UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(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, 1998
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 executive offices) (Zip Code)
Registrant's telephone number, including area code: (813)228-4111
Securities registered pursuant to Section 12(b) of the Act: NONE
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past 90
days.
YES X NO
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy
or information statements incorporated by reference in Part III of
this Form 10-K or any amendment to this Form 10-K. X
The aggregate market value of the voting stock held by nonaffiliates
of the registrant as of February 28, 1999 was zero.
As of February 28, 1999, 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
The registrant meets the conditions set forth in General Instruction
(I) (1) (a) and (b) of Form 10-K and is therefore filing this form
with the reduced disclosure format.
PART I
Item 1. BUSINESS.
Tampa Electric Company (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 wholly owned subsidiary of TECO Energy,
Inc. (TECO Energy), a diversified energy-related holding company.
In June 1997, TECO Energy acquired Lykes Energy, Inc. As part of
this acquisition, Lykes' regulated gas distribution utility was merged
into the company and now operates as the Peoples Gas System division
of Tampa Electric Company (Peoples Gas System or PGS). Also in June
1997, TECO Energy completed its acquisition of West Florida Natural
Gas Company (West Florida Gas), a local distribution company, serving
the Ocala and Panama City, Florida areas. West Florida Gas now
operates as part of the Peoples Gas System division.
Tampa Electric Company is a public utility operating within the
s t ate of Florida. Through its Tampa Electric division (Tampa
Electric), it is engaged in the generation, purchase, transmission,
distribution and sale of electric energy; through its Peoples Gas
System division, it is engaged in the purchase, distribution and
marketing of natural gas for residential, commercial, industrial and
electric power generation customers wholly in the State of Florida.
Tampa Electric's retail electric service territory comprises an
area of about 2,000 square miles in west central Florida, including
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, Tampa Electric engages in wholesale sales to utilities
and other resellers of electricity. It has three electric generating
stations in or near Tampa, one electric generating station in
southwestern Polk County, Florida, and two electric generating
stations (one of which is on long-term standby) located near Sebring,
a city located in Highlands County in south central Florida. Total net
winter generating capability at Dec. 31, 1998 is 3,615 megawatts
(MWs).
PGS, with 240,000 customers, has operations in Florida's major
metropolitan areas. Annual natural gas throughput (the amount of gas
delivered to its customers including transportation only service) in
1998 was 912 million therms.
P o w er Engineering & Construction, Inc. (PEC), a Florida
corporation formed in late 1996, is a wholly owned subsidiary of Tampa
Electric Company and is engaged in engineering and construction
services with principal focus on power facilities not owned or
operated by Tampa Electric. Operations of PEC in 1998 were not
significant.
TAMPA ELECTRIC--Electric Operations
Tampa Electric had 2,833 employees as of Dec. 31, 1998, of which
1,089 were represented by the International Brotherhood of Electrical
Workers (IBEW) and 334 by the Office and Professional Employees
International Union.
In 1998, approximately 46 percent of Tampa Electric's total
operating revenue was derived from residential sales, 27 percent from
commercial sales, 9 percent from industrial sales and 18 percent from
other sales including bulk power sales for resale.
2
The sources of electric operating revenue for 1998 were as follows:
(millions) 1998
Residential $ 563.2
Commercial 335.2
Industrial-Phosphate 59.3
Industrial-Other 53.4
Other retail sales
of electricity 86.9
Sales for resale 89.6
Deferred revenues 38.3
Other 8.7
$1,234.6
No significant part of Tampa Electric's business is dependent
upon a single customer or a few customers, the loss of any one or more
of whom would have a significantly adverse effect on Tampa Electric,
except for IMC-Agrico (IMCA), a large phosphate producer representing
less than 3 percent of Tampa Electric's 1998 base revenues. See the
discussion of IMCA on page 25.
Tampa Electric's business is not a seasonal one, but winter peak
loads are experienced due to fewer daylight hours and colder
temperatures, and summer peak loads are experienced due to use of air
conditioning and other cooling equipment.
Regulation
The retail operations of Tampa Electric 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.
In general, the FPSC's pricing objective is to set rates at a
level that allows the utility to collect total revenues (revenue
requirements) equal to its cost of providing service, including a
reasonable return on invested capital.
The costs of owning, operating and maintaining the utility
system, other than fuel, purchased power, conservation and certain
environmental costs, are recovered through base rates. These costs
include operation and maintenance expenses, depreciation and taxes, as
well as a return on Tampa Electric's investment in assets used and
useful in providing electric service (rate base). The rate of return
on rate base, which is intended to approximate Tampa Electric's
weighted cost of capital, primarily includes its costs for debt 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 which occur at irregular intervals at the
initiative of Tampa Electric, the FPSC or other parties. See the
discussion of the FPSC-approved agreements covering 1995 through 1999
on pages 22 and 23.
Fuel, conservation, certain environmental and certain purchased
p o w e r costs are recovered through levelized monthly charges
established pursuant to the FPSC's fuel adjustment and cost recovery
clauses. These charges, which are reset annually in an FPSC hearing,
are based on estimated costs of fuel, environmental compliance,
conservation programs and purchased power and estimated customer usage
for a specific recovery period, with a true-up adjustment to reflect
the variance of actual costs from the projected charges.
3
The FPSC may disallow recovery of any costs that it considers
imprudently incurred.
Tampa Electric is also subject to regulation by the Federal
Energy Regulatory Commission (FERC) in various respects including
wholesale power sales, certain wholesale power purchases, transmission
services and accounting and depreciation practices.
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 7 and 8.
T E C O Transport 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
Tampa Electric in addition to third parties. The transactions between
Tampa Electric and these affiliates and the prices paid by Tampa
Electric are subject to regulation by the FPSC and FERC, and any
charges deemed to be imprudently incurred may not be allowed to be
recovered from Tampa Electric's customers.
Competition
Tampa Electric s retail electric business is substantially free
from direct competition with other electric utilities, municipalities
and public agencies. At the present time, the principal form of
competition at the retail level consists of natural gas and propane
for residences and businesses and the self-generation option available
to larger users of electric energy. Such users may seek to expand
their options through various initiatives including legislative and/or
regulatory changes that would permit competition at the retail level.
Tampa Electric intends to take all appropriate actions to retain and
expand its retail business, including managing costs and providing
high-quality service to retail customers.
In 1998, the FPSC approved a tariff for Tampa Electric that
should assist in reducing the loss of existing at-risk load and assist
in the acquisition of new load. The Commercial/Industrial Service
Rider included in this tariff is a load retention, or economic
development contract, that provides for flexible pricing to meet
competitive alternatives available to existing or potential new
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 for independent power producers certain regulatory barriers
and required utilities to transmit power from such producers,
utilities and others to wholesale customers.
In April 1996, the FERC issued its Final Rule on Open Access Non-
discriminatory Transmission, Stranded Costs, Open Access Same-time
Information System (OASIS) and Standards of Conduct. These rules work
together to open access for wholesale power flows on transmission
systems. Utilities owning transmission facilities (including Tampa
Electric) are required to provide services to wholesale transmission
customers comparable to those they provide to themselves on comparable
terms and conditions including price. Among other things, the rules
require transmission services to be unbundled from power sales and
owners of transmission systems must take transmission service under
their own transmission tariffs.
4
Transmission system owners are also required to implement an
OASIS system providing, via the Internet, access to transmission
service information (including price and availability), and to rely
exclusively on their own OASIS system for such information for
purposes of their own wholesale power transactions. To facilitate
compliance, owners must implement Standards of Conduct to ensure that
personnel involved in marketing wholesale power are functionally
separated from personnel involved in transmission services and
reliability functions. Tampa Electric, together with other utilities,
has implemented an OASIS system and believes it is in compliance with
the Standards of Conduct.
In addition to these transmission developments at the federal
level, there have been initiatives at the state level to facilitate
the construction of merchant power plants, i.e. plants built on
speculation with a portion or all of their capacity not subject to
purchase agreements. Tampa Electric has opposed these efforts. See
Wholesale Power Market on page 25 for a further description of
proposed projects and the issues involved.
Fuel
About 97 percent of Tampa Electric's generation for 1998 was from
its coal-fired units. About the same level is anticipated for 1999.
Tampa Electric's average fuel cost per million BTU and average
cost per ton of coal burned for 1998 were as follows:
Average cost
per million BTU: 1998
Coal $ 1.99
Oil $ 3.14
Composite $ 2.03
Average cost per ton
of coal burned $44.44
Tampa Electric's generating stations burn fuels as follows:
Gannon Station burns low-sulfur coal; Big Bend Station burns a
combination of low-sulfur coal and coal of a somewhat higher sulfur
content; Polk Power Station burns high-sulfur coal which is gasified
subject to sulfur removal prior to combustion; 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, burned natural gas and oil.
Coal. Tampa Electric used approximately 7.9 million tons of coal
during 1998 and estimates that its coal consumption will be about 8.1
m i llion tons for 1999. During 1998, Tampa Electric purchased
approximately 41 percent of its coal under long-term contracts with
six suppliers, including TECO Coal, and 59 percent of its coal in the
spot market or under intermediate-term purchase agreements. About 9
percent of Tampa Electric's 1998 coal requirements were supplied by
TECO Coal. During December 1998, the average delivered cost of coal
(including transportation) was $41.37 per ton, or $1.78 per million
BTU. Tampa Electric expects to obtain approximately 31 percent of its
coal requirements in 1999 under long-term contracts with five
suppliers, including TECO Coal, and the remaining 69 percent in the
spot market or under intermediate-term purchase agreements. Tampa
Electric estimates that about 7 percent of its 1999 coal requirements
will be supplied by TECO Coal. Tampa Electric'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
5
deliveries if environmental regulations should prevent Tampa Electric
from burning the coal supplied, provided that a good faith effort has
been made to continue burning such coal.
In 1998, about 66 percent of Tampa Electric's coal supply was
deep-mined, approximately 32 percent was surface-mined and the
remainder was a processed oil by-product known as petroleum coke.
Federal surface-mining laws and regulations have not had any material
adverse impact on Tampa Electric's coal supply or results of its
operations. Tampa Electric, however, cannot predict the effect 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 Tampa Electric'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 Tampa Electric.
Oil. Tampa Electric had supply agreements through Dec. 31, 1998
for No. 2 fuel oil and No. 6 fuel oil for its Polk, Hookers Point and
Phillips stations, and its four combustion turbine units at prices
based on Gulf Coast Cargo spot prices. Contracts for the supply of No.
2 and No. 6 fuel oil through Dec. 31, 1999 are expected to be
finalized in early 1999. The price for No. 2 fuel oil deliveries taken
in December 1998 was $16.17 per barrel, or $2.79 per million BTU. The
price for No. 6 fuel oil deliveries taken in December 1998 was $14.42
per barrel, or $2.28 per million BTU.
Franchises
Tampa Electric 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 Tampa
Electric, although, in certain events, they are subject to forfeiture.
Florida municipalities are prohibited from granting any franchise
for a term exceeding 30 years. If a franchise is not renewed by a
municipality, the franchisee has the statutory right to require the
municipality to purchase any and all property used in connection with
the franchise at a 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 Tampa Electric's property
used in the exercise of its franchise, if the franchise is not
renewed.
Tampa Electric 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.
Tampa Electric has no reason to believe that any of these franchises
will not be renewed.
Franchise fees payable by Tampa Electric, which totaled $20.9
million in 1998, 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 2033 and 2005.
6
Environmental Matters
Tampa Electric's operations are subject to county, state and
f e deral 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.
T h e 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.
Tampa Electric believes that it has all required environmental
permits. In addition, monitoring programs are in place to assure
compliance with permit conditions.
Tampa Electric has been identified as a potentially responsible
party (PRP) for certain superfund sites. While the total costs of
remediation at these sites may be significant, Tampa Electric shares
potential liability with other PRPs, many of which have substantial
assets. Accordingly, Tampa Electric expects that its liability in
connection with these sites will not be significant. The environmental
remediation costs associated with these sites are not expected to have
a material impact on customer prices.
The U.S. Environmental Protection Agency (EPA) has commenced an
investigation of coal-fired electric power generators under the 1990
C l ean Air Act Amendments (CAAA) to determine compliance with
e n v ironmental permitting requirements associated with repairs,
m a intenance, modifications and operations changes made to the
facilities over the years. The EPA's focus is on whether new source
p e r formance standards should be applied to the changes and,
accordingly, whether the best available control technology was or
should have been used. Tampa Electric is one of several electric
utilities that have been visited by EPA personnel and received a
comprehensive request for information pursuant to Section 114 of EPA's
Clean Air Act regulations. Tampa Electric is furnishing appropriate
information. It believes that it has built, maintained and operated
its facilities in compliance with relevant environmental permitting
requirements. The timing of completion and the outcome of the EPA s
investigation are uncertain.
Expenditures. During the five years ended Dec. 31, 1998, Tampa
E l e c tric spent $172.1 million on capital additions to meet
environmental requirements, including $108.2 million for the Polk
Power Station project. Environmental expenditures are estimated at
$9.9 million for 1999 and $8.8 million in total for 2000 through 2003.
These totals exclude amounts required to comply with the CAAA, as
discussed in the following paragraphs.
Tampa Electric is complying with the Phase I emission limitations
imposed by the CAAA which became effective Jan. 1, 1995 by using
b l e nds of lower-sulfur coal, controlling stack emissions and
purchasing emission allowances.
In 1998, Tampa Electric decided to add a flue gas desulfurization
(FGD) system, or "scrubber," in order to comply with Phase II of the
CAAA. The $83-million scrubber will reduce the amount of sulfur
dioxide emitted by Tampa Electric's Big Bend Units One and Two and
will allow significant fuel savings at other Tampa Electric units. As
a result of this project, all of the units at Big Bend Station, Tampa
Electric's largest generating station, will be equipped with scrubber
technology. Tampa Electric has spent approximately $16 million on this
project in 1998 and estimates capital expenditures related to this
scrubber to be $61 million in 1999 and $6 million thereafter.
7
The FPSC approved the FGD system as the most cost effective
a l t e rnative for Tampa Electric to meet its CAAA compliance
requirements and the recovery of prudently incurred costs through the
environmental cost recovery clause. Cost recovery will not begin,
however, until the FGD system is in service and Tampa Electric has
applied for such recovery specifying the costs actually incurred.
Tampa Electric may petition the FPSC for recovery of certain other
environmental compliance costs on a current basis pursuant to a
statutory environmental cost recovery procedure used in connection
with the above described FGD system..
In 1998, Tampa Electric recovered $5.4 million of environmental
compliance costs through the environmental cost recovery clause. These
were costs incurred by Tampa Electric after April 1993 to comply with
environmental regulations that were not included in the then current
base rates. In addition, Tampa Electric may recover environmental
compliance costs through base rates. Under the October 1996 agreement
with the FPSC, the earliest any new prices could be in effect to cover
such costs is in the year 2000.
PEOPLES GAS SYSTEM--Gas Operations
PGS is engaged in the purchase, distribution and marketing of
natural gas for residential, commercial, industrial and electric power
generation customers in the State of Florida.
PGS has no gas reserves, but relies on two interstate pipelines
to deliver gas to it for sale or other delivery to customers connected
to its distribution system. PGS does not engage in the exploration for
or production of natural gas. Currently, PGS operates a distribution
system that serves approximately 240,000 customers. The system
includes approximately 7,300 miles of mains and over 4,800 miles of
service lines.
In 1998, industrial and power generation customers consumed
approximately 65 percent of PGS' annual therm volume. Commercial
customers use approximately 29 percent with the balance consumed by
residential customers.
While the residential market represents only a small percentage
of total therm volume, residential operations generally comprise 24
p e r c ent of total revenues. New residential construction and
conversions of existing residences to gas have steadily increased
since the late 1980's.
Natural gas has historically been used in many traditional
industrial and commercial operations throughout Florida, including
production of products such as steel, glass, ceramic tile and food
products. Gas climate control technology is expanding throughout
F l orida, and commercial/industrial customers including schools,
hospitals, office complexes and churches are utilizing this new
technology.
Within the PGS operating territory, large cogeneration facilities
utilize gas technology in the production of electric power and steam.
Over the past three years, the company has transported on average
a b o ut 300 million therms annually to facilities involved in
cogeneration.
8
Revenues for PGS for 1998 were as follows:
(millions) 1998
Residential $ 57.7
Commercial 141.2
Industrial 20.9
Power Generation 10.4
Other revenues 22.6
Total $252.8
PGS had 897 employees as of Dec. 31, 1998. A total of 128
employees in six of the company's 13 operating divisions are
represented by various union organizations.
Regulation
The operations of PGS are regulated by the FPSC separate from the
regulation of Tampa Electric's electric operations. The FPSC has
jurisdiction over rates, service, issuance of certain securities,
safety, accounting and depreciation practices and other matters.
In general, the FPSC sets rates at a level that allows a utility
such as PGS to collect total revenues (revenue requirements) equal to
its cost of providing service, including a reasonable return on
invested capital.
The basic costs, other than the costs of purchased gas and
interstate pipeline capacity, of providing natural gas service are
recovered through base rates, which are designed to recover the costs
of owning, operating and maintaining the utility system. The rate of
return on rate base, which is intended to approximate PGS' weighted
cost of capital, primarily includes its cost for debt, deferred income
taxes at a zero cost rate, and an allowed return on common equity.
Base prices are determined in FPSC proceedings which occur at
irregular intervals at the initiative of PGS, the FPSC or other
parties.
PGS recovers the charges (both reservation and usage) it pays for
transportation of gas for system supply through the purchased gas
adjustment charge. This charge is designed to recover the costs
incurred by PGS for purchased gas, and for holding and using
interstate pipeline capacity for the transportation of gas it sells to
its customers. These charges, which are reset annually in an FPSC
hearing, are based on estimated costs of purchased gas and pipeline
capacity, and estimated customer usage for a specific recovery period,
with a true-up adjustment to reflect the variance of actual costs and
usage from the projected charges for prior periods.
In addition to its base rates and purchased gas adjustment clause
c h a r g es for system supply customers, PGS customers (except
interruptible customers) also pay a per-therm charge for all gas
consumed to recover the costs incurred by the company in developing
and implementing energy conservation programs, which are mandated by
Florida law and approved and supervised by the FPSC. PGS is permitted
to recover, on a dollar-for-dollar basis, expenditures made in
connection with these programs if it demonstrates that the programs
are cost effective for its ratepayers.
In June 1996, following informal workshops held in late 1995, the
FPSC initiated a proceeding for the purpose of investigating the
unbundling of natural gas services provided by PGS and other local
distribution companies subject to the FPSC's regulatory jurisdiction.
In September 1998, the FPSC staff circulated a proposed rule that
would require natural gas utilities to offer transportation-only
service to all non-residential customers. The proposed rule is vague
9
and does not prescribe any method for achieving this requirement. PGS
believes a generic rule is unnecessary and is opposed to this broad
proposal. The rulemaking process is expected to last anywhere from six
months to in excess of a year. It is unclear whether the FPSC staff
action will lead to FPSC adoption of a rule requiring further
unbundling.
Under a separate docket, in February 1999, the FPSC approved PGS
petition to expand for a two-year period its existing, experimental
unbundling program to a maximum of 1,000 customers from the current
170 customers for two years. This program, known as the Firm
Transportation Aggregation (FTA) program, advances the unbundling
initiative being pursued by the FPSC Staff, but contemplates a more
reasonable pace toward total unbundled service to non-residential
customers.
In addition to economic regulation, PGS is subject to the FPSC's
safety jurisdiction, pursuant to which the FPSC regulates the
construction, operation and maintenance of PGS' distribution system.
In general, the FPSC has implemented this by adopting the Minimum
Federal Safety Standards and reporting requirements for pipeline
facilities and transportation of gas prescribed by the U.S. Department
of Transportation in Parts 191, 192 and 199, Title 49, Code of Federal
Regulations.
PGS is also subject to Federal, state and local environmental
laws and regulations pertaining to air and water quality, land use,
noise and aesthetics, solid waste and other environmental matters.
Competition
PGS is not in direct competition with any other regulated
distributors of natural gas for customers within its service areas. At
the present time, the principal form of competition for residential
and small commercial customers is from companies providing other
sources of energy and energy services including fuel oil, electricity
and in some cases liquid propane gas. PGS has taken actions to retain
and expand its commodity and transportation business, including
managing costs and providing high-quality service to customers.
Competition is most prevalent in the large commercial and
industrial markets. In recent years, these classes of customers have
been targeted by competing companies seeking to sell gas directly
either using PGS facilities or transporting gas through other
f a c i lities, thereby bypassing PGS facilities. Many of these
competitors are larger natural gas marketers with a national presence.
The FPSC has allowed PGS to adjust rates to meet competition for the
largest interruptible customers.
Gas Supplies
PGS purchases gas from various suppliers depending on the needs
of its customers. The gas is delivered to the PGS distribution system
for further delivery by PGS to its customers through two interstate
pipelines on which PGS has reserved firm transportation capacity.
Gas is delivered by Florida Gas Transmission through more than 40
interconnections (gate stations) serving PGS' operating divisions. In
addition, PGS' Jacksonville Division receives gas delivered by the
South Georgia Natural Gas Company pipeline through a gate station
located northwest of Jacksonville.
PGS has commitments for pipeline capacity with various expiration
dates.
Companies with firm pipeline capacity receive priority in
scheduling deliveries during times when the pipeline is operating at
10
its maximum capacity. PGS presently holds sufficient firm capacity to
permit it to meet the gas requirements of its system commodity
customers except during localized emergencies affecting the PGS
d i s tribution system, and on extremely cold days, which have
historically been rare in Florida.
Firm transportation rights on an interstate pipeline represent a
right to use the amount of the capacity reserved for transportation of
gas, on any given day. PGS pays reservation charges on the full amount
of the reserved capacity whether or not it actually uses such capacity
on any given day. When the capacity is actually used, PGS pays a
volumetrically based usage charge for the amount of the capacity
actually used. The levels of the reservation and usage charges are
regulated by FERC. PGS actively markets any excess capacity available
on a day to day basis to partially offset costs recovered through the
Purchased Gas Adjustment Clause.
PGS procures natural gas supplies using base load and swing
supply contracts distributed among various vendors along with spot
market purchases. Pricing generally takes the form of either a
variable price based on published indices, or a fixed price for the
contract term.
The current supply portfolio consists of approximately 1 percent
spot purchases, 17 percent swing purchases and 82 percent base load
purchases.
PGS has one long-term supply contract which expires in 2002.
This long-term contract has approximately 58 million therms remaining
to be purchased with a total cost of $12.7 million over the remaining
years. The purchase price is $.22 per therm.
Neither PGS nor any of its interconnected interstate pipelines
has storage facilities in Florida. PGS occasionally faces situations
when the demands of all of its customers for the delivery of gas
cannot be met. In these instances, it is necessary that PGS interrupt
or curtail deliveries to its interruptible customers. In general, the
largest of PGS' industrial customers are in the categories that are
first curtailed in such situations. PGS tariff and transportation
agreements with these customers give PGS the right to divert these
customers gas to other higher priority users during the period of
curtailment or interruption. PGS pays these customers for such gas at
the price they paid their suppliers (if purchased by the customer
under a contract with a term of five years or longer), or at a
published index price (if purchased by the customer pursuant to a
contract with a term less than five years), and in either case pays
t h e c u stomer for charges incurred for interstate pipeline
transportation to the PGS system.
Franchises
PGS holds franchise and other rights with 89 municipalities
within its service area. These include the cities of Jacksonville,
Daytona Beach, Eustis, Orlando, Lakeland, Tampa, St. Petersburg,
Bradenton, Sarasota, Avon Park, Frostproof, Palm Beach Gardens,
Pompano Beach, Fort Lauderdale, Hollywood, North Miami, Miami Beach,
Miami, Panama City and Ocala. These agreements give PGS a right to
operate within the franchise territory. The franchises are irrevocable
and are not subject to amendment without the consent of PGS, although
in certain events, they are subject to forfeiture.
Municipalities are prohibited from granting any franchise for a
term exceeding 30 years. If a franchise is not renewed by a
municipality, the franchisee has the statutory right to require the
municipalities to purchase any and all property used in connection
with the franchise at a valuation to be fixed by arbitration. In
11
addition, several of the municipalities have reserved the right to
purchase PGS property used in the exercise of its franchise, if the
franchise is not renewed.
PGS franchise agreements with the incorporated municipalities
within its service area have various expiration dates ranging from
April 1999 through June 2028.
In January 1999, the City of Lakeland notified PGS that it was
considering exercising its right to purchase PGS property in the
Lakeland franchise area when its franchise agreement with PGS expires
in March 2000. PGS serves approximately 5,000 customers in Lakeland.
PGS has commenced discussions with the City of Lakeland to renew this
agreement. While PGS believes it is best suited to serve these
customers, it cannot at this time predict the ultimate outcome of
these activities.
PGS has no reason to believe that any of its other franchises
will not be renewed.
Franchise fees payable by PGS, which totaled $7.9 million in
1 9 9 8, are calculated using various formulas which are based
principally on natural gas revenues. Franchise fees are collected from
only those customers within each franchise area.
U t ility operations in areas 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 and these
rights are, therefore, considered perpetual.
Environmental Matters
PGS's operations are subject to federal, state and local
statutes, rules and regulations relating to the discharge of materials
into the environment and to the protection of the environment
generally that require monitoring, permitting and ongoing
expenditures. These expenditures have not been significant in the
past, but the trend is toward stricter standards, greater regulation
and more extensive permitting requirements.
PGS has been identified as a potentially responsible party for
certain former manufactured gas plant sites. The joint and several
liability associated with these sites presents the potential for
significant response costs; PGS estimates its ultimate financial
liability of approximately $20 million over the next ten years. To
date, PGS has been permitted by the FPSC to recover prudently incurred
costs of environmental remediation and cleanup associated with these
manufactured gas sites. The environmental remediation costs associated
with these sites are not expected to have a material impact on
customer prices.
PGS believes that it is in substantial compliance with applicable
environmental laws, regulations, orders and rules. It is allowed to
recover certain prudently incurred environmental costs through rates
charged to its customers.
Expenditures. During the five years ended Dec. 31, 1998, PGS has
not incurred any material capital additions to meet environmental
requirements, nor are any anticipated for 1999 through 2003.
12
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.
Electric Properties
At Dec. 31, 1998, Tampa Electric had five electric generating
plants and four combustion turbine units in service with a total net
winter generating capability of 3,615 megawatts, including Big Bend
( 1 , 742-MW capability from four coal units), Gannon (1,180-MW
capability from six coal units), Hookers Point (215-MW capability from
five oil units), Phillips (34-MW capability from two diesel units),
Polk (250-MW capability from one integrated gasification combined
cycle unit (IGCC)) and four combustion turbine units located at the
Big Bend and Gannon stations (194 MWs). The capability indicated
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. The Polk IGCC unit began commercial operation in September
1996. In 1991, Tampa Electric 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 was placed on long-term reserve standby.
T a m pa Electric owns 182 substations having an aggregate
transformer capacity of 16,368,281 KVA. The transmission system
c o n s ists of approximately 1,196 pole miles of high voltage
transmission lines, and the distribution system consists of 6,905 pole
miles of overhead lines and 2,741 trench miles of underground lines.
As of Dec. 31, 1998, there were 537,107 meters in service. All of this
property is located in Florida.
All plants and important fixed assets are held in fee except that
title to some of the properties is subject to easements, leases,
contracts, covenants and similar encumbrances and minor defects, of a
nature common to properties of the size and character of those of
Tampa Electric.
Tampa Electric has easements for rights-of-way adequate for the
m a i ntenance and operation of its electrical transmission and
distribution lines that are not constructed upon public highways,
roads and streets. It has the power of eminent domain under Florida
law for the acquisition of any such rights-of-way for the operation of
transmission and distribution lines. Transmission and distribution
lines located in public ways are maintained under franchises or
permits.
Tampa Electric has a long-term lease for its office building in
downtown Tampa which serves as headquarters for TECO Energy, Tampa
Electric and numerous other TECO Energy subsidiaries.
Gas Properties
PGS' distribution system extends throughout the areas it serves
in Florida, and consists of more than 12,100 miles of pipe, including
approximately 7,300 miles of mains and over 4,800 miles of service
lines.
P G S operating divisions are located in thirteen markets
throughout Florida. While most of the operations, storage and
administrative facilities are owned, a small number are leased.
13
Item 3. LEGAL PROCEEDINGS.
None.
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, Inc.
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
$147.5 million in 1998 and $145.9 million for 1997. See Note C on page
39 for a description of restrictions on dividends on the company's
common stock.
Item 7. MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS.
The Management's Narrative Analysis of Results of Operations which
follows contains forward-looking statements which are subject to the
inherent uncertainties in predicting future results and conditions.
Certain factors that could cause actual results to differ materially
from those projected in these forward-looking statements include the
following: general economic conditions, particularly those in Tampa
Electric Company's service areas affecting energy sales; weather
variations affecting energy sales and operating costs; potential
competitive changes in the electric and gas industries, particularly
in the area of retail competition; regulatory actions; commodity price
changes affecting the competitive positions of both Tampa Electric and
Peoples Gas System; and changes in and compliance with environmental
r e gulations that may impose additional costs or curtail some
activities. These factors are discussed more fully under "Investment
Considerations" in TECO Energy Inc.'s Annual Report on Form 10-K for
the year ended Dec. 31, 1998, and reference is made thereto.
EARNINGS SUMMARY
The acquisitions of Peoples Gas System, Inc. and West Florida
Natural Gas Company in June 1997, were accounted for as poolings of
interests and, accordingly, the 1997 financial and operating data
include the results of Peoples Gas System, Inc. and West Florida
Natural Gas Company, combined for the full year. The amounts presented
for 1996 have been restated to reflect the merger with Peoples Gas
System, Inc. However, prior year financial statements have not been
restated to reflect the results of West Florida Natural Gas Company
due to its size.
Net income for 1998 of $146.4 million declined 1 percent from
1997's results. The 1998 results included a first quarter after-tax
charge of $5.9 million and a fourth quarter after-tax charge of $4.4
million. Net income for 1997 of $148.6 million declined 4 percent
from 1996's restated results due primarily to an FPSC decision
directing the regulatory treatment of two wholesale power sales
contracts.
One-time charges in 1998 at Tampa Electric reflected charges
associated with ongoing actions to mitigate the effects of a 1997 FPSC
ruling that separated two wholesale power sales contracts from the
retail jurisdiction through 1999, and from a regulatory ruling denying
recovery of coal expenses over an established benchmark for coal
14
purchases from Gatliff since 1992 (described in the Tampa Electric -
Electric Operating Results section).
Results in 1997 reflected one-time costs from the 1997 Peoples
Gas companies merger and an FPSC decision, described in the Tampa
E l ectric - Electric Operating Results section, to change the
regulatory treatment of two wholesale power sales contracts.
Operating income, excluding a $9.6-million one-time, pretax
charge, grew 5.3 percent in 1998 reflecting good growth from a strong
local economy, expansion of the gas system and the recognition of
$38.3 million of previously deferred revenues at Tampa Electric. For a
description of the origination and treatment of deferred revenues, see
Utility Regulation - Rate Stabilization Strategy section.
Operating income in 1997 reflected the recognition of $30.5
million of previously deferred electric revenues and the inclusion of
Polk Unit One in rate base for earnings purposes. In 1996, Tampa
Electric deferred $34.2 million of revenues under agreements approved
by the FPSC. See Utility Regulation - Rate Stabilization Strategy
section.
Contributions by Operating Division
(millions) 1998 Change 1997 Change 1996
Operating income
Tampa Electric $ 203.4(1) 5.3% $ 193.1 11.9% $ 172.6
Peoples Gas System 25.8 5.3% 24.5 4.3% 23.5
229.2 5.3% 217.6 11.0% 196.1
Non-recurring charge (9.6) -- -- -- --
Total $ 219.6 .9% $ 217.6 11.0% $ 196.1
(1) Excludes one-time, pretax charge of $9.6 million for treatment of
a wholesale contract.
Tampa Electric - Electric Operations
Tampa Electric's Operating Results
Tampa Electric's 1998 operating income, before the one-time
charge, increased 5 percent from 1997, reflecting strong customer
growth and continued strength in the local economy. Results in 1998
reflected recognition of $38.3 million of previously deferred
revenues.
In 1997, Tampa Electric benefited from a strong local economy,
favorable customer growth and cost controls. Its 1997 operating income
increased more than 11 percent, after the recognition of $30.5 million
of previously deferred revenues.
Tampa Electric Results
(millions) 1998 Change 1997 Change 1996
Revenues(1) $1,234.6 3.8% $1,189.2 6.8% $1,112.9
Operating expenses 1,031.2(2) 3.5% 996.1 5.9% 940.3
Operating income $ 203.4 5.3% $ 193.1 11.9% $ 172.6
(1) Includes the recognition of $38.3 million and $30.5 million of
previously deferred revenues in 1998 and 1997, respectively. 1996
revenues are net of $34.2 million of deferred revenues.
(2) Excludes one-time, pretax charge of $9.6 million for treatment of
a wholesale contract.
15
Tampa Electric's Operating Revenues
Tampa Electric's 1998 operating revenues increased almost 4
percent, after the recognition of $38.3 million of previously deferred
revenues. The company had customer growth of 2.3 percent and retail
energy sales growth of more than 6 percent. Tampa Electric's 1997
revenues, including recognition of $30.5 million of previously
deferred revenues, increased almost 7 percent, with customer growth
increasing more than 2 percent and retail energy sales up 1 percent.
The economy in Tampa Electric's service area continued to grow in
1998, with increased employment from corporate relocations and
e x p ansions. Combined residential and commercial sales volumes
increased over 7 percent in 1998, reflecting the addition of almost
12,000 customers and increased demand during warmer-than-normal summer
weather. Combined residential and commercial energy sales declined
slightly in 1997, as the effects of mild weather more than offset the
addition of more than 12,000 new customers.
Non-phosphate industrial sales increased in 1998 and 1997,
reflecting the shift of some commercial customers to the industrial
classification to take advantage of favorable tax law changes on
electricity used in manufacturing. This shift does not affect Tampa
Electric revenues.
Sales to the phosphate industry in 1998 were slightly below 1997
levels, reflecting a gradual migration of phosphate mining activity
out of Tampa Electric's service area. Revenues from the phosphate
customer group represented slightly more than 3 percent of base
revenues in 1998.
Non-fuel revenues from sales to other utilities were $36 million
in 1998, $39 million in 1997 and $36 million in 1996. The non-fuel
revenue increase in 1997 reflected the shift from broker system
economy sales to longer-term higher-margin wholesale power sales.
Megawatt hours sold to other utilities decreased in 1998 primarily
because higher retail energy sales absorbed more generation capacity,
and were lower in 1997 due to lower Tampa Electric generating unit
availability. The decrease in non-fuel revenue in 1998 is the result
of lower sales volumes and a shift from longer-term sales to shorter-
term sales, because of an adverse FPSC decision in late 1997,
described in the Utility Regulation - Wholesale Power Sales Contracts
section. Tampa Electric will concentrate its prospective wholesale
power sales efforts on energy broker or other short-term sales, and
not on longer-term capacity contracts as was the case prior to this
ruling. The FPSC decision, which required Tampa Electric to change the
regulatory treatment of two wholesale power sales contracts, had the
effect of reducing Tampa Electric's 1997 earnings by about $6.5
million, after tax. The company terminated one contract and incurred
an after-tax charge of $5.9 million in 1998 for actions to mitigate
the effect of this treatment on the second contract.
Tampa Electric Megawatt-Hour Sales
(thousands) 1998 Change 1997 Change 1996
Residential 7,050 8.5% 6,500 -1.6% 6,607
Commercial 5,173 5.5% 4,901 1.8% 4,815
Industrial 2,520 2.2% 2,466 7.0% 2,304
Other 1,284 5.0% 1,223 1.7% 1,203
Total retail 16,027 6.2% 15,090 1.1% 14,929
Sales for resale 2,486 -21.3% 3,160 -2.5% 3,241
Total energy sold 18,513 1.4% 18,250 .4% 18,170
Retail customers (average) 530.3 2.3% 518.4 2.4% 506.0
16
Tampa Electric's Operating Expenses
Non-fuel operation and maintenance expenses increased almost 7
percent in 1998. Required expenditures to enhance system reliability
and timing of generation station outages contributed to an increase of
over $16 million in maintenance expense. Other operation expenses were
essentially level with 1997, the result of effective cost management
and improved efficiency throughout the company.
In September 1996, Tampa Electric completed construction of the
250-megawatt, state-of-the-art, clean-coal technology Polk Unit One.
The FPSC has allowed full recovery of capital costs and operating
expenses associated with the plant as described in the Utility
Regulation - Rate Stabilization Strategy section. The addition of this
facility was the primary reason for the increased non-fuel operating
expenses in 1997. Through 1998, a total of $21 million from the U.S.
Department of Energy (DOE) was received to partially offset a
s i gnificant portion of the non-fuel operation and maintenance
expenses. For 1999, approximately $7 million in funds are available
from the DOE.
Operating Expenses
(millions) 1998 Change 1997 Change 1996
Other operating expenses $ 165.8 .4% $165.1 .6% $164.1
Maintenance 94.6 21.0% 78.2 19.4% 65.5
Depreciation 146.1 3.3% 141.4 17.6% 120.2
Taxes-federal and state
income 76.3 -2.8% 78.5 10.1% 71.3
Taxes, other than income 97.2 5.9% 91.8 5.5% 87.0
Operating expenses 580.0 4.5% 555.0 9.2% 508.2
Fuel 366.5 -1.8% 373.4 -2.5% 383.1
Purchased power 84.7 25.1% 67.7 38.2% 49.0
Total fuel expense 451.2 2.3% 441.1 2.1% 432.1
Total operating expenses $1,031.2 3.5% $996.1 5.9% $940.3
Reflecting normal plant additions to serve the growing customer
base, depreciation expense increased by $4.7 million in 1998.
Depreciation expense increased $21 million in 1997 due to normal plant
additions and a full year of service of Polk Unit One. Depreciation
expense is projected to rise moderately for the next several years due
to normal additions to utility plant, as well as the addition of a
flue gas desulfurization system in 2000. See Environmental Compliance
section.
Income taxes decreased in 1998 primarily due to lower pretax
income. The increase in 1997's income tax expense from 1996 is due to
higher pretax income and the effect of lower AFUDC on equity funds.
Taxes other than income increased in 1998 as a result of higher
gross receipts taxes and franchise fees related to higher energy
sales. These taxes are recovered through customer bills. In 1997,
changes in taxes other than income reflected the property taxes
associated with Polk Unit One.
Total fuel expense and purchased power increased in 1998 and 1997
due to higher energy sales. Average coal costs, on a cents-per-million
BTU basis, increased 1.3 percent in 1998 after a 2.4 percent decrease
in 1997. The overall success in controlling system fuel expense is a
result of Tampa Electric's use of lower-priced coals, the mix in
operating generating units and favorable prices in spot coal markets.
In 1998, the FPSC disallowed, retroactively to 1992, certain quality
adjustments for coal purchased from a Tampa Electric affiliate,
resulting in a one-time pretax nonoperating charge of $7.3 million.
17
Purchased power increased in 1998 due to weather-related demand
and the provision of replacement power for certain wholesale power
sales contracts. In 1997, purchased power increased primarily due to
lower generating unit availability. In each year, substantially all
fuel and purchased power expenses were recovered through the fuel
adjustment clause.
Nearly all of Tampa Electric's generation in the last three years
has been from coal. On a total energy supply basis, self-generation
accounted for 92 percent of the total system energy requirement in
1998.
Peoples Gas System
Peoples Gas System Results
PGS achieved operating income growth of 5 percent over 1997, with
the increase due primarily to new customer additions and higher
average utilization per customer. The benefits of customer growth for
the year were partially offset by the effects of warmer-than-normal
weather during the winter months and by restructuring costs associated
with the 1998 decision to exit the appliance sales and service
business.
Operating income grew 4 percent in 1997 over 1996, reflecting
increased customers, effective cost control and the acquisition of
West Florida Natural Gas Company (WFNG). These factors were somewhat
offset by the mild weather early in 1997.
The actual cost of gas and upstream transportation purchased and
resold to end-use customers is recovered through a Purchased Gas
Adjustment clause approved by the FPSC.
Peoples Gas System Results(1)
(millions) 1998 Change 1997 Change 1996
Revenues $252.8 1.3% $249.5 -3.5% $258.6
Cost of gas sold 115.4 -3.5% 119.6 -8.1% 130.1
Operating expenses 111.6 5.9% 105.4 .4% 105.0
Operating income $ 25.8 5.3% $ 24.5 4.3% $ 23.5
Therms sold (millions)-by Customer Segment
Residential 52.7 7.8% 48.9 1.5% 48.2
Commercial 266.0 7.4% 247.6 3.9% 238.4
Industrial 305.0 5.7% 288.6 9.7% 263.2
Power Generation 288.3 -8.4% 314.7 7.7% 292.3
Total 912.0 1.4% 899.8 6.9% 842.1
Therms sold (millions)-By Sales Type
System Supply 320.8 9.6% 292.6 -14.5% 342.3
Transportation 591.2 -2.6% 607.2 21.5% 499.8
Total 912.0 1.4% 899.8 6.9% 842.1
Customers (thousands) 239.6 2.1% 234.7 16.0% 202.4
(1) 1996 data does not include the operating revenues and expenses,
therms sold and customers of WFNG. WFNG was acquired in 1997 in a
merger transaction accounted for as a pooling of interests.
Prior-year financial results were not restated for the effects of
this merger due to its size.
18
Residential gas sales increased in 1998, primarily as a result of
overall customer growth and the addition of high-end customers
throughout the year. Results reflected slightly warmer weather in 1998
compared to 1997.
Residential gas sales increased in 1997 due to the addition of
WFNG, partially offset by a mild winter which followed a much colder-
than-normal winter in 1996.
Operating revenues from residential and commercial customers grew
almost 2 percent in 1998, while revenues from industrial and power
generation customers were approximately 10 percent below last year.
The increase in residential revenues was primarily due to higher
average utilization per customer, reflecting the addition of high-end,
multiple appliance customers.
O p e rating expenses increased during 1998, reflecting
restructuring costs totaling $3.4 million. These costs were primarily
for early retirement and severance costs affecting 200 employees,
associated with a decision in April to exit the appliance sales and
service business. The restructuring, which was initiated in July, was
completed and began to yield savings in ongoing expenses by the end of
1998. PGS began partnering with companies in an established dealer
network to provide sales, installation and repair services to
customers.
PGS is the largest investor-owned gas distribution utility in
Florida, with about 70 percent of the market. It serves almost 240,000
customers in all of the major metropolitan areas of Florida.
PGS expects to invest an average of $50-60 million per year for
the next five years to grow the business, roughly doubling the
historical level of capital expenditures. Infrastructure is being
expanded both in areas currently served and into areas not yet served
by natural gas.
In April 1998, PGS announced plans to expand into the Southwest
Florida market providing service to Fort Myers, Naples, Cape Coral and
surrounding areas. It is anticipated that 110,000 new homes and
businesses will be added in this market over the next decade,
representing a significant opportunity for growth in the high-end
residential and the commercial customer sectors. The company also is
expanding to the U.S. Naval Station at Mayport near Jacksonville and
anticipates that the Mayport facilities and surrounding communities
will use over 2.6 million therms of natural gas annually.
YEAR 2000 COMPUTER SYSTEMS READINESS:
Background
There is a global awareness that many computer programs use only
two digits to refer to a year and, therefore, may not correctly
recognize and process date information beyond the year 1999. This is
referred to as the "Year 2000" issue.
The Year 2000 issue exists in two primary areas of Tampa Electric
Company's operations: the critical business systems (such as the
financial reporting, procurement, payroll and customer information and
billing systems) and the control systems (such as those used in the
operation of electric generation, transmission and distribution
facilities).
The company began work on Year 2000 readiness in August 1995. The
project is segmented into the following phases: awareness, inventory,
assessment, renovation, testing and contingency planning.
19
Readiness
The company has completed its assessment of all hardware,
software and embedded systems and is currently engaged in renovation,
testing and contingency planning. Set forth below is a description of
readiness by functional area.
Critical Business Systems
The critical business systems, including mainframe hardware which
was replaced in July 1998, have been substantially renovated and
functionally tested. Mainframe integrated system testing has begun and
is scheduled to be completed in the first half of 1999. To assist in
assuring readiness, the renovation work and the integration testing
are being handled by separate outside firms.
Control Systems
The company's management believes that its transmission and
distribution systems, including energy management and control and
related embedded systems, are now ready for the Year 2000, i.e.
renovated and tested to the extent necessary.
The company retained industry specialty firms to assist with
identifying areas where renovations were needed in the embedded
systems associated with generator unit controls and with making these
renovations. A number of successful unit tests have been conducted for
Tampa Electric's generating units, and all required plant control
system renovations are scheduled to be complete and tested by May
1999.
Critical systems (those required for uninterrupted operations)
have been renovated, with the exception of a portion of the Peoples
Gas System control system , which is scheduled to be fully renovated
and tested in the first half of 1999.
Coordination with Others
The company has surveyed its largest suppliers (approximately
1,000) with respect to their Year 2000 readiness, including all
providers of technology supplies and services, and plans to complete
its customer survey process in the first half of 1999. As part of its
Year 2000 project, the company will be coordinating with its suppliers
and customers based on their responses to these surveys.
A t the request of the DOE, the North American Electric
Reliability Council (NERC) prepared a Year 2000 coordination plan and
preliminary status report in September 1998 and updated it in January
1999. A full status report is expected by July 1999. NERC is
conducting monthly readiness assessment surveys and coordinating
information sharing and contingency planning activities among the
member firms. The NERC activity addresses all aspects of the
interconnected electric grid. The aggregated results are being
reported to the DOE and other regulatory bodies in the U.S., Canada
and Mexico. The Natural Gas Council, through the American Gas
A s sociation, is coordinating similar processes within the gas
industry, reporting to the Federal Energy Regulatory Commission
(FERC). Tampa Electric and Peoples Gas System are active participants
in these industry groups.
Costs
The total cost of Year 2000 remediation is expected to be $9
million, which includes contracted resources, purchases and internal
labor. An estimated breakdown of project costs is as follows: Tampa
E l ectric - $6 million and Peoples Gas System - $3 million.
Approximately 40 percent of the projected costs are attributable to
testing expenses, and the remainder consists primarily of renovation
20
or replacement costs. Through Dec. 31, 1998, approximately $6 million
had been spent, including approximately $1 million spent prior to
1998. The company expects to spend approximately $3 million in 1999
for Year 2000 remediation.
Risks
The company believes the most reasonably likely worst case
scenario would be the occurrence of isolated outages of limited
duration for utility customers. The utilities have assessed the risk
of this scenario, and believe that their contingency efforts,
primarily the ability to bypass automated controls, would mitigate the
effect of such a scenario.
Contingency Plans
The company's contingency plan is scheduled to be completed by
the middle of 1999. The contingency plan will include a team to be
e s t ablished in 1999 to monitor all critical systems through
significant date transitions and to promptly respond to any problems.
Forward-Looking Statements
The costs of Tampa Electric Company's Year 2000 efforts and the
dates on which the company believes it will complete such efforts are
based upon management's best estimates, which were derived using
numerous assumptions regarding future events, including the continued
availability of certain resources, third-party remediation plans and
other factors. There can be no assurance that these estimates will
prove to be accurate, and actual results could differ materially from
those currently projected. Specific factors that could cause such
differences include, but are not limited to, the availability and cost
of personnel trained in Year 2000 issues, the ability to identify,
assess, remediate and test all relevant computer codes and embedded
technology and similar uncertainties.
NON-OPERATING ITEMS:
Other Income (Expense)
Other income (expense) includes a one-time pretax charge of $7.3
million at Tampa Electric reflecting the FPSC decision denying
recovery of certain coal expenses. See Utility Regulation - Cost
Recovery Clauses section.
The dividend requirement for Tampa Electric preferred stock,
included in Other Income (expense), declined in 1997 reflecting the
redemption of all outstanding preferred stock. Allowance for other
funds used during construction (AFUDC) was $.1 million in 1997 and
$16.5 million in 1996; no AFUDC was recorded in 1998. AFUDC is
expected to be approximately $1-2 million per year over the next five
years.
Interest Charges
Interest charges were $63.4 million, down 5 percent from $66.4
million in 1997 due to lower interest on a declining deferred revenue
balance at Tampa Electric and lower short-term rates in 1998.
Interest charges were up 16 percent in 1997, reflecting lower
AFUDC on borrowed funds at Tampa Electric.
ENVIRONMENTAL COMPLIANCE:
Tampa Electric is complying with the Phase I emission limitations
21
imposed by the Clean Air Act Amendments (CAAA) which became effective
Jan. 1, 1995 by using blends of lower-sulfur coal, integrating the Big
Bend Unit Four FGD system with Unit Three, controlling stack emissions
and using emission allowances. In 1998, Tampa Electric made a decision
to add a scrubber in order to comply with Phase II of the CAAA. The
$84 million scrubber will reduce the amount of sulfur dioxide emitted
by the Tampa Electric's Big Bend Units One and Two and will allow
significant fuel savings at other Tampa Electric units. As a result of
this project, all of the units at Big Bend Station, Tampa Electric's
largest generating station, will be equipped with scrubber technology.
The FPSC approved the FGD system as the most cost effective
a l t e rnative for Tampa Electric to meet its CAAA compliance
requirements and the recovery of prudently incurred costs through the
environmental cost recovery clause. Cost recovery will not begin,
however, until the FGD system is in service and Tampa Electric has
applied for such recovery specifying the costs actually incurred.
The U.S. Environmental Protection Agency (EPA) has commenced an
investigation under the Clean Air Act of coal-fired electric power
generators to determine compliance with environmental permitting
requirements associated with repairs, maintenance, modifications and
operations changes made to the facilities over the years. The EPA's
focus is on whether new source performance standards should be applied
to the changes and, accordingly, whether the best available control
technology was or should have been used. Tampa Electric is one of
several electric utilities that have been visited by EPA personnel and
received a comprehensive request for information pursuant to Section
114 of EPA's Clean Air Act regulations. Tampa Electric is furnishing
appropriate information. It believes that it has built, maintained and
operated its facilities in compliance with relevant environmental
permitting requirements. The timing of completion and the outcome of
the EPA s investigation are uncertain.
Tampa Electric Company is a potentially responsible party for
certain superfund sites and, through its Peoples Gas System division,
for certain former manufactured gas plant sites. While the joint and
several liability associated with these sites presents the potential
for significant response costs, Tampa Electric Company estimates its
ultimate financial liability at approximately $20 million over the
next 10 years. The environmental remediation costs associated with
these sites are not expected to have a material impact on customer
prices.
UTILITY REGULATION:
Rate Stabilization Strategy
Tampa Electric's objectives of stabilizing prices through 1999
and securing fair earnings opportunities during this period are being
accomplished through agreements entered into with the Florida Office
of Public Counsel (OPC) and the Florida Industrial Power Users Group
(FIPUG) which were approved by the FPSC.
Prior to these agreements, the FPSC approved a plan submitted by
Tampa Electric to defer certain 1995 revenues. Under this plan Tampa
Electric's allowed return on equity increased to an 11.75 percent
midpoint with a range of 10.75 percent to 12.75 percent. For 1995 an
initial $15 million of revenues were deferred as well as 50 percent of
actual revenues in excess of a ROE of 11.75 percent up to a net earned
ROE of 12.75 percent. Also as part of this plan, Tampa Electric's oil
backout tariff was eliminated in January 1996, reducing annual
revenues by approximately $12 million.
In 1995, Tampa Electric deferred $51 million of revenues under
this plan. The deferred revenues accrue interest at the 30-day
22
commercial paper rate as specified in the Florida Administrative Code.
In 1996, the FPSC approved agreements between Tampa Electric, the
OPC and the FIPUG which froze base rates for the electric utility
through 1999, returned $50 million to customers between October 1996
and December 1998 through refunds and a temporary base rate reduction
and allowed full recovery for the capital costs incurred in the Polk
Unit One project.
In addition, the agreements set forth multi-year plans for
allocating revenues based on Tampa Electric's ROE. For the years 1996
through 1998, Tampa Electric retained all revenues contributing to a
ROE of 11.75 percent. Under this plan, any additional revenues were
allocated as follows:
*In 1996, 40 percent of any actual revenues contributing to a ROE
in excess of 11.75 percent were included in 1996 revenues. The
remaining 60 percent were deferred for use in 1997 and 1998. The
company deferred $34 million in 1996. This amount and the deferred
revenues and interest from 1995 (less $25 million of refunds) provided
$68 million for use by the company in 1997 and 1998.
*In 1997, 40 percent of any revenues that contributed to a ROE in
excess of 11.75 percent up to 12.75 percent were included in revenues.
The remaining 60 percent were deferred for use in 1998 as were all
revenues in excess of 12.75 percent. The company recognized $31
million in 1997 of the revenues and interest deferred from 1995 and
1996.
*In 1998, 40 percent of any revenues that contributed to a ROE in
excess of 11.75 percent up to 12.75 percent were included in revenues.
The remaining 60 percent, along with all revenues contributing to a
ROE in excess of 12.75 percent, including deferrals from prior years,
will be refunded to customers in 1999. In 1998, Tampa Electric
recognized all of the remaining deferred revenues and interest from
1995 and 1996, and based on 1998 earnings levels, expects to refund $1
million to customers in 1999, following audits for the years 1997 and
1998 and final review by the FPSC.
*For 1999, 60 percent of the revenues contributing to a ROE in
excess of 12 percent will be refunded to customers in 2000 following
audit and review by the FPSC along with any 1999 revenues that
contribute to a ROE above 12.75 percent.
In 1998, Tampa Electric recorded $1.1 million in after-tax
charges relating to its 1996 earnings as a result of an FPSC audit of
t h a t year which involved several adjustments, including the
establishment for regulatory purposes of an equity ratio cap of 58.7
percent for 1996 compared to the actual ratio for the year of 59.5
percent. Because of the return on equity thresholds in Tampa
Electric's regulatory agreements described above and the potential for
customer refunds in 1999 and 2000, Tampa Electric expects continuing
audit scrutiny by the FPSC and active involvement of intervenors in
the proceedings for determining the appropriate level of earnings for
the remaining years of the stipulation and the resulting level of
deferrals and/or refunds.
The regulatory arrangements described above covered periods that
end on Dec. 31, 1999. In the absence of any new arrangement, Tampa
Electric's rates and the midpoint of its allowed rate of return on
common equity (11.75 percent) will continue in effect until such time
as changes are occasioned by an agreement approved by the FPSC or
other FPSC action as a result of rate or other proceedings initiated
by Tampa Electric, FPSC staff or other interested parties. Tampa
Electric cannot predict whether there will be any such agreement or
the potential outcome related to any other proceedings.
The effective implementation of the rate stabilization strategy
has resulted in residential retail rates for 1999 that are below $80
23
per 1,000 kwh, even as Polk Unit One was brought on line. This rate is
almost 10 percent lower than 1994 rates just prior to the rate
stabilization plan and comparable to rates in 1985.
Wholesale Power Sales Contracts
In 1997, the FPSC ruled that costs associated with two long-term,
wholesale power sales contracts should be assigned to the wholesale
jurisdiction for 1997 through 1999. It further required that, for
retail rate making purposes through the end of the stipulation period,
the costs separated from retail to wholesale should reflect average
costs rather than the lower incremental costs on which the two
contracts were based. By 1998, one of these contracts had been
terminated.
In order to mitigate the impacts of the FPSC's ruling on the
remaining contract, which expires in 2001, Tampa Electric entered into
firm purchased power contracts with third parties in early 1998 to
provide replacement power through 1999. As a result, Tampa Electric is
no longer separating the associated generation assets from the retail
jurisdiction. Because the costs under the firm purchased power
c o ntracts exceeded the revenues associated with the remaining
wholesale power sale agreement, Tampa Electric recorded a $9.6-million
pre-tax charge in the first quarter of 1998.
Tampa Electric is considering applying to the FPSC for a ruling
that would provide for more favorable regulatory accounting treatment
after 1999, as well as other mitigation measures.
Cost Recovery Clauses
In 1998, the FPSC changed its proceedings for the recovery of
fuel, purchase power and environmental costs from semi-annual to
annual. In the November 1998 proceeding for calendar year 1999, the
FPSC disallowed retroactively to 1992 certain quality adjustments for
coal purchased from a Tampa Electric affiliate in excess of an
established benchmark. This resulted in a one-time pretax charge of
$7.3 million in 1998. In this same proceeding, the FPSC allowed the
recovery of $4.5 million in 1999 for environmental costs, a portion of
which constitutes a return on investment. These recoveries, subject to
annual approval, are expected to continue in future years in declining
amounts as assets depreciate.
Long Range Power Supply Planning
Tampa Electric filed a Ten Year Site Plan with the FPSC in April
1998. An amended plan was filed in August 1998 as the result of
greater-than-expected growth in retail load. Strong demand in 1997,
followed by record energy sales throughout the summer of 1998, were
evidence of this growth. This trend resulted in a projection of
reserves falling below the planning criteria of a 15 percent reserve
margin prior to the originally scheduled in service date of the next
proposed generation addition in 2003. The revised plan includes a
combustion turbine with a winter rating of 180 MW in January 2001.
Plans for the addition of an already scheduled combustion turbine for
2003 remain unchanged.
These additions are not subject to the FPSC's competitive bidding
requirements for capacity requirements, but they are subject to its
standard offer. A standard offer is a requirement of the FPSC that is
made to qualifying facilities and municipal solid waste facilities for
purchased power in order to offset the construction of a new unit.
Construction of a new unit may be disallowed entirely if enough power
is contracted. The quantity of power placed in the standard offer as
well as the terms and conditions of the contract are specified by the
utility and require the approval of the FPSC.
24
Utility Competition: Electric
Tampa Electric's retail electric business is substantially free
from direct competition with other electric utilities, municipalities
and public agencies. At the present time, the principal form of
competition at the retail level consists of self-generation available
to larger users of electric energy. Such users may seek to expand
their options through various initiatives, including legislative
and/or regulatory changes that would permit competition at the retail
level. One such initiative, which has apparently been terminated,
involved the proposed merchant power plant described below with a
claimed self generation use. This is further discussed in the
Wholesale Power Market section which follows. Tampa Electric intends
to take all appropriate actions to retain and expand its retail
business, including managing costs and providing high-quality service
to retail customers.
In 1998, the FPSC approved a tariff for Tampa Electric that
should assist in reducing the loss of existing at-risk load and assist
in the acquisition of new load. This Commercial/ Industrial Service
Rider is a load retention or economic development contract, that
provides for flexible pricing to meet competitive alternatives
available to existing or potential new customers.
Wholesale Power Market
There is presently active competition in the wholesale power
markets in Florida, increasing largely as a result of the Energy
Policy act of 1992 and related federal initiatives. This Act removed
for independent power producers certain regulatory barriers and
required utilities to transmit power from such producers, utilities
and others to wholesale customers.
A significant question to be addressed in Florida is whether
merchant power plants should be permitted to serve growing customer
demand for electricity. Merchant plants are built on speculation
without a portion or all of their capacity committed under firm
purchase agreements. Tampa Electric believes that only Florida
utilities or entities with contracts for firm capacity to serve the
long-term needs of a Florida utility can legally be applicants under
the Florida Power Plant Siting Act (PPSA). The PPSA governs the
building of new generation involving steam capacity of 75 megawatts or
more and requires the applicant to demonstrate that a plant is needed
prior to receiving construction and operating permits.
In 1997, IMC Agrico (IMCA), a retail customer of Tampa Electric
and other utilities, and Duke Energy announced that they had signed a
letter of intent for the construction of a natural gas-fired,
combined-cycle power plant with a minimum capacity of 240 megawatts to
serve load currently served by Tampa Electric and two other utilities,
and the merchant wholesale function described above.
Tampa Electric and others objected to the proposed project on the
grounds that it involved retail transactions within defined service
areas that are prohibited under existing Florida regulation. In early
1998 and prior to an FPSC-ordered evidentiary hearing to determine if
the proposed project should be considered permitted self-generation or
a prohibited retail sale, IMCA withdrew its petition. Duke Energy
subsequently announced that it did not intend to pursue the project
with IMCA.
In late 1998, New Smyrna Beach and Duke Energy New Smyrna Beach
Power Company Ltd. applied for FPSC determination of need for a
proposed 514-megawatt merchant power plant in Volusia County, Florida,
to supply 30 megawatts of capacity and associated energy to the
Utilities Commission of the City of New Smyrna Beach with the
remaining capacity designated for wholesale sales to other utilities.
25
Tampa Electric and others intervened to oppose this proposal. On March
4, 1999, the FPSC determined that the proponents of the merchant plant
are proper applicants under the PPSA and voted to approve the need for
the proposed merchant plant. These decisions are expected to be
appealed. The proposed plant is still subject to environmental and
other regulatory approvals.
If the FPSC decision is upheld or other regulatory or legislative
actions are taken that allow the construction of wholesale merchant
power plants, the wholesale operations of Tampa Electric and other
Florida utilities could be adversely affected.
Utility Competition: Gas
Although Peoples Gas System is not in direct competition with any
other regulated distributors of natural gas for customers within its
service areas, there are other forms of competition. At the present
time, the principal form of competition for residential and small
commercial customers is from companies providing other sources of
energy and energy services.
Competition is most prevalent in the large commercial and
industrial markets. In recent years, these classes of customers have
been targeted by companies seeking to sell gas directly, either using
Peoples Gas System facilities or transporting gas through other
facilities, thereby bypassing Peoples Gas System facilities. In
response to this competition, various programs have been developed
including the provision of transportation services at discounted
rates.
In general, Peoples Gas System faces competition from other
energy source suppliers offering fuel oil, electricity and in some
cases propane. Peoples Gas System has taken actions to retain and
expand its commodity and transportation business, including managing
costs and providing high-quality service to customers.
FINANCING ACTIVITY:
In the second quarter of 1998, Tampa Electric Company filed a
registration statement for the issuance of up to $200 million of
medium-term notes. In July 1998, Tampa Electric Company issued $50
million of Remarketed Notes due 2038. The notes, which bear an initial
coupon rate of 5.94%, are subject to mandatory tender on July 15,
2001, at which time they will be remarketed or redeemed. Net proceeds
were $51 million which included a premium paid to Tampa Electric by
the remarketing agent for the right to purchase the notes in 2001. If
this right is exercised, for the following 10 years the Notes will
bear interest at 5.41% plus a premium based on Tampa Electric
Company's then-current credit spread above United States Treasury
Notes with 10 years to maturity.
Proceeds from the note issue were used to repay short-term debt
and for general corporate purposes.
Derivatives and Hedging Policy
Based on policies and procedures approved by the Board of
Directors, from time to time Tampa Electric Company enters into
futures, swaps and option contracts to moderate its exposure to
interest rate changes. The benefits of these arrangements are at risk
only in the event of non-performance by the other party to the
agreement, which the company does not anticipate.
Based on policies and procedures approved by the Board of
Directors, from time to time Tampa Electric Company enters into
futures, swaps and options contracts to limit exposure to gas price
increases at the regulated natural gas utility. The benefits of these
26
financial arrangements are at risk only in the event of non-
performance by the other party to the agreement, which the company
does not anticipate.
Tampa Electric Company does not use derivatives or other
financial instruments for speculative purposes.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
Tampa Electric Company is exposed to changes in interest rates
primarily as a result of its borrowing activities.
From time to time, Tampa Electric Company enters into futures,
swaps and option contracts to moderate exposure to interest rate
changes.
A hypothetical 10 percent increase in Tampa Electric Company's
weighted average interest rate on its variable rate debt would not
have a significant impact on Tampa Electric Company's pretax earnings
over the next fiscal year.
A hypothetical 10 percent decrease in interest rates would not
have a significant impact on the estimated fair value of Tampa
Electric Company's long-term debt at Dec. 31, 1998.
Commodity Price Risk
Tampa Electric and Peoples Gas System are sensitive to changes in
certain commodity prices. Such changes could affect the prices they
charge, their operating costs and the competitive position of their
products and services.
In the case of Tampa Electric, fuel costs used for generation are
mostly affected by the cost of coal. Tampa Electric is able to recover
the cost of fuel through retail customers' bills, but increases in
fuel costs affect electric prices and therefore the competitive
position of electricity against other energy sources. On the wholesale
side, the ability to make sales and the margins on power sales are
affected by the cost of coal to Tampa Electric, particularly as it
relates to the cost of gas and oil to other power producers.
In the case of Peoples Gas System, costs for purchased gas and
pipeline capacity are recovered through retail customers' bills, but
increases in gas costs affect total retail prices and therefore the
competitive position of Peoples Gas relative to electricity, other
forms of energy and other gas suppliers.
From time to time, Tampa Electric Company enters into futures,
swaps and options contracts to limit exposure to gas price increases
at the regulated natural gas utility.
Tampa Electric Company does not use derivatives or other
financial products for speculative purposes.
27
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
No.
Report of Independent Accountants 29
Balance Sheets, Dec. 31, 1998 and 1997 30
Statements of Income for the years ended
Dec. 31, 1998, 1997 and 1996 31
Statements of Cash Flows for the years ended
Dec. 31, 1998, 1997 and 1996 32
Statements of Retained Earnings for the years ended
Dec. 31, 1998, 1997 and 1996 33
Statements of Capitalization, Dec. 31, 1998 and 1997 33-35
Notes to Financial Statements 36-46
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.
28
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
of Tampa Electric Company
In our opinion, the accompanying balance sheets and the related
statements of income, of cash flows, of retained earnings and of
capitalization present fairly, in all material respects, the financial
position of Tampa Electric Company, (a wholly owned subsidiary of TECO
Energy, Inc.) at Dec. 31, 1998 and 1997, and the results of its
operations and its cash flows for each of the three years in the
period ended Dec. 31, 1998, in conformity with generally accepted
accounting principles. 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 of these financial statements in accordance
with generally accepted auditing standards which require that we plan
and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts
and disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for the opinion expressed
above.
PricewaterhouseCoopers LLP
Tampa, Florida
Jan. 15, 1999
29
BALANCE SHEETS
(millions)
Assets
Dec. 31, 1998 1997
Property, Plant and Equipment,
At Original Cost
Utility plant in service
Electric $3,742.6 $3,632.0
Gas 518.5 471.1
Construction work in progress 71.5 40.6
4,332.6 4,143.7
Accumulated depreciation (1,722.2) (1,595.3)
2,610.4 2,548.4
Other property 8.1 6.5
2,618.5 2,554.9
Current Assets
Cash and cash equivalents .8 2.8
Receivables, less allowance
for uncollectibles 142.8 161.4
Inventories, at average cost
Fuel 87.3 69.5
Materials and supplies 45.5 45.6
Prepayments 8.4 7.3
284.8 286.6
Deferred Debits
Unamortized debt expense 16.1 17.5
Deferred income taxes 116.1 112.2
Regulatory asset-tax related 39.0 41.8
Other 72.0 85.9
243.2 257.4
$3,146.5 $3,098.9
Liabilities and Capital
Capital
Common stock $1,026.1 $ 972.1
Retained earnings 288.5 289.6
1,314.6 1,261.7
Preferred stock, redemption not required -- --
Long-term debt, less amount due
within one year 774.5 727.1
2,089.1 1,988.8
Current Liabilities
Long-term debt due within one year 4.6 4.1
Notes payable 79.7 219.1
Accounts payable 189.1 118.4
Customer deposits 77.5 77.3
Interest accrued 8.8 18.7
Taxes accrued 8.8 8.5
368.5 446.1
Deferred Credits
Deferred income taxes 447.6 415.6
Investment tax credits 45.1 49.7
Regulatory liability-tax related 73.0 77.0
Other 123.2 121.7
688.9 664.0
$3,146.5 $3,098.9
The accompanying notes are an integral part of the financial statements.
30
STATEMENTS OF INCOME
(millions)
Year ended Dec. 31, 1998 1997 1996
Operating Revenues
Electric $1,234.6 $1,189.2 $1,112.9
Gas 252.8 249.5 258.6
1,487.4 1,438.7 1,371.5
Operating Expenses
Operation
Fuel 366.5 373.4 383.1
Purchased power 84.7 67.7 49.0
Natural gas sold 115.4 119.6 130.1
Other 221.2 215.7 216.9
Maintenance 98.8 83.4 70.3
Non-recurring charge 9.6 -- --
Depreciation 167.2 161.2 137.4
Taxes-Federal and state income 86.3 87.5 79.9
Taxes-Other than income 118.1 112.6 108.7
1,267.8 1,221.1 1,175.4
Operating Income 219.6 217.6 196.1
Other Income (Expense)
Allowance for other funds
used during construction -- .1 16.5
Other expense, net (9.8) (2.7) (.1)
(9.8) (2.6) 16.4
Income before interest charges 209.8 215.0 212.5
Interest Charges
Interest on long-term debt 50.4 50.7 46.5
Other interest 13.0 15.8 16.9
Allowance for borrowed funds
used during construction -- (.1) (6.4)
63.4 66.4 57.0
Net Income 146.4 148.6 155.5
Preferred dividend
requirements -- .5 1.8
Balance Applicable to
Common Stock $ 146.4 $ 148.1 $ 153.7
The accompanying notes are an integral part of the financial statements.
31
STATEMENTS OF CASH FLOWS
(millions)
Year ended Dec. 31, 1998 1997 1996
Cash Flows from
Operating Activities
Net income $146.4 $148.6 $ 155.5
Adjustments to reconcile net
income to net cash
Depreciation 167.2 161.2 137.4
Deferred income taxes 28.5 21.1 9.4
Investment tax credits, net (4.6) (4.7) (4.7)
Allowance for funds used
during construction -- (.2) (22.9)
Deferred clause revenues
(expenses) 17.4 2.7 7.4
Deferred revenue (38.3) (30.5) 34.2
Refund to customers -- (19.8) (6.0)
Non-recurring charges 16.9 -- --
Receivables, less allowance
for uncollectibles 18.6 2.7 (10.0)
Inventories (17.7) (15.2) 10.8
Taxes accrued .3 (3.5) (8.4)
Accounts payable 70.7 (15.0) (15.9)
Other 10.1 (23.3) 9.3
415.5 224.1 296.1
Cash Flows from
Investing Activities
Capital expenditures (232.1) (155.3) (229.3)
Allowance for funds used
during construction -- .2 22.9
(232.1) (155.1) (206.4)
Cash Flows from
Financing Activities
Proceeds from contributed
capital from parent 54.0 5.0 83.0
Proceeds from long-term debt 51.2 -- 78.1
Repayment of long-term debt (3.7) (16.7) (26.3)
Net borrowings (payments)
under credit lines -- (10.0) --
Net increase (decrease)
in short-term debt (139.4) 118.9 (45.9)
Redemption of preferred stock -- (20.4) (35.5)
Dividends (147.5) (146.5) (147.1)
(185.4) (69.7) (93.7)
Net decrease in cash and
cash equivalents (2.0) (.7) (4.0)
Cash and cash equivalents at
beginning of year 2.8 3.5 7.5
Cash and cash equivalents at
end of year $ .8 $ 2.8 $ 3.5
Supplemental Disclosure of Cash Flow Information
Cash paid during the year for:
Interest $ 58.1 $ 57.1 $ 48.6
Income taxes $ 40.4 $ 85.3 $ 91.1
The accompanying notes are an integral part of the financial statements.
32
STATEMENTS OF RETAINED EARNINGS
(millions)
Year ended Dec. 31, 1998 1997 1996
Balance, Beginning of Year $289.6 $285.7 $277.3
Add-Net income 146.4 148.6 155.5
West Florida Gas Merger -- 2.3 --
436.0 436.6 432.8
Deduct-
Cash dividends on capital stock
Preferred -- .6 2.1
Common 147.5 145.9 145.0
Other - adjustment -- .5 --
147.5 147.0 147.1
Balance, End of Year $288.5 $289.6 $285.7
The accompanying notes are an integral part of the financial statements.
STATEMENTS OF CAPITALIZATION
Capital Stock
Outstanding Cash Dividends
Dec.31, 1998 Paid in 1998(1)
Current
Redemption Per
Price Shares Amount(2) Share Amount(2)
Common stock-Without par value
25 million shares
authorized N/A 10 $1,026.1 N/A $147.5
Preferred Stock-$100 Par Value
1.5 million shares authorized, none outstanding.
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.
33
STATEMENTS OF CAPITALIZATION (continued)
Long-Term Debt Outstanding at Dec. 31, Due 1998 1997
Tampa Electric
First mortgage bonds (issuable in series):
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 23.5 23.8
7 7/8% Refunding bonds(3) 2021 25.0 25.0
8% Refunding bonds(3) 2022 100.0 100.0
6 1/4% Refunding bonds(4) 2034 86.0 86.0
5.85% 2030 75.0 75.0
Variable rate: 3.06% for 1998 and
3.55% for 1997(1) 2025 51.6 51.6
Variable rate: 3.17% for 1998 and
3.45% for 1997(1) 2018 54.2 54.2
Variable rate: 3.39% for 1998 and
3.78% for 1997(1) 2020 20.0 20.0
Medium-term note payable: 5.11% (1)(5) 2001 38.0 --
703.3 665.6
Peoples Gas System
Senior Notes(6)
10.35% 2007 6.8 7.4
10.33% 2008 8.6 9.2
10.3% 2009 9.2 9.4
9.93% 2010 9.4 9.6
8.0% 2012 32.0 33.5
Medium-term note payable: 5.11% (1)(5) 2001 12.0 --
78.0 69.1
Unamortized debt premium (discount), net (2.2) (3.5)
779.1 731.2
Less amount due within one year(7) 4.6 4.1
Total long-term debt $ 774.5 $ 727.1
(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 February 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) These notes are subject to mandatory tender on July 15, 2001, at
which time they will be redeemed or remarketed.
(6) These long-term debt agreements contain various restrictive
covenants, including provisions related to interest coverage,
maximum levels of debt to total capitalization and limitations on
dividends.
(7) Of the amount due in 1998, $.8 million may be satisfied by the
substitution of property in lieu of cash payments.
34
STATEMENTS OF CAPITALIZATION (continued)
Substantially all of the property, plant and equipment of the
company is pledged as collateral. Maturities and annual sinking fund
requirements of long-term debt for the years 2000, 2001, 2002 and 2003
are $84.8 million, $55.2 million, $6.0 million, and $81.5 million,
respectively. Of these amounts $.8 million per year for 2000 through
2003 may be satisfied by the substitution of property in lieu of cash
payments.
At Dec. 31, 1998, total long-term debt had a carrying amount of
$774.5 million and an estimated fair market value of $878.7 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 accompanying notes are an integral part of the financial
statements.
35
NOTES TO FINANCIAL STATEMENTS
A. Summary of Significant Accounting Policies
Basis of Accounting
Tampa Electric Company's regulated electric and gas operations
maintain their accounts in accordance with recognized policies
prescribed or permitted by the Florida Public Service Commission
(FPSC). In addition, Tampa Electric maintains its accounts in
accordance with recognized policies prescribed or permitted by the
Federal Energy Regulatory Commission (FERC). These policies conform
w i th 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 experience of the regulated utilities, but when cost
recovery is ordered over a period longer than a fiscal year, costs are
recognized in the period that the regulatory agency recognizes them in
accordance with FAS 71. Also as provided in FAS 71, Tampa Electric has
deferred revenues in accordance with the various regulatory agreements
approved by the FPSC in 1995 and 1996. Revenues are recognized as
allowed in 1997 and 1998 under the terms of the agreements.
The regulated utilities retail business is regulated by the FPSC
and Tampa Electric s wholesale business is regulated by FERC. Prices
allowed, with respect to Tampa Electric, 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
s t a t e ments 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, conservation and environmental
costs for Tampa Electric and purchased gas, interstate pipeline
capacity and conservation costs for Peoples Gas System. These
adjustment factors are based on costs projected for a specific
recovery period. Any over-recovery or under-recovery of costs plus an
interest factor are taken into account in the process of setting
adjustment factors for subsequent recovery periods. Over-recoveries of
costs are recorded as deferred credits and under-recoveries of costs
are recorded as deferred debits.
In August 1996, the FPSC approved Tampa Electric's petition for
recovery of certain environmental compliance costs through the
Environmental Cost Recovery Clause.
In December 1994, Tampa Electric bought out a long-term coal
supply contract which would have expired in 2004 for a lump sum
payment of $25.5 million and entered into two new contracts with the
supplier. The coal supplied under the new contracts is competitive in
price with coal 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 10-year period beginning April 1, 1995. In
1998, 1997 and 1996, $2.7 million of buy-out costs were amortized to
expense.
36
Certain other costs incurred by the regulated utilities are
allowed to be recovered from customers through prices approved in the
regulatory process. These costs are recognized as the associated
revenues are billed.
The regulated utilities accrue base revenues for services
rendered but unbilled to provide a closer matching of revenues and
expenses.
In May 1996, the FPSC issued an order approving an agreement
among Tampa Electric, the Office of Public Counsel (OPC) and the
Florida Industrial Power Users Group (FIPUG) regarding 1996 earnings.
This agreement provided for a $25-million revenue refund to customers
to be made over the 12-month period beginning Oct. 1, 1996. This
refund consisted of $15 million of revenues deferred from 1996 and $10
million of revenues deferred from 1995, plus accrued interest.
In October 1996, the FPSC approved an agreement among Tampa
Electric, OPC and FIPUG that resolved all pending regulatory issues
associated with the Polk Power Station. The agreement allows the full
recovery of the capital costs incurred in the construction of the Polk
Power Station project, and calls for an extension of the base rate
freeze established in the May agreement through 1999. The October
agreement also established a $25-million temporary base rate reduction
reflected as a credit on customer bills over a 15-month period. The
reduction began Oct. 1, 1997 which immediately followed the $25-
million refund in the May agreement.
Depreciation
The company provides for depreciation primarily by the straight-
line method at annual rates that amortize the original cost, less net
salvage, of depreciable property over its estimated service life. The
provision for utility plant in service, expressed as a percentage of
the original cost of depreciable property, was 4.1% for 1998 and 4.0%
for 1997 and 1996.
The original cost of utility plant retired or otherwise disposed
of and the cost of removal less salvage are charged to accumulated
depreciation.
Asset Impairment
The company periodically assesses whether there has been a
permanent impairment of its long-lived assets and certain intangibles
held and used by it, in accordance with FAS 121, Accounting for the
Impairment of Long-lived Assets and Long-Lived Assets to be Disposed
of. No write-down of assets due to impairment was required in 1998 or
1997.
Reporting Comprehensive Income
In 1997, the Financial Accounting Standards Board issued FAS 130,
Reporting Comprehensive Income, effective for fiscal years beginning
after Dec. 15, 1997. The new standard requires that comprehensive
income, which includes net income as well as certain changes in assets
and liabilities recorded in common equity, be reported in the
financial statements. There were no components of comprehensive income
other than net income for the years ended Dec. 31, 1998, 1997 and
1996.
Deferred Income Taxes
The liability method is utilized in the measurement of deferred
income taxes. Under the liability method, the temporary differences
b e tween the financial statement and tax bases of assets and
liabilities are reported as deferred taxes measured at current tax
37
rates. Tampa Electric and Peoples Gas System are regulated, and their
books and records reflect approved regulatory treatment, including
certain adjustments to accumulated deferred income taxes and the
e s tablishment of a corresponding net regulatory tax liability
reflecting the amount payable to customers through future rates.
Investment Tax Credits
Investment tax credits have been recorded as deferred credits and
are being amortized 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 Tampa Electric's cost of capital. The rate was 7.79% for
1998, 1997 and 1996. Total AFUDC for 1997 and 1996 was $0.2 million
and $22.9 million, respectively. There were no qualifying projects in
1998. The base on which AFUDC is calculated excludes construction work
in progress which has been included in rate base.
Hedges - Gas Prices
Peoples Gas System enters into natural gas options contracts,
from time to time, to limit its exposure to gas price increases.
Tampa Electric Company does not use derivatives or other
financial products for speculative purposes.
Accounting for Derivative Instruments and Hedging
In 1998, the Financial Accounting Standards Board issued FAS 133,
Accounting for Derivative Instruments and Hedging, effective for
fiscal years beginning after June 15, 1999. The new standard requires
that an entity recognize derivatives as either assets or liabilities
in the financial statements, to measure those instruments at fair
value and to reflect the changes in fair value of those instruments as
either components of comprehensive income or net income, depending on
the types of those instruments. Tampa Electric Company does not use
derivatives or other financial products for speculative purposes. The
company has not yet determined to what extent the standard will impact
its financial statements.
Mergers
In June 1997, TECO Energy, Inc. completed its merger with Lykes
E n e rgy, Inc. Concurrent with this merger, the regulated gas
distribution utility, Peoples Gas System, Inc., was merged into Tampa
Electric Company and now operates as the Peoples Gas System division
of Tampa Electric Company.
Also in June 1997, TECO Energy completed its merger with West
Florida Gas Inc. (West Florida). Concurrent with this merger, West
Florida's regulated gas distribution utility, West Florida Natural Gas
Company, was merged into Tampa Electric Company and now operates as
part of the Peoples Gas System division.
These mergers were accounted for as poolings of interests and,
accordingly, the company's Balance Sheet as of Dec. 31, 1997 and its
Statements of Income and Cash Flows for the period ended Dec. 31, 1997
include the results of Peoples Gas System and West Florida.
Financial statements and all financial information presented for
periods prior to 1997 have been restated to include the results of the
Peoples Gas System. Prior period financial statements have not been
38
restated to reflect the operations and financial position of West
Florida Natural Gas due to its size.
Reclassifications and Restatements
Certain prior year amounts were reclassified or restated to
conform with current year presentation.
B. Common Stock
The company is a wholly owned subsidiary of TECO Energy, Inc.
Common Stock Issue
(thousands) Shares Amount Expense Total
Balance Dec. 31, 1995 10 $ 879.5 $(1.4) $ 878.1
Contributed capital from parent - 83.0 -- 83.0
Costs associated with Preferred
Stock retirements (1) -- 0.6 0.6
Balance Dec. 31, 1996 10 962.5 (0.8) 961.7
Contributed capital from parent - 5.0 -- 5.0
Costs associated with Preferred
Stock retirements (2) -- 0.1 0.1
West Florida Natural Gas merger - 5.3 -- 5.3
Balance Dec. 31, 1997 10 972.8 (0.7) 972.1
Contributed capital from parent - 54.0 -- 54.0
Balance Dec. 31, 1998 10 $1,026.8 $(0.7) $1,026.1
(1) In April 1996, the Tampa Electric retired $35 million aggregate
par value of 8.00% Series E and 7.44% series F preferred stock.
In connection with this retirement, $.6 million of associated
issuance costs were recognized.
(2) In July 1997, Tampa Electric retired all of its outstanding
shares ($20 million aggregate par value) of 4.32% Series A.
4.16% Series B and 4.58% Series D preferred stock at redemption
prices of $103.75, $102.875 and $101.00 per share, respectively.
In connection with this retirement, $.1 million of associated
issuance costs were recognized.
C. Retained Earnings
Tampa Electric's first mortgage bonds and certain of Peoples Gas
System's long-term debt issues contain provisions that limit the
dividend payment on the company's common stock. At Dec. 31, 1998,
substantially all of the company's retained earnings were available
for dividends on its common stock.
D. Retirement Plan
Tampa Electric is a participant in the comprehensive retirement
plan of TECO Energy, including 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. About 70 percent of plan
assets were invested in common stocks and 30 percent in fixed income
investments at Dec. 31, 1998.
The Peoples Gas System retirement plan was merged with the TECO
Energy retirement plan effective Jan. 1, 1998. As of Dec. 31, 1997,
39
Peoples Gas System had a non-contributory defined benefit retirement
plan which covered substantially all employees. Benefits were based on
employees' years of service and average compensation during specified
years of employment.
Peoples Gas System s retirement plan was funded annually by the
company within the guidelines set by ERISA for the minimum annual
contribution and the maximum allowable as a tax deduction by the IRS.
Plan assets were invested primarily in a collective investment trust
consisting of equity securities, fixed income securities and cash
equivalents.
All information prior to 1998 has been restated to include the
Peoples Gas System Retirement Plan.
In 1997, the Financial Accounting Standards Board issued FAS
132, Employers' Disclosures about Pensions and Other Post Retirement
Benefits. FAS 132 standardizes the disclosure requirements for pension
and other postretirement benefits with additional information required
on changes in the benefit obligations and fair values of plan assets.
TECO Energy adopted FAS 132 with the additional disclosures included
here and in Footnote E, Postretirement Benefit Plan.
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) 1998 1997 1996
Service cost
(benefits earned during the period) $11.2 $ 9.6 $ 9.9
Interest cost on projected
benefit obligations 24.8 23.6 22.2
Less: Expected return on plan assets (31.5) (28.4) (26.4)
Amortization of:
Unrecognized transition asset (1.1) (1.2) (1.2)
Prior service cost 0.9 0.9 0.8
Actuarial (gain) loss -- (0.3) (0.1)
Net pension expense 4.3 4.2 5.2
Special termination benefit charge 0.7 -- --
Curtailment charge (0.8) -- (1.0)
Net pension expense recognized
in TECO Energy's Consolidated
Statements of Income (1) $ 4.2 $ 4.2 $ 4.2
(1) Tampa Electric Company's portion was $2.1 million, $2.6 million
and
$3.5 million for 1998, 1997 and 1996, respectively.
40
Reconciliation of the Funded Status of the Retirement Plan and the
Accrued Pension Prepayment/(Liability)
(millions)
Dec. 31, Dec. 31,
1998 1997
Projected benefit obligation, beginning
of year $344.7 $262.2
Change in benefit obligation due to:
Service cost 11.2 9.6
Interest cost 24.8 23.6
Actuarial (gain) loss 22.4 22.1
Acquisitions -- 47.6
Curtailments (1.1) --
Special termination benefits 0.7 --
Gross benefits paid (19.0) (20.4)
Projected benefit obligation, end
of year 383.7 344.7
Fair value of plan assets, beginning
of year 414.8 320.5
Change in plan assets due to:
Actual return on plan assets 72.2 65.8
Employer contributions 0.7 --
Acquisitions -- 48.9
Gross benefits paid (19.0) (20.4)
Fair value of plan assets, end
of year 468.7 414.8
Funded status, end of year 85.0 70.1
Unrecognized net actuarial gain (102.9) (83.7)
Unrecognized prior service cost 10.7 11.0
Unrecognized net transition asset (7.0) (8.1)
Accrued pension liability (2) $(14.2) $(10.7)
(2) Tampa Electric Company's portion was $12.1 million and $10.6
million
at Dec. 31, 1998 and 1997, respectively.
Assumptions Used in Determining Actuarial Valuations
1998 1997
Discount rate to determine projected
benefit obligation 6.75% 7.25%
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
Tampa Electric 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.
Tampa Electric Company reserves the right to terminate or modify the
plan in whole or in part at any time.
41
Components of Postretirement Benefit Cost
(millions)
1998 1997 1996
Service cost (benefits earned
during the period) $1.5 $1.3 $1.4
Interest cost on projected
benefit obligations 4.2 4.4 4.6
Amortization of transition obligation
(straight line over 20 years) 2.1 2.1 2.1
Amortization of actuarial loss/(gain) (0.1) (0.1) 0.2
Net periodic Postretirement
benefit expense $7.7 $7.7 $8.3
Reconciliation of the Funded Status of the Postretirement Benefit Plan
and the Accrued Liability (millions)
Dec. 31, Dec. 31,
1998 1997
Accumulated postretirement benefit obligation,
beginning of year $ 61.7 $ 62.2
Change in benefit obligation due to:
Service cost 1.5 1.3
Interest cost 4.2 4.4
Plan participants' contributions 0.1 0.2
Actuarial (gain) loss 0.3 (2.5)
Gross benefits paid (3.7) (3.9)
Accumulated postretirement benefit obligation,
end of year $ 64.1 $ 61.7
Funded status, end of year $(64.1) $(61.7)
Unrecognized net loss from past experience 5.3 4.9
Unrecognized transition obligation 29.5 31.6
Liability for accrued postretirement benefit $(29.3) $(25.2)
Assumptions Used in Determining Actuarial Valuations
1998 1997
Discount rate to determine projected
benefit obligation 6.75% 7.25%
The assumed health care cost trend rate for medical costs prior
to age 65 was 8.75% in 1998 and decreases to 5.75% in 2002 and
thereafter. The assumed health care cost trend rate for medical costs
after age 65 was 6.75% in 1998 and decreases to 5.75% in 2002 and
thereafter.
A 1-percent increase in the medical trend rates would produce a
9-percent ($0.5 million) increase in the aggregate service and
interest cost for 1998 and an 8-percent($4.9 million) increase in the
accumulated postretirement benefit obligation as of Dec. 31, 1998.
A 1-percent decrease in the medical trend rates would produce a
7-percent ($0.4 million) decrease in the aggregate service and
interest cost for 1998 and a 7-percent($4.2 million) decrease in the
accumulated postretirement benefit obligation as of Dec. 31, 1998.
42
F. 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
1998
Currently payable $ 52.8 $ 9.3 $ 62.1
Deferred 24.7 3.8 28.5
Amortization of investment
tax credits (4.6) - (4.6)
Total income tax expense $ 72.9 $ 13.1 86.0
Included in other income, net (0.3)
Included in operating expenses $ 86.3
1997
Currently payable $ 62.9 $ 7.1 $ 70.0
Deferred 15.0 6.1 21.1
Amortization of investment
tax credits (4.7) -- (4.7)
Total income tax expense $ 73.2 $ 13.2 86.4
Included in other income, net (1.1)
Included in operating expenses $ 87.5
1996
Currently payable $ 63.9 $ 11.1 $ 75.0
Deferred 8.3 1.1 9.4
Amortization of investment
tax credits (4.7) - (4.7)
Total income tax expense $ 67.5 $ 12.2 79.7
Included in other income, net (0.2)
Included in operating expenses $ 79.9
D e f erred 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) 1998 1997
Deferred tax assets(1)
Property related $ 90.1 $ 87.4
Leases 4.8 5.2
Insurance reserves 10.7 9.2
Early capacity payments 2.2 2.2
Other 8.3 8.2
Total deferred income tax assets 116.1 112.2
Deferred income tax liabilities(1)
Property related (475.9) (450.9)
Other 28.3 35.3
Total deferred income tax liabilities (447.6) (415.6)
Accumulated deferred income taxes $(331.5) $(303.4)
_________________
(1) Certain property related assets and liabilities have been netted.
43
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) 1998 1997 1996
Net income $146.4 $148.6 $155.5
Total income tax provision 86.0 86.4 79.7
Income before income taxes $232.4 $235.0 $235.2
Income taxes on above at federal
statutory rate of 35% $ 81.3 $ 82.3 $ 82.3
Increase (decrease) due to
State income tax, net of federal
income tax 8.5 8.6 8.0
Amortization of investment tax
credits (4.6) (4.7) (4.7)
Equity portion of AFUDC -- -- (5.8)
Other 0.8 0.2 (0.1)
Total income tax provision $ 86.0 $ 86.4 $ 79.7
Provision for income taxes as
a percent of income before
income taxes 37.0% 36.7% 33.9%
G. Short-term Debt
Notes payable consisted primarily of commercial paper with
weighted average interest rates of 5.18% and 5.72% at Dec. 31, 1998
a n d 1997, 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, 1998 were $230
million. Certain lines of credit require commitment fees of .05% on
the unused balances.
H. Related Party Transactions (millions)
Net transactions with affiliates are as follows:
1998 1997 1996
Fuel and interchange related, net $149.6 $154.6 $154.9
Administrative and general, net $ 13.5 $ 9.5 $ 10.6
Amounts due from or to affiliates of the company at year-end are as
follows:
1998 1997
Accounts receivable $ 3.6 $ 7.7
Accounts payable $ 19.2 $ 20.1
Accounts receivable and accounts payable were incurred in the ordinary
course of business and do not bear interest.
44
I. Non-Recurring Charges
In 1998, the company recognized one-time charges totaling $16.9
million, pretax ($10.3 million after-tax). Of the $16.9 million pretax
charges, $9.6 million ($5.9 million, after-tax) was recorded in
operating expenses a non-recurring charge and $7.3 million ($4.4
million, after-tax) was recorded in other expense.
The FPSC in September 1997 ruled that under the regulatory
agreements effective through 1999 the costs associated with two long-
term wholesale power sales contracts should be assigned to the
wholesale jurisdiction and that for retail rate making purposes the
costs transferred from retail to wholesale should reflect average
costs rather than the lower incremental costs on which the two
contracts are based. As a result of this decision and the related
reduction of the retail rate base upon which Tampa Electric is allowed
to earn a return, these contracts became uneconomical. One contract
was terminated in 1997. As to the other contract, which expires in
2001, Tampa Electric has entered into firm power purchase contracts
with third parties to provide replacement power through 1999 and is no
longer separating the associated generation assets from the retail
jurisdiction. The cost of purchased power under these contracts
e x c eeds the revenues expected through 1999. To reflect this
difference, Tampa Electric recorded a $5.9-million after-tax charge in
1998.
Tampa Electric also recorded a $4.4-million, after-tax charge in
1998 for a recent FPSC denial of the recovery of certain BTU coal
quality adjustments for coal purchase since 1993. This was recorded as
other expense on the income statement.
J. Commitments and Contingencies
Tampa Electric's capital expenditures are estimated to be $142
million in 1999 and $506 million for 2000 through 2003 for equipment
and facilities to meet customer growth and generation reliability
programs. Additionally, Tampa Electric is also expecting to spend $61
million in 1999 and $6 million during 2000-2003 to complete the
scrubber project at Big Bend Power Station and is forecasting $19
million in 1999 and $194 million during 2000-2003 to construct
additional generation expansion. At the end of 1998, Tampa Electric
had outstanding commitments of about $68 million to complete the
scrubber and $44 million to construct additional generation expansion.
Peoples Gas System s capital expenditures are estimated to be $75
million for 1999 and $208 million for 2000 through 2003 for
infrastructure expansion to grow the customer base and normal asset
replacement. At the end of 1998, Peoples Gas System had outstanding
commitments of $8 million related to its Southwest Florida expansion.
45
K. Segment Information
Tampa Electric Company is a public utility operating within the state of
Florida. Through its Tampa Electric division, it is engaged in the generation,
purchase, transmission, distribution and sale of electric energy to more than
537,000 customers in West Central Florida. Its Peoples Gas System division is
engaged in the purchase, distribution and marketing of natural gas for almost
240,000 residential, commercial, industrial and electric power generation
customers in the State of Florida. FAS 131 was adopted in 1998 and all prior
years presented here have been restated to conform to the requirements of FAS
131.
Income Capital
From Assets Expenditures
(millions) Revenues Operations(1) Depreciation at Dec. 31, for the Year
1998
Tampa Electric $1,234.6(2)(3) $203.4 (4) $146.1 $2,770.9 $176.2
Peoples Gas System 252.8 25.8 21.1 375.6 55.9
Non-recurring pretax charge -- (9.6) -- -- --
Tampa Electric Company $1,487.4 $219.6 $167.2 $3,146.5 $232.1
1997
Tampa Electric $1,189.2 (2) $193.1 $141.4 $2,750.0 $125.1
Peoples Gas System 249.5 24.5 19.8 348.9 30.2
Tampa Electric Company $1,438.7 $217.6 $161.2 $3,098.9 $155.3
1996
Tampa Electric $1,112.9 (2) $172.6 $120.2 $2,723.2 $203.3
Peoples Gas System 258.6 23.5 17.2 302.7 25.9
Tampa Electric Company $1,371.5 $196.1 $137.4 $3,025.9 $229.3
(1) Operating income is net of income tax expense. Total income tax
expense was $86.3 million, $87.5 million and $79.9 million in
1998, 1997 and 1996, respectively.
(2) Revenues from sales to affiliates were $23.2 million, $22.2
million and $20.5 million in 1998, 1997 and 1996, respectively.
(3) Revenues shown in 1998 and 1997 include the recognition of
previously deferred revenue of $38.3 million and $30.5 million,
respectively. Revenues shown in 1996 are after the revenues
deferral of $34.2 million.
(4) Operating income excludes a non-recurring pretax charge of $9.6
million in 1998. See Note I.
46
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE.
During the period from Jan. 1, 1997 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 IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM
8-K.
(a) 1. Financial Statements - See index on page 28.
2. Financial Statement Schedules - See index on page 28.
3. Exhibits
*3.1 A r ticles of Incorporation (Exhibit 3.1 to
Registration Statement No. 2-70653).
*3.2 Bylaws, as amended, effective April 16, 1997 (Exhibit
3, Form 10-Q for the quarter ended June 30, 1997 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 Thirteenth Supplemental Indenture, dated as of Jan.
1, 1974, to Exhibit 4.1 (Exhibit 2-g-l, Registration
Statement No. 2-51204).
*4.3 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).
*4.4 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).
*4.5 Installment Purchase and Security Contract between
t h e 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).
*4.6 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).
*4.7 Third Supplemental Installment Purchase Contract,
dated as of May 1, 1976 (Exhibit 4.12, Form 10-K for
1986 of Tampa Electric Company).
*4.8 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).
*4.9 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).
*4.10 Second Supplemental Installment Purchase Contract,
dated as of June 1, 1983 (Exhibit 4.11, Form 10-K for
1994 of Tampa Electric Company).
*4.11 Third Supplemental Installment Purchase Contract,
47
dated as of Aug. 1, 1989 (Exhibit 4.16, Form 10-K for
1989 of Tampa Electric Company).
*4.12 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).
*4.13 First Supplemental Installment Purchase Contract,
dated as of Aug. 2, 1984 (Exhibit 4.14, Form 10-K for
1994 of Tampa Electric Company).
*4.14 Second Supplemental Installment Purchase Contract,
dated as of July 1, 1993 (Exhibit 4.3, Form 10-Q for
the quarter ended June 30, 1993).
*4.15 Loan and Trust Agreement among the Hillsborough
C o u nty 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).
*4.16 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).
*4.17 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).
*4.18 Loan and Trust Agreement, dated as of Dec. 1, 1996,
a m o n g the Polk County Industrial Development
Authority, Tampa Electric Company and the Bank of New
York, as trustee (Exhibit 4.18, Form 10-K for 1996 of
Tampa Electric Company).
*4.19 First Supplemental Indenture dated as of July 15,
1998 between Tampa Electric Company and The Bank of
New York, as trustee (Exhibit 4.1, Form 8-K dated
July 28, 1998 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 TECO Energy Group Supplemental Executive Retirement
Plan, as amended and restated as of Oct. 16, 1996
(Exhibit 10.3, Form 10-K for 1996 of Tampa Electric
Company).
*10.3 TECO Energy Group Supplemental Retirement Benefits
Trust Agreement, as amended and restated as of Jan.
15, 1997 (Exhibit 10.4, Form 10-K for 1996 of Tampa
Electric Company).
10.4 Annual Incentive Compensation Plan for TECO Energy
and subsidiaries, as revised Jan. 20, 1999.
*10.5 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).
*10.6 Forms of Severance Agreements between TECO Energy,
Inc. and certain senior executives, as amended and
48
restated as of July 15, 1998 (Exhibit 10.1, Form 10-Q
for the quarter ended Sept. 30, 1998 of Tampa
Electric Company).
*10.7 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).
*10.8 Supplemental Executive Retirement Plan for R.H.
Kessel, as amended and restated as of Jan. 15, 1997
(Exhibit 10.10, Form 10-K for 1996 of Tampa Electric
Company).
*10.9 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.).
*10.10 Supplemental Executive Retirement Plan for A.D. Oak,
as amended and restated effective as of Oct. 16, 1996
(Exhibit 10.12, Form 10-K for 1996 of Tampa Electric
Company).
*10.11 Supplemental Executive Retirement Plan for G.F.
Anderson, as amended and restated effective as of
Oct. 16, 1996 (Exhibit 10.15, Form 10-K for 1996 of
Tampa Electric Company).
*10.12 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).
10.13 TECO Energy Group Retirement Savings Excess Benefit
Plan, as amended and restated effective as of July
15, 1998.
*10.14 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.).
*10.15 Supplemental Executive Retirement Plan for R.A. Dunn,
as amended and restated effective as of Jan. 15, 1997
(Exhibit 10.20, Form 10-K for the 1996 of Tampa
Electric Company).
*10.16 Form of Nonstatutory Stock Option under the TECO
Energy, Inc. 1996 Equity Incentive Plan (Exhibit
10.1, Form 10-Q for the quarter ended June 30, 1996
of Tampa Electric Company).
*10.17 Form of Amendment to Nonstatutory Stock Option, dated
as of July 15, 1998, under the TECO Energy, Inc. 1996
Equity Incentive Plan (Exhibit 10.3, Form 10-Q for
the quarter ended Sept. 30, 1998 of Tampa Electric
Company).
*10.18 Form of Restricted Stock Agreement between TECO
Energy, Inc. And certain executives under the TECO
Energy, Inc. 1996 Equity Incentive Plan (Exhibit
10.1, Form 10-Q for the quarter ended June 30, 1998
of Tampa Electric Company).
*10.19 Form of Amendment to Restricted Stock Agreements,
dated as of July 15, 1998, between TECO Energy, Inc.
and certain senior executives under the TECO Energy,
Inc. 1996 Equity Incentive Plan (Exhibit 10.2, Form
10-Q for the quarter ended Sept. 30, 1998 of Tampa
Electric Company).
*10.20 Form of Restricted Stock Agreement between TECO
Energy, Inc. and G. F. Anderson under the TECO
Energy, Inc. 1996 Equity Incentive Plan (Exhibit
10.2, Form 10-Q for the quarter ended June 30, 1998
49
of Tampa Electric Company).
*10.21 TECO Energy, Inc. 1997 Director Equity Plan (Exhibit
10.1, Form 8-K dated April 16, 1997 of Tampa Electric
Company).
*10.22 Form of Nonstatutory Stock Option under the TECO
Energy, Inc. 1997 Director Equity Plan (Exhibit 10,
Form 10-Q for the quarter ended June 30, 1997 of
Tampa Electric Company).
12. Ratio of earnings to fixed charges.
23. Consent of Independent Accountants.
24.1 Power of Attorney.
24.2 Certified copy of resolution authorizing Power of
Attorney.
27. Financial Data Schedule (EDGAR filing only).
_____________
* Indicates exhibit previously filed with the Securities and
Exchange Commission and incorporated herein by reference.
Exhibits filed with periodic reports of Tampa Electric
Company and TECO Energy, Inc. were filed under Commission
File Nos. 1-5007 and 1-8180, respectively.
Certain instruments defining the rights of holders of
long-term debt of Tampa Electric Company authorizing in each
case a total amount of securities not exceeding 10 percent of
total assets on a consolidated basis are not filed herewith.
Tampa Electric Company will furnish copies of such instruments
to the Securities and Exchange Commission upon request.
Executive Compensation Plans and Arrangements
Exhibits 10.1 through 10.22 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 registrant did not file any Current Reports on Form 8-K
during the last quarter of 1998.
50
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 30th day of March, 1999.
TAMPA ELECTRIC COMPANY
By G. F. Anderson*
G. F. Anderson, 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 30, 1999:
Signature Title
G. F. ANDERSON* Chairman of the Board,
G. F. ANDERSON Director and Chief Executive
Officer (Principal Executive
Officer)
/S/G. L. GILLETTE Vice President-Finance
G. L. GILLETTE and Chief Financial Officer
(Principal Financial Officer)
W. L. GRIFFIN* Vice President-Controller
W. L. GRIFFIN (Principal Accounting Officer)
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.
T. L. RANKIN* Director
T. L. RANKIN
51
R. L. RYAN* Director
R. L. RYAN
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/ G. L. GILLETTE
G. L. GILLETTE, Attorney-in-fact
52
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 April 16, 1997 *
(Exhibit 3, Form 10-Q for the quarter ended June 30,
1997 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 Thirteenth Supplemental Indenture, dated as of *
Jan. 1, 1974, to Exhibit 4.1 (Exhibit 2-g-l,
Registration Statement No. 2-51204).
4.3 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).
4.4 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).
4.5 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).
4.6 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).
4.7 Third Supplemental Installment Purchase Contract, *
dated as of May 1, 1976 (Exhibit 4.12, Form 10-K
for 1986 of Tampa Electric Company).
4.8 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).
4.9 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).
4.10 Second Supplemental Installment Purchase Contract, *
dated as of June 1, 1983 (Exhibit 4.11, Form 10-K for
1994 of Tampa Electric Company).
4.11 Third Supplemental Installment Purchase Contract, *
dated as of Aug. 1, 1989 (Exhibit 4.16, Form 10-K
for 1989 of Tampa Electric Company).
4.12 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).
4.13 First Supplemental Installment Purchase Contract, *
dated as of Aug. 2, 1984 (Exhibit 4.14, Form 10-K for
1994 of Tampa Electric Company).
53
4.14 Second Supplemental Installment Purchase Contract, *
dated as of July 1, 1993 (Exhibit 4.3, Form 10-Q
for the quarter ended June 30, 1993).
4.15 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).
4.16 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).
4.17 Loan and Trust Agreement, dated as of June 23, *
1993, among the Hillsborough County Industrial
D e velopment 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).
4.18 Loan and Trust Agreement, dated as of Dec. 1, 1996, *
among the Polk County Industrial Development Authority,
Tampa Electric Company and the Bank of New York, as
trustee (Exhibit 4.18, Form 10-K for 1996 of Tampa
Electric Company).
4.19 First Supplemental Indenture dated as of July 15, 1998 *
between Tampa Electric Company and The Bank of New York,
as trustee (Exhibit 4.1, Form 8-K dated July 28, 1998 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 TECO Energy Group Supplemental Executive Retirement *
Plan, as amended and restated as of Oct. 16, 1996
(Exhibit 10.3, Form 10-K for 1996 of Tampa Electric
Company).
10.3 TECO Energy Group Supplemental Retirement Benefits *
Trust Agreement as amended and restated as of Jan. 15,
1997 (Exhibit 10.4, Form 10-K for 1996 of Tampa Electric
Company).
10.4 Annual Incentive Compensation Plan for TECO Energy 57
and subsidiaries, revised Jan. 20, 1999.
10.5 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).
10.6 Forms of Severance Agreements between TECO Energy, *
Inc. and certain senior executives, as amended and
restated as of July 15, 1998 (Exhibit 10.1, Form 10-Q
for the quarter ended Sept. 30, 1998 of Tampa Electric
Company).
10.7 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).
10.8 Supplemental Executive Retirement Plan for *
R.H. Kessel, as amended and restated as of Jan. 15, 1997
(Exhibit 10.10, Form 10-K for 1996 of Tampa Electric
Company).
54
10.9 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.).
10.10 Supplemental Executive Retirement Plan for *
A.D. Oak, as amended and restated effective as of Oct.
16, 1996 (Exhibit 10.12, Form 10-K for 1996 of Tampa
Electric Company).
10.11 Supplemental Executive Retirement Plan for *
G.F. Anderson, as amended and restated effective as of
Oct. 16, 1996 (Exhibit 10.15, Form 10-K for 1996 of
Tampa Electric Company).
10.12 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).
10.13 TECO Energy Group Retirement Savings Excess Benefit 61
Plan, as amended and restated effective as of July 15,
1998.
10.14 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.).
10.15 Supplemental Executive Retirement Plan for R.A. Dunn, *
as amended and restated as of Jan. 15, 1997 (Exhibit
10.20, Form 10-K for 1996 of Tampa Electric Company).
10.16 Form of Nonstatutory Stock Option under the TECO Energy, *
Inc. 1996 Equity Incentive Plan (Exhibit 10.1, Form 10-Q
for the quarter ended June 30, 1996 of Tampa Electric
Company).
10.17 Form of Amendment to Nonstatutory Stock Option, dated *
as of July 15, 1998, under the TECO Energy, Inc. 1996
Equity Incentive Plan (Exhibit 10.3, Form 10-Q for the
quarter ended Sept. 30, 1998 of Tampa Electric Company).
10.18 Form of Restricted Stock Agreement between TECO Energy, *
Inc. And certain executives under the TECO Energy, Inc.
1996 Equity Incentive Plan (Exhibit 10.1, Form 10-Q for
the quarter ended June 30, 1998 of Tampa Electric
Company).
10.19 Form of Amendment to Restricted Stock Agreements, dated *
as of July 15, 1998, between TECO Energy, Inc. and
certain senior executives under the TECO Energy, Inc.
1996 Equity Incentive Plan (Exhibit 10.2, Form 10-Q for
the quarter ended Sept. 30, 1998 of Tampa Electric
Company).
10.20 Form of Restricted Stock Agreement between TECO Energy, *
Inc. and G. F. Anderson under the TECO Energy, Inc. 1996
Equity Incentive Plan (Exhibit 10.2, Form 10-Q for the
quarter ended June 30, 1998 of Tampa Electric Company).
10.21 TECO Energy, Inc. 1997 Director Equity Plan *
(Exhibit 10, Form 10-Q for the quarter ended June 30,
1997 of Tampa Electric Company).
10.22 Form of Nonstatutory Stock Option under the TECO *
Energy, Inc. 1997 Director Equity Plan (Exhibit 10, Form
10-Q for the quarter ended June 30, 1997 of Tampa
Electric Company).
55
12. Ratio of earnings to fixed charges. 68
23. Consent of Independent Accountants. 69
24.1 Power of Attorney. 70
24.2 Certified copy of resolution authorizing Power 72
of Attorney.
27.1 Financial Data Schedule (EDGAR filing only).
* Indicates exhibit previously filed with the Securities and
Exchange Commission and incorporated herein by reference.
Exhibits filed with periodic reports of Tampa Electric Company
and TECO Energy, Inc. were filed under Commission File Nos.
1-5007 and 1-8180, respectively.
56