issues with respect to the
calculation of earned ROE during the periods covered by the agreement,
including the appropriate regulatory treatment of the Polk Power
Station.
Finally, the agreement calls for an expeditious review of the regulatory
treatment of the company's Polk Power Station. The company is optimistic that
the FPSC will complete this review in the third quarter of 1996. An objective of
the agreement is to maintain price stability by utilizing the 1995, 1996 and
1997 deferred revenues to offset a portion of the revenue requirements
associated with the Polk Power Station.
Coal Settlement
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 agreed to refund $10 million plus interest to its
customers through the fuel adjustment clause over a 12-month period
beginning April 1, 1993. The company refunded $7.6 million to its
customers in 1993 and the remainder in 1994.
Utility 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 natural gas for residences and businesses
and the self-generation option available to larger users of electric
energy. 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, to control costs, and provide high
quality service to retail customers.
There is presently active competition in the wholesale power
markets in Florida, 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 and
required utilities to transmit power from such producers, utilities
and others to wholesale customers under certain circumstances. The
company continues its cost reduction efforts to increase its wholesale
business, which is dependent on access to transmission systems owned
by others.
17
In March 1995 the Federal Energy Regulatory Commission (FERC)
issued its Notice Of Proposed Rulemaking on Open Access Transmission
Services (NOPR). The NOPR would require open access to transmission
systems and utilities owning transmission facilities (including the
company) to provide services to wholesale transmission customers
comparable to those they provide to themselves on comparable terms and
conditions (including price). Among other things the NOPR would
unbundle transmission services from power sales and require owners of
transmission systems to take service under their own transmission
tariffs.
FERC Transmission/Interchange Proceedings
The company is one of several utilities that intervened in
Florida Power and Light's (FPL) proceeding before the 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 aspects of FPL s
filing, the company maintains that FPL s transmission tariffs
adversely affect competition in the wholesale market and violate
FERC s comparability standard governing open access to wholesale
transmission.
In December 1995 an Administrative Law Judge appointed by the
FERC issued his initial decision which is generally favorable to the
positions advocated by the company. Briefs on this decision have been
filed by the active intervenors, FERC staff and FPL, and the case is
now fully submitted for a decision by the FERC. Any disposition of
transmission issues is expected to reflect FERC action on the NOPR.
The company protested transmission tariff filings by Florida
Power Corporation (FPC), likewise based principally on their adverse
competitive effects on the wholesale power market and failure to
comply with the FERC s comparability standard. FPC has withdrawn these
tariffs and substituted tariffs which conform to the pro forma tariffs
in the NOPR. The ultimate terms of these tariffs will be determined
after final action by FERC under the NOPR.
In November 1995 the FERC accepted for filing the company s
open access transmission tariffs, which conform to the pro forma
tariffs contained in the NOPR, subject to refund and the outcome of
the final rule under the NOPR.
FINANCING ACTIVITY
The company s 1995 year-end capital structure was 41 percent
debt, 56 percent common equity and 3 percent preferred equity. 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 Standard & Poor s
AA+ Aa2 AA
The current ratings reflect actions taken by Duff & Phelps in
March 1995 to increase the company s senior and subordinate debt
ratings one level and by Moody s Investor Services in April to lower
the company s senior and subordinate debt ratings one level.
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
18
series having a 9.9-percent interest rate. For accounting and
ratemaking purposes the company began recording interest expense using
a blended rate for the original and refunding bonds. This blended rate
was used from July 1993 and will continue to be used through the
maturity dates of the original bonds.
As a part of its risk management program the company entered into
an interest rate exchange agreement to moderate its exposure to
interest rate changes. This agreement expired in early 1996.
Currently, the company is not a party to and does not own any
derivative instruments.
LIQUIDITY, CAPITAL RESOURCES
The company met cash needs during 1995 largely with internally
generated funds, short-term debt and capital contributions from its
parent.
At Dec. 31, 1995 the company had bank credit lines of $180
million, all of which was available.
The company anticipates meeting its capital requirements for
ongoing operations in 1996 through 2000 substantially from internally
generated funds. In 1996, the company expects to issue about $100
million of long-term debt, primarily to reduce short-term debt and
redeem current maturities. In addition, the company anticipates some
capital contributions from its parent in 1996.
On March 29, 1996, the company issued a notice to call and retire
on April 29, 1996, $35 million aggregate par value Series E and F
Preferred Stock at redemption prices of $102 and $101, respectively,
plus accrued dividends.
19
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
No.
Report of Independent Accountants 21
Balance Sheets, Dec. 31, 1995 and 1994 22
Statements of Income for the years ended
Dec. 31, 1995, 1994 and 1993 23
Statements of Cash Flows for the years ended
Dec. 31, 1995, 1994 and 1993 24
Statements of Retained Earnings for the years ended
Dec. 31, 1995, 1994 and 1993 25
Statements of Capitalization, Dec. 31, 1995 and 1994 25-26
Notes to Financial Statements 27-35
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.
20
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, 1995 and
1994, and the related statements of income, cash flows, retained
earnings and capitalization for each of the three years in the period
ended Dec. 31, 1995. 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, evidence 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, 1995 and 1994, and the results
of its operations and its cash flows for each of the three years in
the period ended Dec. 31, 1995, 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. 15, 1996
21
BALANCE SHEETS
(millions)
Assets
Dec. 31, 1995 1994
Property, Plant and Equipment,
At Original Cost
Utility plant in service $2,930.2 $2,854.2
Construction work in progress 475.2 246.1
3,405.4 3,100.3
Accumulated depreciation (1,203.3) (1,115.2)
2,202.1 1,985.1
Other property .9 .2
2,203.0 1,985.3
Current Assets
Cash and cash equivalents 3.8 7.1
Short-term investments .2 --
Receivables, less allowance
for uncollectibles 120.1 103.5
Inventories, at average cost
Fuel 70.0 95.8
Materials and supplies 38.7 38.5
Prepayments 3.5 2.7
236.3 247.6
Deferred Debits
Unamortized debt expense 18.3 19.8
Deferred income taxes 94.6 86.5
Regulatory asset-tax related 36.9 30.8
Other 50.1 47.8
199.9 184.9
$2,639.2 $2,417.8
Liabilities and Capital
Capital
Common stock $ 851.9 $ 775.9
Retained earnings 188.2 173.3
1,040.1 949.2
Preferred stock, redemption not required 55.0 55.0
Long-term debt, less amount due
within one year 583.1 607.3
1,678.2 1,611.5
Current Liabilities
Long-term debt due within one year 26.0 1.3
Notes payable 144.5 91.8
Accounts payable 117.4 113.8
Customer deposits 51.3 49.4
Interest accrued 8.9 11.2
Taxes accrued 16.5 2.1
364.6 269.6
Deferred Credits
Deferred income taxes 331.8 327.6
Investment tax credits 58.5 63.3
Regulatory liability-tax related 84.5 88.3
Other 121.6 57.5
596.4 536.7
$2,639.2 $2,417.8
The accompanying notes are an integral part of the financial
statements.
22
STATEMENTS OF INCOME
(millions)
Year ended Dec. 31, 1995 1994 1993
Operating Revenues
Residential $ 523.3 $ 505.5 $ 464.1
Commercial 316.1 316.8 298.3
Industrial-Phosphate 61.7 58.3 55.1
Industrial-Other 45.0 50.0 48.9
Sales for resale 80.0 70.4 76.1
Deferred and other revenues 66.2 93.9 98.8
1,092.3 1,094.9 1,041.3
Operating Expenses
Operation
Fuel 384.3 389.3 363.2
Purchased power 44.4 33.4 39.0
Other 163.3 171.6 157.7
Restructuring charge -- 21.3 --
Maintenance 69.6 72.9 71.4
Depreciation 113.3 115.1 111.9
Taxes-Federal and state income 66.2 57.4 60.5
Taxes-Other than income 87.9 86.8 83.5
929.0 947.8 887.2
Operating Income 163.3 147.1 154.1
Other Income (Expense)
Allowance for other funds
used during construction 13.7 3.5 1.6
Other income (expense), net (.4) (1.2) (6.7)
13.3 2.3 (5.1)
Income before interest charges 176.6 149.4 149.0
Interest Charges
Interest on long-term debt 38.2 36.9 39.3
Other interest 10.3 4.6 5.1
Allowance for borrowed funds
used during construction (5.6) (2.2) (2.1)
42.9 39.3 42.3
Net Income 133.7 110.1 106.7
Preferred dividend
requirements 3.6 3.6 3.6
Balance Applicable to
Common Stock $ 130.1 $ 106.5 $ 103.1
The accompanying notes are an integral part of the financial
statements.
23
STATEMENTS OF CASH FLOWS
(millions)
Year ended Dec. 31, 1995 1994 1993
Cash Flows from
Operating Activities
Net income $133.7 $ 110.1 $ 106.7
Adjustments to reconcile net
income to net cash
Depreciation 113.3 115.1 111.9
Deferred income taxes (13.8) (14.1) 10.8
Restructuring charge and
other cost reductions -- 21.3 --
Investment tax credits, net (4.8) (5.4) (4.9)
Allowance for funds used
during construction (19.3) (5.6) (3.7)
Deferred clause revenues
(expenses) (12.4) 19.9 (10.6)
Fuel cost settlement -- -- 10.0
Deferred revenue 50.8 -- --
Coal contract buyout 2.0 (25.5) --
Refund to customers -- (2.4) (7.6)
Receivables, less allowance
for uncollectibles (16.6) (5.5) (3.9)
Fuel inventory 25.8 (18.4) 9.0
Taxes accrued 14.4 (10.2) 2.1
Accounts payable 3.6 27.8 6.1
Other 25.1 18.0 (.4)
301.8 225.1 225.5
Cash Flows from
Investing Activities
Capital expenditures (334.5) (230.8) (205.6)
Allowance for funds used
during construction 19.3 5.7 3.7
Short-term investments (.2) .2 1.7
(315.4) (224.9) (200.2)
Cash Flows from
Financing Activities
Proceeds from contributed
capital from parent 76.0 111.0 37.0
Proceeds from long-term debt .6 .7 15.6
Repayment of long-term debt (.2) (.2) (48.0)
Net increase in short-term debt 52.7 10.3 52.3
Dividends (118.8) (119.4) (106.0)
10.3 2.4 (49.1)
Net increase (decrease)
in cash and cash equivalents (3.3) 2.6 (23.8)
Cash and cash equivalents at
beginning of year 7.1 4.5 28.3
Cash and cash equivalents at
end of year $ 3.8 $ 7.1 $ 4.5
Supplemental Disclosure of Cash Flow Information
Cash paid during the year for:
Interest $ 42.6 $ 39.8 $ 43.5
Income taxes $ 71.2 $ 83.9 $ 51.4
The accompanying notes are an integral part of the financial
statements.
24
STATEMENTS OF RETAINED EARNINGS
(millions)
Year ended Dec. 31, 1995 1994 1993
Balance, Beginning of Year (1) $173.3 $182.6 $182.2
Add-Net income 133.7 110.1 106.7
307.0 292.7 288.9
Deduct-Cash dividends on
capital stock
Preferred 3.6 3.6 3.6
Common 115.2 115.8 102.4
118.8 119.4 106.0
Balance, End of Year $188.2 $173.3 $182.9
(1) The Retained Earnings balance at Jan. 1, 1994 was 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 29.
STATEMENTS OF CAPITALIZATION
Capital Stock Outstanding Cash Dividends
Dec.31, 1995 Paid in 1995(1)
Current
Redemption Per
Price Shares Amount(2) Share Amount(2)
Common stock-Without par value
25 million shares
authorized N/A 10 $851.9 N/A $115.2
Preferred Stock-$100 Par Value
1.5 million shares
authorized
4.32% Cumulative,
Series A $103.75 49,600 $ 5.0 $4.32 $ .2
4.16% Cumulative,
Series B $102.875 50,000 5.0 $4.16 .2
4.58% Cumulative,
Series D $101.00 100,000 10.0 $4.58 .5
8.00% Cumulative,
Series E (3) $102.00 149,960 15.0 $8.00 1.2
7.44% Cumulative,
Series F (3) $101.00 200,000 20.0 $7.44 1.5
549,560 $55.0 $3.6
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) Millions.
(3) On March 29, 1996, the company issued a notice to call and retire on
April 29, 1996, the Series E and F Preferred Stock at the redemption
prices set forth plus accrued dividends.
At Dec. 31, 1995, preferred stock had a carrying amount of $55.0 million and
an estimated fair market value of $49.1 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.
25
STATEMENTS OF CAPITALIZATION (continued)
(millions)
Long-Term Debt Outstanding at Dec. 31, Due 1995 1994
First mortgage bonds (issuable in series)
5 1/2% 1996 $ 25.0 $ 25.0
7 3/4% 2022 75.0 75.0
5 3/4% 2000 80.0 80.0
6 1/8% 2003 75.0 75.0
Installment contracts payable(2)
5 3/4% 2007 24.4 24.7
7 7/8% Refunding bonds(3) 2021 25.0 25.0
8% Refunding bonds(3) 2022 100.0 100.0
6.25% Refunding bonds(4) 2034 86.0 86.0
Variable rate: 3.81% for 1995
and 4.10% for 1994(1) 2025 51.6 51.6
Variable rate: 3.72% for 1995
and 4.02% for 1994(1) 2018 54.2 54.2
Variable rate: 3.90% for 1995
and 4.23% for 1994(1)(5) 2020 16.9 16.3
Unamortized debt premium/(discount) (4.0) (4.2)
609.1 608.6
Less amount due within one year(6) (26.0) (1.3)
Total Long-Term Debt $583.1 $607.3
Maturities and annual sinking fund requirements of long-term debt for
the years 1997, 1998, 1999 and 2000 are $1.0 million, $1.1 million, $1.1
million, and $81.1 million, respectively. Of these amounts $0.8 million per
year for 1997 through 2000 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) Proceeds of these bonds
were used to refund bonds with an interest rate of 9.9% in Feb. 1995. For
accounting purposes, interest expense has been recorded using a blended
rate of 6.52% on the original and refunding bonds, consistent with
regulatory treatment.
(5) This amount is recorded net of $3.1 million and $3.7 million at Dec. 31,
1995 and Dec. 31, 1994, respectively, on deposit with the trustee.
(6) Of the amount due in 1996, $.8 million may be satisfied by the
substitution of property in lieu of cash payments.
At Dec. 31, 1995, long-term debt had a carrying amount of $583.1 million
and an estimated fair market value of $638.6 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, which expired
Jan. 11, 1996, to reduce the cost of $100 million of fixed rate long-term
debt. The agreement reduced interest expense by $2.3 million per year in
1995, 1994 and 1993.
The accompanying notes are an integral part of the financial statements.
26
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.
The use of estimates is inherent in the preparation of financial statements
in accordance with generally accepted accounting principles.
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.
On May 10, 1995, the FPSC approved the termination of the oil backout
clause effective Jan. 1, 1996. Any oil backout project costs incurred beginning
Jan 1, 1996 will no longer be recovered through the cost recovery clause.
In December 1994, the company bought out a 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 coal supplied under the
new contracts is competitive in price with coals of comparable quality. As a
result of this buyout, Tampa Electric customers will benefit from anticipated
net fuel savings of more than $40 million through the year 2004. In February
1995, the FPSC authorized the recovery of the $25.5 million buy-out amount plus
carrying costs through the Fuel and Purchased Power Cost Recovery Clause over
the next ten years beginning April 1, 1995. In 1995, $2 million of buy-out
costs were amortized to expense.
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.
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.
27
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 3.9% for 1995, and 4.2% for 1994 and 1993.
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 its books and records reflect 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.
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 7.79% for 1995, 7.28% for 1994 and 7.70% for 1993.
The base on which AFUDC is calculated excludes construction work in
progress which has been included in rate base.
28
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
available-for-sale are highly liquid, high-quality debt instruments
purchased with a maturity of three months or less. There are no available-
for-sale securities at Dec. 31, 1995.
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, 1995 or 1994 and the change in net unrealized gains and
losses on trading securities included in earnings in 1995 and 1994 was not
significant.
Reclassifications
Certain 1994 and 1993 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)
Balance Dec. 31, 1992 10 $629.3 $(1.7)
Contributed capital from parent 37.0 --
Balance Dec. 31, 1993 10 666.3 (1.7)
Contributed capital from parent 111.0 --
Reclassification to other
capital accounts(1) -- .3
Balance Dec. 31, 1994 10 777.3 (1.4)
Contributed capital from parent 76.0 --
Balance Dec. 31, 1995 10 $853.3 $(1.4)
(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, 1995, substantially
all of the company's retained earnings were available for dividends on its
common stock.
29
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 earnings.
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 $0.2 million for 1995, $0.9 million
for 1994 and $1.1 million for 1993. 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, 1995.
Components of net pension expense, reconciliation of the funded
status and the accrued pension liability are presented below for TECO
Energy consolidated.
Components of Net Pension Expense
(millions)
1995 1994 1993
Service cost
(benefits earned during the period) $ 7.2 $ 8.8 $ 7.7
Interest cost on projected
benefit obligations 17.3 15.8 15.0
Less: Return on plan assets
Actual 66.4 (3.7) 30.5
Less net amortization of unrecognized
transition asset and deferred return 43.3 (25.8) 10.3
Net return on assets 23.1 22.1 20.2
Net pension expense 1.4 2.5 2.5
Effect of restructuring charge -- 13.3 --
Net pension expense recognized
in the Consolidated Statements
of Income $ 1.4 $15.8 $ 2.5
Reconciliation of the Funded Status of the Retirement Plan and the Accrued
Pension Prepayment/(Liability)
(millions)
Dec. 31, Dec. 31,
1995 1994
Fair market value of plan assets $ 286.7 $ 239.2
Projected benefit obligation (260.2) (218.0)
Excess of plan assets over projected
benefit obligation 26.5 21.2
Less unrecognized net gain from past
experience different from that assumed 33.4 23.8
Less unrecognized prior service cost (7.1) (7.7)
Less unrecognized net transition asset
(being amortized over 19.5 years) 9.5 10.5
Accrued pension prepayment/(liability) $ (9.3) $ (5.4)
Accumulated benefit obligation
(including vested benefits of
$193.2 for 1995 and $163.8 for 1994) $ 215.2 $ 183.4
30
Assumptions Used in Determining Actuarial Valuations
1995 1994
Discount rate to determine projected
benefit obligation 7.3% 8.25%
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.
Components of Postretirement Benefit Cost (millions)
1995 1994 1993
Service cost (benefits earned
during the period) $ 1.2 $1.5 $1.2
Interest cost on projected
benefit obligations 4.8 4.1 3.6
Amortization of transition obligation
(straight line over 20 years) 2.0 2.1 2.1
Amortization of actuarial (gain)/loss .2 .2 --
Net periodic postretirement
benefit expense 8.2 7.9 6.9
Effect of restructuring charge -- 2.6 --
Net periodic postretirement
benefit expense recognized in
the Statements of Income $ 8.2 $10.5 $ 6.9
Reconciliation of the Funded Status of the Postretirement Benefit Plan and
the Accrued Liability (millions)
Dec. 31, Dec. 31,
1995 1994
Accumulated postretirement benefit obligation
Active employees eligible to retire $ (2.2) $ (9.4)
Active employees not eligible to retire (22.6) (19.9)
Retirees and surviving spouses (41.8) (33.0)
(66.6) (62.3)
Less unrecognized net gain/(loss)
from past experience (16.7) (14.1)
Less unrecognized transition obligation (33.9) (35.9)
Liability for accrued postretirement benefit $(16.0) $(12.3)
31
Assumptions used in Determining Actuarial Valuations
Discount rate to determine projected
benefit obligation 7.3% 8.25%
The assumed health care cost trend rate for medical costs prior to age 65,
and for certain retirees after age 65, was 11% in 1995 and decreases to
5.75% in 2002 and thereafter. The assumed health care cost trend rate for
medical costs after age 65 was 7.5% in 1995 and decreases to 5.75% in 2002
and thereafter.
A 1 percent increase in the medical trend rates would produce an
8 percent ($0.5 million) increase in the aggregate service and interest
cost for 1995 and a 7 percent ($4.7 million) increase in the accumulated
postretirement benefit obligation as of Dec. 31, 1995.
F. Restructuring Charge
In 1994, the company implemented a corporate restructuring program which
resulted in a $21.3 million charge ($13.1 million after tax). The cost of
this restructuring 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 and $3.8 million in 1995. The impact on pension cost resulting from
the restructuring as determined under the provisions of FAS 88, "Accounting
for Settlements and Curtailments 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 $21.3
million. See Note D on pages 30 and 31, and Note E on pages 31 and 32.
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:
(millions) Federal State Total
1995
Currently payable $ 72.1 $ 12.4 $ 84.5
Deferred (11.8) (2.0) (13.8)
Amortization of investment
tax credits (4.8) - (4.8)
Total income tax expense $ 55.5 $ 10.5 $ 65.9
Included in other income, net (.3)
Included in operating expenses $ 66.2
32
1994
Currently payable $ 68.3 $ 9.9 $ 78.2
Deferred (11.1) (3.0) (14.1)
Investment tax credits (.6) -- (.6)
Amortization of investment
tax credits (4.8) -- (4.8)
Total income tax expense $ 51.8 $ 6.9 58.7
Included in other income, net 1.3
Included in operating expenses $ 57.4
1993
Currently payable $ 43.6 $ 7.6 $ 51.2
Deferred 9.4 1.4 10.8
Amortization of investment
tax credits (4.9) -- (4.9)
Total income tax expense $ 48.1 $ 9.0 57.1
Included in other income, net (3.4)
Included in operating expenses $ 60.5
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,
(millions) 1995 1994
Deferred tax assets(1)
Property related $ 76.6 $ 69.8
Leases 5.5 5.2
Insurance reserves 6.6 5.4
Early capacity payments 2.2 2.2
Other 3.7 3.9
Total deferred income tax assets 94.6 86.5
Deferred income tax liabilities(1)
Property related (361.5) (336.6)
Other 29.7 9.0
Total deferred income tax liabilities (331.8) (327.6)
Accumulated deferred income taxes $(237.2) $(241.1)
_________________
(1) Certain property related assets and liabilities have been netted.
33
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:
(millions) 1995 1994 1993
Net income $133.7 $110.1 $106.7
Total income tax provision 66.0 58.7 57.1
Income before income taxes $199.7 $168.8 $163.8
Income taxes on above at federal
statutory rate (35% for 1995,
1994 and 1993) $ 70.0 $ 59.1 $ 57.3
Increase (decrease) due to
State income tax, net of federal
income tax 6.8 4.5 5.9
Amortization of investment tax
credits (4.8) (4.8) (4.9)
Equity portion of AFUDC (4.9) (1.4) (.8)
Other (1.1) 1.3 (.4)
Total income tax provision $ 66.0 $ 58.7 $ 57.1
Provision for income taxes as
a percent of income before
income taxes 33.0% 34.8% 34.9%
H. Short-Term Debt
Notes payable consisted exclusively of commercial paper with weighted
average interest rates of 5.69% and 5.92% at Dec. 31, 1995 and Dec. 31,
1994, respectively. 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, 1995 were $180 million. Certain lines of credit
require commitment fees ranging from .05% to .075% on the unused balances.
I. Related Party Transactions (millions)
Net transactions with affiliates are as follows:
1995 1994 1993
Fuel and interchange related, net $166.4 $180.0 $189.5
Administrative and general, net $ 11.8 $ 9.0 $ 15.5
Amounts due from or to affiliates of the company at year-end are as
follows:
1995 1994
Accounts receivable $ 2.6 $ 1.6
Accounts payable $ 23.9 $ 17.3
Accounts receivable and accounts payable were incurred in the ordinary
course of business and do not bear interest.
34
J. Commitments and Contingencies
The company has made certain commitments in connection with its continuing
capital improvements program. Capital expenditures are estimated to be $178
million for 1996 and $569 million for 1997 through 2000 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 construction funding from the Department
of Energy under its Clean Coal Technology Program. The company expects to
spend $70 million to complete this project in 1996. At the end of 1995, the
company had outstanding commitments of approximately $72 million primarily
for the construction of Polk Unit One.
35
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
During the period from Jan. 1, 1994 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 on 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 64 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 58 Chairman, Macfarlane, Ausley, 1992
Ferguson & McMullen (attorneys),
Tallahassee, Florida; formerly
President, Ausley, McMullen,
McGehee, Carothers & Proctor,
P.A. (attorneys), Tallahassee,
Florida; also a director of Sprint
Corporation and Capital City Bank
Group Inc.
Sara L. Baldwin 64 Private Investor; formerly 1980
Vice President, Baldwin and
Sons, Inc. (insurance agency),
Tampa, Florida
Hugh L. Culbreath 74 Retired; formerly Chairman of 1971
the Board of TECO Energy, Inc.
and Tampa Electric Company
James L. Ferman, Jr. 52 President, Ferman Motor Car 1985
Company, Inc. (automobile
dealerships), Tampa, Florida;
also a director of The Bank of
Tampa and its holding company,
The Tampa Banking Company
36
Edward L. Flom 66 Retired; formerly Chairman 1980
of the Board and Chief Executive
Officer, Florida Steel
Corporation (production and
fabrication of steel products),
Tampa, Florida; also a director
of Outback Steakhouse, Inc.
Henry R. Guild, Jr. 67 President and Director, Guild, 1980
Monrad & Oates, Inc. (private
trustees and family investment
advisers), Boston, Massachusetts
Timothy L. Guzzle 59 Chairman of the Board and 1988
Chief Executive Officer,
Tampa Electric Company and
TECO Energy, Inc.; also a director
of NationsBank Corporation
Dennis R. Hendrix 56 Chairman of the Board and formerly 1995
Chief Executive Officer and
President, Panhandle Eastern
Corporation (interstate gas
pipeline), Houston, Texas;
also a director of Texas Eastern
Products Pipeline Company, general
partner of TEPPCO Partners, LP, a
publicly traded limited partnership
Robert L. Ryan 52 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.
William P. Sovey 62 Vice Chairman and Chief Executive 1996
Officer and formerly President
and Chief Operating Officer,
Newell Co. (consumer products),
Freeport, Illinois; also a director
of Acme Metals Co.
37
J. Thomas Touchton 57 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 67 President, John A. Urquhart 1991
Associates (management
consultants), Fairfield,
Connecticut and Vice Chairman and
Director of Enron Corp. (diversified
natural gas company), Houston, Texas;
formerly Senior Vice President,
G. E. Industrial & Power Systems,
General Electric Company; also a
director of
Aquarion Company
James O. Welch, Jr. 64 Retired; formerly Vice Chairman, 1976
RJR Nabisco, Inc. and Chairman,
Nabisco Brands, Inc.; also a
director of Kmart Corporation and
Vanguard Group of Investment Companies
The term of office of each director extends to the next annual
meeting of shareholders, scheduled to be held on April 17, 1996, 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 59 Chairman of the Board and
Chief Executive Officer;
also Chairman of the
Board and Chief Executive
Officer of TECO Energy, Inc.
Keith S. Surgenor 48 President and Chief
Operating Officer, 1994 to
date; and prior thereto, Vice
President-Human Resources.
William N. Cantrell 43 Vice President-Energy Supply,
1994 to date; and prior
thereto, Vice President-Energy
Resource Planning.
38
Roger A. Dunn 53 Vice President-Human Resources,
1995 to date; also
Vice President-Human Resources
of TECO Energy, Inc., 1995 to date; and
prior thereto, Senior Vice
President-Human Resources and
Corporate Affairs of LTV
Corporation (steel
manufacturer), Cleveland, Ohio.
Gordon L. Gillette 36 Vice President-Regulatory
Affairs, 1994 to date;
and prior thereto,
Director-Project Services,
TECO Power Services
Corporation.
William L. Griffin 41 Vice President-Controller,
January 1996 to date; also Vice
President-Controller, TECO
Energy, Inc, May 1994 to
date; and prior thereto, Vice
President and Group Controller,
Automatic Transmission Systems,
a division of Borg-Warner
Automotive Corporation.
(automobile parts
manufacturer), Chicago,
Illinois.
Roger H. Kessel 59 General Counsel and Secretary, 1992
to date; and prior thereto, Vice
President-General Counsel of TECO
Energy, Inc.; Also Senior Vice
President-General Counsel and
Secretary of TECO Energy, Inc.,
April 1995 to date.
Alan D. Oak 49 Vice President, Treasurer and
Chief Financial Officer, 1992
to date; and prior thereto
Chief Financial Officer; also
Senior Vice President-Finance
and Chief Financial Officer
of TECO Energy, Inc.
39
John B. Ramil 40 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 57 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 17, 1996, 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 four other most
highly compensated executive officers of the company.
40
Summary Compensation Table
Long-Term
Compensation
Annual Compensation Awards
Other
Annual
Name and Compen- Shares Underlying All Other
Principal Position Year Salary Bonus sation (1) Options/SARs(#)(2) Compensation(3)
Timothy L. Guzzle(4) 1995 $493,750 $415,000 $50,925 60,000 $31,092
Chairman of the Board 1994 468,750 384,000 40,000 28,703
Chief Executive Officer 1993 443,750 194,000 40,000 28,267
Keith S. Surgenor(4)(5) 1995 272,500 195,000 45,664 25,000 17,994
President and Chief 1994 215,376 225,000 12,000 13,728
Operating Officer 1993 179,500 60,000 12,000 11,986
Roger H. Kessel(4) 1995 238,500 135,000 44,765 17,000 9,052
General Counsel and 1994 228,750 150,000 14,000 10,257
Secretary 1993 219,750 80,000 14,000 10,417
Alan D. Oak(4) 1995 225,000 135,000 44,264 17,000 14,432
Vice President, 1994 201,750 130,000 13,000 12,905
Treasurer and Chief 1993 192,875 74,000 13,000 12,843
Financial Officer
William N. Cantrell 1995 145,250 42,000 43,126 6,000 10,143
Vice President- 1994 129,917 50,000 4,600 8,902
Energy Supply 1993 121,500 28,000 4,600 8,204
_________________
(1) Participants in the company car program received a one-time cash payment in connection with
its elimination in 1995. The amount set forth includes this payment, which in the case of the
named executive officers was $40,890.
(2) Limited stock appreciation rights were awarded in tandem with options granted. See Footnote
(2) under "Option/SAR Grants In Last Fiscal Year" on page 41.
(3) The reported amounts for 1995 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.
(4) Includes compensation for services as an officer of TECO Energy.
(5) Prior to July 19, 1994, Mr. Surgenor served as Vice President-Human Resources.
41
TECO Energy and its subsidiaries, including the company. Information for 1995 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 60,000 12.29% $20.75 4/03/05 $236,799
Keith S. Surgenor 25,000 5.12% $20.75 4/03/05 $ 98,666
Roger H. Kessel 17,000 3.48% $20.75 4/03/05 $ 67,093
Alan D. Oak 17,000 3.48% $20.75 4/03/05 $ 67,093
William N. Cantrell 6,000 1.23% $20.75 4/03/05 $ 23,680
_________________
(1) The options are exercisable beginning on the date of grant, April 3, 1995.
(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 1995. 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 Black-Scholes valuation model and are stated in current
annualized dollars on a present value basis. The key assumptions used for purposes of this
calculation include the following: (a) a 7.5% discount rate; (b) a volatility factor based upon
the average trading price for the 36-month period ending Dec. 31, 1994; (c) a dividend factor
based upon the 3-year average dividend paid by TECO Energy for the period ending Dec. 31, 1994;
(d) the 10-year option term; and (e) the closing price of TECO Energy's Common Stock on Dec. 31,
1994. The present value of the options reported has been calculated by multiplying $20.75, the
share price on the date of grant, by 0.1902, the Black-Scholes valuation factor, and by the number
of shares underlying the options granted. The actual value an executive may realize will depend
upon the extent to which the stock price exceeds the exercise price on the date the option is
exercised. Accordingly, the value, if any, realized by an executive will not necessarily be the
value determined by the Black-Scholes model.
42
Aggregated Option/SAR Exercises In Last Fiscal Year and
Fiscal Year-End Option/SAR Value
Number of
Shares Value of
Underlying Unexercised
Unexercised In-The-Money
Options/SARs Options/SARs
at Year-End(#) at Year-End
Value
Shares Acquired Realized Exercisable/ Exercisable/
Name On Exercise(#) ($) Unexercisable Unexercisable
Timothy L. Guzzle 0 0 220,000/0 $1,210,000/0
Keith S. Surgenor 0 0 91,000/0 603,563/0
Roger H. Kessel 0 0 137,000/0 1,127,248/0
Alan D. Oak 0 0 69,000/0 381,220/0
William N. Cantrell 0 0 57,600/0 586,225/0
Pension Table
The following table shows estimated annual benefits payable under the
company's pension plan arrangements for the named executive officers other
than Messrs. Guzzle and Kessel.
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, and the amounts payable to Mr. Kessel are based on 5% of
earnings and a maximum of 9 years of service.
The earnings covered by the pension plan arrangements are the same as
those reported as salary and bonus in the summary compensation table above.
Years of service for the named executive officers are as follows: Mr.
Guzzle (8 years), Mr. Surgenor (7 years), Mr. Kessel (6 years), Mr. Oak (22
43
years) and Mr. Cantrell (20 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 TECO Energy
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 the named executive
officers of the company, under which payments will be made under certain
circumstances following a change in control of TECO Energy. A change in
control means in general the acquisition by any person of 30% or more of
the common stock of TECO Energy, the change in a majority of the directors
o r the approval by the TECO Energy shareholders of a merger or
consolidation of TECO Energy in which TECO Energy s shareholders do not
have majority voting power in the surviving entity or of the liquidation or
sale of the assets of TECO Energy. Each of these officers 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 one of these
officers for good reason (as defined) following a change in control, TECO
Energy will make a lump sum severance payment to the officer of three times
(two times in the case of Mr. Cantrell) 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 three
years (two years in the case of Mr. Cantrell) 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. In addition, Messrs.
Guzzle, Surgenor, Kessel and Oak will receive a payment to compensate for
the additional taxes, if any, payable on the benefits received under the
severance agreements and any other benefits contingent on a change in
control as a result of the application of the excise tax associated with
Section 280G of the Internal Revenue Code.
Any benefit payable to Mr. Cantrell 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 1995 option grant
provides for a two-year exercise extension period in the event of such a
termination. TECO Energy also has an agreement with Mr. Kessel providing
44
for a minimum base salary of $189,000 and salary continuation payments for
one year in the event of termination by TECO Energy without cause.
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 $27,000 and a fee of $750 for attendance
at each meeting of the Board of TECO Energy, $750 for each meeting of the
Board of the company and $1,000 for attendance at each meeting of a
Committee of the Board on which they serve. 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 a severance benefit (in the event of termination of
Mr. Culbreath s consultancy following a change in control of TECO Energy)
equal to the total compensation that would have been payable over the
remaining term of the agreement. This benefit is payable under the same
circumstances as the benefits described under "Executive
Compensation Employment and Severance Agreements" above and will be reduced
to the extent that such benefit, 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.
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 and
an annual grant of options for 2,000 shares for each continuing director.
Grants are made on the first trading day of TECO Energy common stock after
e a ch TECO Energy annual meeting of shareholders. 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 at the rate of $20,000 per year. 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.
45
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, 1996, 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, 1996 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, 1996.
Name Shares (1)
Girard F. Anderson 144,368(2)(3)
DuBose Ausley 21,527
Sara L. Baldwin 20,918(4)
Hugh L. Culbreath 75,825(5)
James L. Ferman, Jr. 26,185(6)
Edward L. Flom 20,784(7)
Henry R. Guild, Jr. 121,604(8)
Timothy L. Guzzle 243,756(2)(9)
Dennis R. Hendrix 2,500
Robert L. Ryan 20,000(10)
William P. Sovey 1,000
J. Thomas Touchton 22,000(11)
John A. Urquhart 19,452(12)
James O. Welch, Jr. 26,600(13)
Keith S. Surgenor 102,429(2)(14)
Roger H. Kessel 138,975(2)
Alan D. Oak 98,723(2)(15)
William N. Cantrell 78,317(2)(16)
23 directors and executive
officers as a group (including
those named above) 1,226,373(2)(17)
__________________
(1) The amounts listed include the following shares that are subject to
options granted under TECO Energy s stock option plans: Mr.
Anderson, 112,000 shares; Mr. Ausley, 16,000 shares; Mrs. Baldwin
and Messrs. Culbreath, Ferman, Flom, Guild, Ryan, Touchton and
Welch, 18,000 shares each; Mr. Guzzle, 140,000 shares; Mr. Urquhart,
15,200 shares; Mr. Surgenor, 77,000 shares; Mr. Kessel, 137,000
shares; Mr. Oak, 69,000 shares; Mr. Cantrell, 57,600 shares; and all
directors and executive officers as a group, 833,300 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,
1,756 shares; Mr. Anderson, 8,448 shares; Mr. Surgenor, 2,332
shares; Mr. Kessel, 1,975 shares; Mr. Oak, 9,593 shares; Mr.
Cantrell, 6,709 shares; and all directors and executive officers as
a group, 44,585 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.
46
(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 881 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 101,204 shares held by trusts of which Mr. Guild is a
trustee. Of these shares, 49,825 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 8,996 shares owned jointly by Mr. Surgenor and his wife.
(15) Includes 20,130 shares owned by a Revocable Living Trust of which
Mr. Oak s wife is the sole trustee.
(16) Includes 9,600 shares owned jointly by Mr. Cantrell and his wife,
and 4,408 shares held by a trust of which Mr. Cantrell is trustee.
(17) Includes a total of 23,180 shares owned jointly with spouses and
1,169 shares owned jointly with parent and sibling. Also includes a
total of 12,277 shares owned by spouses, as to which shares
beneficial interest is disclaimed.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Macfarlane, Ausley, Ferguson & McMullen, of which Mr. Ausley is the
chairman, rendered legal services to TECO Energy and its subsidiaries
during 1995.
In addition, reference is made to Note I on page 34.
47
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM
8-K.
(a) 1. Financial Statements - See index on page 20.
2. Financial Statement Schedules - See index on page 20.
3. Exhibits
*3.1 Articles of Incorporation (Exhibit 3.1 to Registration
Statement No. 2-70653).
*3.2 Bylaws, as amended, effective July 18, 1995 (Exhibit 3,
Form 10-Q for the quarter ended June 30, 1995 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 (Exhibit 4.11, Form 10-K for 1994 of
Tampa Electric Company).
*4.12 Third Supplemental Installment Purchase Contract, dated as
of Aug. 1, 1989 (Exhibit 4.16, Form 10-K for 1989 of Tampa
Electric Company).
*4.13 Installment Purchase Contract between the Hillsborough
County Industrial Development Authority and Tampa Electric
Company, dated as of Jan. 31, 1984 (Exhibit 4.13, Form
10-K for 1993 of Tampa Electric Company).
*4.14 First Supplemental Installment Purchase Contract, dated as
of Aug. 2, 1984 (Exhibit 4.14, Form 10-K for 1994 of Tampa
Electric Company).
48
*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 the quarter
ended June 30, 1989 of TECO Energy, Inc.).
*10.2 Directors' Retirement Plan, as amended effective July 1,
1995 (Exhibit 10.1, Form 10-Q for the quarter ended June
30, 1995 of Tampa Electric Company).
*10.3 TECO Energy Group 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
F i r st Amendment to TECO Energy Group Supplemental
Executive Retirement Plan, effective as of Oct. 1, 1994
(Exhibit 10.3, Form 10-K for 1994 of Tampa Electric
Company).
*10.4 TECO Energy, Inc. Group Supplemental Retirement Benefits
Trust Agreement Amendment and Restatement, effective July
17, 1995 (Exhibit 10.2, Form 10-Q for the quarter ended
June 30, 1995 of Tampa Electric Company).
*10.5 Annual Incentive Compensation Plan for TECO Energy and
subsidiaries, as revised January 1993 (Exhibit 10.2, Form
10-Q for the quarter ended March 31, 1994 of Tampa
Electric Company).
*10.6 TECO Energy, Inc. Group Supplemental Disability Income
Plan, dated as of March 20, 1989 (Exhibit 10.19, Form 10-K
for 1988 of Tampa Electric Company).
10.7 Forms of Severance Agreements between TECO Energy, Inc.
and certain senior executives, as amended and restated as
of March 20, 1996.
*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 (Exhibit 10.10, Form
10-K for 1994 of Tampa Electric Company).
49
*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 (Exhibit 10.12, Form 10-K for 1994 of Tampa Electric
Company).
*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, 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 (Exhibit 10.14, Form 10-K for
1994 of Tampa Electric Company).
*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 (Exhibit
10.15, Form 10-K for 1994 of Tampa Electric Company).
*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 (Exhibit 10.17, Form 10-K for 1994 of Tampa Electric
Company).
*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 Plan,
as amended and restated effective Aug. 1, 1994 (Exhibit
10.20, Form 10-K for 1994 of Tampa Electric Company).
*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.).
*10.22 Supplemental Executive Retirement Plan for R.A. Dunn,
dated as of July 17, 1995 (Exhibit 10.3, Form 10-Q for the
quarter ended June 30, 1995 of Tampa Electric Company).
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)
50
_____________
* 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 10.22 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
1995.
The registrant filed a Current Report on Form 8-K dated Jan. 4,
1996 reporting under "Item 5. Other Events" on a proposed agency
action by the FPSC relating to the deferral in 1996 of revenues
under certain circumstances.
The registrant filed a Current Report on Form 8-K dated Feb. 13,
1996 reporting under "Item 5. Other Events" on the filings with
the FPSC by the Office of Public Counsel and the Florida
Industrial Power Users Group, which protest the FPSC s order of
proposed agency action on the deferral in 1996 of revenues under
certain circumstances.
The registrant filed a Current Report on Form 8-K dated March 25,
1996 reporting under "Item 5. Other Events" the agreement among the
registrant, the Office of Public Counsel and the Florida Industrial
Power Users Group on a multi-year base rate freeze, revenue deferral
and refund plan for the registrant.
51
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
28th day of March, 1996.
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 28, 1996:
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/ W. L. GRIFFIN Vice President-Controller
W. L. GRIFFIN (Principal Accounting Officer)
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.
D. R. HENDRIX* Director
D. R. HENDRIX
R. L. RYAN* Director
R. L. RYAN
52
W. P. SOVEY* Director
W. P. SOVEY
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/ W. L. GRIFFIN
W. L. GRIFFIN, Attorney-in-fact
53
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, effective July 18, 1995 *
(Exhibit 3, Form 10-Q for the quarter ended June 30,
1995 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, *
dated as of June 1, 1983 (Exhibit 4.11, Form 10-K for 1994 of
Tampa Electric Company).
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).
54
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 (Exhibit 4.14, Form 10-K for 1994 of
Tampa Electric Company).
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 the quarter ended June 30, 1989 of
TECO Energy, Inc.).
10.2 Directors' Retirement Plan, as amended effective *
July 1, 1995 (Exhibit 10.1, Form 10-Q for the quarter ended
June 30, 1995 of Tampa Electric Company).
10.3 TECO Energy Group 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 (Exhibit 10.3,
Form 10-K for 1994 of Tampa Electric Company).
10.4 TECO Energy, Inc. Group Supplemental Retirement *
Benefits Trust Agreement Amendment and Restatement, effective
July 17, 1995 (Exhibit 10.2, Form 10-Q for the quarter ended
June 30, 1995 of Tampa Electric Company).
10.5 Annual Incentive Compensation Plan for TECO Energy and *
subsidiaries, as revised January 1993 (Exhibit 10.2, Form
10-Q for the quarter ended March 31, 1994 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).
55
10.7 Forms of Severance Agreements between TECO Energy, Inc. 58
and certain senior executives, as amended and restated as of
March 20, 1996.
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 (Exhibit 10.10, Form 10-
K for 1994 of Tampa Electric Company).
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
(Exhibit 10.12, Form 10-K for 1994 of Tampa Electric
Company).
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, 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 (Exhibit 10.14, Form 10-K
for 1994 of Tampa Electric Company).
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 (Exhibit
10.15, Form 10-K for 1994 of Tampa Electric Company).
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 (Exhibit 10.17, Form 10-K for 1994 of Tampa Electric
Company).
56
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 *
Plan, as amended and restated effective Aug. 1, 1994 (Exhibit
10.20, Form 10-K for 1994 of Tampa Electric Company).
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.).
10.22 Supplemental Executive Retirement Plan for R.A. Dunn, *
dated as of July 17, 1995 (Exhibit 10.3, Form 10-Q for the
quarter ended June 30, 1995 of Tampa Electric Company).
12. Ratio of earnings to fixed charges. 95
23. Consent of Independent Accountants. 96
24.1 Power of Attorney. 97
24.2 Certified copy of resolution authorizing Power 99
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.
57