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 _____ to _____
Commission File Number 1-8180
TECO ENERGY, INC.
(Exact name of registrant as specified in its charter)
FLORIDA 59-2052286
(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:
Name of each exchange on
Title of each class which registered
Common Stock, $1.00 par value New York Stock Exchange
Common Stock Purchase Rights New York Stock Exchange
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 amendments 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 $2,861,810,975.
The number of shares of the registrant's common stock outstanding as of
February 28, 1999 was 131,956,702.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Definitive Proxy Statement relating to the 1999 Annual
Meeting of Shareholders of the registrant are incorporated by reference
into Part III.
PART I
Item 1. BUSINESS.
TECO ENERGY
TECO Energy, Inc. (TECO Energy) was incorporated in Florida in
1981, as part of a restructuring in which it became the parent
corporation of Tampa Electric Company.
TECO Energy currently owns no operating assets but holds all of
the common stock of Tampa Electric and the other subsidiaries listed
below. TECO Energy is a public utility holding company exempt from
registration under the Public Utility Holding Company Act of 1935.
In June 1997, TECO Energy acquired Lykes Energy, Inc. (the
Peoples companies). As part of this acquisition, Lykes' regulated gas
distribution utility was merged into Tampa Electric Company and now
operates as the Peoples Gas System division of Tampa Electric Company.
TECO Energy's significant business segments are identified below:
-- Tampa Electric Company, a Florida corporation and TECO
Energy's largest subsidiary, provides retail electric service to more
than 537,000 customers in West Central Florida with a net system
generating capability of 3,615 megawatts (MWS) (Tampa Electric). The
Peoples Gas System division (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. With 240,000 customers, PGS has operations in Florida's major
metropolitan areas. Annual natural gas throughput (the amount of gas
delivered to its customers including transportation only service) in
1998 was 912 million therms.
-- TECO Transport Corporation (TECO Transport), a Florida
corporation, owns no operating assets but owns all of the common stock
of four subsidiaries which transport, store and transfer coal and
other dry bulk commodities.
-- TECO Coal Corporation (TECO Coal), a Kentucky corporation,
owns no operating assets but owns all of the common stock of five
subsidiaries that own mineral rights, and own/or operate surface and
underground mines and coal processing and loading facilities in
Kentucky and Tennessee.
-- TECO Power Services Corporation (TECO Power Services), a
F l o rida corporation, has subsidiaries that have interests in
i n dependent power projects in Florida and Guatemala, and has
i n v e stments in unconsolidated affiliates that participate in
independent power projects in other parts of the U.S. and the world.
TECO Energy's other diversified businesses include the following
corporations identified below:
-- TECO Coalbed Methane, Inc. (TECO Coalbed Methane), an
Alabama corporation, participates in the production of natural gas
from coalbeds located in Alabama's Black Warrior Basin.
2
-- Peoples Gas Company (PGC), a Florida corporation, sells
liquefied petroleum gas, or propane, to almost 55,000 customers,
primarily within peninsular Florida.
-- TECO Gas Services, Inc. (TECO Gas Services), a Florida
corporation, markets natural gas to large commercial and industrial
customers.
-- TeCom Inc. (TeCom), a Florida corporation, markets advanced
energy management, automation and control systems.
-- B o sek, Gibson and Associates, Inc. (BGA), a Florida
corporation, provides engineering and energy services to customers
primarily in Florida and California.
For financial information regarding TECO Energy's significant
business segments, see Note K, Segment Information on pages 77 and 78.
TECO Energy and its subsidiaries had 5,470 employees as of Dec.
31, 1998.
TAMPA ELECTRIC--Electric Operations
Tampa Electric Company was incorporated in Florida in 1899 and
was reincorporated in 1949. Tampa Electric Company is a public utility
operating within the state of Florida. Through its Tampa Electric
division, it is engaged in the generation, purchase, transmission,
distribution and sale of electric energy. The retail territory served
comprises an area of about 2,000 square miles in West Central Florida,
including Hillsborough County and parts of Polk, Pasco and Pinellas
Counties, 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.
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.
3
The sources of operating revenue for the years indicated were as
follows:
(millions) 1998 1997 1996
Residential $ 563.2 $ 532.3 $ 539.7
Commercial 335.2 326.7 321.3
Industrial-Phosphate 59.3 61.3 59.6
Industrial-Other 53.4 51.5 43.3
Other retail sales
of electricity 86.9 85.0 83.5
Sales for resale 89.6 94.3 93.3
Deferred revenues 38.3 30.5 (34.2)
Other 8.7 7.6 6.4
$1,234.6 $1,189.2 $1,112.9
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
further discussion of IMCA on page 46.
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 43 through 44.
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
4
for a specific recovery period, with a true-up adjustment to reflect
the variance of actual costs from the projected charges.
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 8 and 9.
TECO Transport, TECO Coal and TECO Power Services subsidiaries
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. See Utility
Regulation on pages 43 through 47. Except for transportation services
performed by TECO Transport under the U.S. bulk cargo preference
p r ogram, the prices charged by TECO Transport and TECO Coal
subsidiaries to third-party customers are not subject to regulatory
oversight. See also TECO Power Services on pages 15 through 18.
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 as more fully described
below.
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
5
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.
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 pages 46 and 47 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 delivered fuel cost per million BTU and
average delivered cost per ton of coal burned have been as follows:
Average cost
per million BTU: 1998 1997 1996 1995 1994
Coal $ 1.99 $ 1.97 $ 2.01 $ 2.15 $ 2.22
Oil $ 3.14 $ 3.76 $ 3.68 $ 2.76 $ 2.49
Composite $ 2.03 $ 2.01 $ 2.05 $ 2.16 $ 2.22
Average cost per ton
of coal burned $44.44 $44.50 $46.71 $50.97 $53.39
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
6
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
deliveries if environmental regulations should prevent Tampa Electric
from burning the coal supplied, provided that a good faith effort has
been made to continue burning such coal. For information concerning
transportation services and sales of coal by affiliated companies to
Tampa Electric, see TECO Transport on pages 13 and 14 and TECO Coal on
pages 14 and 15.
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
7
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.
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
8
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 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.
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
Peoples Gas System, Inc. and West Florida Natural Gas Company
were acquired by TECO Energy in June 1997 and now operate as the
Peoples Gas System division of Tampa Electric Company. 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 natural gas
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 used 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
9
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.
Revenues for PGS for the years ended Dec. 31, are as follows:
(millions) 1998 1997 1996
Residential $ 57.7 $ 56.3 $ 51.6
Commercial 141.2 138.9 141.3
Industrial 20.9 23.2 30.9
Power Generation 10.4 11.7 12.4
Other revenues 22.6 19.5 22.5
Total $252.8 $249.6 $258.7
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
10
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
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
11
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 (FGT) 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 (South Georgia)
pipeline through a gate station located northwest of Jacksonville.
Companies with firm pipeline capacity receive priority in
scheduling deliveries during times when the pipeline is operating at
its maximum capacity. PGS presently holds sufficient firm capacity to
permit it to meet the gas requirements of its system commodity
customers except during localized emergencies affecting the PGS
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.
12
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
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 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 at approximately $20 million over the next 10 years. To
date, PGS has been permitted by the FPSC to recover prudently incurred
13
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.
TECO TRANSPORT
TECO Transport owns all of the common stock of four subsidiaries
w h ich transport, store and transfer coal and other dry bulk
commodities. TECO Transport currently owns no operating assets.
TECO Transport and its subsidiaries had 1,139 employees as of
Dec. 31, 1998.
All of TECO Transport's subsidiaries perform substantial services
for Tampa Electric. In 1998, approximately 51 percent of TECO
Transport's revenues were from third-party customers and 49 percent
were from Tampa Electric. The pricing for services performed by TECO
Transport's operating companies for Tampa Electric is based on a fixed
price per ton, adjusted quarterly for changes in certain fuel and
price indices. Most of the third-party utilization of the ocean-going
b a r ges is for domestic phosphate movements and domestic and
international movements of other dry bulk commodities. Both the
terminal and river transport operations handle a variety of dry bulk
commodities for third-party customers.
A substantial portion of TECO Transport's business is dependent
upon Tampa Electric, industrial phosphate customers, export coal and
g r ain customers, and participation in the U.S. Department of
Agriculture cargo preference program.
TECO Transport's barge subsidiaries consist of Gulfcoast Transit
Company (Gulfcoast), which transports products in the Gulf of Mexico
and worldwide, and Mid-South Towing Company (Mid-South), which
operates on the Mississippi, Ohio and Illinois rivers. Their primary
competitors are other barge and shipping lines and railroads with a
number of other companies offering transportation services on the
waterways used by TECO Transport's subsidiaries. To date, physical and
technological improvements have allowed barge operators to maintain
competitive rate structures with alternate methods of transporting
bulk commodities when the origin and destination of such shipments are
contiguous to navigable waterways.
Electro-Coal Transfer Corporation (Electro-Coal) operates a major
transfer and storage terminal on the Mississippi River south of New
Orleans. Demand for the use of such terminals is dependent upon
customers' use of water transportation versus alternate means of
moving bulk commodities and the demand for these commodities.
Competition consists primarily of mid-stream operators and another
land-based terminal located nearby.
The business of TECO Transport's subsidiaries, taken as a whole,
is not subject to significant seasonal fluctuation.
The Interstate Commerce Act exempts from regulation water
t r ansportation of certain dry bulk commodities. In 1998, all
transportation services provided by TECO Transport's subsidiaries were
within this exemption.
14
TECO Transport's subsidiaries are also subject to the provisions
of the Clean Water Act of 1977 which authorizes the Coast Guard and
t h e EPA to assess penalties for oil and hazardous substance
discharges. Under this Act, these agencies are also empowered to
assess clean-up costs for such discharges. TECO Transport believes it
is in substantial compliance with applicable environmental laws,
regulations, orders and rules. In 1998, TECO Transport spent $.8
million for environmental compliance. Environmental expenditures are
estimated at $.7 million in 1999, primarily for work on solid waste
disposal and storm water drainage at the Electro-Coal facility in
Louisiana and for expenses related to oil and bilge water disposal at
its river-barge repair facility in Illinois.
TECO COAL
TECO Coal owns no operating assets but holds all of the common
stock of Gatliff Coal Company (Gatliff), Rich Mountain Coal Company
( R ich Mountain), Clintwood Elkhorn Mining Company (Clintwood),
Pike-Letcher Land Company (Pike-Letcher) and Premier Elkhorn Coal
Company (Premier). TECO Coal's subsidiaries own mineral rights, and
own or operate surface and underground mines and coal processing and
loading facilities in Kentucky and Tennessee.
TECO Coal and its subsidiaries had 315 employees as of Dec. 31,
1998.
In 1998, TECO Coal subsidiaries sold 6.8 million tons of coal,
with approximately 89 percent sold to third parties and 11 percent
sold to Tampa Electric. Tampa Electric is reducing its coal purchases
from TECO Coal as a result of its efforts to reduce costs and its
successful increased use of conventional steam coal from other
sources. TECO Coal expects increased sales volumes to other parties
from the Premier and Clintwood operations to offset the impact on
operating results of lower sales to Tampa Electric in 1999. The Tampa
Electric contract with TECO Coal expires at the end of 1999 and will
not be renewed.
Rich Mountain has no reserves; it mines coal reserves owned by
Gatliff.
Primary competitors of TECO Coal's subsidiaries are other coal
suppliers, many of which are located in Central Appalachia. To date,
TECO Coal has been able to compete for coal sales by mining high-
quality steam and specialty coals and by effectively managing
production and processing costs.
The operations of underground mines, including all related
surface facilities, are subject to the Federal Coal Mine Safety and
Health Act of 1977. TECO Coal's subsidiaries are also subject to
various Kentucky and Tennessee mining laws which require approval of
roof control, ventilation, dust control and other facets of the coal
mining business. Federal and state inspectors inspect the mines to
ensure compliance with these laws. TECO Coal believes it is in
substantial compliance with the standards of the various enforcement
agencies. It is unaware of any mining laws or regulations having a
prospective effective date that would materially affect the market
price of coal sold by its subsidiaries.
TECO Coal's subsidiaries are subject to various federal, state
a n d local air and water pollution standards in their mining
o p e rations. In 1998 approximately $1.5 million was spent on
environmental protection and reclamation programs. TECO Coal expects
to spend a similar amount in 1999 on these programs.
The coal mining operations are also subject to the Surface Mining
15
Control and Reclamation Act of 1977 which places a charge of $.15 and
$.35 on every net ton mined of underground and surface coal,
respectively, to create a fund for reclaiming land and water adversely
affected by past coal mining. Other provisions establish standards for
the control of environmental effects and reclamation of surface coal
mining and the surface effects of underground coal mining, and
requirements for federal and state inspections.
TECO POWER SERVICES
TECO Power Services (TPS) has subsidiaries that have interests in
i n dependent power projects in Florida and Guatemala, and has
investments in unconsolidated affiliated entities that participate in
independent power projects in other parts of the U.S. and the world.
It had 88 employees as of Dec. 31, 1998.
There are a number of companies competing with TPS for investment
opportunities in the U.S. and worldwide. Several of these competitors
are larger and have access to more resources. To date, TPS has been
a b l e to compete effectively for independent power investment
opportunities based on its success in developing independent power
projects in the U.S. and in Guatemala, and its associations with
experienced partners.
Hardee Power Partners Ltd. (Hardee Power), a Florida limited
partnership whose general and limited partners are wholly owned
subsidiaries of TPS, owns the Hardee Power Station, a 295-megawatt
combined cycle electric generating facility located in Hardee County,
Florida, which began commercial operation on Jan. 1, 1993. Hardee
Power has 20-year power supply agreements, which began in 1993, for
all of the capacity and energy of the Hardee Power Station with
Seminole Electric Cooperative (Seminole Electric), a Florida electric
cooperative that provides wholesale power to 10 electric distribution
cooperatives, and with Tampa Electric. Under the Seminole Electric
agreement, Hardee Power has agreed to supply Seminole Electric with an
additional 145 megawatts of capacity during the first 10 years of the
contract, which it is purchasing from Tampa Electric's coal-fired Big
Bend Unit Four for resale to Seminole Electric.
The Hardee Power Station is fueled by natural gas or No. 2 fuel
oil. In April 1998, TPS signed a contract with PGS for the supply of
natural gas to the station until 2000. About 99 percent of the Hardee
Power Station's generation for 1998 was from natural gas.
Hardee Power's average fuel cost per million BTU has been as
follows:
Average cost
per million BTU: 1998 1997 1996 1995 1994
Oil $4.21 $4.73 $ 4.61 $ 4.64 $ 3.68
Gas $2.46 $2.90 $ 3.60 $ 2.70 $ 2.02
Composite $2.48 $3.15 $ 3.65 $ 2.71 $ 2.40
The price for natural gas deliveries taken in December 1998 was
$2.21 per thousand cubic feet, or $2.09 per million BTU. The price for
fuel oil deliveries taken in November 1998 was $20.62 per barrel, or
$3.539 per million BTU. There were no fuel oil deliveries taken in
1998 subsequent to that date.
Through its ownership and operation of a wholesale generating
facility in the U.S., TECO Power Services is subject to regulation by
the FERC in various respects. Depending upon the nature of the
16
project, FERC may regulate, among other things, the rates, terms and
conditions for the sale of electric capacity and energy.
Like Tampa Electric, the U.S. operations of TECO Power Services
are subject to federal, state and local environmental laws and
regulations covering air quality, water quality, land use, power
plant, substation and transmission line siting, noise and aesthetics,
solid waste and other environmental matters.
Tampa Centro Americana de Electricidad, Limitada (TCAE), an
entity 96.06-percent owned by TPS Guatemala One, Inc. (TPS Guatemala
One), a subsidiary of TECO Power Services, has a U.S. dollar-
denominated power sales agreement to provide 78 megawatts of capacity
to an electric utility in Guatemala for a 15-year period ending in
2010. The project (the Alborada Power Station) consists of two
combustion turbines built at a total cost of approximately $50
million. TECO Power Services has obtained political risk insurance
from the Overseas Private Investment Corporation (OPIC), an agency of
the U.S. government, for currency inconvertibility, expropriation and
political violence covering up to 90 percent of its equity investment
and economic returns. In January 1997, TECO Power Services also
secured $29 million of limited-recourse financing for the Alborada
Power Station from OPIC.
TCAE began commercial operation of the Alborada Power Station on
Sept. 14, 1995. The power sales agreement between TCAE and the power
purchaser, Empresa Electrica de Guatemala, S.A. (EEGSA), provides for
a capacity charge and operations and maintenance expense payments. The
capacity charge is subject to adjustment due to output, heat rate and
availability. EEGSA is responsible for providing the fuel for the
p l a nt with TECO Power Services providing assistance in fuel
administration.
EEGSA, a private distribution and generation company formed in
1894, serves more than 530,000 customers. EEGSA s service territory
includes the capital of Guatemala, Guatemala City.
In 1996, Central Generadora Electrica San Jose, SRL (CGESJ), an
entity in which a TECO Power Services affiliate has a 46 percent
ownership interest, signed a U.S.-dollar denominated power sales
agreement with EEGSA to provide 120 megawatts of capacity for 15 years
beginning in 2000. The project consists of a single unit pulverized
coal baseload facility (San Jose Power Station) including port
modifications to accommodate the importation of coal. The total cost
of the project is estimated at $181 million. At Dec. 31, 1998, 46
percent of CGESJ was owned by another U.S. independent power producer
(a subsidiary of The Coastal Corporation) and 8 percent was owned by
the same Guatemalan business group that TECO Power Services partnered
with for the Alborada Power Station project. The U.S. partners have
obtained political risk insurance from OPIC for inconvertibility,
expropriation and political violence covering up to 90 percent of
their equity investment and economic returns. The project entity has
obtained construction financing, guaranteed by TPS and the other U.S.
owner. Upon the commencement of commercial operation of the San Jose
Power Station in 2000, the construction financing is expected to be
converted to limited-recourse debt.
In September 1998, a consortium that includes TPS, Iberdrola, an
electric utility in Spain, and Electricidade de Portugal, an electric
utility in Portugal, completed the purchase of an 80 percent ownership
interest in EEGSA. TPS owns a 30 percent interest in this consortium
and contributed $100 million in equity. The total purchase price paid
by the consortium was $520 million. The consortium obtained limited-
recourse debt financing for a portion of the purchase price.
17
In August 1998, TPS and Mosbacher Power Partners, Ltd. (Mosbacher
Power), an independent power company headquartered in Houston, agreed
to jointly develop, own and operate domestic and international
independent power projects. Under this arrangement, TPS will, among
other things, provide capital and technical expertise to Mosbacher and
g a i n a n expanded domestic and international presence with
opportunities for project returns, including preferred returns before
benefits are shared.
In October 1998, TPS, through the Mosbacher Power joint venture
discussed above, acquired an interest in a repowered independent power
project in the Czech Republic. The TPS/Mosbacher Power joint venture
entity, Nations Energy Corp., NRG Energy, El Paso Energy International
a n d S tredoceske Energeticke Zavody (STE), a Czech regional
distribution company, are owners of the project. The facility, after
planned expansion, will have a net total capacity of 344 megawatts and
is scheduled to go in service during the fourth quarter of 1999.
In February 1999, TPS formed a joint venture relationship with
Energia Global International, Ltd. (EGI), a Bermuda-based energy
development firm. EGI owns and operates electric generation and
cogeneration facilities in Central America with a particular emphasis
on renewable power (i.e. hydro, geothermal, wind, biomass). It also
has interests in electric distribution companies in El Salvador and
Panama.
See the discussion of the risks inherent in doing business
internationally in the Investment Considerations section on page 49.
TECO COALBED METHANE
TECO Coalbed Methane participates in the production of natural
gas from coalbeds located in Alabama's Black Warrior Basin. TECO
Coalbed Methane has invested $210 million as the principal investor in
three ventures which control, in the aggregate, approximately 100,000
acres of lease holdings. At the end of 1998, TECO Coalbed Methane had
interests in 734 wells that were operational and producing gas for
sale. These wells are operated by Energen Resources, a unit of Energen
Corporation, and, to a much lesser extent, by other third-party
operators.
A non-conventional fuel tax credit is available on all production
through the year 2002. The tax credit escalates with inflation and
could be limited based upon domestic oil prices. In 1998, domestic oil
prices would have had to exceed $49 per barrel for this limitation to
have been effective.
All production from these wells is committed for the life of the
reserves based on spot prices which are tied to the price of onshore
Louisiana gas.
TECO Coalbed Methane s operations are subject to federal, state
and local regulations for air emissions and water and waste disposal.
It believes its operations are in substantial compliance with all
applicable environmental laws and regulations.
PEOPLES GAS COMPANY
P e o p les Gas Company (PGC) is engaged in the purchase,
distribution and marketing of propane gas for residential, commercial,
and industrial customers in the State of Florida. It possesses no
production facilities but purchases propane gas from major national
suppliers. In 1998, PGC had 54,500 customers and sold 31 million
gallons of propane.
18
In 1998, PGC acquired three additional Florida propane gas
businesses. These acquisitions facilitated growth of PGC's existing
market in Jacksonville, and its expansion into new markets in
Gainesville, Ocala, Fort Myers and Naples.
Propane gas has historically been used in many residential,
industrial and commercial operations throughout Florida, including
production of durable products such as steel, glass, ceramic tile and
food products.
Propane is purchased under short-term contracts which enables PGC
to make purchases at prevailing market prices. During 1997, PGC
entered into options contracts to limit the exposure to propane price
increases; these contracts expired in early 1998, and PGC did not
enter into any additional options contracts. PGC may employ similar or
other price management strategies in the future.
PGC purchases propane from a small number of major national
suppliers. The company has storage capacity in excess of one million
gallons, mostly in South and Central Florida. Delivery of propane
product to PGC storage facilities is primarily via rail cars and
tanker trucks. PGC owns rail cars and tanker trucks used throughout
the northern and northeastern markets in Florida. Propane is delivered
to PGC's storage facilities throughout the central and southeastern
parts of the State by trucks and railcars controlled by a major
propane supplier.
The majority of PGC s propane is delivered into tanks and
containers on the customer's premises via bulk delivery trucks.
Propane block systems are also an integral part of the company's
propane distribution operations in the residential market. Large
industrial and commercial customers often take delivery in tanker
trucks directly from the supply terminals.
In the Florida propane market, there are over 30 distributors
competing within the residential and commercial markets. Competition
in Florida ranges from a number of large, national companies to
numerous local, independent operators. The primary focus among
distributors is to gain market share through new customer growth
(i.e., providing service for home construction). PGC, presently the
largest independent propane distributor in Florida, expects to
increase its customers and volumes through increased marketing
activity and acquisitions. Propane competes directly with natural gas,
electricity and fuel oil, and its marketing areas are not limited by a
pipeline infrastructure.
TECO GAS SERVICES
TECO Gas Services (formerly Gator Gas Marketing) provides gas
management and marketing services for large industrial customers. In
1998, it provided gas management for three cogeneration facilities.
TECO Gas Services owns no operating assets.
TeCom
TeCom is marketing advanced energy management, automation and
control systems for commercial and residential applications, named the
InterLane systems. Several utilities and end-use operators have
purchased products from TeCom to demonstrate, test and use the
InterLane systems.
Because of a continued high level of product enhancement
activity, TeCom capitalized $6.8 million pretax of product development
costs in 1998, $6.5 million in 1997 and $4.9 million in 1996. In 1998,
19
TeCom wrote off certain product development costs associated with
InterLane residential system features developed early in the product
life and no longer incorporated in the current system's design.
Capitalized costs related to the commercial product and other common
costs began to be amortized in late 1998 as its commercial product
became available for general distribution. TeCom had 46 employees at
Dec. 31, 1998.
BOSEK, GIBSON AND ASSOCIATES
BGA is an engineering energy services company headquartered in
Tampa. It has 9 offices in Florida and two in California, and had 119
employees as of Dec. 31, 1998.
It provides engineering, construction management and energy
services to more than 300 customers, including public schools,
universities, health care facilities and other governmental facilities
throughout Florida and California.
Item 2. PROPERTIES.
TECO Energy believes that the physical properties of its
operating companies are adequate to carry on their businesses as
currently conducted. The properties of Tampa Electric and the
subsidiaries of TECO Power Services are generally subject to liens
securing long-term debt.
TAMPA ELECTRIC
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 Station 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
20
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.
PEOPLES GAS SYSTEM
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.
TECO TRANSPORT
Electro-Coal's storage and transfer terminal is on a 1,070-acre
site fronting on the Mississippi River, approximately 40 miles south
of New Orleans. Electro-Coal owns 342 of these acres in fee, with the
remainder held under long-term leases.
Mid-South operates a fleet of 18 towboats and over 710 river
barges, most of which it owns, on the Mississippi, Ohio and Illinois
rivers. This includes three towboats and 110 covered river barges
chartered in March 1998 under a five-year agreement which provides for
the acquisition of these assets at the conclusion of the charter term.
Mid-South owns 15 acres of land fronting on the Ohio River at
Metropolis, Illinois on which its operating offices, warehouse and
repair facilities are located. Fleeting and repair services for its
barges and those of other barge lines are performed at this location.
Additionally, Mid-South performs fleeting and supply activities at
leased facilities in Cairo, Illinois.
Gulfcoast owns and operates a fleet of 12 ocean-going tug/barge
units, a 30,000 ton ocean-going ship and a 40,000 ton ocean-going
ship, with a combined cargo capacity of over 413,000 tons.
TECO COAL
TECO Coal, through its subsidiaries, controls over 100,000 acres
of coal reserves and mining property in Kentucky and Tennessee.
Pike-Letcher controls in excess of 50,000 acres in Pike and
Letcher Counties, Kentucky. These properties contain estimated proven
and probable reserves in excess of 110 million tons.
Premier owns and operates a preparation plant and unit-train
loadout facility in Pike County, Kentucky and conducts surface and
deep mining operations of reserves which are leased from Pike-Letcher.
Premier does not own any coal reserves.
Clintwood has 32,000 acres of coal reserves held under long-term
leases in Pike County, Kentucky. These properties contain estimated
proven and probable reserves in excess of 25 million tons. Clintwood
21
owns and operates a rail tipple and a coal preparation plant near the
mines.
Gatliff has 39,000 acres of coal reserves and mining property in
Knox and Whitley Counties, Kentucky and Campbell County, Tennessee.
Gatliff owns 9,300 acres in fee and leases 29,700 acres under
long-term leases. These properties contain estimated proven and
probable coal reserves in excess of 10 million tons. This coal, which
combines low-sulfur and low-ash fusion temperature characteristics, is
found in both deep and surface mines. Gatliff owns and operates a
rapid-loading rail tipple and a coal preparation plant near its deep
mines. In 1996, TECO Coal closed certain of its older Gatliff mines.
Rich Mountain operates a surface mine for Gatliff in Campbell
County, Tennessee, and does not own any coal reserves.
TECO POWER SERVICES
Hardee Power has a lease for approximately 1,300 acres of land in
Hardee and Polk Counties, Florida on which the Hardee Power Station is
located. The lease has a term that runs through 2012 with options to
extend the term for up to an additional 20 years.
In addition, a TECO Power Services' subsidiary has a 96.06-
percent interest in TCAE, which owns 7 acres in Guatemala on which the
Alborada Power Station is located. Another TECO Power Services
subsidiary has a 46-percent ownership in a project entity, CGESJ,
which owns 190 acres in Guatemala on which the San Jose Power Station
is being built.
TECO COALBED METHANE
TECO Coalbed Methane's interest in proved gas reserves at Dec.
31, 1998 was independently estimated to be 162 billion cubic feet for
655 wells.
TECO Coalbed Methane's gas production for 1998 was 17.6 billion
cubic feet.
PEOPLES GAS COMPANY
PGC's operating divisions are located in 21 markets throughout
the state; most of its facilities are leased.
Item 3. LEGAL PROCEEDINGS.
None.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matter was submitted during the fourth quarter of 1998 to a
vote of TECO Energy's security holders, through the solicitation of
proxies or otherwise.
22
EXECUTIVE OFFICERS OF THE REGISTRANT
Information concerning the current executive officers of TECO Energy
is as follows:
Current Positions and Principal
Name Age Occupations During Last Five Years
Girard F. Anderson 67 Chairman of the Board, President and
Chief Executive Officer, February
1998 to date; President and Chief
Executive Officer, November 1997 to
February 1998; President and Chief
Operating Officer, July 1994 to
November 1997; and prior thereto,
Executive Vice President-Utility
Operations and President and Chief
Operating Officer of Tampa Electric
Company.
Alan D. Oak 52 Executive Vice President and Chief
Operating Officer, November 1997 to
date; Senior Vice President-Finance
and Chief Financial Officer, April
1995 to November 1997; and prior
t h ereto, Senior Vice President-
F i nance, Treasurer and Chief
Financial Officer.
Roger H. Kessel 62 Executive Vice President, January
1 9 9 9 to date; Senior Vice
President-Legal and Regulatory
Affairs and General Counsel, July
1998 to January 1999; Senior Vice
President-General Counsel and
Secretary, April 1995 to July 1998;
a n d prior thereto, Vice
President-General Counsel and
Secretary.
William N. Cantrell 46 President-Peoples Gas Companies,
June 1997 to date; Director of
Peoples Gas Transition Team, January
1997 to June 1997; Vice President-
Energy Supply of Tampa Electric
Company, April 1995 to January 1997;
and prior thereto, Vice President-
Energy Resources Planning of Tampa
Electric Company.
Roger A. Dunn 56 Vice President-Human Resources, July
1995 to date; and prior thereto,
S e n ior Vice President-Human
Resources and Corporate Affairs of
L T V C o r p oration (steel
manufacturer), Cleveland, Ohio.
Royston K. Eustace 57 Senior Vice President-Business
Development, April 1998 to date; and
prior thereto, Vice President-
S t rategic Planning and Business
Development.
23
Current Positions and Principal
Name Age Occupations During Last Five Years
Gordon L. Gillette 39 Vice President-Finance and Chief
Financial Officer, April 1998 to
date; Vice President-Regulatory
Affairs, April 1997 to April 1998;
Vice President-Regulatory and
Business Strategy of Tampa Electric
Company, April 1996 to April 1997;
Vice President-Regulatory Affairs of
Tampa Electric Company, January 1995
to April 1996; and prior thereto,
Director-Project Services of TECO
Power Services Corporation.
Sheila M. McDevitt 52 Vice President-General Counsel,
January 1999 to date; and prior
thereto, Vice President-Assistant
General Counsel.
John B. Ramil 43 President of Tampa Electric Company,
April 1998 to date; Vice President-
Finance and Chief Financial Officer,
November 1997 to April 1998; Vice
President-Energy Services and
Planning of Tampa Electric Company,
November 1994 to November 1997; Vice
President-Energy Services and Bulk
Power of Tampa Electric Company,
April 1994 to November 1994; and
prior thereto, Director-Resource
Planning of Tampa Electric Company.
There is no family relationship between any of the persons named
above. The term of office of each officer extends to the meeting of
t h e Board of Directors following the next annual meeting of
shareholders, scheduled to be held on April 21, 1999, and until his
successor is elected and qualified.
24
PART II
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS.
The following table shows the high, low and closing sale prices
for shares of TECO Energy common stock, which is listed on the New
York Stock Exchange, and dividends paid per share, per quarter.
1st 2nd 3rd 4th
1998
High $28 1/2 $28 5/16 $28 7/8 $30 5/8
Low $25 9/16 $25 3/16 $24 3/4 $26 3/4
Close $28 1/4 $26 13/16 $28 9/16 $28 3/16
Dividend $.295 $.31 $.31 $.31
1997
High $25 1/8 $25 5/8 $25 7/8 $28 3/16
Low $23 3/4 $23 3/4 $23 7/8 $22 3/4
Close $24 $25 9/16 $24 1/2 $28 1/8
Dividend $.28 $.295 $.295 $.295
___________________
The approximate number of shareholders of record of common stock
of TECO Energy as of Feb. 28, 1999 was 26,884.
TECO Energy's primary source of funds is dividends from its
operating companies. Tampa Electric's first mortgage bonds and certain
long-term debt issues at Peoples Gas System contain provisions that
limit the payment of dividends on the common stock of Tampa Electric
Company. Substantially all of Tampa Electric Company's retained
earnings were available for dividends throughout 1998.
25
Item 6. SELECTED FINANCIAL DATA.
Year ended Dec. 31, 1998 1997 1996 1995 1994
(millions, except per share amounts)
Revenues (1) $1,958.1 $1,862.3 $1,775.3 $ 1,658.9 $1,615.4
Net income:
From continuing operations $ 200.4(2) $ 211.4(3) $ 217.4 $ 200.8 $ 163.8(4)
From discontinued operations -- (6.5) (0.9) (0.5) --
Disposal of discontinued
operations 6.1 (3.0) -- -- --
Net income $ 206.5 $ 201.9 $ 216.5 $ 200.3 $ 163.8
Total assets $4,179.3 $3,960.4 $3,901.6 $3,801.0 $3,622.6
Long-term debt $1,279.6 $1,080.2 $1,118.0 $1,126.4 $1,156.3
Earnings per average share (EPS)
outstanding -- basic:
From continuing operations $ 1.52(2) $ 1.62(3) $ 1.68 $ 1.56 $ 1.28(4)
From discontinued operations -- (0.05) (0.01) -- --
Disposal of discontinued
operations .05 (0.03) -- -- --
Earnings per average common
share outstanding -- basic $ 1.57 $ 1.54 $ 1.67 $ 1.56 $ 1.28
Common dividends paid per
common share (5) $ 1.225 $ 1.165 $ 1.105 $ 1.0475 $ .9975
_________________
(1) Amounts shown in 1998, 1997, 1996 and 1995 include the impact of
d e f erred revenues, as discussed on pages 43 and 44 of
Management's Discussion and Analysis.
(2) Includes the effect of one-time non-recurring charges, which
reduced net income by $21.3 million and earnings per share by
$0.16 in 1998 as discussed on page 27 of Management's Discussion
and Analysis.
(3) Includes the effect of one-time merger-related transaction
expenses, which reduced net income by $5.3 million and earnings
per share by $0.04 in 1997 as discussed on page 27 of
Management's Discussion and Analysis.
(4) Includes the effect of a corporate restructuring charge which
reduced net income by $15 million and earnings per share by $0.12
in 1994.
(5) Amounts shown are the actual dividends paid per share (and have
not been restated to reflect the shares issued in connection with
the Peoples companies merger).
26
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.
The Management's Discussion and Analysis which follows contains
f o r ward-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 are set forth in
the Investment Considerations section.
EARNINGS SUMMARY:
All prior year amounts have been restated to reflect the 1997 merger
with the Peoples Gas companies and to exclude the discontinued
operations of TECO Oil & Gas, which are now separately presented.
TECO Energy reported basic earnings from continuing operations of
$1.52 per share in 1998 compared to $1.62 per share in 1997. Earnings
from continuing operations in 1998, excluding the impact of $.16 per
share in one-time charges, totaled $1.68 per share. Earnings from
continuing operations in 1997, excluding $.04 per share in one-time
merger related charges, were $1.66 per share. Earnings, including a
net gain of $.05 per share from discontinued oil and gas operations,
were $1.57 per share in 1998. This compares with earnings of $1.54 per
share in 1997, which included losses from discontinued oil and gas
operations of $.08 per share.
One-time charges in 1998 reflect asset value adjustments at TECO
Coal's Gatliff mining facilities relating to the expiration of the
coal supply contract with Tampa Electric in 1999 (described in the
TECO Coal section), a write off of product development costs
associated with InterLane residential system features developed early
in the product life and no longer incorporated in the current system's
design at TeCom (described in the TeCom section), a charge at Tampa
Electric associated with ongoing actions to mitigate the effects of a
1997 Florida Public Service Commission (FPSC) ruling that separated
two wholesale power sales contracts from the retail jurisdiction
through 1999, and a charge at Tampa Electric resulting from a 1998
r e g ulatory ruling denying recovery of coal expenses over an
established benchmark for coal purchases from Gatliff since 1992
(described in the Tampa Electric section).
Results in 1997 reflected one-time costs from the Peoples Gas
companies merger and an FPSC decision, described in the Tampa Electric
section, to change the regulatory treatment of two wholesale power
sales contracts. These items more than offset earnings growth from the
diversified businesses.
1998 Change 1997 Change 1996
Earnings Per Share - basic
Continuing operations $ 1.52 -6.2% $ 1.62 -3.6% $ 1.68
Discontinued operations .05 -- (.08) -- (.01)
Earnings per share $ 1.57 1.9% $ 1.54 -7.8% $ 1.67
Earnings Per Share - diluted
Continuing operations $ 1.52 -5.6% $ 1.61 -3.6% $ 1.67
Discontinued operations .05 -- (.07) -- --
Earnings per share $ 1.57 1.9% $ 1.54 -7.8% $ 1.67
27
Earnings Per Share by Operating Group
From Continuing Operations - basic
Regulated companies
Tampa Electric $ 1.07(1) 3.9% $ 1.03 -4.6% $ 1.08
Peoples Gas System .12 9.1% .11(2) -- .11
Diversified companies
/other .49(3) -5.8% .52(3) 6.1% .49
1.68 1.2% 1.66 -1.2% 1.68
One-time charges
Wholesale contract
-Tampa Electric (.04) -- -- -- --
Coal quality
-Tampa Electric (.03) -- -- -- --
Asset adjustment
-TECO Coal (.07) -- -- -- --
Asset adjustment
-TeCom (.01) -- -- -- --
Merger related costs (.01) -- (.04) -- --
Earnings per share from
continuing operations $ 1.52 -6.2% $ 1.62 -3.6% $ 1.68
Net Income from continuing
operations (millions)(4) $200.4 -5.2% $211.4 -2.8% $217.4
Average common shares
outstanding
Basic (millions) 131.7 .7% 130.8 1.2% 129.3
Diluted (millions) 132.2 .8% 131.2 1.1% 129.8
Return on average common equity from continuing operations
After one-time charges 13.0% 14.3% 15.6%
Before one-time charges 14.4% 14.6% 15.6%
(1) Excludes one-time charges totaling $.07 per share.
(2) Excludes one-time merger related charges of $.01 per share.
(3) Excludes asset adjustments of $.08 per share in 1998 and one-time
merger related charges of $.01 per share in 1998 and $.03 per
share in 1997.
(4) Includes one-time charges.
OPERATING RESULTS:
TECO Energy's Operating Results
Operating income, excluding $25.9 million in one-time pretax
charges, grew 2.1 percent in 1998. Tampa Electric and Peoples Gas
contributed to the increase, 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. TECO Coal
and TECO Transport also achieved higher operating income, while TECO
Power Services and TECO Coalbed Methane were lower.
Operating income in 1997 reflected the recognition of $30.5
million of previously deferred revenues at Tampa Electric, the
inclusion of Polk Unit One in rate base for earnings purposes and
strong performance by the diversified companies, particularly TECO
Transport. In 1996, Tampa Electric deferred $34.2 million of revenues
under agreements approved by the FPSC. See Utility Regulation - Rate
Stabilization Strategy section.
28
The following table identifies the unconsolidated revenues and
operating income from continuing operations, excluding one-time
charges, of the significant business segments. For additional detail,
refer to the Notes to Consolidated Financial Statements - Footnote K,
Segment Information.
Contributions by Operating Group (unconsolidated)
(millions) 1998 Change 1997 Change 1996
Revenues
Tampa Electric(1) $1,234.6 3.8% $1,189.2 6.9% $1,112.9
Peoples Gas System 252.8 1.3% 249.6 -3.5% 258.7
Diversified companies(2)
TECO Transport 230.0 5.2% 218.7 5.4% 207.5
TECO Coal 232.4 7.8% 215.6 3.9% 207.5
TECO Power Services 98.7 6.1% 93.0 5.6% 88.1
Other diversified
businesses 113.0 7.4% 105.2 2.2% 102.9
Operating income
Tampa Electric $ 279.7(4) 3.0% $ 271.5 11.3% $ 244.0
Peoples Gas System 35.8 6.5% 33.6 5.0% 32.0
Diversified companies(2)(3)
TECO Transport 43.2 2.6% 42.1 8.2% 38.9
TECO Coal 23.5(5) 18.1% 19.9 8.7% 18.3
TECO Power Services 13.0 -14.5% 15.2 -9.0% 16.7
Other diversified
businesses 34.7(6) -8.4% 37.9 -5.0% 39.9
(1) Includes the recognition of previously deferred revenues totaling
$38.3 million and $30.5 million in 1998 and 1997, respectively.
1996 revenues are net of $34.2 million deferred under agreements
described in the Utility Regulation - Rate Stabilization Strategy
section.
(2) From continuing operations.
(3) Includes items which were reclassified for consolidated financial
statement purposes. The principal items are the non-conventional
fuels tax credit related to coalbed methane production and
interest expense on the limited-recourse debt related to the
independent power operations. In the Consolidated Statements of
Income, the tax credit is part of the provision for income taxes
and the interest is part of interest expense. Certain amounts
have been restated to conform to current year presentation.
(4) Excludes one-time, pretax charge of $9.6 million for treatment of
a wholesale contract.
(5) Excludes one-time, pretax charge of $13.6 million for asset
valuation adjustments.
(6) Excludes one-time, pretax charge of $2.7 million for TeCom.
Tampa Electric - Electric Operations
Tampa Electric's Operating Results
Tampa Electric's 1998 operating income, before one-time charges,
increased three 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.
29
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 954.9(2) 4.1% 917.7 5.6% 868.9
Operating income $ 279.7 3.0% $ 271.5 11.3% $ 244.0
(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.
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. This decline could accelerate if
customers within the phosphate customer group decide to pursue new
self-generation projects. Revenues from the phosphate customer group
represented slightly more than 3 percent of base revenues in 1998.
Based on expected growth reflecting both population and business
activity increases, Tampa Electric projects retail energy sales growth
of approximately 2.5 percent annually over the next five years, with
combined energy sales growth in the residential and commercial sectors
of almost 3 percent annually. Energy sales to non-phosphate industrial
customers are expected to grow almost 2 percent annually over the next
five years.
All of these growth projections assume continued local area
economic growth, normal weather and other factors. See the Investment
Considerations section.
30
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 $.05 per
share. The company terminated one contract and incurred a charge of
$.04 per share 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 2.1% 2,466 7.0% 2,304
Other 1,284 5.1% 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
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. Based on maintenance
activity in 1998, non-fuel operations and maintenance expenses in 1999
are expected to be lower than 1998, then increase at approximately the
rate of inflation over the next several years.
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.
31
Operating Expenses
(millions) 1998 Change 1997 Change 1996
Other operating expenses $165.7 .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, other than income 97.2 5.9% 91.8 5.5% 87.0
Operating expenses 503.6 5.7% 476.5 9.1% 436.8
Fuel 366.6 -1.8% 373.4 -2.5% 383.1
Purchased power 84.7 25.1% 67.8 38.4% 49.0
Total fuel expense 451.3 2.3% 441.2 2.1% 432.1
Total operating expenses $954.9 4.1% $917.7 5.6% $868.9
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.
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.
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, and the fuel mix is expected to continue to be
substantially coal.
External forecasts indicate relatively stable coal prices for the
next few years compared to oil or gas prices. 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
Peoples Gas System (PGS) achieved operating income growth in
excess of 6 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 5 percent in 1997 over 1996, reflecting
32
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% $249.6 -3.5% $258.7
Cost of gas sold 115.4 -3.5% 119.6 -8.1% 130.1
Operating expenses 101.6 5.4% 96.4 -.2% 96.6
Operating income $ 35.8 6.5% $ 33.6 5.0% $ 32.0
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.
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 is the largest investor-owned gas distribution utility in
Florida, with about 70 percent of the market. It serves almost 240,000
33
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.
PGS expects savings from the discontinuance of its appliance
sales and service business and will continue making cost control
improvements. PGS began partnering with companies in an established
dealer network to provide sales, installation and repair services to
customers.
PGS expects increases in sales volumes and corresponding revenues
in 1999 and, beginning in late 1999, customer additions and related
revenues will begin to reflect the Southwest Florida expansion.
All of these growth projections assume continued local area
economic growth, normal weather and other factors. See the Investment
Considerations section.
TECO Transport
TECO Transport recorded slightly higher operating income in 1998,
primarily from utilizing added equipment on the river system, a full
year's operation of the ocean vessel acquired in late 1997, increased
northbound shipments on the river, lower fuel costs and continued
initiatives to control operating expenses. Depreciation expense
decreased, reflecting longer estimated economic lives of certain
assets. Improvements were partially offset by a number of factors,
including unprecedented extreme weather in the early part of the year
and hurricanes later in the year, which created delays and difficult
operating conditions in each of the transportation businesses. The
Asian economic situation and the strong U. S. dollar also affected
TECO Transport, resulting in lower prices and export volumes.
In 1997, TECO Transport achieved higher operating income due to
increased Tampa Electric volumes at the transfer terminal to replenish
coal inventories depleted in 1996 and increased operating efficiencies
in each of the operating companies. The ocean-going business also
benefited from a full year of operations from a vessel added in 1996
and increased grain charter business. The river business was impacted
by adverse weather conditions early in 1997. This was partially offset
by increased northbound business and higher volumes handled for Tampa
Electric.
In 1998, TECO Transport expanded its river fleet by about 20
percent, adding 110 barges and three towboats.
I n 1999, TECO Transport expects increased transfers and
additional northbound river shipments of steel and steel-related
products as a result of steel mini-mills built along the river system.
Also in 1999, revenue improvement is expected from the continued
strong domestic demand for coal and phosphate products. In addition,
the company will continue to diversify into new markets and cargoes.
Significant factors that will influence results are weather, commodity
grain prices and domestic and international economic conditions. See
34
the Investment Considerations section.
TECO Coal
TECO Coal's operating income, excluding the one-time adjustment
to asset values discussed below, increased 18 percent in 1998 due to
continued growth in sales to the metallurgical and steam markets,
lower unit costs at its Gatliff and Clintwood Elkhorn facilities and
improved preparation plant performance at its Clintwood Elkhorn
facility.
In 1997, operating income increased 9 percent due to increased
shipments of specialty coals to third parties from the new facilities
at Clintwood Elkhorn. The growth in third-party steam coal sales and a
slight improvement in prices for coal from the Premier mines more than
offset higher production costs at Premier and lower shipments to Tampa
Electric.
Coal sales increased to 6.8 million tons in 1998, compared with
6.1 million tons in 1997 and 5.9 million tons in 1996. Volumes in 1999
are expected to approach 7 million tons.
Tampa Electric shipments represented slightly more than 10
percent of total volumes in 1998 and 16 percent in 1997. Shipments to
Tampa Electric of 750,000 tons declined by about 250,000 tons, or
about 25 percent, in 1998 after a similar decline in 1997. Tampa
Electric's volume in 1999 is expected to be 500,000 tons. Success in
burning more conventional and lower-cost steam coals has enabled Tampa
Electric to adopt a competitive strategy of phasing down coal
shipments from TECO Coal for the last several years. The contract with
Tampa Electric expires at the end of 1999 and will not be renewed.
In 1998, TECO Coal recorded a one-time pretax charge of $13.6
million to adjust the value of certain mining facilities. The majority
of this charge reflects a revaluation of assets at TECO Coal's Gatliff
mine dedicated to the Tampa Electric contract. Because of the
anticipated loss in value of this facility at the end of the Tampa
Electric contract, an adjustment was required to reduce the carrying
value of the assets. The $13.6 million charge also reflected
adjustments for other assets which have decreased in market value,
reflecting limited markets that exist for the coal from these
facilities due to the specific characteristics of the product and high
mining costs.
In September 1996, TECO Coal acquired 25 million tons of
metallurgical grade coal reserves contiguous to its existing Clintwood
Elkhorn operation and constructed a new preparation plant at this
location. This facility, which supports an additional one million tons
of annual production, went in service in mid-1997. Metallurgical coal
has unique characteristics and is sold primarily to the steel industry
both domestically and internationally. Sales to this market increased
in 1998 and are expected to increase in 1999. See the Investment
Considerations section.
TECO Power Services
TECO Power Services (TPS) recorded slightly lower operating
income in 1998 and 1997, primarily as a result of a significant
increase in business development activity in 1998 and increased
interest expense associated with the $29-million limited-recourse
project financing in 1997 for the Alborada Power Station in Guatemala.
Although operating income was below 1997, net income was slightly
above last year, reflecting lower taxes in Guatemala.
TPS accomplished a number of long-term initiatives during 1998,
including participation in a consortium which purchased 80 percent of
35
EEGSA, Guatemala's largest electric distribution company and also the
largest in Central America. TPS owns a 30 percent interest in this
consortium and contributed $100 million in equity. The total purchase
price paid by the consortium was $520 million.
TPS also entered into a joint venture arrangement with Mosbacher
Power Group Partners in 1998. Through this affiliation, it is
currently participating in one generation project and is working on
the development of others. TPS provides capital, technical experience,
support for development costs and other business strengths. In return,
TPS gains an expanded domestic and international presence with
opportunities for project returns, including preferred returns before
benefits are shared.
In February 1999, TPS formed a joint venture relationship with
Energia Global International, Ltd. (EGI), a Bermuda-based energy
development firm. The transaction provides TPS with an immediate stake
in four power projects in operation or under construction in Costa
Rica and Guatemala, and electric distribution companies in El Salvador
and Panama. TPS has initially committed $25 million in the form of a
loan, and may provide an additional $9 million for new projects or
acquisitions. The transaction provides a mechanism for TPS to acquire
direct ownership in EGI without additional funding.
TPS has a 46 percent interest in a partnership to build, own and
operate a 120-megawatt pulverized coal-fired power plant, the San Jose
Power Station in Guatemala. The other partners are The Coastal
Corporation and the same local partner it has for the Alborada Power
Station. The partnership has a 15-year power supply agreement with
EEGSA, the same Guatemalan distribution utility in which TPS purchased
an equity interest in 1998. The $181-million San Jose Power Station is
under construction and was 56 percent complete as of the end of 1998.
The partnership closed on financing for the project in September 1998,
and commercial operation is expected in early 2000.
TPS expects to double its earnings contribution from identified
domestic and international generation projects over the next two to
three years.
TECO Power Services' domestic project, the Hardee Power Station
in West Central Florida, continues to operate reliably, supplying
power to Seminole Electric Cooperative and Tampa Electric. The
Alborada Power Station in Guatemala also continues to operate
reliably, achieving its highest annual capacity factor in 1998. See
the Investment Considerations section.
Other Diversified Companies
TECO Coalbed Methane's operating income declined 12 percent in
1998, because of declines in production and lower gas prices that were
only partially offset by reduced operating costs and an effective
hedging program. Production declined to 17.6 billion cubic feet (Bcf)
in 1998, from 19.2 Bcf in 1997. Effective gas prices averaged $.15 per
thousand cubic feet (Mcf) below 1997, including the favorable results
of hedging, which resulted in an additional $.25 per Mcf. Proven
reserves were estimated at 162 Bcf as of year-end, compared to 195 Bcf
in 1997.
In 1997, operating income increased more than 2 percent as lower
per unit operating costs more than offset a production decline to 19.2
Bcf from 19.8 Bcf in 1996. Production is expected to decline
approximately 9 percent in 1999.
Production from TECO Coalbed Methane's reserves are eligible for
non-conventional fuels tax credits under Section 29 of the Internal
Revenue Code through the year 2002. The credit, which grows with
inflation, was $1.07 per Mcf in 1998, compared to $1.05 per Mcf in
36
1997. The credit is estimated to be $1.07 per Mcf in 1999.
All gas produced is sold under contract at spot market prices for
the life of the reserves. Although natural gas prices can be volatile,
the Section 29 tax credits provide stability to TECO Coalbed Methane's
operating results. See the Investment Considerations section.
Peoples Gas Company (PGC), the unregulated propane gas business
acquired in the 1997 Peoples Gas companies merger, is the largest
independent propane distributor in Florida.
In January 1998, TECO Energy acquired Griffis Gas, Inc. in a
stock-for-stock merger transaction that was accounted for as a pooling
of interests. About 600,000 shares of TECO Energy common stock were
issued in the transaction. This acquisition facilitated growth of the
company's existing market in the Jacksonville area and expansion into
new markets in Gainesville and Ocala. Prior-year financial results
were not restated for the effects of this merger due to its size.
P G C ' s operating income increased significantly in 1998,
reflecting higher volumes resulting from the acquisition of Griffis
Gas and two other propane businesses, which increased its customer
base by 40 percent. Operating results were also favorably impacted by
improved margins throughout the year. Reflecting the impact of the
acquisitions, operating expenses were higher in 1998, which partially
offset the volume growth and improved margins.
The company ended 1998 with approximately 55,000 customers and
sales of 31 million gallons of propane, compared with 37,000 customers
and 22 million gallons in 1997. PGC expects to continue its growth
initiatives throughout 1999, through acquisitions and expansion of
existing markets. See the Investment Considerations section.
TECO Gas Services (formerly Gator Gas Marketing) is another
unregulated business acquired in the Peoples Gas companies merger. The
company provides gas management and marketing services for large
municipal, industrial and power generation customers. In 1998, the
company focused on increasing its customer base while continuing to
p r o vide gas management services for three large cogeneration
facilities.
TeCom is marketing advanced energy management, automation and
control systems for residential and commercial applications, named the
InterLane Home Manager and the InterLane Power Manager, respectively.
T e Com continued to capitalize development costs in 1998,
reflecting continued product development and enhancement activity.
Total costs capitalized in 1998 were $6.8 million, compared with $6.5
million in 1997. In accordance with accepted accounting practices, the
company began amortizing capitalized costs in 1998 in conjunction with
commercial product availability. A total of $.8 million was amortized
in 1998. In addition, a one-time after-tax charge of $1.7 million was
recorded in 1998, reflecting the write off of product development
costs associated with InterLane residential system features developed
early in the product life and no longer incorporated in the current
system s design. Total capitalized costs as of Dec. 31, 1998 were
$14.7 million.
The completion of a significant product development phase has
enabled the company to reduce expenditures by almost one half as it
continues strategic, marketing and distribution activities.
Bosek, Gibson and Associates, Inc. (BGA), an energy services
company headquartered in Tampa with nine offices throughout Florida
and two in California, was acquired by TECO Energy in November 1996.
It provides design, engineering and construction services to more than
300 customers, including public schools, universities, health care
facilities and other governmental facilities throughout Florida and
California.
D u r ing the year, BGA expanded its offerings to include
37
performance contracting for a number of county school districts, as
well as the Florida State Department of Corrections, and it completed
a district cooling project in Tampa. In addition, BGA continued work
begun in 1997 for the Jacksonville Naval Air Station and the Suncoast
District of the United States Postal Service.
Discontinued Operations
In August 1997, TECO Energy announced its intent to exit the
conventional oil and gas exploration and production business because
of its small scale of operations and earnings volatility.
F o r 1997, TECO Energy reported an after-tax loss from
discontinued operations of $9.5 million which included the net
operating results for the year and also included the write off of
three offshore wells that ceased production.
In January 1998, TECO Energy announced that it had entered into
an agreement to sell the offshore assets of TECO Oil & Gas to American
Resources Offshore, Inc. (ARO). In March 1998, TECO Oil & Gas closed
this sale for $57.7 million, consisting of $39.2 million in cash and a
subordinated note in the principal amount of $18.5 million.
Based on the likely impact of certain economic factors, including
low oil and gas prices and unfavorable business and operational
developments at ARO, TECO Energy has written off the recorded value of
all assets associated with the discontinued oil and gas operation,
including the $18.5-million note and associated interest income
accrued and remaining on-shore assets. The after-tax gain net of
charges from discontinued operations in 1998 was $6.1 million, or
approximately 5 cents per share.
In March 1999, the company completed a transaction in which it
sold the note from ARO in return for $500,000 in cash. The company
also sold an option relating to its ARO warrants; in the event such
option is exercised, the company will receive the exercise price of
$600,000. In a separate transaction, ARO agreed to be responsible for
disputed joint billing payments of approximately $425,000. As part of
this settlement, ARO also conveyed to the company an overriding
royalty interest in two offshore Gulf of Mexico blocks. The company
does not expect any future royalty payments to be significant.
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 TECO Energy'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 and
coal mining facilities).
TECO Energy 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. The project
addresses readiness at Tampa Electric, Peoples Gas System and the
diversified companies.
Readiness
TECO Energy has completed its assessment of all hardware,
software and embedded systems and is currently engaged in renovation,
38
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. Ninety-five
percent of the renovations to the critical business systems have been
made, which represents 70 percent of the work required to achieve Year
2000 readiness for this part of the project. To assist in assuring
readiness, the renovation work and the integration testing are being
handled by separate outside firms.
Control Systems
Tampa Electric 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.
Tampa Electric 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. Ninety percent of these renovations have been made, which
represents an estimated 80 percent of the work required to achieve
Year 2000 readiness for this part of the project. 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) in
the other parts of TECO Energy have been renovated, with the exception
of a portion of the Peoples Gas System and the Hardee Power Station
control systems and a portion of the TECO Coal plant control systems,
which are scheduled to be fully renovated and tested in the first half
of 1999. Sixty percent of these renovations have been made, which
represents an estimated 40 percent of the work required to achieve
Year 2000 readiness for this part of the project.
Coordination with Others
TECO Energy 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.
39
Costs
The total cost of Year 2000 remediation is expected to be $8 to
$10 million, which includes contracted resources, purchases and
internal labor. An estimated breakdown of project costs is as follows:
Tampa Electric - $6 million, Peoples Gas System - $2.5 million, and
the diversified companies - $.5 million. Approximately 40 percent of
the projected costs are attributable to testing expenses, and the
remainder consists primarily of renovation 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
TECO Energy believes the most reasonably likely worst case
scenario would be the occurrence of isolated outages of limited
duration for utility customers, similar to those occurring during the
utilities' storm season. 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
TECO Energy'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 TECO Energy'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
a s s u mptions 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.
40
Interest Charges
Interest charges were $104.3 million, down slightly from $105.8
million in 1997. Lower interest on a declining deferred revenue
balance at Tampa Electric and lower short-term rates were partially
offset by higher borrowing levels for new TECO Power Services
initiatives and for interest on a capital lease of river barges in
1998.
Interest charges were up 7 percent in 1997, reflecting lower
AFUDC on borrowed funds at Tampa Electric.
Income Taxes
Income tax expense decreased in 1998 as pretax income was reduced
by $25.9 million of non-recurring charges. In 1997, income taxes were
higher than in 1996, reflecting higher pretax income and the effect of
lower AFUDC on equity funds at Tampa Electric. Income tax expense as a
percent of income from continuing operations before taxes was 29
percent in 1998, 31 percent in 1997 and 27 percent in 1996.
Total income tax expense was reduced by the federal tax credit
related to the production of coalbed methane. This tax credit totaled
$18.9 million in 1998, $20.2 million in 1997, and $19.6 million in
1996. The tax credit was $1.07 per Mcf in 1998, up from $1.05 in 1997.
This rate escalates with inflation and could be limited by domestic
oil prices. In 1998, domestic oil prices would have had to exceed $49
per barrel for this limitation to have been effective. The federal tax
credit on production of coalbed methane is available through the year
2002.
The income tax effect of gains and losses from discontinued
operations is shown as a component of results from discontinued
operations.
ACCOUNTING STANDARDS:
Accounting for Derivative Instruments and Hedging
I n 1998, the Financial Accounting Standards Board issued
Financial Accounting Standard (FAS) 133, Accounting for Derivative
Instruments and Hedging, effective for fiscal years beginning after
June 15, 1999. The new standard requires an entity to recognize
d e rivatives 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 in net income, depending on the types of those
instruments. TECO Energy 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.
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
f i n ancial statements. For 1998, there were no components of
comprehensive income other than net income.
CAPITAL EXPENDITURES:
TECO Energy's 1998 capital expenditures of $296 million included
$176 million for Tampa Electric, $56 million for Peoples Gas System
41
and $64 million for the diversified companies. Tampa Electric invested
$154 million in 1998 for equipment and facilities to meet its growing
customer base and generating equipment improvements, $16 million to
begin construction of a flue gas desulfurization (FGD) system, or
"scrubber" for Big Bend Units One and Two, and $6 million toward
construction of Polk Unit Two, a gas and No. 2 oil-fired combustion
t u rbine. Capital expenditures for Peoples Gas System included
approximately $43 million for system expansion, including
approximately $2.5 million related to its Southwest Florida expansion,
and approximately $13 million for maintenance of the existing system.
TECO Transport invested $46 million in 1998 for equipment additions
and normal equipment replacement. TECO Coal spent $11 million for
mining equipment replacements.
TECO Energy estimates total capital expenditures for ongoing
operations to be $422 million for 1999 and $1.2 billion during the
2000-2003 period. For 1999, Tampa Electric expects to spend $222
million, consisting of $61 million for a scrubber at Big Bend Power
Station, $19 million in construction costs on Polk Unit Two and $142
million for other capital expenditures. At the end of 1998, Tampa
Electric had outstanding commitments of about $68 million to complete
the scrubber and $44 million to complete Polk Unit Two. Tampa
Electric's total capital expenditures over the 2000-2003 period are
projected to be $706 million, including $194 million for generation
expansion and $6 million to complete the scrubber.
Capital requirements for Peoples Gas System are expected to be
about $75 million in 1999 and $208 million during the 2000-2003 period
for infrastructure expansion to grow the customer base. Included in
these amounts are $21 million in 1999 for the Southwest Florida
expansion, and expenditures of approximately $40 million annually for
other revenue-producing projects associated with normal system growth
and expansion. The remainder represents expenditures for ongoing
system maintenance. At the end of 1998, $8 million of these amounts
had been committed.
The diversified companies expect capital expenditures of about
$125 million in 1999 and $259 million during the 2000-2003 period.
Included in these amounts are $65 million at TECO Power Services for
construction of the San Jose Power Station and identified investments
in additional projects. These estimates do not take into account any
other future projects which are expected to emerge. Also included in
t h e se amounts are the acquisition of coal mining equipment,
acquisition of ocean transportation equipment and river barges and
normal asset replacement. At the end of 1998, $34 million of these
amounts had been committed.
ENVIRONMENTAL COMPLIANCE:
Tampa Electric is complying with the Phase I emission limitations
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
42
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 as of January 1996, reducing annual
revenues by approximately $12 million.
In 1995, Tampa Electric deferred $51 million of revenues under
this plan. The deferred revenues accrued interest at the 30-day
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
43
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
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.
44
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
pretax 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.
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
45
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.
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.
46
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.
INVESTMENT ACTIVITY:
At Dec. 31, 1998, TECO Energy had $16.9 million in cash, cash
equivalents and short-term investments versus $10.6 million at year-
end 1997.
The company also has a continuing investment in leveraged leases
of $57 million. At Dec. 31, 1998, the net leveraged lease investment
was essentially a zero balance and all leases were performing on a
current basis. The company has made no investment in leveraged leases
since 1989.
FINANCING ACTIVITY:
TECO Energy's 1998 year-end capital structure, excluding the
effect of unearned compensation, was 51 percent debt and 49 percent
common equity. The company's objective is to maintain a capital
structure over time that will support its current credit ratings.
Credit Ratings / Senior Debt
Duff & Phelps Moody's Standard & Poor's
Tampa Electric Company AA+ Aa2 AA
TECO Finance /
TECO Energy AA- A1 AA-
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.
In the third quarter of 1998, TECO Energy filed a registration
statement for the issuance of up to $200 million of medium-term notes.
47
In September 1998, TECO Energy issued $150 million of Remarketed
Notes, due 2038. The notes, which bear an initial coupon rate of
5.54%, are subject to mandatory tender on Sept. 15, 2001, at which
time they will be remarketed or redeemed. Net proceeds were $153
million which included a premium paid to TECO Energy 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 TECO Energy's then-current
credit spread above United States Treasury Notes with 10 years to
maturity.
Proceeds from both note issues were used to repay short-term debt
and for general corporate purposes.
TECO Energy raised $9.2 million of common equity in 1996 from the
sale of common stock through its Dividend Reinvestment and Common
Stock Purchase Plan (DRP). In 1997 and 1998, the DRP purchased TECO
Energy shares on the open market for plan participants.
As a part of its risk management program, during 1995 TECO
Finance entered into an interest rate exchange agreement to moderate
its exposure to short-term interest rate changes. This three-year
agreement effectively converted the interest rate on $100 million of
short-term debt from a floating rate to a fixed rate. TECO Finance
paid a fixed rate of 5.8% and received a floating rate based on a 30-
day commercial paper index. This agreement, which expired in June
1998, did not have a significant impact on interest expense in 1998,
1997 or 1996.
TECO Energy is exposed to changes in interest rates primarily as
a result of its borrowing activities. A hypothetical 10 percent
increase in TECO Energy's weighted average interest rate on its
variable rate debt would not have a significant impact on TECO
Energy'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 TECO Energy's
long-term debt at Dec. 31, 1998.
Based on policies and procedures approved by the Board of
Directors, from time to time TECO Energy 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 TECO Energy enters into futures, swaps
and options contracts to hedge the selling price for its physical
production at TECO Coalbed Methane, to limit exposure to gas price
increases at both the regulated natural gas utility and unregulated
propane business, and to limit exposure to fuel price increases at
TECO Transport. The benefits of these 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.
T E CO Energy does not use derivatives or other financial
instruments for speculative purposes.
LIQUIDITY, CAPITAL RESOURCES:
TECO Energy and its operating companies met cash needs during
1998 largely with internally generated funds, with the balance of cash
needs coming from net borrowings.
At Dec. 31, 1998, TECO Energy had bank credit lines of $485
million, all of which were available.
TECO Energy anticipates meeting its capital requirements for
o n going operations in the 1999-2003 period substantially from
48
internally generated funds. TECO Power Services expects to finance the
San Jose Power Station with limited-recourse project financing upon
commercial operation.
INVESTMENT CONSIDERATIONS:
The following are certain factors that could affect TECO Energy's
f u ture results. They should be considered in connection with
evaluating forward-looking statements contained in this report and
otherwise made by or on the behalf of TECO Energy, since these factors
could cause actual results and conditions to differ materially from
those projected in these forward-looking statements.
G e neral Economic Conditions. The company's businesses are
dependent on general economic conditions. In particular, the projected
growth in Tampa Electric's service area and in Florida is important to
the realization of Tampa Electric's and the Peoples Gas companies'
forecasts for annual energy sales growth. An unanticipated downturn in
the local area's or Florida's economy could adversely affect Tampa
Electric's or the Peoples Gas companies' performance.
The activities of the diversified businesses, particularly TECO
Transport and TECO Coal, are also affected by general economic
conditions in the respective industries and geographic areas they
serve, both nationally and internationally.
Weather Variations. Most of TECO Energy's businesses are affected
by variations in general weather conditions and unusually severe
weather. Tampa Electric's and the Peoples Gas companies' energy sales
are particularly sensitive to variations in weather conditions. The
TECO Energy companies forecast energy sales on the basis of normal
weather, which represents a long-term historical average. Significant
variations from normal weather could have a material impact on energy
sales. Unusual weather, such as hurricanes, could also have an effect
on operating costs as well as sales.
Peoples Gas System and Peoples Gas Company are more weather
sensitive, with a single winter peak period, than Tampa Electric, with
both summer and winter peak periods. Mild winter weather in Florida
can be expected to negatively impact results at the Peoples Gas
companies.
Variations in weather conditions also affect the demand and
prices for the commodities sold by TECO Coalbed Methane and TECO Coal.
TECO Transport also is impacted by weather because of its effects on
the supply of and demand for the products transported. Severe weather
conditions that could interrupt or slow service and increase operating
costs also affects these businesses.
Potential Competitive Changes. The electric industry has been
undergoing certain restructuring. Competition in wholesale power sales
has been introduced on a national level. Some states have mandated or
encouraged competition at the retail level, and in some situations
required divestiture of generating assets. While there is active
wholesale competition in Florida, the retail electric business has
remained substantially free from direct competition. Changes in the
competitive environment occasioned by legislation, regulation, market
conditions or initiatives of other electric power providers, however,
particularly with respect to retail competition, could adversely
affect Tampa Electric's business and its performance. The company's
long-range projections are based on its expectation that there will
not be any significant change in Tampa Electric's competitive
environment.
The gas distribution industry has been subject to competitive
forces for several years. Further unbundling of gas service could
adversely affect Peoples Gas System.
49
Regulatory Actions. Tampa Electric and Peoples Gas System operate
in highly regulated industries. Their retail operations, including the
prices charged, are regulated by the FPSC, and Tampa Electric's
wholesale power sales and transmission services are subject to
regulation by FERC. Changes in regulatory requirements or adverse
regulatory actions could have an adverse effect on Tampa Electric's or
Peoples Gas System's performance.
Commodity Price Changes. Most of TECO Energy's businesses 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.
At the diversified companies, changes in gas and coal prices
directly affect the margins at TECO Coalbed Methane, TECO Coal and
TECO Transport. TECO Coalbed Methane is exposed to commodity price
risk through the sale of natural gas. A 10 percent change in the
market price of natural gas would not have a significant impact on
TECO Energy's earnings. TECO Coal is exposed to commodity price risk
through coal sales. A 10 percent change in the market price of coal in
any one year would not have a significant impact on TECO Energy's
earnings for that year.
Gas Production Levels. Results at TECO Coalbed Methane are
affected by its level of production which is declining. The company's
long-range forecast assumes that production will decline approximately
9 percent annually. Actual production levels may be greater or less
than those assumed.
Business Growth Opportunities. Part of the company's previously
announced long-term strategy is to grow its diversified business. Much
of its targeted growth is dependent on the ability to find attractive
acquisition and development opportunities and independent power
p r o jects. The company's long-range forecast is based on its
expectation that it will be successful in finding and capitalizing on
these acquisition and development opportunities and independent power
projects, but there can be no assurance that its efforts will be
successful.
International Risks. TECO Power Services is involved in several
i n t e rnational projects and expects to enter into additional
international projects during the next few years. These projects
involve numerous risks that are not present in domestic projects,
including expropriation, political instability, currency exchange rate
fluctuations, repatriation restrictions, and regulatory and legal
uncertainties. The company's long-range forecast assumes that TECO
Power Services will mitigate losses associated with these risks
through a variety of risk mitigation measures, including specific
contractual provisions, teaming with strong international and local
partners, obtaining limited-recourse financing and, where appropriate,
obtaining political risk insurance.
Environmental Matters. TECO Energy's businesses are subject to
50
regulation by various governmental authorities dealing with air, water
and other environmental matters. Changes in compliance requirements or
the interpretation by governmental authorities of existing
requirements may impose additional costs on the company or result in
the curtailment of some activities.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
TECO Energy is exposed to changes in interest rates primarily as
a result of its borrowing activities.
From time to time, TECO Energy or its affiliates may enter into
futures, swaps and option contracts to moderate exposure to interest
rate changes.
See the discussion of interest rate risk in the Financing
Activity section on page 48.
Commodity Price Risk
Currently, at Tampa Electric and Peoples Gas System, commodity
price increases due to changes in market conditions for fuel,
purchased power and natural gas are recovered through cost recovery
clauses, with no effect on earnings.
TECO Coalbed Methane is exposed to commodity price risk through
the sale of natural gas, and TECO Coal is exposed to commodity price
risk through coal sales.
From time to time, TECO Energy or its affiliates may enter into
futures, swaps and options contracts to hedge the selling price for
physical production at TECO Coalbed Methane, to limit exposure to gas
price increases at both the regulated natural gas utility and
unregulated propane business, or to limit exposure to fuel price
increases at TECO Transport.
See the discussions of commodity price risks in the Financing
Activities section on page 48 and in the Investment Considerations --
Commodity Price Changes section on page 50.
TECO Energy and its affiliates do not use derivatives or other
financial products for speculative purposes.
51
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
No.
Report of Independent Accountants 53
Consolidated Balance Sheets, Dec. 31, 1998 and 1997 54
Consolidated Statements of Income for the years ended
Dec. 31, 1998, 1997 and 1996 55
Consolidated Statements of Cash Flows for the years
ended Dec. 31, 1998, 1997 and 1996 56
Consolidated Statements of Common Equity for the years
ended Dec. 31, 1998, 1997 and 1996 57
Notes to Consolidated Financial Statements 58-80
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.
52
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
and shareholders of
of TECO Energy, Inc.
In our opinion, the accompanying consolidated balance sheets and
the related consolidated statements of income, of cash flows and of
common equity present fairly, in all material respects, the financial
position of TECO Energy, Inc. and its subsidiaries at Dec. 31, 1998
and 1997, and the results of their operations and their cash flows for
each of the three years in the period ended Dec. 31, 1998, in
conformity with generally accepted accounting principles. These
f i n ancial 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, except for certain
information included in Note I,
for which the date is March 26, 1999
53
CONSOLIDATED BALANCE SHEETS
(millions)
Assets
Dec. 31, 1998 1997
Current Assets
Cash and cash equivalents $ 16.9 $ 10.6
Receivables, less allowance
for uncollectibles 229.6 222.7
Inventories, at average cost
Fuel 93.2 80.8
Materials and supplies 64.1 63.1
Prepayments 15.1 12.9
418.9 390.1
Property, Plant and Equipment,
at Original Cost
Utility plant in service
Electric 3,991.3 3,880.6
Gas 518.5 471.1
Construction work in progress 101.1 57.0
Other property 989.6 950.8
5,600.5 5,359.5
Accumulated depreciation (2,292.9) (2,123.0)
3,307.6 3,236.5
Other Assets
Other investments 72.0 88.3
Deferred income taxes 99.1 88.1
Deferred charges and other assets 281.7 157.4
452.8 333.8
$4,179.3 $3,960.4
Liabilities and Capital
Current Liabilities
Long-term debt due within one year $ 36.0 $ 12.7
Notes payable 319.0 447.5
Accounts payable 208.1 158.7
Customer deposits 78.3 77.9
Interest accrued 14.2 21.8
Taxes accrued 5.1 14.0
660.7 732.6
Other Liabilities
Deferred income taxes 499.9 470.9
Investment tax credits 46.7 51.7
Regulatory liability-tax related 34.0 35.1
Other deferred credits 150.6 145.2
Long-term debt, less amount
due within one year 1,279.6 1,080.2
Capital
Common equity 1,569.2 1,512.2
Unearned compensation (61.4) (67.5)
$4,179.3 $3,960.4
The accompanying notes are an integral part of the consolidated financial
statements.
54
CONSOLIDATED STATEMENTS OF INCOME
(millions)
Year ended Dec. 31, 1998 1997 1996
Revenues $1,958.1 $ 1,862.3 $ 1,775.3
Expenses
Operation 1,030.1 966.6 955.5
Maintenance 128.9 114.2 97.4
Non-recurring charges 25.9 -- --
Depreciation 228.3 225.4 202.8
Taxes, other than income 149.4 143.5 137.8
1,562.6 1,449.7 1,393.5
Income from Operations 395.5 412.6 381.8
Other Income (Expense)
Allowance for other funds used
during construction -- 0.1 16.5
Other income (expense) (9.8) (0.3) 1.4
Preferred dividend requirements of
Tampa Electric -- (0.5) (1.8)
(9.8) (0.7) 16.1
Income Before Interest and
Income Taxes 385.7 411.9 397.9
Interest Charges
Interest expense 104.3 105.9 105.1
Allowance for borrowed funds
used during construction -- (0.1) (6.4)
104.3 105.8 98.7
Income Before Provision for
Income Taxes 281.4 306.1 299.2
Provision for income taxes 81.0 94.7 81.8
Net income from continuing
operations 200.4 211.4 217.4
Net Loss from Discontinued
Operations, net of income tax
benefit of $3.5 million and $0.5
million for 1997 and 1996,
respectively -- (6.5) (0.9)
Gain (Loss) on Disposal of
Discontinued Operations, net of
income tax expense of $3.9 million
for 1998 and income tax benefit of
$1.6 million for 1997 6.1 (3.0) --
Net Income $ 206.5 $ 201.9 $ 216.5
Average common shares
outstanding during year 131.7 130.8 129.3
Earnings per Average Common Share
Outstanding
From continuing operations
--Basic $ 1.52 $ 1.62 $ 1.68
--Diluted $ 1.52 $ 1.61 $ 1.67
Net income
--Basic $ 1.57 $ 1.54 $ 1.67
--Diluted $ 1.57 $ 1.54 $ 1.67
The accompanying notes are an integral part of the consolidated financial
statements.
55
CONSOLIDATED STATEMENTS OF CASH FLOWS
(millions)
Year ended Dec. 31, 1998 1997 1996
Cash Flows from Operating Activities
Net income $ 206.5 $ 201.9 $ 216.5
Adjustments to reconcile net income to
net cash from operating activities
Depreciation 228.3 225.4 202.8
Deferred income taxes 14.6 (1.9) 9.7
Investment tax credits, net (5.0) (5.0) (5.1)
Allowance for funds used
during construction -- (0.2) (22.9)
Amortization of unearned
compensation 7.8 5.9 5.4
Loss (gain) on disposal of
discontinued operations, pretax (10.0) -- --
Deferred revenue (38.3) (30.5) 34.2
Deferred recovery clause 17.4 2.7 7.4
Refund to customers -- (19.8) (6.0)
Non-recurring charges 33.2 -- --
Receivables, less allowance for
uncollectibles (6.9) 6.4 (26.3)
Inventories (13.5) (21.4) 7.6
Taxes accrued (8.8) (0.9) (1.6)
Interest accrued (7.7) 1.6 2.8
Accounts payable 47.3 (2.8) (9.6)
Other 25.5 (10.6) (1.3)
490.4 350.8 413.6
Cash Flows from Investing Activities
Capital expenditures (296.1) (212.6) (296.3)
Allowance for funds used
during construction -- 0.2 22.9
Investment in short-term investments -- -- 32.3
Net proceeds from sale of assets 37.5 -- --
Investment in unconsolidated
affiliates (135.1) (4.9) --
Other non-current investments 7.8 6.9 2.8
(385.9) (210.4) (238.3)
Cash Flows from Financing Activities
Common stock 6.7 5.1 13.9
Proceeds from long-term debt 201.2 29.3 78.1
Repayment of long-term debt (16.2) (103.8) (34.0)
Net increase (decrease) in
credit lines -- (49.8) (6.2)
Net increase (decrease) in
short-term debt (128.5) 141.2 (55.8)
Redemption of preferred stock -- (20.4) (35.5)
Dividends (161.4) (147.3) (134.2)
(98.2) (145.7) (173.7)
Net increase (decrease) in
cash and cash equivalents 6.3 (5.3) 1.6
Cash and cash equivalents at
beginning of year 10.6 15.9 14.3
Cash and cash equivalents at
end of year $ 16.9 $ 10.6 $ 15.9
Supplemental Disclosure of Cash Flow Information
Cash paid during the year for
Interest (net of amounts capitalized)$ 99.3 $115.5 $ 93.8
Income taxes $ 66.2 $ 97.4 $ 87.1
The accompanying notes are an integral part of the consolidated financial
statements.
56
CONSOLIDATED STATEMENTS OF COMMON EQUITY
(millions)
Additional Total
Common Paid-in Retained Unearned Common
Shares(1) Stock Capital Earnings Compensation Equity
Balance, Dec. 31, 1995 128.8 $128.8 $332.3 $ 878.1 $(74.2) $1,265.0
Net income for 1996 216.5 216.5
Common stock issued 0.9 0.9 17.2 (1.9) 16.8
Cash dividends declared (134.2) (134.2)
Amortization of unearned
compensation 5.4 5.4
Premium on redemption of
preferred stock (0.5) (0.5)
Tax benefits-ESOP dividends
and stock options 0.9 2.2 2.5
Balance, Dec. 31, 1996 129.7 129.7 350.4 962.1 (70.7) 1,371.5
Net income for 1997 201.9 201.9
Common stock issued 0.4 0.4 7.3 (2.7) 5.0
Common stock issued-
West Florida Gas Inc. merger 0.8 0.8 (1.1) 5.8 5.5
Cash dividends declared (147.3) (147.3)
Amortization of unearned
compensation 5.9 5.9
Tax benefits-ESOP dividends
and stock options 0.1 2.1 2.2
Balance, Dec. 31, 1997 130.9 130.9 356.7 1,024.6 (67.5) 1,444.7
Net income for 1998 206.5 206.5
Common stock issued 0.5 0.5 7.2 (1.7) 6.0
Common stock issued-
Griffis, Inc. merger 0.6 0.6 0.8 1.4
Dividends declared (161.4) (161.4)
Amortization of unearned
compensation 7.8 7.8
Tax benefits-ESOP dividends
and stock options 0.7 2.1 2.8
Balance, Dec. 31, 1998 132.0 $132.0 $364.6 $1,072.6 $(61.4) $1,507.8
The accompanying notes are an integral part of the consolidated financial
statements.
(1) TECO Energy had 400 million shares of $1 par value common stock
authorized in 1998, 1997 and 1996.
57
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. Summary of Significant Accounting Policies
Principles of Consolidation
The significant accounting policies for both utility and
diversified operations are as follows:
The consolidated financial statements include the accounts of
TECO Energy, Inc. (TECO Energy or the company) and its wholly owned
subsidiaries, including the Peoples Gas companies acquired in 1997.
The equity method of accounting is used to account for
investments in partnership arrangements in which TECO Energy or its
subsidiary companies do not have majority ownership or exercise
control.
T h e proportional share of expenses, revenues and assets
reflecting TECO Coalbed Methane's and TECO Oil & Gas undivided
interest in joint venture property is included in the consolidated
financial statements.
All significant intercompany balances and intercompany
transactions have been eliminated in consolidation.
Basis of Accounting
Tampa Electric and Peoples Gas System (the regulated utilities)
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
with generally accepted accounting principles in all material
respects.
The impact of Financial Accounting Standard (FAS) No. 71,
Accounting for the Effects of Certain Types of Regulation, has been
minimal in the 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 ements 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
58
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.
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
TECO Energy 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 the Company, in accordance with FAS 121, Accounting
59
for the Impairment of Long-Lived Assets and Long-Lived Assets to be
Disposed of. In 1998, TECO Coal Corporation recorded a one-time
after-tax charge of $8.9 million to adjust assets values of certain
mining operations, and TeCom, Inc. recorded an after-tax charge of
$1.7 million to write off product development costs associated with
InterLane features developed early in the product life and no longer
incorporated in the current system's design. No write-down of assets
due to impairment was required in 1997 or 1996.
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.
Foreign Operations
The functional currency of the company's foreign investments is
primarily the U.S. dollar. Transactions in the local currency are
remeasured to the U.S. dollar for financial reporting purposes with
aggregate transaction gains or losses included in net income. The
aggregate transaction gains or losses included in net income in 1998,
1997 and 1996 were not significant.
The investments are generally protected from any significant
currency gains or losses by the terms of the power sales agreements
and other related contracts, in which payments are defined in U.S.
dollars.
Deferred Income Taxes
TECO Energy utilizes the liability method in the measurement of
deferred income taxes. Under the liability method, the temporary
differences between the financial statement and tax bases of assets
and liabilities are reported as deferred taxes measured at current
tax rates. Tampa Electric and Peoples Gas System are regulated, and
their books and records reflect approved regulatory treatment,
including certain adjustments to accumulated deferred income taxes
and the establishment of a corresponding regulatory tax liability
reflecting the amount payable to customers through future rates.
Investment Tax Credits
Investment tax credits have been recorded as deferred credits
and are being amortized 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.
60
Capitalized Development Costs
TeCom, a subsidiary of TECO Energy, is developing for market
advanced energy management and automation systems for commercial and
residential applications. TeCom capitalized product development costs
of $6.8 million in 1998, $6.5 million in 1997 and $4.9 million in
1996. The costs capitalized since 1996 and those anticipated to be
capitalized during the product enhancement period are will be
amortized over the expected life of the products, generally estimated
to be the 4-year period after they become available for general
distribution. Amortization expense, which began in September 1998,
for products that have reached general availability was $0.8 million
in 1998.
Interest Capitalized
Interest costs for the construction of non-utility facilities
are capitalized and depreciated over the service lives of the related
property.
Cash Equivalents
C a s h equivalents are highly liquid, high-quality debt
instruments purchased with a maturity of three months or less. The
carrying amount of cash equivalents approximated fair market value
because of the short maturity of these instruments. The amount of
cash equivalents outstanding at Dec. 31, 1998 and 1997 was not
significant.
Other Investments
Other investments include longer-term passive investments,
primarily leveraged leases.
Coalbed Methane Gas Properties
TECO Coalbed Methane, a subsidiary of TECO Energy, has developed
jointly the natural gas potential in a portion of Alabama's Black
Warrior Basin.
TECO Coalbed Methane utilizes the successful efforts method to
account for its gas operations. Under this method, expenditures for
unsuccessful exploration activities are expensed currently.
Capitalized costs are amortized on the unit-of-production method
u s i ng estimates of proven reserves. Investments in unproven
properties and major development projects are not amortized until
proven reserves associated with the projects can be determined or
until impairment occurs.
Aggregate capitalized costs related to wells producing and under
development at Dec. 31, 1998 and 1997 were $210.3 million and $209.1
million respectively. Net proven reserves at Dec. 31, 1998 and 1997
were as follows:
Net Proven Reserves - Coalbed Methane Gas
(billion cubic feet) 1998 1997
Proven reserves,
beginning of year 195.0 190.4
Production (17.6) (19.2)
Revisions of previous estimates (15.6) 23.8
Proven reserves, end of year 161.8 195.0
Number of wells 655 669
Hedges - Fuel Prices
61
TECO Energy enters into futures and options contracts, from time
to time, to hedge the selling price for TECO Coalbed Methane s
physical production, and to limit its exposure to gas price increases
in both the regulated Peoples Gas System and the unregulated propane
business, and oil price increases in the transportation business.
TECO Energy does not use derivatives or other hedging instruments 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. TECO Energy 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 completed its merger with Lykes
Energy, Inc. (the Peoples companies) and issued approximately 12.1
million shares of its common stock. 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) and issued approximately .8 million
shares of its common stock. 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 Consolidated Balance Sheet as of Dec. 31,
1997 and its Consolidated Statements of Income and Cash Flows for the
period ended Dec. 31, 1997 include the results of the Peoples
companies and West Florida.
In January 1998, the company acquired an unregulated Florida
propane business, Griffis, Inc. (Griffis) and its affiliate, U.S.
Propane, Inc., in a merger transaction and issued approximately .6
million shares of its common stock. These acquired businesses were
then merged into and now operate as part of Peoples Gas Company.
Financial statements and all financial information presented for
periods prior to 1997 have been restated to include the results of
the Peoples Gas companies. Prior period financial statements have
not been restated to reflect the operations and financial position of
West Florida and Griffis due to their size.
Reclassifications and Restatements
Certain prior year amounts were reclassified or restated to
conform with current year presentation.
62
B. Common Equity
Stock-Based Compensation
In April 1996, the shareholders approved the 1996 Equity
Incentive Plan (the "1996 Plan"). The 1996 Plan superseded the 1990
Equity Incentive Plan (the "1990 Plan") which superseded the 1980
Stock Option and Appreciation Rights Plan (the "1980 Plan") and no
additional grants will be made under the superseded Plans. The rights
of the holders of outstanding options under the 1990 Plan and the
1980 Plan were not affected. The purpose of the 1996 Plan is to
attract and retain key employees of the company, to provide an
incentive for them to achieve long-range performance goals and to
enable them to participate in the long-term growth of the company.
The 1996 Plan amended the 1990 Plan to increase the number of shares
of common stock subject to grants by 3,750,000 shares, expand the
types of awards available to be granted and specify a limit on the
maximum number of shares with respect to which stock options and
stock appreciation rights may be made to any participant under the
Plan. Under the 1996 Plan, the Compensation Committee of the Board of
Directors may award stock grants, stock options and/or stock
equivalents to officers and key employees of TECO Energy and its
subsidiaries. The Compensation Committee has discretion to determine
the terms and conditions of each award, which may be subject to
conditions relating to continued employment, restrictions on transfer
or performance criteria.
In April 1998, under the 1996 Plan, 749,585 stock options were
granted, each with a weighted average option price of $27.56 and a
maximum term of 10 years. In addition, 60,257 shares of restricted
stock were awarded, each with a weighted average fair value of
$27.56. Compensation expense recognized for stock grants awarded
under the 1996 Plan was $2.3 million, $1.3 million and $0.5 million
in 1998, 1997 and 1996. In general, the stock grants are restricted
subject to continued employment; the 1998 stock grants vest in five
years with the remainder vesting at normal retirement age.
Stock option transactions during the last three years under the
1996 Plan, the 1990 Plan and the 1980 Plan (collectively referred to
as the "Equity Plans"), are summarized as follows:
Stock Options - Equity Plans
Option Weighted Avg.
Shares Option
(thousands) Price
1998
Outstanding, beginning of year 2,372 $20.70
Granted 750 $27.56
Exercised 385 $17.26
Canceled 5 $26.48
Outstanding, end of year 2,732 $23.06
Exercisable, end of year 2,732 $23.06
Available for grant 4,047
1997
Outstanding, beginning of year 2,286 $19.77
Granted 352 $24.38
Exercised 265 $17.53
Canceled 1 $24.38
Outstanding, end of year 2,372 $20.70
Exercisable, end of year 2,372 $20.70
Available for grant 4,852
63
1996
Outstanding, beginning of year 2,263 $18.99
Granted 293 $23.69
Exercised 268 $17.42
Canceled 2 $23.56
Outstanding, end of year 2,286 $19.77
Exercisable, end of year 2,286 $19.77
Available for grant 5,314
As of Dec. 31, 1998 the 2.7 million options outstanding and
currently exercisable under the Equity Plans are summarized in the
following table:
Stock Options Outstanding at Dec. 31, 1998
Weighted
Weighted Avg.
Option Avg. Remaining
Shares Range of Option Contractual
(thousands) Option Prices Price Life
70 $11.53 - $14.56 $13.95 1 Years
1,008 $17.38 - $21.63 $19.65 5 Years
1,654 $23.56 - $27.56 $25.52 8 years
In April 1997, the Shareholders approved the 1997 Director
Equity Plan (the "1997 Plan"), as an amendment and restatement of the
1991 Director Stock Option Plan (the 1991 Plan ). The 1997 Plan
supersedes the 1991 Plan, and no additional grants will be made under
the 1991 Plan. The rights of the holders of outstanding options under
the 1991 Plan will not be affected. The purpose of the 1997 Plan is
to attract and retain highly qualified non-employee directors of the
company and to encourage them to own shares of TECO Energy common
stock. The 1997 Plan is administered by the Board of Directors. The
1997 Plan amended the 1991 Plan to increase the number of shares of
common stock subject to grants by 250,000 shares, expanded the types
of awards available to be granted and replaced the current fixed
formula grant by giving the Board discretionary authority to
determine the amount and timing of awards under the Plan.
In April 1998, 24,000 options were granted, each with a weighted
average option price of $27.56. Transactions during the last three
years under the 1997 Plan are summarized as follows:
64
Director Equity Plan
Option Weighted Avg.
Shares Option
(thousands) Price
1998
Outstanding, beginning of year 249 $20.59
Granted 24 $27.56
Exercised 32 $21.10
Canceled -- --
Outstanding, end of year 241 $21.22
Exercisable, end of year 241 $21.22
Available for grant 400
1997
Outstanding, beginning of year 215 $19.96
Granted 34 $24.60
Exercised -- --
Canceled -- --
Outstanding, end of year 249 $20.59
Exercisable, end of year 249 $20.59
Available for grant 428
1996
Outstanding, beginning of year 175 $19.13
Granted 40 $23.63
Exercised -- --
Canceled -- --
Outstanding, end of year 215 $19.96
Exercisable, end of year 215 $19.96
Available for grant 246
As of Dec. 31, 1998, the 241,000 options outstanding and
currently exercisable under the 1997 Plan with option prices of
$17.72-$27.56, had a weighted average option price of $21.22 and a
weighted average remaining contractual life of five years.
TECO Energy has adopted the disclosure-only provisions of FAS
123, Accounting for Stock-Based Compensation (FAS 123), but applies
Accounting Principles Board Opinion No. 25 and related
i n t e rpretations in accounting for its plans. Therefore, no
compensation expense has been recognized for stock options granted
under the 1996 Plan and the 1997 Plan. If the company had elected to
recognize compensation expense for stock options based on the fair
value at grant date, consistent with the method prescribed by FAS
123, net income and earnings per share would have been reduced to the
pro forma amounts shown below:
65
1998 1997 1996
Net Income
from
continuing
operations As reported $200.4 $211.4 $217.4
(millions) Pro forma $198.8 $210.7 $216.7
Net Income As reported $206.5 $201.9 $216.5
(millions) Pro forma $204.9 $201.1 $215.8
Net Income
from
continuing
operations As reported $ 1.52 $ 1.62 $ 1.68
- -EPS basic Pro forma $ 1.51 $ 1.61 $ 1.68
Net Income As reported $ 1.57 $ 1.54 $ 1.67
- -EPS basic Pro forma $ 1.56 $ 1.54 $ 1.67
These pro forma amounts were determined using the Black-Scholes
valuation model with the following key assumptions: (a) a discount
rate of 5.64%, 6.81% and 6.42% for 1998, 1997 and 1996, respectively;
(b) an expected volatility factor and dividend yield to equal the
rate in effect for the 36 months prior to grant; and (c) an average
expected option life of 6 years.
Dividend Reinvestment Plan
In 1992, TECO Energy implemented a Dividend Reinvestment and
Common Stock Purchase Plan (DRP). TECO Energy raised common equity
from this plan of $9.2 million in 1996. In 1998 and 1997, the DRP
purchased shares of TECO Energy common stock on the open market for
plan participants.
Shareholder Rights Plan
In 1989, TECO Energy declared a distribution of Rights to
purchase one additional share of the company's common stock at a
price of $40 per share for each share outstanding. The Rights expire
in May 1999. The Rights will become exercisable 10 days after a
person acquires 20 percent or more of the company's outstanding
common stock or commences a tender offer that would result in such
person owning 30 percent or more of such stock or at the time the
Board of Directors declares a person who acquired 10 percent or more
of such stock to be an "adverse person." If any person acquires 20
percent or more of the outstanding common stock or the Board declares
that a person is an adverse person, the rights of holders, other than
such acquiring person or adverse person, become rights to buy shares
of common stock of the company (or of the acquiring company if the
company is involved in a merger or other business combination and is
not the surviving corporation) having a market value of twice the
exercise price of each right.
The company may redeem the Rights at a nominal price per Right
until 10 days after a person acquires 20 percent or more of the
outstanding common stock but not after the Board has declared a
person to be an adverse person.
In October 1998, the Board of Directors renewed the Shareholder
Rights Plan on substantially the same terms. Under the renewed plan,
among other things, the Rights become effective upon the expiration
(in May 1999) or the earlier termination of the existing Rights plan,
the exercise price of the Rights is $90, the threshold percentage of
beneficial ownership at which the Rights entitle holders to purchase
66
common stock at a discount is 10% and the Rights expire in May 2009,
subject to extension.
Employee Stock Ownership Plan
Effective Jan. 1, 1990, TECO Energy amended the TECO Energy
Group Retirement Savings Plan, a tax-qualified benefit plan available
to substantially all employees, to include an employee stock
ownership plan (ESOP). During 1990, the ESOP purchased 7 million
shares of TECO Energy common stock on the open market for $100
million. The share purchase was financed through a loan from TECO
Energy to the ESOP. This loan is at a fixed interest rate of 9.3% and
will be repaid from dividends on ESOP shares and from TECO Energy's
contributions to the ESOP.
TECO Energy's contributions to the ESOP were $4.3 million, $3.4
million and $3.6 million in 1998, 1997 and 1996, respectively. TECO
Energy's annual contribution equals the interest accrued on the loan
during the year plus additional principal payments needed to meet the
matching allocation requirements under the plan, less dividends
received on the ESOP shares. The components of net ESOP expense
recognized for the past three years are as follows:
(millions) 1998 1997 1996
Interest expense $7.3 $7.7 $8.0
Compensation expense 5.5 4.7 4.9
Dividends (8.1) (7.8) (7.5)
Net ESOP expense $4.7 $4.6 $5.4
Compensation expense was determined by the shares allocated
method.
At Dec. 31, 1998, the ESOP had 2.4 million allocated shares, .1
million committed-to-be-released shares, and 4.1 million unallocated
shares. Shares are released to provide employees with the company
match in accordance with the terms of the TECO Energy Group
Retirement Savings Plan and in lieu of dividends on allocated ESOP
shares. The dividends received by the ESOP are used to pay debt
service.
For financial statement purposes, the unallocated shares of TECO
Energy stock are reflected as a reduction of common equity,
classified as unearned compensation. Dividends on all ESOP shares are
recorded as a reduction of retained earnings, as are dividends on all
TECO Energy common stock. The tax benefit related to the dividends
paid to the ESOP for allocated shares is a reduction of income tax
expense and for unallocated shares is an increase in retained
earnings. All ESOP shares are considered outstanding for earnings per
share computations.
C. Preferred Stock
Preferred Stock of TECO Energy - $1 Par
10 million shares authorized, none outstanding.
Preferred Stock of Tampa Electric - no Par
2.5 million shares authorized, none outstanding.
Preference Stock of Tampa Electric - no Par
2.5 million shares authorized, none outstanding.
Preferred Stock of Tampa Electric - $100 Par Value
1.5 million shares authorized, none outstanding.
67
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.
Cash dividends paid in 1997 were $0.2 million, $0.1 million and
$0.3 million for Series A, Series B and Series D, respectively. These
amounts reflect dividends paid through July 16, 1997, the date that
these series were redeemed.
D. Short-term Debt
Notes payable consisted primarily of commercial paper with
weighted average interest rates of 5.16% and 5.72% at Dec. 31, 1998
and 1997, respectively. The carrying amount of notes payable
approximated fair market value because of the short maturity of these
instruments. Consolidated unused lines of credit at Dec. 31, 1998
were $485 million. Certain lines of credit require commitment fees
ranging from .05% to .075% on the unused balances.
During 1995, TECO Finance entered into an interest rate exchange
agreement to moderate its exposure to interest rate changes. This
t h ree-year agreement, which ended June 26, 1998, effectively
converted the interest rate on $100 million of short-term debt from a
floating rate to a fixed rate. TECO Finance paid a fixed rate of 5.8%
and received a floating rate based on a 30-day commercial paper
index. The costs of this agreement did not have a significant impact
on interest expense in 1998, 1997 or 1996.
68
E. Long-term Debt
Dec. 31,
(millions) Due 1998 1997
TECO Energy
Medium-term notes payable: 9.29%(1) 2000 $ 50.0 $ 50.0
Medium-term notes payable: 5.35%(1)(2) 2001 150.0 --
200.0 50.0
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(3):
5 3/4% 2007 23.5 23.8
7 7/8% Refunding bonds(4) 2021 25.0 25.0
8% Refunding bonds(4) 2022 100.0 100.0
6 1/4% Refunding bonds(5) 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 notes payable: 5.11% (1)(6) 2001 38.0 --
703.3 665.6
Peoples Gas System
Senior Notes (7)
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 notes payable: 5.11% (1)(6) 2001 12.0 --
78.0 69.1
Diversified companies
Dock and wharf bonds, variable rate:
3.15% for 1998 and 3.75% for 1997(1)(3) 2007 110.6 110.6
Mortgage notes payable: 7.6% 1999 0.2 0.8
Non-recourse secured facility notes,
Series A: 7.8% 1999-2012 137.9 143.5
Limited recourse secured facility
note: 9.875% 1999-2008 24.4 26.8
Capital lease: implicit rate of
8.5% for 1998 1999-2003 33.4 --
306.5 281.7
TECO Finance
Medium-term notes payable, various rates:
7.26% for 1998 and 1997(1) 1999-2002 30.0 30.0
Unamortized debt premium (discount), net (2.2) (3.5)
1,315.6 1,092.9
Less amount due within one year(8) 36.0 12.7
Total long-term debt $1,279.6 $1,080.2
(1) Composite year-end interest rate.
(2) These notes are subject to mandatory tender on Sept. 15, 2001,
at which time they will be redeemed or remarketed.
(3) Tax-exempt securities.
69
(4) 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.
(5) 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.
(6) These notes are subject to mandatory tender on July 15, 2001, at
which time they will be redeemed or remarketed.
(7) 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.
(8) Of the amount due in 1999, $0.8 million may be satisfied by the
substitution of property in lieu of cash payments.
TECO Transport entered into a capital lease agreement with
Midwest Marine Management Company in March 1998 for the charter of
additional capacity. This lease covers 110 river barges and three
towboats, classified as property, plant and equipment on the balance
sheet; the corresponding $35 million five-year lease commitment was
recorded as a long-term debt on the balance sheet. The following is a
schedule of future minimum lease payments under the capitalized lease
together with the present value of the net minimum lease payments as
of Dec. 31, 1998:
Amount
Year Ended Dec. 31: (millions)
1999 $ 4.6
2000 4.6
2001 4.6
2002 4.6
2003 25.5
Total minimum lease payments 43.9
Less: Amount representing interest 10.5
Present value of net minimum lease
payments, including current
maturities of $1.8 million $33.4
Substantially all of the property, plant and equipment of Tampa
Electric is pledged as collateral to secure its long-term debt.
Maturities and annual sinking fund requirements of long-term debt for
the years 2000, 2001, 2002 and 2003 are $145.7 million, $216.8
million, $27.3 million, and $117.0 million, respectively. Of these
amounts $0.8 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
$1,279.6 million and an estimated fair market value of $1,404.7
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.
70
F. Retirement Plan
TECO Energy Retirement Plan
TECO Energy has a non-contributory defined benefit retirement
plan which covers substantially all employees. Benefits are based on
employees' years of service and average final salary.
The company'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,
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. The company adopted FAS 132 with the additional
disclosures included here and in Footnote G, Postretirement Benefit
Plan.
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 the Consolidated Statements
of Income $ 4.2 $ 4.2 $ 4.2
71
Reconciliation of the Funded Status of the Retirement Plan and the
Accrued Pension Prepayment/(Liability)
(millions)
Dec. 31, Dec. 31,
1998 1997
Project 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 $(14.2) $(10.7)
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%
G. Postretirement Benefit Plan
TECO Energy and its subsidiaries currently provide certain
postretirement health care benefits for substantially all employees
retiring after age 55 meeting certain service requirements. The
company contribution toward health care coverage for most employees
retiring after Jan. 1, 1990 is limited to a defined dollar benefit
based on years of service. Postretirement benefit levels are
substantially unrelated to salary. The company reserves the right to
terminate or modify the plans in whole or in part at any time.
72
Components of Postretirement Benefit Cost
(millions)
1998 1997 1996
Service cost (benefits earned
during the period) $ 2.6 $ 2.2 $ 2.4
Interest cost on projected
benefit obligations 6.1 6.1 6.1
Amortization of transition obligation
(straight line over 20 years) 2.7 2.7 2.7
Amortization of actuarial loss/(gain) 0.1 (0.1) 0.3
Net periodic Postretirement
benefit expense $11.5 $10.9 $11.5
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 $ 85.8 $ 83.4
Change in benefit obligation due to:
Service cost 2.6 2.3
Interest cost 6.1 6.1
Plan participants' contributions 0.3 0.3
Actuarial (gain) loss 3.3 (1.2)
Gross benefits paid (5.0) (5.1)
Accumulated postretirement benefit obligation,
end of year $ 93.1 $ 85.8
Funded status, end of year $(93.1) $(85.8)
Unrecognized net loss from past experience 12.2 9.0
Unrecognized transition obligation 38.4 41.1
Liability for accrued postretirement benefit $(42.5) $(35.7)
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 ($0.7 million) increase in the aggregate service and
interest cost for 1998 and a 8-percent($7.4 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 ($0.6 million) decrease in the aggregate service and
interest cost for 1998 and a 7-percent($6.4 million) decrease in the
accumulated postretirement benefit obligation as of Dec. 31, 1998.
73
H. Income Tax Expense
Income tax expense consists of the following components:
(millions) Federal State Total
1998
Currently payable $ 56.9 $ 10.9 $ 67.8
Deferred 15.2 3.0 18.2
Amortization of investment tax credits (5.0) -- (5.0)
Income tax expense from continuing
operations 67.1 13.9 81.0
Currently payable 6.9 0.6 7.5
Deferred (3.6) -- (3.6)
Income tax benefit from discontinued
operations 3.3 0.6 3.9
Total income tax expense $ 70.4 $ 14.5 $ 84.9
1997
Currently payable $ 88.5 $ 9.9 $ 98.4
Deferred (6.0) 7.3 1.3
Amortization of investment tax credits (5.0) -- (5.0)
Income tax expense from continuing
operations 77.5 17.2 94.7
Currently payable (4.1) 0.4 (3.7)
Deferred (1.0) (0.4) (1.4)
Income tax benefit from discontinued
operations (5.1) -- (5.1)
Total income tax expense $ 72.4 $ 17.2 $ 89.6
1996
Currently payable $ 67.4 $ 12.7 $ 80.1
Deferred 6.9 (0.1) 6.8
Amortization of investment tax credits (5.1) -- (5.1)
Income tax expense from continuing
operations 69.2 12.6 81.8
Currently payable (3.1) (0.3) (3.4)
Deferred 2.6 0.3 2.9
Income tax benefit from discontinued
operations (0.5) -- (0.5)
Total income tax expense $ 68.7 $ 12.6 $ 81.3
74
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:
(millions) Dec. 31, Dec. 31,
1998 1997
Deferred income tax assets(1)
Property related $ 63.0 $ 59.1
Basis differences in oil and gas
producing properties (2.4) --
Other 38.5 29.0
Total deferred income tax assets 99.1 88.1
Deferred income tax liabilities(1)
Property related (548.5) (521.9)
Basis differences in oil and gas
producing properties (15.7) (22.2)
Revenue deferral plan -- 11.7
Alternative minimum tax
credit carry forward 39.3 40.8
Other 25.0 20.7
Total deferred income
tax liabilities (499.9) (470.9)
Accumulated deferred income taxes $(400.8) $(382.8)
(1) Certain property related assets and liabilities have been netted.
The total income tax provisions differ from amounts computed by
applying the federal statutory tax rate to income before income taxes
for the following reasons:
(millions) 1998 1997 1996
Net income from continuing operations $200.4 $211.4 $217.4
Total income tax provision 81.0 94.7 81.8
Preferred dividend requirements -- 0.5 1.8
Income from continuing operations
before income taxes and
preferred dividend requirements $281.4 $306.6 $301.0
Income taxes on above at federal
statutory rate of 35% $ 98.5 $107.3 $105.3
Increase (Decrease) due to:
State income tax, net of
federal income tax 9.1 11.2 8.2
Amortization of investment
tax credits (5.0) (5.0) (5.1)
Non-conventional fuels tax credit (18.9) (20.2) (19.6)
Equity portion of AFUDC -- -- (5.8)
Other (2.7) 1.4 (1.2)
Total income tax provision from
continuing operations $ 81.0 $ 94.7 $ 81.8
Provision for income taxes as a percent
of income from continuing operations,
before income taxes 28.8% 30.9% 27.1%
75
The provision for income taxes as a percent of income from
discontinued operations was 35.0%, 34.8% and 34.7% for 1998, 1997 and
1996, respectively. The total effective income tax rate differs from
the federal statutory rate due to state income tax, net of federal
income tax and other miscellaneous items.
I. Discontinued Operations
On Aug. 28, 1997, the company announced its plan to discontinue
operations of its conventional oil and gas subsidiary, TECO Oil &
Gas, Inc. Since its formation in the second half of 1995, TECO Oil &
Gas has participated in joint ventures utilizing 3-D seismic imaging
in the exploration for oil and gas. It acquired a portfolio of
interests in producing wells, discoveries not yet producing and lease
prospects in the shallow waters of the Gulf of Mexico and on shore in
Texas.
As a result of the company s intention to sell this business, all
activities of the subsidiary through Aug. 31, 1997, the measurement
date, were reported as discontinued operations on the Consolidated
Statements of Income. An estimate of activities at TECO Oil & Gas
after that date, including the sale of the assets at book value, was
reported in 1997 as a loss on the disposal of discontinued
operations. A summary of net assets is as follows:
(millions) Dec. 31, Dec. 31,
1998 1997
Current assets $ 0.2 $ 1.5
Net property, plant and equipment -- 19.5
Other assets -- 3.9
Taxes currently payable 9.5 0.2
Deferred taxes 2.0 (1.6)
Total liabilities (0.8) (1.7)
Net assets $10.9 $21.8
Total revenues from discontinued operations for the years ended
Dec. 31, 1997 and 1996 were $9.6 million and $4.7 million,
respectively. There were no revenues in 1998.
In March 1998, TECO Oil & Gas sold its offshore assets to
A m e rican Resources Offshore, Inc. (ARO), for $57.7 million,
consisting of $39.2 million in cash and a subordinated note in the
principal amount of $18.5 million. Based on unfavorable developments
at ARO late in the year and the likely impact of certain economic
factors on that business, the company wrote off the recorded value of
all assets associated with the discontinued oil and gas operation,
including the $18.5 million note and associated interest income
accrued. The net, after-tax gain, net of charges, from discontinued
operations in 1998 was $6.1 million for the year, or $0.05 per share.
In March 1999, the company completed a transaction in which it
sold the note from ARO in return for $500,000 in cash. The company
also sold an option relating to its ARO warrants; in the event such
option is exercised, the company will receive the exercise price of
$600,000. In a separate transaction, ARO agreed to be responsible for
disputed joint billing payments of approximately $425,000. As part of
this settlement, ARO also conveyed to the company an overriding
royalty interest in two offshore Gulf of Mexico blocks. The company
does not expect any future royalty payments to be significant.
76
J. Earnings Per Share
In 1997, the Financial Accounting Standards Board issued FAS 128,
Earnings per Share, which requires disclosure of basic and diluted
earnings per share and a reconciliation (where different) of the
numerator and denominator from basic to diluted earnings per share.
The reconciliation of basic and diluted earnings per share is shown
below:
Year ended Dec. 31,
1998 1997 1996
Numerator (Basic and Diluted)
Net income from continuing operations $200.4 $211.4 $217.4
Net income $206.5 $201.9 $216.5
Denominator
Average number of shares outstanding
- basic 131.7 130.8 129.3
Plus: incremental shares for assumed
conversions: Stock options at end
of period 3.0 2.6 2.5
Less: Treasury shares which could
be purchased (2.5) (2.2) (2.0)
Average number of shares outstanding
- diluted 132.2 131.2 129.8
Earnings per share from continuing operations
Basic $1.52 $1.62 $1.68
Diluted $1.52 $1.61 $1.67
Earnings per share
Basic $1.57 $1.54 $1.67
Diluted $1.57 $1.54 $1.67
77
K. Segment Information
TECO Energy is an electric and gas utility holding company with
important diversified activities. The Management of TECO Energy
d e termined its reportable segments based on each subsidiaries'
contribution of revenues, operating income and total assets. All
significant intercompany transactions are eliminated in the
consolidated financial statements of TECO Energy but are included in
determining reportable segments in accordance with FAS 131, Disclosures
about Segments of an Enterprise and Related Information. 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(1) Operations(1) Depreciation(1) at Dec. 31, for the Year
1998
Tampa Electric $1,234.6(2)(3) $279.7 (7) $146.1 $2,705.0 $176.2
Peoples Gas System 252.8 35.8 21.0 375.6 55.9
TECO Transport 230.0 (4) 43.2 26.6 309.7 45.6
TECO Coal 232.4 (5) 23.5 (8) 10.6 180.0 11.2
TECO Power Services 98.7 (6) 13.0 (9) 9.2 412.9(11) 0.4
Other diversified businesses 113.0 34.7 (10) 14.7 301.5 5.6
2,161.5 429.9 228.2 4,284.7 294.9
Other and eliminations (203.4) (34.4)(12) 0.1 (105.4) 1.2
TECO Energy consolidated $1,958.1 $395.5 $228.3 $4,179.3 $296.1
1997
Tampa Electric $1,189.2 (2) $271.5 $141.4 $2,678.4 $125.1
Peoples Gas System 249.6 33.6 19.8 348.9 30.2
TECO Transport 218.7 (4) 42.1 27.3 266.8 28.9
TECO Coal 215.6 (5) 19.9 11.6 191.4 12.3
TECO Power Services 93.0 (6) 15.2 (9) 8.9 273.3(11) 2.1
Other diversified businesses 105.2 37.9 (10) 16.4 301.3 6.7
2,071.3 420.2 225.4 4,060.1 205.3
Other and eliminations (209.0) (7.6) -- (99.7) 7.3
TECO Energy consolidated $1,862.3 $412.6 $225.4 $3,960.4 $212.6
78
Income Capital
From Assets Expenditures
(millions) Revenues(1) Operations(1) Depreciation(1) at Dec. 31, for the Year
1996
Tampa Electric $1,112.9 (2) $244.0 $120.2 $2,645.8 $203.3
Peoples Gas System 258.7 32.0 17.2 302.7 25.9
TECO Transport 207.5 (4) 38.9 27.4 265.9 34.2
TECO Coal 207.5 (5) 18.3 11.4 181.9 12.8
TECO Power Services 88.1 (6) 16.7 (9) 8.4 260.4(11) 4.5
Other diversified businesses 102.9 39.9 (10) 18.2 306.6 2.2
1,977.6 389.8 202.8 3,963.3 282.9
Other and eliminations (202.2) (8.0) -- (61.8) 13.4
TECO Energy consolidated $1,775.4 $381.8 $202.8 $3,901.5 $296.3
(1) From continuing operations
(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) Revenues from sales to affiliates were $112.8 million, $114.7
million and $105.0 million in 1998, 1997 and 1996, respectively.
(5) Revenues from sales to affiliates were $33.8 million, $44.3
million and $51.5 million in 1998, 1997 and 1996, respectively.
(6) Revenues from sales to affiliates were $32.7 million, $26.7
million and $25.0 million in 1998, 1997 and 1996, respectively.
(7) Operating income excludes a one-time pretax charge of $9.6
million in 1998. See Note L.
(8) Operating income excludes a one-time pretax charge of $13.6
million in 1998. See Note L.
(9) Operating income includes interest cost on the limited-recourse
debt related to independent power operations of $13.4 million,
$14.1 million and $12.0 million in 1998, 1997 and 1996,
respectively.
(10) Operating income includes a non-conventional fuels tax credit of
$18.9 million, $20.2 million and $19.6 million in 1998, 1997 and
1996, respectively.
(11) Total assets include $141.2 million and $5.8 million in
investments in unconsolidated affiliates for 1998 and 1997,
respectively, classified as deferred charges and other assets on
the balance sheet.
(12) Operating income includes one-time pretax charges totaling $25.9
million in 1998. See Note L.
79
T a mpa Electric Company, provides retail electric utility
services 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.
TECO Transport Corporation, through its wholly owned
subsidiaries, transports, stores and transfers coal and other dry
b u lk commodities for third parties and Tampa Electric. TECO
Transport's subsidiaries operate on the Mississippi, Ohio and
Illinois rivers, in the Gulf of Mexico and worldwide.
TECO Coal Corporation, through its wholly owned subsidiaries,
owns mineral rights, and owns or operates surface and underground
mines and coal processing and loading facilities in Kentucky and
Tennessee. TECO Coal's subsidiaries sell its coal production to third
parties and to Tampa Electric.
TECO Power Services Corporation (TPS) has subsidiaries that have
interests in independent power projects in Florida and Guatemala, and
has investments in unconsolidated affiliates that participate in
independent power projects in other parts of the U.S. and the world.
TECO Energy's other diversified operating businesses are engaged
in natural gas production from coalbeds, the sale of propane gas, the
marketing of natural gas, energy services and engineering, and the
marketing of advanced energy management, automation and control
systems.
Foreign Operations
T P S has independent power operations and investments in
Guatemala.
TPS, through its subsidiaries, owns and operates a 78-megawatt
power station that supplies energy to Empresa Electrica de Guatemala,
S.A.(EEGSA), an electric utility in Guatemala, under a U.S. dollar-
denominated power sales agreement.
TPS, through a wholly owned subsidiary, has a 46-percent
ownership interest in an entity that is constructing a 120-megawatt
power station and transmission facilities in Guatemala. This project
is expected to be completed in early 2000 and begin providing
capacity under a U.S. dollar-denominated power sales agreement to
EEGSA. In 1998, a consortium that includes TPS, Iberdrola, an
electric utility in Spain, and Electricidade de Portugal, an electric
utility in Portugal, acquired an 80-percent ownership interest in
EEGSA.
Total assets at Dec. 31, 1998, 1997 and 1996 included $154.1
million, $34.7 million and $53.9 million, respectively, related to
these Guatemalan investments. Revenues included $16.9 million, $15.8
million and $15.1 million for the years ended Dec. 31, 1998, 1997 and
1996, respectively, and operating income included $7.9 million, $6.5
million and $8.3 million for the years ended Dec. 31, 1998, 1997 and
1996, respectively, from these Guatemalan operations and investments.
L. Assets Adjustment and One-Time Charges
In 1998, the company recognized one-time charges totaling $33.8
million, pretax ($21.3 million after-tax). Of the $33.8 million
pretax charges, $25.9 million ($16.5 million, after-tax) is recorded
in operating expenses, as non-recurring charges and $7.9 million
($4.8 million, after-tax) is recorded in other income.
The $8.9-million, after-tax charge recorded by TECO Coal was to
adjust the asset values of certain mining facilities, primarily at
its Gatliff mine, to reflect their expected value after the Tampa
80
Electric contract expires in 1999. TECO Coal expects no further asset
adjustments related to the expiration of the Tampa Electric contract.
TeCom recorded a one-time after-tax charge of $1.7 million to
write off certain development costs related to residential system
features developed early in the product life and no longer used in
the current system design.
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 exceeds 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 income on the income statement.
TECO Energy recorded $0.4 million, after tax of merger related
costs in connection with the Griffis, Inc. merger, which is recorded
as other income on the income statement.
M. Commitments and Contingencies
TECO Energy has made certain commitments in connection with its
continuing capital improvements program. TECO Energy estimates that
capital expenditures for ongoing businesses during 1999 will be about
$422 million and approximately $1.2 billion for the years 2000
through 2003.
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
s c r ubber 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.
At the diversified companies, capital expenditures are estimated
at $125 million for 1999 and $259 million for the years 2000 through
2003, primarily for asset replacement and refurbishment at TECO
Transport and TECO Coal, the construction of the San Jose power
station and a joint venture investment at TECO Power Services. This
includes commitments of $34 million at the end of 1998, mainly for
81
the construction of the San Jose Power Plant in Guatemala.
N. Quarterly Data (unaudited)
Financial data by quarter is as follows: (unaudited)
Quarter ended
March 31 June 30 Sept. 30 Dec. 31
1998
Revenues(1) $ 467.8 $ 490.6 $ 525.6 $ 474.1
Income from operations(1) $ 69.8 $ 110.4 $ 128.2 $ 87.1
Net income(1)
Net income from
continuing operations $ 30.8 $ 57.9 $ 70.8 $ 40.9
Net income $ 53.0 $ 57.9 $ 70.8 $ 24.8
Earnings per share (EPS)
- basic
EPS from continuing
operations $ 0.23 $ 0.44 $ 0.54 $ 0.31
EPS $ 0.40 $ 0.44 $ 0.54 $ 0.19
Dividends paid per common
share (2) $ .295 $ 0.31 $ 0.31 $ 0.31
Stock price per common
share(3)
High $ 28 1/2 $ 28 5/16 $ 28 7/8 $ 30 5/8
Low $ 25 9/16 $ 25 3/16 $ 24 3/4 $ 26 3/4
Close $ 28 1/4 $26 13/16 $ 28 9/16 $ 28 3/16
1997
Revenues(1) $ 450.3 $ 460.8 $ 494.7 $ 456.5
Income from operations(1) $ 98.0 $ 103.4 $ 125.6 $ 85.6
Net income(1)
Net income from
continuing operations $ 50.8 $ 50.5 $ 67.5 $ 42.6
Net income $ 50.8 $ 50.5 $ 59.3 $ 41.3
Earnings per share (EPS)
- basic
EPS from continuing
operations $ 0.39 $ 0.39 $ 0.51 $ 0.33
EPS $ 0.39 $ 0.39 $ 0.45 $ 0.31
Dividends paid per common
share (2) $ 0.28 $ .295 $ .295 $ .295
Stock price per common
share(3)
High $ 25 1/8 $ 25 5/8 $ 25 7/8 $ 28 3/16
Low $ 23 3/4 $ 23 3/4 $ 23 7/8 $ 22 3/4
Close $ 24 $ 25 9/16 $ 24 1/2 $ 28 1/8
(1) Millions.
(2) Dividends paid for TECO Energy common stock (not restated for
Peoples Companies merger).
(3) Trading prices for common shares.
82
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE.
During the period Jan. 1, 1997 to the date of this report, TECO
Energy has not had and has not filed with the Commission a report as
to any changes in or disagreements with accountants on accounting
principles or practices, financial statement disclosure, or auditing
scope or procedure.
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
(a) The information required by Item 10 with respect to the directors
of the registrant is included under the caption "Election of
Directors" on pages 1 through 4 of TECO Energy's definitive proxy
s t a tement, dated March 4, 1999, for its Annual Meeting of
Shareholders to be held on April 21, 1999 (Proxy Statement) and is
incorporated herein by reference.
(b) The information required by Item 10 concerning executive officers
of the registrant is included under the caption "Executive Officers
of the Registrant" on pages 23 and 24 of this report.
Item 11. EXECUTIVE COMPENSATION.
The information required by Item 11 is included in the Proxy
Statement beginning on page 9 and ending just before the caption
"Shareholder Proposal" on page 12 and under the caption "Compensation
of Directors" on page 4, and is incorporated herein by reference.
Item 12. S E CURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT.
The information required by Item 12 is included under the
caption "Share Ownership" on pages 4 and 5 of the Proxy Statement and
is incorporated herein by reference.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information required by Item 13 is included under the caption
"Election of Directors" on page 3 of the Proxy Statement and is
incorporated herein by reference.
83
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K.
(a) 1. Financial Statements - See index on page 52
2. Financial Statement Schedules - See index on page 52
3. Exhibits
*3.1 Articles of Incorporation, as amended on April 20, 1993
(Exhibit 3, Form 10-Q for the quarter ended March 31,
1993 of TECO Energy, Inc.).
*3.2 Bylaws, as amended effective May 1, 1998 (Exhibit 3,
Form 10-Q for the quarter ended June 30, 1998 of TECO
Energy, Inc.).
*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-1, 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 TECO Energy, Inc.).
*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 of TECO Energy, Inc.).
*4.5 Installment Purchase and Security Contract between the
Hillsborough County Industrial Development Authority and
Tampa Electric Company, dated as of March 1, 1972
(Exhibit 4.9, Form 10-K for 1986 of TECO Energy, Inc.).
*4.6 First Supplemental Installment Purchase and Security
Contract, dated as of Dec. 1, 1974 (Exhibit 4.10, Form
10-K for 1986 of TECO Energy, Inc.).
*4.7 Third Supplemental Installment Purchase Contract, dated
as of May 1, 1976 (Exhibit 4.12, Form 10-K for 1986 of
TECO Energy, Inc.).
*4.8 Installment Purchase Contract between the Hillsborough
C o unty Industrial Development Authority and Tampa
Electric Company, dated as of Aug. 1, 1981 (Exhibit
4.13, Form 10-K for 1986 of TECO Energy, Inc.).
*4.9 Amendment to Exhibit A of Installment Purchase Contract,
dated April 7, 1983 (Exhibit 4.14, Form 10-K for 1989
of TECO Energy, Inc.).
*4.10 Second Supplemental Installment Purchase Contract, dated
as of June 1, 1983 (Exhibit 4.11, Form 10-K for 1994 of
TECO Energy, Inc.).
*4.11 Third Supplemental Installment Purchase Contract, dated
as of Aug. 1, 1989 (Exhibit 4.16, Form 10-K for 1989 of
TECO Energy, Inc.).
*4.12 Installment Purchase Contract between the Hillsborough
C o unty Industrial Development Authority and Tampa
Electric Company, dated as of Jan. 31, 1984 (Exhibit
4.13, Form 10-K for 1993 of TECO Energy, Inc.).
*4.13 First Supplemental Installment Purchase Contract, dated
as of Aug. 2, 1984 (Exhibit 4.14, Form 10-K for 1994 of
TECO Energy, Inc.).
84
*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 of TECO Energy, Inc.).
*4.15 Loan and Trust Agreement among the Hillsborough County
Industrial Development Authority, Tampa Electric Company
and NCNB National Bank of Florida, as trustee, dated as
of Sept. 24, 1990 (Exhibit 4.1, Form 10-Q for the
quarter ended Sept. 30, 1990 for TECO Energy, Inc.).
*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 TECO Energy, Inc.).
*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 TECO Energy, Inc.).
*4.18 Installment Sales Agreement between the Plaquemines
Port, Harbor and Terminal District (Louisiana) and
Electro-Coal Transfer Corporation, dated as of Sept. 1,
1985 (Exhibit 4.19, Form 10-K for 1986 of TECO Energy,
Inc.).
*4.19 Reimbursement Agreement between TECO Energy, Inc. and
Electro-Coal Transfer Corporation, dated as of March 22,
1989 (Exhibit 4.19, Form 10-K for 1988 of TECO Energy,
Inc.).
*4.20 Rights Agreement between TECO Energy, Inc. and The First
National Bank of Boston, as Rights Agent, dated as of
April 27, 1989 (Exhibit 4, Form 8-K, dated as of May 2,
1989 of TECO Energy, Inc.).
*4.21 Amendment No. 1 to Rights Agreement dated as of July 20,
1993 between TECO Energy Inc. and the First National
Bank of Boston, as Rights Agent (Exhibit 1.2, Form 8-
A/A, dated as of July 27, 1993 of TECO Energy, Inc.).
*4.22 Renewed Rights Agreement between TECO Energy, Inc. and
BankBoston, N.A. as Rights Agent, dated as of Oct. 21,
1998 (Exhibit 4, Form 8-K dated Oct. 31, 1998 of TECO
Energy, Inc.).
*4.23 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 4.22, Form 10-K for 1996 of TECO
Energy, Inc.).
*4.24 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 10-Q for the quarter ended
June 30, 1998 of TECO Energy, Inc.).
*4.25 First Supplemental Indenture dated as of Sept. 1, 1998
between TECO Energy, Inc. and The Bank of New York, as
trustee (Exhibit 4.1, Form 8-K dated Sept. 11, 1998 of
TECO Energy, Inc.).
*10.1 1980 Stock Option and Appreciation Rights Plan, as
amended on July 18, 1989 (Exhibit 28.1, Form 10-Q for
quarter ended June 30, 1989 of TECO Energy, Inc.).
*10.2 S u pplemental 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.).
85
*10.3 Supplemental Executive Retirement Plan for R. H. Kessel,
as amended and restated as of Jan. 15, 1997 (Exhibit
10.5, Form 10-K for 1996 of TECO Energy, Inc.).
*10.4 TECO Energy Group Supplemental Executive Retirement
Plan, as amended and restated as of Oct. 16, 1996
(Exhibit 10.6, Form 10-K for 1996 of TECO Energy, Inc.).
*10.5 TECO Energy Group Supplemental Retirement Benefits Trust
Agreement as amended and restated as of Jan. 15, 1997
(Exhibit 10.7, Form 10-K for 1996 of TECO Energy, Inc.).
10.6 Annual Incentive Compensation Plan for TECO Energy and
subsidiaries, as revised Jan. 20, 1999.
*10.7 TECO Energy Group Supplemental Disability Income Plan,
dated as of March 20, 1989 (Exhibit 10.22, Form 10-K for
1988 of TECO Energy, Inc.).
*10.8 Forms of Severance Agreement 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 TECO Energy, Inc.).
*10.9 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.).
*10.10 Loan and Stock Purchase Agreement between TECO Energy,
Inc. and Barnett Banks Trust Company, N.A., as trustee
of the TECO Energy Group Savings Plan Trust Agreement
(Exhibit 10.3, Form 10-Q for the quarter ended March 31,
1990 for TECO Energy, Inc.).
*10.11 Supplemental Executive Retirement Plan for A.D. Oak, as
amended and restated effective as of Oct. 16, 1996
(Exhibit 10.14, Form 10-K for 1996 of TECO Energy,
Inc.).
*10.12 S u pplemental Executive Retirement Plan for G. F.
Anderson, as amended and restated effective as of Oct.
16, 1996 (Exhibit 10.17, Form 10-K for 1996 of TECO
Energy, Inc.).
*10.13 TECO Energy Directors' Deferred Compensation Plan, as
amended and restated effective as of April 1, 1994
(Exhibit 10.1, Form 10-Q for the quarter ended March 31,
1994 for TECO Energy, Inc.).
10.14 TECO Energy Group Retirement Savings Excess Benefit
Plan, as amended and restated effective as of July 15,
1998.
*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 1996 of TECO Energy,
Inc.).
*10.16 TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit
10.1, Form 10-Q for the quarter ended March 31, 1996 of
TECO Energy, Inc.).
*10.17 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 TECO Energy,
Inc.).
*10.18 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 TECO Energy, Inc.).
*10.19 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 TECO Energy, Inc.).
86
*10.20 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 TECO Energy, Inc.).
*10.21 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 TECO Energy, Inc.).
*10.22 TECO Energy, Inc. 1997 Director Equity Plan (Exhibit
10.1, Form 8-K dated April 16, 1997 of TECO Energy,
Inc.).
*10.23 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 TECO Energy,
Inc.).
*10.24 Supplemental Executive Retirement Plan for R. K. Eustace
as of Jan. 15, 1997 (Exhibit 10.24, Form 10-K for 1997
of TECO Energy, Inc.).
12. Ratio of Earnings to Fixed Charges.
21. Subsidiaries of the Registrant.
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 TECO Energy, Inc. were
filed under Commission File No. 1-8180.
Executive Compensation Plans and Arrangements
Exhibits 10.1 through 10.9 and 10.11 through 10.24 above are
management contracts or compensatory plans or arrangements in which
executive officers or directors of TECO Energy, Inc. participate.
Certain instruments defining the rights of holders of long-term
d e bt of TECO Energy, Inc. and its consolidated subsidiaries
authorizing in each case a total amount of securities not exceeding
10 percent of total assets on a consolidated basis are not filed
herewith. TECO Energy, Inc. will furnish copies of such instruments
to the Securities and Exchange Commission upon request.
(b) TECO Energy, Inc. filed the following reports on Form 8-K during
the last quarter of 1998.
The registrant filed a Current Report on Form 8-K dated Oct. 21,
1998 reporting under "Item 5. Other Events" the renewal of its
existing shareholder rights plan.
The registrant filed a Current Report on Form 8-K dated Dec. 17,
1998 reporting under "Item 5. Other Events" fourth quarter 1998
earnings expectations.
87
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.
TECO ENERGY, INC.
By G. F. ANDERSON*
G. F. ANDERSON, Chairman of the Board,
President 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, President,
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
R. L. RYAN* Director
R. L. RYAN
88
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
89
INDEX TO EXHIBITS
Exhibit Page
No. Description No.
3.1 Articles of Incorporation, as amended on *
April 20, 1993 (Exhibit 3, Form 10-Q for the
quarter ended March 31, 1993 of TECO Energy,
Inc.).
3.2 Bylaws, as amended effective May 1, 1998 (Exhibit 3, *
Form 10-Q for the quarter ended June 30, 1998 of
TECO Energy, Inc.).
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-1,
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
TECO Energy, Inc.).
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 of TECO
Energy, Inc.).
4.5 Installment Purchase and Security Contract *
between the Hillsborough County Industrial
Development Authority and Tampa Electric Company,
dated as of March 1, 1972 (Exhibit 4.9, Form 10-K
for 1986 of TECO Energy, Inc.).
4.6 First Supplemental Installment Purchase and *
Security Contract, dated as of Dec. 1, 1974
(Exhibit 4.10, Form 10-K for 1986 of TECO Energy,
Inc.).
4.7 Third Supplemental Installment Purchase *
Contract, dated as of May 1, 1976 (Exhibit 4.12,
Form 10-K for 1986 of TECO Energy, Inc.).
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
TECO Energy, Inc.).
4.9 Amendment to Exhibit A of Installment *
Purchase Contract, dated April 7, 1983 (Exhibit
4.14, Form 10-K for 1989 of TECO Energy, Inc.).
4.10 Second Supplemental Installment Purchase *
Contract, dated as of June 1, 1983 (Exhibit 4.11,
Form 10-K for 1994 of TECO Energy, Inc.).
4.11 Third Supplemental Installment Purchase *
Contract, dated as of Aug. 1, 1989 (Exhibit 4.16,
Form 10-K for 1989 of TECO Energy, Inc.).
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 TECO Energy, Inc.).
4.13 First Supplemental Installment Purchase *
Contract, dated as of Aug. 2, 1984 (Exhibit 4.14,
90
Form 10-K for 1994 of TECO Energy, Inc.).
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 of TECO
Energy, Inc.).
4.15 Loan and Trust Agreement among the Hillsborough *
County Industrial Development Authority, Tampa
Electric Company and NCNB National Bank of
Florida, as trustee, dated as of Sept. 24, 1990
(Exhibit 4.1, Form 10-Q for the quarter ended
Sept. 30, 1990 for TECO Energy, Inc.).
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 TECO Energy, Inc.).
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 TECO Energy, Inc.).
4.18 Installment Sales Agreement between the *
Plaquemines Port, Harbor and Terminal District
(Louisiana) and Electro-Coal Transfer
Corporation, dated as of Sept. 1, 1985 (Exhibit
4.19, Form 10-K for 1986 of TECO Energy, Inc.).
4.19 Reimbursement Agreement between TECO Energy, *
Inc. and Electro-Coal Transfer Corporation, dated
as of March 22, 1989 (Exhibit 4.19, Form 10-K for
1988 of TECO Energy, Inc.).
4.20 Rights Agreement between TECO Energy, Inc. *
and The First National Bank of Boston, as Rights
Agent, dated as of April 27, 1989 (Exhibit 4,
Form 8-K, dated as of May 2, 1989 of TECO Energy,
Inc.).
4.21 Amendment No. 1 to Rights Agreement dated as *
of July 20, 1993 between TECO Energy Inc. and the
First National Bank of Boston, as Rights Agent
(Exhibit 1.2, Form 8-A/A, dated as of July 27,
1993 of TECO Energy, Inc.).
4.22 Renewed Rights Agreement between TECO Energy, *
Inc. and BankBoston, N.A. as Rights Agent, dated
as of Oct. 21, 1998 (Exhibit 4, Form 8-K dated
Oct. 31, 1998 of TECO Energy, Inc.).
4.22 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 4.22, Form 10-K for
1996 of TECO Energy, Inc.).
4.24 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 10-Q for
the quarter ended June 30, 1998 of TECO Energy,
Inc.).
4.25 First Supplemental Indenture dated as of Sept. *
1, 1998 between TECO Energy, Inc. and The Bank of
New York, as trustee (Exhibit 4.1, Form 8-K dated
Sept. 11, 1998 of TECO Energy, Inc.).
91
10.1 1980 Stock Option and Appreciation Rights *
Plan, as amended on July 18, 1989 (Exhibit 28.1,
Form 10-Q for quarter ended June 30, 1989 of TECO
Energy, Inc.).
10.2 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.).
10.3 Supplemental Executive Retirement Plan for *
R. H. Kessel, as amended and restated as of Jan.
15, 1997 (Exhibit 10.5, Form 10-K for 1996 of
TECO Energy, Inc.).
10.4 TECO Energy Group Supplemental Executive Retirement *
Plan, as amended and restated as of Oct. 16, 1996
(Exhibit 10.6, Form 10-K for 1996 of TECO Energy,
Inc.)
10.5 TECO Energy Group Supplemental Retirement Benefits *
Trust Agreement, as amended and restated as of
Jan. 15, 1997 (Exhibit 10.7, Form 10-K for 1996
of TECO Energy, Inc.).
10.6 Annual Incentive Compensation Plan for 94
TECO Energy and subsidiaries, as revised Jan. 20,
1999.
10.7 TECO Energy Group Supplemental Disability Income *
Plan, dated as of March 20, 1989 (Exhibit 10.22,
Form 10-K for 1988 of TECO Energy, Inc.).
10.8 Forms of Severance Agreement 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
TECO Energy, Inc.).
10.9 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.).
10.10 Loan and Stock Purchase Agreement between *
TECO Energy, Inc. and Barnett Banks Trust
Company, N.A., as trustee of the TECO Energy
Group Savings Plan Trust Agreement (Exhibit 10.3,
Form 10-Q for the quarter ended March 31, 1990
for TECO Energy, Inc.).
10.11 Supplemental Executive Retirement Plan *
for A. D. Oak, as amended and restated effective
as of Oct. 16, 1996 (Exhibit 10.14, Form 10-K for
1996 of TECO Energy, Inc.).
10.12 Supplemental Executive Retirement Plan *
for G. F. Anderson, as amended and restated
effective as of Oct. 16, 1996 (Exhibit 10.17,
Form 10-K for 1996 of TECO Energy, Inc.).
10.13 TECO Energy Directors' Deferred Compensation Plan, *
as amended and restated effective as of April 1, 1994
(Exhibit 10.1, Form 10-Q for the quarter ended
March 31, 1994 for TECO Energy, Inc.).
10.14 TECO Energy Group Retirement Savings Excess Benefit 98
Plan, as amended and restated effective as of July 15,
1998.
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 1996 of TECO Energy,
Inc.).
92
10.16 TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit *
10.1, Form 10-Q for the quarter ended March 31, 1996
of TECO Energy, Inc.).
10.17 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 TECO
Energy, Inc.).
10.18 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 TECO
Energy, Inc.).
10.19 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 TECO Energy, Inc.).
10.20 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 TECO Energy, Inc.).
10.21 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
TECO Energy, Inc.).
10.22 TECO Energy, Inc. 1997 Director Equity Plan *
(Exhibit 10.1, Form 8-K dated April 16, 1997 of
TECO Energy, Inc.).
10.23 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 TECO Energy, Inc.).
10.24 Supplemental Executive Retirement Plan for R. K. *
Eustace as of Jan. 15, 1997 (Exhibit 10.24, Form
10-K for 1997 of TECO Energy, Inc.).
12. Ratio of Earnings to Fixed Charges. 105
21. Subsidiaries of the Registrant. 106
23. Consent of Independent Accountants. 107
24.1 Power of Attorney. 108
24.2 Certified copy of resolution authorizing Power of
Attorney. 110
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 TECO Energy, Inc. were filed under Commission
File No. 1-8180.
93