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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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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, 2000
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.
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(Exact name of registrant as specified in its charter)
FLORIDA 59-2052286
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
TECO PLAZA
702 N. FRANKLIN STREET
TAMPA, FLORIDA 33602
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (813) 228-4111
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Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
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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 March 23, 2001 was $3,568,883,947.
The number of shares of the registrant's common stock outstanding as of March
23, 2001 was 135,184,998.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Definitive Proxy Statement relating to the 2001 Annual Meeting
of Shareholders of the registrant are incorporated by reference into Part III.
Index to Exhibits appears on page 74
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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 Company 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.
TECO Energy's significant business segments are identified below:
-- Tampa Electric Company, a Florida corporation and TECO Energy's
largest subsidiary, through its Tampa Electric division (Tampa Electric)
provides retail electric service to more than 568,000 customers in West Central
Florida with a net system generating capability of 3,960 megawatts (MW). Peoples
Gas System, a 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 Florida. PGS was merged
into Tampa Electric Company as part of the 1997 acquisition of Lykes Energy,
Inc. (the Peoples companies) by TECO Energy. With more than 262,000 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 2000 was 1.1 billion 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 eight subsidiaries that
own mineral rights, and own or operate surface and underground mines, synthetic
fuel facilities, and coal processing and loading facilities in Kentucky,
Tennessee and Virginia.
-- TECO Power Services Corporation (TECO Power Services), a Florida
corporation, has subsidiaries that have interests in independent power projects
in Florida, Virginia, Hawaii, Arkansas, Mississippi, Texas, Arizona and
Guatemala, and has investments in unconsolidated affiliates that participate in
independent power projects and electric distribution 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.
-- TECO Solutions, Inc. (TECO Solutions) a Florida corporation, has
subsidiaries that provide engineering and energy services to customers
primarily in Florida and in California, mechanical contracting, air
conditioning, electrical and plumbing systems and repair and maintenance
services in Florida and gas management and marketing services to large
municipal, industrial and power generation customers.
For financial information regarding TECO Energy's significant business
segments, see NOTE L, SEGMENT INFORMATION, on pages 61 through 63.
TECO Energy and its subsidiaries had 5,872 employees as of Dec. 31,
2000.
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.
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Tampa Electric had 2,885 employees as of Dec. 31, 2000, of which 1,019
were represented by the International Brotherhood of Electrical Workers (IBEW)
and 347 by the Office and Professional Employees International Union (OPEIU).
In 2000, approximately 45 percent of Tampa Electric's total operating
revenue was derived from residential sales, 28 percent from commercial sales, 9
percent from industrial sales and 18 percent from other sales including bulk
power sales for resale.
The sources of operating revenue and megawatt-hour sales for the years
indicated were as follows:
OPERATING REVENUE
(millions) 2000 1999 1998
--------- --------- ---------
Residential $ 613.3 $ 557.4 $ 563.2
Commercial 377.1 345.5 335.2
Industrial-Phosphate 61.6 54.2 59.3
Industrial-Other 62.6 56.2 53.4
Other retail sales of electricity 95.0 86.8 86.9
Sales for resale 109.1 86.1 89.6
Deferred revenues -- (11.9) 38.3
Other 35.1 25.5 8.7
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$ 1,353.8 $ 1,199.8 $ 1,234.6
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MEGAWATT-HOUR SALES
(thousands) 2000 1999 1998
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Residential 7,369 6,967 7,050
Commercial 5,541 5,336 5,173
Industrial 2,390 2,224 2,520
Other retail sales of electricity 1,338 1,278 1,284
Sales for resale 2,564 2,160 2,486
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19,202 17,965 18,513
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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. IMC-Agrico, a large
phosphate producer, is Tampa Electric's largest customer representing less than
3 percent of Tampa Electric's 2000 base revenues.
Tampa Electric's business is not highly seasonal, 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,
quality of service and reliability, 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, plus 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,
deferred income taxes at a zero cost rate and an allowed return on common
equity. Base rates are determined in FPSC rate 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 in the UTILITY REGULATION -- RATE STABILIZATION STRATEGY section
on page 32.
Fuel, purchased power, conservation and certain environmental costs
are recovered through levelized monthly charges established pursuant to the
FPSC's cost recovery clauses. These charges, which are reset annually in an
FPSC proceeding, are based on estimated costs of fuel, environmental
compliance, conservation programs and purchased power and estimated customer
usage for a specific recovery period, with a true-up adjustment to reflect the
variance of actual costs from the projected charges. 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. See UTILITY REGULATION -- REGIONAL TRANSMISSION
ORGANIZATION section on pages 33 and 34.
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Federal, state and local environmental laws and regulations cover air
quality, water quality, land use, power plant, substation and transmission line
siting, noise and aesthetics, solid waste and other environmental matters. See
ENVIRONMENTAL MATTERS on page 6.
TECO Transport's and TECO Power Services' subsidiaries sell
transportation services, and generating capacity and energy, respectively, to
Tampa Electric in addition to other 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 be disallowed for recovery from Tampa Electric's
customers. See UTILITY REGULATION on pages 32 through 34. Except for
transportation services performed by TECO Transport under the U.S. bulk cargo
preference program, the prices charged by TECO Transport to third-party
customers are not subject to regulatory oversight. See also TECO POWER SERVICES
on pages 11 and 12.
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 residential and commercial
customers and self-generation which is 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 1999, the Federal Energy Regulatory Commission (FERC) approved a
market-based sales tariff for Tampa Electric which allows Tampa Electric to sell
excess power at market prices within Florida. The FERC had already approved
market-based prices for interstate sales for Tampa Electric and the other
investor-owned utilities (IOUs) operating in the state; however, Tampa Electric
is the only IOU with intrastate market-based sales authority.
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. This rule works together
to open access for wholesale power flows on transmission systems. Utilities
such as Tampa Electric owning transmission facilities are required to provide
services to wholesale transmission customers comparable to those they provide
to themselves on comparable terms and conditions including price. Among other
things, the rules require transmission services to be unbundled from power
sales and owners of transmission systems must take transmission service under
their own transmission tariffs.
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 December 1999, the FERC issued Order No. 2000, dealing with Regional
Transmission Organizations (RTOs). This rule is driven by the FERC's continuing
effort to effect open access to transmission facilities in large, regional
markets. In an October 2000 FERC filing, Tampa Electric agreed with the other
IOUs operating in Florida to form an RTO to be known as GridFlorida LLC. As
proposed, the RTO will independently control the transmission assets of the
filing utilities, as well as other utilities in the region that choose to join.
The RTO will be an independent, investor-owned organization that will have
control of the planning and operations of the bulk power transmission systems of
the utilities within peninsular Florida. The three filing utilities represent
almost 80 percent of the aggregate net energy load in the region for the year
2000. Tampa Electric has filed to inform the FERC that it planned to contribute
its transmission assets to the RTO. See UTILITY REGULATION -- REGIONAL
TRANSMISSION ORGANIZATION section on pages 33 and 34 for a further description.
Florida Governor Jeb Bush established the 2020 Energy Study Commission
in 2000 to address several issues by December 2001, including current and
future reliability of electric and natural gas supply, emerging energy supply
and delivery options, electric industry competition, environmental impacts of
energy supply, energy conservation and fiscal impacts of energy supply options
on taxpayers and energy providers. The Study Commission's recent recommendation
to Governor Bush includes, among other provisions, elimination of barriers to
entry for merchant power generators, an open competitive wholesale electric
market, transfer of regulated generating assets to unregulated affiliates or
sale to others, Florida electric system reliability and consumer protection.
See UTILITY COMPETITION: ELECTRIC on page 33 for a further description of
proposed projects and the issues involved.
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FUEL
Approximately 97 percent of Tampa Electric's generation for 2000 was
coal-fired, with oil and natural gas representing the remaining 2-percent and
1-percent, respectively. Tampa Electric used its generating units to meet
approximately 86-percent of the system load requirements with the remaining
14-percent coming from purchased power. A slightly lower level of coal
generation as a percentage of total generation is anticipated for 2001.
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: 2000 1999 1998 1997 1996
-------------------- ------ ------ ------ ------ ------
Coal $ 1.92 $ 2.00 $ 1.99 $ 1.97 $ 2.01
Oil $ 5.33 $ 3.09 $ 3.14 $ 3.76 $ 3.68
Gas (Natural) $ 5.49 -- -- -- --
Composite $ 2.07 $ 2.03 $ 2.03 $ 2.01 $ 2.05
AVERAGE COST PER TON
OF COAL BURNED $44.36 $44.63 $44.44 $44.50 $46.71
Tampa Electric's generating stations burn fuels as follows: Gannon
Station burns low-sulfur coal; Big Bend Station, which has sulfur dioxide
scrubber capabilities, 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, natural gas and oil;
Hookers Point Station burns low-sulfur oil; and Phillips Station burns oil of a
somewhat higher sulfur content.
COAL. Tampa Electric used approximately 7.6 million tons of coal
during 2000 and estimates that its coal consumption will be about 7.5 million
tons for 2001. During 2000, Tampa Electric purchased approximately 61 percent
of its coal under long-term contracts with five suppliers, and 39 percent of
its coal in the spot market. During 1999, Tampa Electric purchased
approximately 64 percent of its coal under long-term contracts with six
suppliers, and 36 percent of its coal in the spot market or under
intermediate-term purchase agreements. Tampa Electric expects to obtain
approximately 54 percent of its coal requirements in 2001 under long-term
contracts with five suppliers and the remaining 46 percent in the spot market.
Tampa Electric's remaining 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 9 and 10 and TECO COAL on page 10.
In 2000, about 65 percent of Tampa Electric's coal supply was
deep-mined, approximately 31 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 of any future mining laws and regulations. Although there
are reserves of surface-minable 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.
OIL. Tampa Electric had supply agreements through Dec. 31, 2000 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, 2001 are expected to be finalized by March 31, 2001.
NATURAL GAS. As of December 2000, Tampa Electric had no gas contracts
for the Polk 2 Unit as purchases were made on the spot market.
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 may choose to exercise its 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 or, if arbitration is
unsuccessful, by eminent domain. 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.
Franchise fees payable by Tampa Electric, which totaled $22.3 million
in 2000, are calculated using a formula based primarily on electric revenues.
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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, respectively.
ENVIRONMENTAL MATTERS
Tampa Electric met the environmental compliance requirements for 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 flue gas desulfurization (FGD), or scrubber,
system with Unit Three, implementing operational modifications and purchasing
emission allowances. For Phase II, which began Jan. 1, 2000, further reductions
in sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions were required. To
comply with the Phase II SO2 requirements, Tampa Electric installed a new
scrubber system at Big Bend Units One and Two and will rely less on fuel
blending and SO2 allowance purchases. The $83-million scrubber was placed in
service on Dec. 30, 1999 and has significantly reduced the amount of SO2 emitted
by Tampa Electric's Big Bend Units One and Two. As a result of this project, all
of the units at Big Bend Station, Tampa Electric's largest generating station,
are equipped with scrubber technology. In order to comply with the Phase II NOx
emission limits on a system wide average, Tampa Electric has implemented
combustion optimization projects at Big Bend and Gannon stations.
On Feb. 29, 2000, Tampa Electric Company, the U.S. Environmental
Protection Agency (EPA) and the U.S. Department of Justice announced they had
resolved the federal agencies' pending enforcement actions filed in 1999
against Tampa Electric. The resolution was in the form of a consent decree,
which became effective Oct. 5, 2000 and has resulted in full and final
settlement of the federal litigation and notice of violation alleging
violations of New Source Review requirements of the Clean Air Act.
The consent decree is substantially the same as Tampa Electric's
earlier agreement with the Florida Department of Environmental Protection (DEP)
with respect to environmental controls and pollution reductions reached on Dec.
7, 1999; however, it contains specific detail with respect to the availability
of the scrubbers and earlier incremental nitrogen oxide NOx reduction efforts
on Big Bend Units One, Two and Three. Under the consent decree, Tampa Electric
is committed to a comprehensive program that will dramatically decrease
emissions from the company's power plants. A significant component of the
program is the repowering of certain Gannon Station units with natural gas.
Engineering for the repowering project began in January 2000, and the
company anticipates that commercial operation for the first repowered unit will
occur by May 1, 2003. The repowering of an additional unit is scheduled to be
completed by May 1, 2004. When these units are repowered, the station will be
renamed the Bayside Power Station and will have an increased total station
capacity of about 1,800 megawatts (nominal) of natural gas-fueled electric
energy.
Tampa Electric filed petitions with the FPSC to seek cost recovery for
various environmental projects required by the consent decree. The petitions
sought cost recovery through the Environmental Cost Recovery Clause for costs
incurred to improve the availability and removal efficiency for its Big Bend
One, Two and Three scrubbers, to reduce particulate matter emissions, and to
reduce NOx emissions. In November, the FPSC approved the recovery of these
types of costs through customers' bills starting January 2001.
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. (See discussion in People's Gas
ENVIRONMENTAL MATTERS section on page 9.) The environmental remediation costs
associated with these sites are not expected to have a significant impact on
customer prices.
EXPENDITURES. During the five years ended Dec. 31, 2000, Tampa
Electric spent $178.0 million on capital additions to meet environmental
requirements. Tampa Electric spent an estimated $13.2 million in 2000 on
environmental projects, including $6.3 million for Polk Power Station Unit One.
Environmental expenditures are estimated at $17.4 million for 2001.
Environmental expenditures are estimated at $27.0 million in total for 2002
through 2005, including costs for continued improvement of the FGD system and
other requirements of the EPA agreement.
The completion of the FGD system on Big Bend Units One and Two and the
improved environmental performance resulting from combustion tuning and boiler
modifications at Gannon and Big Bend Stations have enabled Tampa Electric to
reduce SO2 and NOx emissions and comply with the Phase II requirements of the
Clean Air Act Amendments. Tampa Electric spent approximately $83 million to
complete the Big Bend Units One and Two FGD system to reduce SO2 emissions and
approximately $10 million for NOx reductions.
PEOPLES GAS SYSTEM--GAS OPERATIONS
Peoples Gas System, Inc.(PGS) operates as the Peoples Gas System
division of Tampa Electric Company. PGS is engaged in the purchase,
distribution and sale of natural gas for residential, commercial, industrial
and electric power generation customers in the State of Florida.
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PGS uses two interstate pipelines to receive gas 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 almost 260,000 customers. The
system includes approximately 8,200 miles of mains and over 4,200 miles of
service lines.
In 2000, the total throughput for PGS was 1.1 billion therms. Of this
total throughput, 20 percent was gas purchased and resold to retail customers
by PGS, 72 percent was third party supplied gas delivered for retail customers,
and 8 percent was gas sold off-system. Industrial and power generation
customers consumed approximately 69 percent of PGS' annual therm volume.
Commercial customers used approximately 26 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 23 percent of
total revenues. New residential construction and conversions of existing
residences to gas have steadily increased since the late 1980's.
Natural gas has historically been used in many traditional industrial
and commercial operations throughout Florida, including production of products
such as steel, glass, ceramic tile and food products. Gas climate control
technology is expanding throughout Florida, and commercial/industrial customers
including schools, hospitals, office complexes and churches are utilizing this
technology.
Within the PGS operating territory, large cogeneration facilities
utilize gas-fired technology in the production of electric power and steam.
Over the past three years, the company has transported, on average, about 264
million therms annually to facilities involved in cogeneration.
Revenues and therms for PGS for the years ended Dec. 31, are as follows:
Revenues Therms
(millions) 2000 1999 1998 2000 1999 1998
---------------- ------- ------- ------- ------- ------- -------
Residential $ 73.2 $ 59.0 $ 57.7 57.6 52.1 52.7
Commercial 145.8 125.5 141.2 292.1 273.5 266.0
Industrial 51.7 29.3 20.9 374.1 331.9 305.0
Power Generation 10.7 10.4 10.4 418.6 405.2 288.3
Other revenues 33.0 27.5 22.6 -- -- --
------- ------- ------- ------- ------- -------
Total $ 314.4 $ 251.7 $ 252.8 1,142.4 1,062.7 912.0
======= ======= ======= ======= ======= =======
PGS had 697 employees as of Dec. 31, 2000. A total of 75 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 Company's electric operations. The FPSC has
jurisdiction over rates, service, issuance of 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, plus a reasonable return on invested capital.
The basic costs of providing natural gas service, other than the costs
of purchased gas and interstate pipeline capacity, are recovered through base
rates. Base rates 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 rates are determined in FPSC proceedings which occur at
irregular intervals at the initiative of PGS, the FPSC or other parties.
PGS recovers the costs it pays for gas supply and interstate
transportation for system supply through the Purchased Gas Adjustment (PGA)
clause. 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 are adjusted
monthly based on a cap approved annually in an FPSC hearing. The cap is 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 2000, PGS received FPSC approval for a mid-course adjustment to raise the cap
due to the increased cost of gas supply. In January 2001, PGS notified the FPSC
that it anticipated that its PGA factors approved in December 2000 for 2001 were
understated by approximately $63 million due to significantly higher natural gas
prices. In February 2001, the FPSC approved PGS' request to increase rates to
cover $63 million under-recovery beginning in March 2001.
In addition to its base rates and purchased gas adjustment clause
charges 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 PGS in developing and implementing energy conservation
programs, which are mandated by Florida law and approved and supervised by the
FPSC. PGS is permitted to recover, on a dollar-for-dollar basis, expenditures
made in connection with these programs if
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it demonstrates that the programs are cost effective for its ratepayers.
In February 2000, the FPSC approved a rule that would require natural
gas utilities to offer transportation-only service to all non-residential
customers. The rule required all investor-owned local distribution utilities
under the jurisdiction of the FPSC to file Transportation Program Tariffs in
July, 2000. The FPSC approved PGS' transportation program effective Nov. 1,
called NaturalChoice.
Under the NaturalChoice program, PGS has two Transportation Service
Riders available to non-residential customers. PGS' new Rider NCTS (Natural
Choice Transportation Service) is an aggregation program available to all
non-residential customers. Under Rider NCTS, PGS contracts with gas suppliers,
called Pool Managers, to deliver gas to a group of commercial customers. The
Pool Manager is financially responsible for its customers' gas plus any
penalties. Under PGS' Rider ITS (Individual Transportation Service), customers
who use more than 500,000 therms annually may contract directly with PGS to
deliver their own gas supply. Customers who previously were transporting under
Riders FTA and FTA-2 were transitioned to the new NCTS Transportation Service
as of Nov. 1, 2000.
PGS had approximately 4,500 transportation customers as of Dec. 31,
2000. PGS continues to receive its base rate for distribution regardless of
whether a customer decided to opt for transportation service, or continue
bundled service. It is, therefore, not expected that unbundling will have an
adverse effect on PGS' earnings in the future.
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 propane. PGS has taken actions to
retain and expand its commodity and transportation business, including managing
costs and providing high quality service to customers. The NCTS program that
began in November 2000 is expected to improve the competitiveness of natural
gas for commercial load.
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 alternate fuels or transport gas through
other facilities, 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 customers who use more than 100,000
therms annually.
GAS SUPPLIES
PGS purchases gas from various suppliers depending on the needs of its
customers. The gas is delivered to the PGS distribution system through two
interstate pipelines on which PGS has reserved firm transportation capacity for
further delivery by PGS to its customers.
Gas is delivered by Florida Gas Transmission Company (FGT) through
more than 45 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 distribution system and on abnormally cold days.
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 with various suppliers 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.
Neither PGS nor any of the interconnected interstate pipelines have
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
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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, or at a published index price, and in either case
pays the customer for charges incurred for interstate pipeline transportation
to the PGS system.
FRANCHISES
PGS holds franchise and other rights with approximately 90
municipalities throughout Florida. These include the cities of Jacksonville,
Daytona Beach, Eustis, Fort Myers, Brooksville, Orlando, Tampa, St. Petersburg,
Sarasota, Avon Park, Frostproof, Palm Beach Gardens, Pompano Beach, Fort
Lauderdale, Hollywood, North Miami, Miami Beach, Miami, and Panama City. These
franchises give PGS a right to occupy municipal rights-of-way within the
franchise area. 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 may choose to exercise its 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 or, if arbitration is
unsuccessful, by eminent domain. In addition, several franchises contain
purchase options with respect to the purchase of PGS' property located in the
franchise area, if the franchise is not renewed.
PGS' franchise agreements with the incorporated municipalities within
its service area have various expiration dates ranging from April 2001 through
April 2031.
In March 2000, the franchise agreement between the city of Lakeland
(City) and PGS expired. The City has initiated legal proceedings seeking a
declaration of the city's rights to acquire the PGS facilities under the
franchise. PGS has filed defenses and counter claims and a hearing is scheduled
for May 2001. (See LEGAL PROCEEDINGS section for further discussion). While PGS
believes it is best suited to serve the customers in the City, it cannot at
this time predict the ultimate outcome of these activities. PGS is continuing
to serve under substantially the same terms as contained in the franchise in
the absence of other rules and regulations being adopted by the City. The
Lakeland franchise contributed about $4 million of net revenue to PGS' results
in 2000.
Franchise fees payable by PGS, which totaled $7.9 million in 2000, 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.
Utility 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.
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 $22 million over the next 10 years. The environmental remediation
costs associated with these sites are not expected to have a significant impact
on customer prices.
EXPENDITURES. During the five years ended Dec. 31, 2000, PGS has not
incurred any material capital additions to meet environmental requirements, nor
are any anticipated for 2001 through 2005.
TECO TRANSPORT
TECO Transport owns all of the common stock of four subsidiaries which
transport, store and transfer coal and other dry-bulk commodities. These
subsidiaries include Gulfcoast Transit Company (Gulfcoast), Mid-South Towing
Company (Mid-south), Electro-Coal Transfer, LLC (Electro-Coal) and TECO Towing
Company. TECO Transport currently owns no operating assets.
TECO Transport and its subsidiaries had 993 employees as of Dec. 31,
2000.
TECO Transport's subsidiaries perform substantial services for Tampa
Electric. In 2000, approximately 56 percent of TECO Transport's revenues were
from third-party customers and 44 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, generally adjusted quarterly for
changes in certain fuel and price indices. Most of the third-party utilization
of the ocean-going barges 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, phosphate customers, steel industry customers, grain customers,
and participation in the U.S. Department of Agriculture cargo preference
program.
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Gulfcoast transports products in the Gulf of Mexico and worldwide, and
Mid-South operates on the Mississippi, Ohio and Illinois rivers. Their primary
competitors are other barge and shipping lines and railroads as well as 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 ship and 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 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 other land-based terminals.
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
transportation of certain dry-bulk commodities. In 2000, all transportation
services provided by TECO Transport's subsidiaries were within this exemption.
TECO Transport's subsidiaries are subject to the provisions of the
Clean Water Act of 1977 which authorizes the Coast Guard and the 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. In
2000, TECO Transport spent $.3 million for environmental compliance.
Environmental expenditures are estimated at $.3 million in 2001, 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 (Rich Mountain),
Clintwood Elkhorn Mining Company (Clintwood), Pike-Letcher Land Company
(Pike-Letcher,) Premier Elkhorn Coal Company (Premier), Bear Branch Coal
Company (Bear Branch) and Perry County Coal Corporation (Perry County). Rich
Mountain has no reserves; it mines coal reserves owned by Gatliff. TECO Coal's
subsidiaries own mineral rights, and own or operate surface and underground
mines, synthetic fuel facilities and coal processing and loading facilities in
Kentucky, Virginia and Tennessee.
TECO Coal and its subsidiaries had 416 employees as of Dec. 31, 2000.
In 2000, TECO Coal subsidiaries sold 7.9 million tons of coal, with
approximately 98 percent, or 7.7 million tons, sold to third parties other than
Tampa Electric. TECO Coal's long-term contract with Tampa Electric ended in
December 1999. Of the total sold, 1.9 million tons were produced and sold as
synthetic fuel.
In November 2000, TECO Coal acquired Perry County Coal Corporation
(Perry County), which owns or controls in excess of 23 million tons of low
sulfur reserves and operates both deep and surface contract mines along with a
preparation plant and two loadouts. Perry County expects to produce and sell
2.0 million tons of coal in 2001.
In January 2000, TECO Coal purchased two synthetic fuel (synfuel)
facilities which were relocated to the Premier Elkhorn and Clintwood Elkhorn
mines. The 1.9 million tons of synfuel produced in 2000 replaced some of TECO
Coal's conventional coal production in 2000. Synthetic fuel production is
expected to increase somewhat in 2001. Sales of the fuel processed through
these types of facilities are eligible for non-conventional fuels tax credits
under Section 29 of the Internal Revenue Code, which are available through
2007. During the fourth quarter of 2000, the U.S. Treasury suspended advance
rulings by the Internal Revenue Service with respect to synthetic fuel
production facilities to permit the Treasury and the Service time to review
certain specified legal issues regarding the application of this credit. While
no retroactive interpretation of qualification under the program is expected,
the requirements for obtaining advance rulings could include some
production-limiting factors.
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, Tennessee and
Virginia 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 that
would materially affect the market price of coal sold by its subsidiaries.
TECO Coal's subsidiaries are subject to various federal, state and
local air and water pollution standards in their mining operations. In 2000,
approximately $1.7 million was spent on environmental protection and
reclamation programs. TECO Coal expects to spend a similar amount in 2001 on
these programs.
Coal mining operations are also subject to the Surface Mining 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.
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TECO POWER SERVICES
TECO Power Services (TPS) has subsidiaries that have interests in
independent power projects in Florida, Virginia, Hawaii, Mississippi, Arkansas,
Texas, Arizona 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 213 employees as of Dec. 31, 2000.
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 believes it has competed
effectively for independent power investment opportunities in the U.S. and in
Central America.
Like Tampa Electric, the U.S. operations of TPS 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.
Hardee Power Partners (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 in
1993. In 1993, Hardee Power entered into 20-year power supply agreements, for
all 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.
TPS completed a 75-megawatt expansion at the Hardee Power Station in
May 2000. The added capacity at Hardee serves Tampa Electric. The expansion
consists of a General Electric combustion turbine operating in simple-cycle
mode.
In 1996, a TPS affiliate, Central Generadora Electrica San Jose, Ltda.
(CGSE) 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 (the San Jose Power
Station) including port modifications to accommodate the importation of coal.
The total cost for the facility was $194 million. During 2000, construction
financing was converted to $114 million of long-term secured facility notes,
$32 million of which was provided by the Overseas Private Investment
Corporation (OPIC). In 2000, TPS increased its ownership in the project to 100
percent. Political risk insurance has been obtained for currency
inconvertibility, expropriation and political violence covering up to 100
percent of its equity investment and economic returns. This facility is the
first coal-fueled plant in Central America and meets environmental standards
set by the World Bank.
Tampa Centro Americana de Electricidad, Limitada (TCAE), an entity
96-percent owned by TPS Guatemala One, Inc. (TPS Guatemala One), a subsidiary
of TPS, has a U.S. dollar-denominated power sales agreement to provide 78
megawatts of capacity to an electric utility in Guatemala, Empresa Electrica de
Guatemala, S.A. (EEGSA) for a 15-year period ending in 2010. EEGSA is
responsible for providing the fuel for the plant, with TECO Power Services
providing assistance in fuel administration. TPS has obtained from OPIC, $29
million of limited recourse financing for the Alborada Power Station and
political risk insurance for currency inconvertibility, expropriation and
political violence covering up to 100 percent of TPS' equity investment and
economic returns.
EEGSA, a private distribution and generation company formed in 1994,
serves more than 580,000 customers. EEGSA's service territory includes the
capital of Guatemala, Guatemala City. In 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 for $520 million. TPS owns a 30 percent interest in this
consortium and contributed $100 million in equity. The consortium obtained
limited-recourse debt financing for a portion of the purchase price.
In 1998, TPS and Mosbacher Power Partners, Ltd. (Mosbacher Power), an
independent power company headquartered in Houston, created TM Power Ventures
LLC (TMPV), to jointly develop, own and operate domestic and international
independent power projects. Under this arrangement, TPS provides capital and
technical expertise to Mosbacher Power. In 1998, TPS, through TMPV, made
certain loans to two existing projects and acquired approximately a 13-percent
interest in a repowered independent power project in the Czech Republic. TMPV,
NRG Energy, El Paso Energy International and Stredoceske Energeticke Zavody
(STE), a Czech regional distribution company, are owners of the project. The
facility completed its expansion to a total of 344 megawatts in the first
quarter of 2000 and has gone online.
In 1999, TPS, through TMPV, acquired a 95% interest in the
construction and operation of a 312-megawatt power plant on the Delmarva
Peninsula of Virginia. The project will be completed in two phases. The first
phase of 134 megawatts went into service in the third quarter of 2000. The
second phase is expected to go online in the second quarter of 2001.
In 1999, TPS entered into a loan and subscription agreement with
Energia Global International, Ltd. (EGI), a Bermuda based energy development
firm. EGI owns and operates electric generation and cogeneration facilities in
Central and South 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. In December 2000, this loan was
converted into a 33-percent equity interest in EGI.
Also in 1999, TPS announced its 50-percent participation in the
Hamakua Energy Project, a 60-megawatt combined cycle cogeneration facility in
Hamakua, Hawaii. The facility was constructed and placed into service during
2000. TPS and J.A. Jones Ventures jointly own and operate the project under a
30-year power purchase agreement with Hawaii Electric Light Company.
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In September 2000, TPS announced a $93-million investment in the form
of a loan related to Panda Energy International's (Panda) Texas Independent
Energy Projects (TIE). This investment, under certain circumstances, gives TPS
an opportunity for an effective economic interest, estimated at 75-percent, in
Panda's 1,000-megawatt interest in these projects. The projects operate as
gas-fired, combined-cycle units in the ERCOT market. It is anticipated that
they will be brought online in phases beginning in December 2000, with all the
capacity in-service in the third quarter of 2001.
In October 2000, TPS acquired full ownership of two independent power
projects being developed by GenPower LLC in Arkansas and Mississippi. The
combined capacity of the two plants will be nearly 1,200 megawatts. TPS' equity
investment in the projects is expected to be approximately $330 million. The
two 599-megawatt facilities, known as the McAdams and Dell projects, will be
natural gas-fired combined-cycle plants. Both projects will be interconnected
with the Entergy transmission system and will be able to sell electricity to
wholesale customers in the Southeast and Midwest, including the states of
Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee and Kentucky.
Each plant is expected to begin commercial operation during the fourth quarter
of 2002.
In November 2000, TPS announced a joint venture with Panda to build,
own and operate two natural gas power plants located in Arkansas and Arizona.
TPS' economic interest in the project is estimated at 75-percent. The companies
set up the venture to develop two plants in El Dorado, Arkansas, and Gila Bend,
Arizona. The plants have been under development by Panda. The 2,220-megawatt El
Dorado plant is under construction. The first phase is expected to begin
commercial operation in the second half of 2002, with commercial operation of
the entire facility slated for the following year. It is expected to sell power
primarily to utilities and industrial customers in Arkansas, Louisiana, eastern
Texas and Mississippi. The other project, in Gila Bend, Arizona, is in
development. Electricity from the 2,350-megawatt plant, to be located southwest
of Phoenix, is planned to be sold in Arizona, southern California, Nevada and
New Mexico. The TPS equity investment in these projects at commercial operation
is expected to total more than $1 billion.
In March 2001, TPS acquired American Electric Power's (AEP) Frontera
Power Station, located near McAllen, Texas. Frontera is a 500-megawatt natural
gas-fired combined-cycle plant originally developed by CSW Energy (CSW). As a
condition of the merger of Central and South West Corporation, CSW's parent
company, with AEP the company was required by the Federal Energy Regulatory
Commission to divest its ownership of this facility. Frontera is capable of
selling power domestically, as well as into the Mexican power market, through a
direct interconnection with Comision de Federal Electricidad, the Mexican power
authority. The transaction is expected to be immediately accretive to TECO
Energy's earnings. The TPS equity investment in this acquisition is expected to
be about $120 million in 2001.
See the discussion of the risks applicable to TPS in the INVESTMENT
CONSIDERATIONS section on pages 37 through 39.
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 is
the principal investor in three ventures which control, in the aggregate,
approximately 100,000 acres of lease holdings. At the end of 2000, TECO Coalbed
Methane had interests in 736 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 2000, domestic oil prices did not
exceed the $47 per barrel price that would have resulted in this limitation
being 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. From time to time, the company has entered into price swaps to hedge the
price variability on this production. See the discussion in the ACCOUNTING
STANDARDS -- ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING section. TECO
Coalbed Methane's operations are subject to federal, state and local
regulations for air emissions and water and waste disposal.
TECO PROPANE VENTURES
In August 2000, TECO Energy, Inc., Atmos Energy Corporation, Piedmont
Natural Gas Co., Inc., and AGL Resources, Inc. contributed each company's
propane operations to U.S. Propane L.P., (U.S. Propane) in exchange for an
equity interest in U.S. Propane. This transaction was accounted for as an
acquisition using the purchase method of accounting with Peoples Gas being the
acquirer. Accordingly, Peoples Gas' assets and liabilities were recorded at
historical cost and the assets and liabilities of the other companies were
recorded at fair market value, as determined based on a valuation and
appraisal. TECO Propane Ventures was formed in 2000 to hold TECO Energy's
investment in U.S. Propane.
Also in August 2000, U.S. Propane acquired all of the outstanding
common stock of Heritage Holdings, Inc. (HHI), the General Partner of Heritage
Propane Partners, L.P. (MLP) for $120 million. By virtue of HHI's 2% general
partner interest and a 34% limited partner interest in the MLP, U.S. Propane
gained control of the MLP. Simultaneously, U.S. Propane transferred its propane
operations to the MLP for $139.6 million in cash, $31.8 million of assumed
debt, the issuance of 372,392 Common Units of the MLP valued at $7.3 million
and a $2.7 million limited partnership interest in the MLP's operating
partnership. Upon closing of the transaction, US Propane owned all of the
general partner and an approximate 34-percent limited partnership interest in
Heritage Propane Partners, the master limited partnership. Interests in the
general partner of US Propane are held proportionately among the four companies
that created US Propane.
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The transaction was accounted for as a reverse acquisition in
accordance with Accounting Principles Board Opinion No. 16. Although the MLP is
the surviving entity for legal purposes (referred to as Predecessor Heritage),
U.S. Propane's propane operations will be the acquirer for accounting purposes.
The assets and liabilities of Predecessor Heritage will be reflected at fair
value to the extent acquired by U.S. Propane's propane operations,
approximately 36 percent, in accordance with EITF 90-13. The assets and
liabilities of U.S. Propane were reflected at historical costs.
TECO SOLUTIONS
TECO Solutions was formed to support TECO Energy's strategy of
offering customers a comprehensive and competitive package of energy services
and products with its Florida operations focus. Operating companies under TECO
Solutions include TECO BGA, Inc. (formerly Bosek, Gibson and Associates) (TECO
BGA), BCH Mechanical, Inc. and its affiliated companies (BCH), TECO Gas
Services, Inc. (TECO Gas Services), TECO Properties and TECO Partners.
TECO BGA is an engineering energy services company headquartered in
Tampa. It has 9 offices in Florida and one in California, and had 159 employees
as of Dec. 31, 2000.
It provides engineering, construction management and energy services
to more than 400 customers, including public schools, universities, health care
facilities and other governmental facilities throughout Florida and California.
BCH is a mechanical contracting firm headquartered in Largo. It has
offices in Cocoa Beach and Ft. Lauderdale, and had 402 employees as of Dec. 31,
2000. It provides air-conditioning, electrical and plumbing systems, and repair
and maintenance services to more than 750 institutional and commercial customers
throughout Florida. BCH, one of the leading mechanical contracting firms in
Florida, was purchased by TECO Energy in September 2000.
TECO Gas Services provides gas management and marketing services for
large industrial customers. In 2000, it also provided gas management for three
cogeneration facilities. TECO Gas Services owns no operating assets.
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, 2000, Tampa Electric had five electric generating plants
and four combustion turbine units in service with a total net winter generating
capability of 3,960 megawatts, including Big Bend (1,825-MW capability from
four coal units), Gannon (1,230-MW capability from six coal units), Hookers
Point (197-MW capability from five oil units), Phillips (36-MW capability from
two diesel units), Polk (315-MW capability from one integrated gasification
combined cycle unit (IGCC)) and four combustion turbine units located at the
Big Bend, Polk and Gannon stations (357 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.
Engineering for repowering Gannon Station began in January 2000,(see
ENVIRONMENTAL COMPLIANCE section) and the company anticipates that commercial
operation for the first repowered unit will occur by May 1, 2003. The
repowering of an additional unit is scheduled to be completed by May 1, 2004.
When these units are repowered, the station will be renamed the Bayside Power
Station. Total station capacity is expected to increase to about 1,800
megawatts.
Tampa Electric owns 184 substations having an aggregate transformer
capacity of 16,952,772 KVA. The transmission system consists of approximately
1,211 pole miles of high voltage transmission lines, and the distribution
system consists of 6,967 pole miles of overhead lines and 2,927 trench miles of
underground lines. As of Dec. 31, 2000, there were 568,350 meters in service.
All of this property is located in Florida.
All plants and important fixed assets are held in fee except that
title to some of the properties is subject to easements, leases, contracts,
covenants and similar encumbrances and minor defects, of a nature common to
properties of the size and character of those of Tampa Electric.
Tampa Electric has easements for rights-of-way adequate for the
maintenance and operation of its electrical transmission and distribution lines
that are not constructed upon public highways, roads and streets. It has the
power of eminent domain under Florida law for the acquisition of any such
rights-of-way for the operation of transmission and distribution lines.
Transmission and distribution lines located in public ways are maintained under
franchises or permits.
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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 approximately 12,400 miles of pipe, including
approximately 8,200 miles of mains and over 4,200 miles of service lines.
PGS' 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.
As of Dec. 31, 2000, Gulfcoast owned and operated 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 195,000 acres of
coal reserves and mining property in Kentucky, Virginia 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 100 million tons.
Premier owns and operates a preparation plant, unit-train loadout
facility and synthetic fuel 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 68,000 acres of coal reserves held under long-term
leases in Pike County, Kentucky and Buchanan County, Virginia. These properties
contain estimated proven and probable reserves in excess of 42 million tons.
Clintwood owns and operates two rail tipples, coal preparation plants near the
mines and a synthetic fuel facility.
Gatliff has 35,000 acres of coal reserves and mining property in Knox
and Whitley Counties, Kentucky and Campbell County, Tennessee. Gatliff owns
6,000 acres in fee and leases 29,000 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.
Bear Branch controls by long-term lease 22,000 acres in Perry and
Knott Counties, Kentucky, containing approximately 70 million tons of
undeveloped reserves.
Rich Mountain operates a surface mine for Gatliff in Campbell County,
Tennessee, and does not own any coal reserves.
Perry County Coal controls 20,000 acres in fee and leases. These
properties contain in excess of 23 million tons of reserves. Perry County owns
and operates a coal preparation plant and rail tipple facilities.
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.
TM Delmarva, LLC has a 50-percent interest in Commonwealth Chesapeake
Company, LLC, which has a lease for approximately 105 acres of land outside of
New Church, in Accomack County, Virginia on which the 312-megawatt oil-fired
single cycle Commonwealth Chesapeake Power Station is located.
TPS Dell, L.L.C., owns approximately 100 acres in the City of Dell in
Mississippi County, Arkansas, on which the 599-megawatt gas-fired
combined-cycle electric generation plant is under construction.
TPS McAdams, L.L.C., owns approximately 170 acres of land in McAdams
and Sallis, Mississippi, in Attala County, on which the 599-megawatt gas-fired
combined cycle electric generation plant is under construction.
14
15
TPS Hawaii, Inc. has a 50-percent interest in Enserch/Jones Hamakua
Land Partnership, L.L.C. and owns 140 acres in Hawaii on which the Hamakua
Energy Project is located. TPS Guatemala One, Inc. has a 96.06-percent interest
in TCAE, which owns 7 acres in Guatemala on which the Alborada Power Station is
located. TPS San Jose, LDC has a 100-percent ownership in a project entity,
CGESJ, which owns 190 acres in Guatemala on which the San Jose Power Station is
located.
TECO COALBED METHANE
TECO Coalbed Methane's interest in proven gas reserves at Dec. 31,
2000 was independently estimated to be 182 billion cubic feet for 700 wells.
TECO Coalbed Methane's gas production for 2000 was 15.7 billion cubic
feet.
ITEM 3. LEGAL PROCEEDINGS.
On Feb. 29, 2000, Tampa Electric Company, the U.S. Environmental
Protection Agency (EPA) and the U.S. Department of Justice announced they had
resolved the federal agencies' pending enforcement actions filed in 1999
against Tampa Electric. The resolution was in the form of a consent decree,
which became effective Oct. 5, 2000 and has resulted in full and final
settlement of the federal litigation and Notice of Violation alleging
violations of New Source Review (NSR) requirements of the Clean Air Act.
In 2000, the City of Lakeland notified PGS that it intended to begin
negotiations to exercise its right to purchase PGS' property consisting of
approximately 200 miles of gas lines in the Lakeland franchise area when its
franchise agreement with PGS expired in March 2000. PGS serves approximately
5,000 customers in Lakeland. In August 2000, the City of Lakeland filed a
Complaint for Declaratory and Injunctive Relief against PGS. After an October
2000 hearing on a Motion to Dismiss Complaint filed by PGS, the City of
Lakeland agreed to amend its complaint. In November 2000, the City of Lakeland
filed an Amended Complaint for Declaratory and Injunctive Relief seeking a
declaration of the City's rights to acquire PGS' facilities under the franchise
and seeking restrictions on the Company's gas operations within the City. PGS
has filed defenses and counter claims and a hearing is scheduled for May 2001.
While PGS believes it is best suited to serve the customers in the City, it
cannot at this time predict the ultimate outcome of these activities. PGS is
continuing to serve under substantially the same terms as contained in the
franchise in the absence of other rules and regulations being adopted by the
city.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matter was submitted during the fourth quarter of 2000 to a vote of
TECO Energy's security holders, through the solicitation of proxies or
otherwise.
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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
------------------- --- -----------------------------------------------
Robert D. Fagan 56 Chairman of the Board, President and Chief
Executive Officer, December 1999 to date;
President and Chief Executive Officer, May 1999
to December 1999; and prior thereto, President
of PP&L Global, Inc. (independent power),
Fairfax, Virginia.
William N. Cantrell 48 President-TECO Solutions, September 2000 to
date and President-Peoples Gas Companies, June
1997 to date; Director of Peoples Gas
Transition Team, January 1997 to June 1997; and
Vice President-Energy Supply of Tampa Electric
Company, April 1995 to January 1997.
Royston K. Eustace 59 Senior Vice President-Business Development,
April 1998 to date; and prior thereto, Vice
President-Strategic Planning and Business
Development.
Gordon L. Gillette 41 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.
Richard Lehfeldt 49 Senior Vice President-External Affairs,
November 1999 to date; and prior thereto, Vice
President and Assistant General Counsel of
Edison Mission Energy (independent power),
Irvine, California.
Richard E. Ludwig 55 President of TECO Power Services Corporation,
1992 to date.
Sheila M. McDevitt 54 Vice President-General Counsel, January 1999 to
date; and prior thereto, Vice
President-Assistant General Counsel.
John B. Ramil 45 President of Tampa Electric Company, April 1998
to date; Vice President-Finance and Chief
Financial Officer, November 1997 to April 1998;
and Vice President-Energy Services and Planning
of Tampa Electric Company, November 1994 to
November 1997.
D. Jeffrey Rankin 54 President-TECO Transport Corporation, October
1987 to date.
There is no family relationship between any of the persons named
above. The term of office of each officer extends to the meeting of the Board
of Directors following the next annual meeting of shareholders, scheduled to be
held on April 18, 2001, and until his successor is elected and qualified.
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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
2000
High $20 5/8 $23 1/8 $28 3/4 $33 3/16
Low $17 1/4 $19 3/16 $20 3/16 $26 9/16
Close $19 7/16 $20 1/16 $28 3/4 $32 3/8
Dividend $.325 $.335 $.335 $.335
1ST 2ND 3RD 4TH
1999
High $28 $23 13/16 $23 1/8 $221/2
Low $19 7/8 $19 3/4 $19 5/8 $18 3/8
Close $19 7/8 $22 3/4 $21 1/8 $18 9/16
Dividend $.31 $.325 $.325 $.325
-------------------
The approximate number of shareholders of record of common stock of
TECO Energy as of Mar. 23, 2001 was 23,933.
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 2000.
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(millions, except per share amounts)
ITEM 6. SELECTED FINANCIAL DATA.
YEAR ENDED DEC. 31, 2000 1999 1998 1997 1996
---------- ---------- ---------- ---------- ----------
Revenues $ 2,295.1 $ 1,983.0 $ 1,955.7 $ 1,860.8 $ 1,773.2(4)
========== ========== ========== ========== ==========
Net income:
From continuing operations $ 250.9 $ 200.9(1) $ 204.2(2) $ 211.5(3) $ 217.6(4)
From discontinued operations -- (2.5) (3.8) (6.6) (1.1)
Disposal of discontinued
operations -- (12.3) 6.1 (3.0) --
---------- ---------- ---------- ---------- ----------
Net income $ 250.9 $ 186.1(1) $ 206.5(2) $ 201.9(3) $ 216.5(4)
========== ========== ========== ========== ==========
Total assets $ 5,676.2 $ 4,690.1 $ 4,179.3 $ 3,960.4 $ 3,901.6(4)
Long-term debt $ 1,374.6 $ 1,207.8 $ 1,279.6 $ 1,080.2 $ 1,118.0(4)
Earnings per average share (EPS)
outstanding -- basic:
From continuing operations $ 1.99 $ 1.53(1) $ 1.55(2) $ 1.62(3) $ 1.68(4)
From discontinued operations -- (0.02) (0.03) (0.05) (0.01)
Disposal of discontinued
operations -- (0.09) 0.05 (0.03) --
---------- ---------- ---------- ---------- ----------
Earnings per average common
share outstanding -- basic $ 1.99 $ 1.42(1) $ 1.57(2) $ 1.54(3) $ 1.67(4)
========== ========== ========== ========== ==========
Common dividends paid per
common share (5) $ 1.33 $ 1.285 $ 1.225 $ 1.165 $ 1.105
-----------------
(1) Includes the effect of charges discussed in NOTE M on page 63, which
reduced net income by $19.6 million and earnings per share by $0.15 in
1999.
(2) Includes the effect of charges discussed in NOTE M on page 63, which
reduced net income by $19.6 million and earnings per share by $0.15 in
1998.
(3) Includes the effect of merger-related transaction expenses, which reduced
net income by $5.3 million and earnings per share by $0.04 in 1997.
(4) Amounts shown prior to 1997 have been restated to include the results of
the Peoples Gas companies merger.
(5) Dividend paid for TECO Energy Common Stock (not restated for the Peoples
Gas companies merger).
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
THE MANAGEMENT'S DISCUSSION AND ANALYSIS WHICH FOLLOWS CONTAINS FORWARD-LOOKING
STATEMENTS WHICH ARE SUBJECT TO THE INHERENT UNCERTAINTIES IN PREDICTING FUTURE
RESULTS AND CONDITIONS. CERTAIN FACTORS THAT COULD CAUSE ACTUAL RESULTS TO
DIFFER MATERIALLY FROM THOSE PROJECTED IN THESE FORWARD-LOOKING STATEMENTS ARE
SET FORTH IN THE INVESTMENT CONSIDERATIONS SECTION.
EARNINGS SUMMARY
TECO Energy's basic earnings from continuing operations were $1.99 per
share in 2000 compared with $1.53 per share in 1999. Earnings were $1.99 per
share in 2000 compared to $1.42 per share in 1999, which included charges of
$.11 per share for discontinued operations.
TECO Energy completed its $150-million share repurchase program in
june 2000; approximately 7 million shares were repurchased at an average price
of $20.55 per share. The share repurchase program increased earnings by $.06
per share in 2000. Because the 5.4 million shares repurchased in 1999 were
acquired late in the year, the effect on earnings per share in 1999 was less
than $.01.
2000 CHANGE 1999 CHANGE 1998
------- ------ ------- ------ -------
EARNINGS PER SHARE - BASIC
Continuing operations $ 1.99 30.1% $ 1.53 -1.3% $ 1.55
Discontinued operations -- -- (.11) -- .02
------- ------- -------
Earnings per share $ 1.99 40.1% $ 1.42 -9.6% $ 1.57
======= ======= =======
EARNINGS PER SHARE - DILUTED
Continuing operations $ 1.97 28.8% $ 1.53 -.6% $ 1.54
Discontinued operations -- -- (.11) -- .02
------- ------- -------
Earnings per share $ 1.97 38.7% $ 1.42 -9.0% $ 1.56
======= ======= =======
NET INCOME FROM CONTINUING
OPERATIONS (millions) $ 250.9 24.9% $ 200.9 -1.6% $ 204.2
AVERAGE COMMON SHARES
OUTSTANDING
Basic (millions) 125.9(1) -3.9% 131.0(1) -.5% 131.7
Diluted (millions) 126.3(1) -3.7% 131.2(1) -.8% 132.2
RETURN ON AVERAGE COMMON EQUITY
FROM CONTINUING OPERATIONS
Including charges 16.6% 13.2% 13.3%
Without charges 16.6% 14.5% 14.5%
(1) Average shares outstanding for 2000 reflects the repurchase of an
additional 1.6 million shares in 2000 and the repurchase of 5.4 million
shares between September and Dec. 31, 1999.
Earnings in 1999 and 1998 were affected by certain events and
adjustments that were unusual in nature and resulted in charges which are not
expected to recur in future periods. These charges are described in the CHARGES
TO EARNINGS section.
CHARGES TO EARNINGS
2000 CHARGES
Charges of an unusual and non-recurring nature had no significant net
effect on earnings in 2000. In 2000, TECO Energy's results included an
$8.3-million after-tax gain from thE US Propane and Heritage Propane
transactions offset by after-tax charges of $5.2 million to adjust the value of
leveraged leases and $3.8 million to adjust property values at TECO properties.
1999 CHARGES
Unusual and non-recurring charges in 1999 totaled $21.1 million pretax
($19.6 million after tax, or $.15 per share) and consisted of the following:
Tampa Electric recorded a charge of $10.5 million ($6.4 million after
tax) based on Florida Public Service Commission (FPSC) audits of its 1997 and
1998 earnings which, among other things, limited its regulatory equity ratio to
58.7 percent, a decrease of 91 basis points and 224 basis points from 1997's
and 1998's ratios, respectively.
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20
Tampa Electric also recorded a charge of $3.5 million after tax,
representing management's estimate of additional expenses to resolve the
litigation filed by the United States Environmental Protection Agency (EPA).
See the ENVIRONMENTAL COMPLIANCE section.
After-tax charges totaling $6.1 million were also recorded reflecting
corporate income tax provisions and settlements related to prior years' tax
returns. These charges were recorded at Tampa Electric (a $3.8-million net
after-tax charge, after recovery under the regulatory agreement then in effect)
and at TECO Energy (a $2.3-million after-tax charge).
A charge of $6.0 million ($3.6 million after tax) was recorded to
adjust the carrying value of certain investments in leveraged aircraft leases
to reflect lower anticipated residual values.
1998 CHARGES
In 1998, TECO Energy recorded charges totaling $31.1 million pretax
($19.6 million after tax, or $.15 per share). These charges consisted of the
following:
TECO Coal recorded a charge of $13.6 million ($8.9 million after tax)
to adjust the asset values of certain mining facilities, primarily at its
Gatliff mine, to reflect their expected value after the expiration of the Tampa
Electric contract at the end of 1999.
The FPSC ruled in September 1997 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 were based. One contract was terminated in 1997. As to the
other contract, which expires in March 2001, Tampa Electric entered into firm
power purchase contracts with third parties to provide replacement power
through 1999, and the associated generation assets are no longer separated from
the retail jurisdiction. The cost of purchased power under these contracts
exceeded the revenues expected through 1999. To reflect this difference, Tampa
Electric recorded a $9.6 million charge ($5.9 million after tax) in 1998.
Tampa Electric also recorded a charge of $7.3 million ($4.4 million
after tax) in other expense for an FPSC decision in 1998 denying recovery of
certain BTU coal quality price adjustments for coal purchases since 1993.
STRATEGY AND OUTLOOK
TECO Energy's three-pronged business strategy is: to focus on its
Florida operations, which include Tampa Electric, Peoples Gas System (PGS) and
the Florida energy services business TECO Solutions; grow its TECO Power
Services (TPS) independent power operations; and grow its TECO Transport water
transportation business.
In early 2000, management stated that its objective was to achieve
earnings per share growth of 7 percent over 1999's normalized earnings base of
$1.68, which excluded the effect of the charges discussed previously. In
mid-year, management revised its estimates to 10 percent growth and in
September indicated it expected a $.10 to $.15 per share upside in 2000 from
the synthetic fuel operations at TECO Coal.
In the fall of 2000, management stated that its objective was to
deliver 10 percent earnings growth in 2001 and beyond primarily through rapid
growth from the TPS independent power business, continued strong growth from the
Florida operations and steady long-term growth from the transportation business.
In March 2001, management increased its earnings forecast for 2001, to show
growth of 15 percent over that of 2000.
TPS accelerated its growth in 2000 with four independent power
projects placed in service. TPS also announced participation in seven new
projects in 2000. These projects have increased the number of net megawatts
operating, under construction or in final stages of development from
approximately 1,000 megawatts at the end of 1999 to more than 7,000 megawatts
at the end of 2000.
This growth in unregulated power generation is a major step in
transforming TECO Energy from a company that currently derives about 65 percent
of earnings from regulated businesses and 35 percent from non-regulated
businesses to one that, by 2003, will be a predominately unregulated generating
company operating in competitive markets with more than half of its earnings
from competitive unregulated businesses.
At the same time, TECO Energy is supporting change to the way the
Florida energy market is regulated. The company believes that it has the
opportunity to benefit from a more competitive energy market in Florida for the
following reasons:
The Florida market is a high-growth market with the need for
additional generating capacity. TPS and Tampa Electric have Florida-based
generation that is competitive in the state. Through Tampa Electric, PGS, TECO
Solutions and TPS, TECO Energy already has a statewide presence. Furthermore,
Tampa Electric and TPS already have permitted sites in the state for additional
generation.
Near-term expectations for the various operating companies are
summarized below:
Tampa Electric and PGS are positioned to see growth in sales and
earnings above the rate of customer growth estimated at about 2.5 percent and
5.5 percent, respectively. The expected growth at Tampa Electric is the result
of a more favorable customer mix and return on investments made to support this
growth.
Historically, the natural gas market in Florida has been under served
with the lowest market penetration in the southeastern U.S. The expected growth
at PGS is the result of expansion into areas of Florida previously not served
and expansion of the system in areas currently served.
20
21
At TPS in 2001, growth, more moderate than experienced in 2000, is
expected primarily from the Frontera Power Station acquisition and full-year
operations for those projects brought online in 2000 and Phase II of the
Commonwealth Chesapeake Power Station. Longer-term new TPS projects, with
in-service dates scheduled from 2001 through early 2005, along with those
already in operation, are expected to be major contributors to TECO Energy's
long-term earnings growth targets discussed above.
At TECO Transport, earnings growth is expected from increased
northbound shipments, a slight improvement in phosphate shipments and continued
strong U.S. government grain shipments. Long-term growth is expected from
increased asset utilization, particularly at the river business, and asset
acquisitions at both the ocean-going and river businesses.
TECO Coal expects to benefit from improved prices, increased
production from the addition of the Perry County Coal facilities in 2000, and
Section 29 non-conventional fuels tax credits related to increased production
of synthetic fuel from the facilities acquired in 2000.
TECO Coalbed Methane expects gas prices for 2001 to be significantly
higher than in 2000 and more than offset the normal production decline.
The company expects higher borrowing levels in 2001 associated
primarily with additional investments in TPS generation projects.
In March 2001, the company completed a public offering of 8.625
million common shares resulting in net proceeds to the company of approximately
$232 million. The proceeds from the sale of these shares were used primarily to
reduce commercial paper balances and for general corporate purposes. Additional
equity is expected to be issued in 2002 or 2003 to support the continued
investment in TECO Energy's businesses.
The above forward-looking statements are subject to many factors that
could cause actual results and conditions to differ materially from those
projected in these statements. See the Investment Considerations section.
OPERATING RESULTS
TECO ENERGY'S OPERATING RESULTS
Net income in 2000 was $250.9 million, up 14 percent from $220.5
million from continuing operations and before charges in 1999. These results
reflect continued customer growth and increased energy usage in the Florida
operations, a more than doubling of net income at TPS from the new generation
projects brought on line in late 1999 and 2000 and improved results from the
Guatemalan distribution utility, good operating conditions and strong markets
at TECO Transport, and the addition of synthetic fuel production at TECO Coal
which qualifies for Section 29 tax credits for non-conventional fuel
production. These improvements were partially offset by higher interest expense
associated with increased borrowing levels.
Net income from continuing operations in 1999, excluding charges
described in the CHARGES TO EARNINGS section, declined about 2 percent to
$220.5 million, primarily from the recognition of a $17.5-million net benefit
from deferred revenues at Tampa Electric in 1998 which was not available in
1999. For a description of deferred revenues, see the UTILITY REGULATION - RATE
STABILIZATION STRATEGY section. Contributing favorably to 1999 results were
strong Tampa Electric customer growth of over 2.5 percent and lower operations
and maintenance expenses at both Tampa Electric and Peoples Gas System. TECO
Transport and TPS achieved higher net income in 1999, while TECO Coal's and
TECO Coalbed Methane's net income were lower.
The following table shows the unconsolidated revenues, operating, net
income and earnings per share contribution from continuing operations of the
significant business segments, excluding charges described in the CHARGES TO
EARNINGS section. For additional detail, refer to the NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS - FOOTNOTE L, SEGMENT.
CONTRIBUTIONS BY OPERATING GROUP (UNCONSOLIDATED)
(millions) 2000 CHANGE 1999 CHANGE 1998
--------- ------ ----------- ------ -----------
Revenues
Tampa Electric $ 1,353.8 12.8% $ 1,199.8(1) -2.8% $ 1,234.6(2)
Peoples Gas System 314.5 24.9% 251.7 -0.4% 252.8
Unregulated companies(3)
TECO Transport 269.8 7.1% 251.9 9.5% 230.0
TECO Coal 232.8 -1.9% 237.3 2.1% 232.4
TECO Power Services 204.9 87.1% 109.5 10.9% 98.7
Other unregulated businesses 148.0 34.8% 109.8 -0.7% 110.6
21
22
CONTRIBUTIONS BY OPERATING GROUP (UNCONSOLIDATED) - continued
(millions) 2000 CHANGE 1999 CHANGE 1998
------- ------- ------- ------- -------
OPERATING INCOME(3)
Tampa Electric $ 293.5 11.2% $ 263.9 - 5.6% $ 279.7
Peoples Gas System 47.0 8.8% 43.2 20.7% 35.8
Unregulated companies(4)
TECO Transport 51.9 10.9% 46.8 8.3% 43.2
TECO Coal 25.2 17.2% 21.5 -8.5% 23.5
TECO Power Services 31.0 79.2% 17.3 33.1% 13.0
Other unregulated businesses 27.2 -17.6% 33.0 -12.7% 37.8
NET INCOME(3)(5)
Tampa Electric $ 144.5 4.1% $ 138.8 -1.7% $ 141.2
Peoples Gas System 21.8 10.1% 19.8 27.7% 15.5
Unregulated companies(4)
TECO Transport 28.7 9.5% 26.2 10.1% 23.8
TECO Coal 37.5 134.4% 16.0 -8.6% 17.5
TECO Power Services 36.9 152.7% 14.6 50.1% 9.7
Other unregulated businesses 31.3 14.7% 27.3 -11.4% 30.8
Financing/Other (49.8) 124.3% (22.2) 51.0% (14.7)
EARNINGS PER SHARE - BASIC(3)(5)
Tampa Electric $ 1.09 3.8% $ 1.05 -1.9% $ 1.07
Peoples Gas System .16 6.7% .15 25.0% .12
Unregulated companies(4)
TECO Transport .22 10.0% .20 11.1% .18
TECO Coal .28 133.3% .12 -7.7% .13
TECO Power Services .28 154.5% .11 57.1% .07
Other unregulated businesses .24 14.3% .21 -12.5% .24
Financing/Other (.34) 100.0% (.17) 54.5% (.11)
Effect of share repurchase .06 500.0% .01 -- --
EPS from continuing operation, before charges $ 1.99 18.5% $ 1.68 -1.2% $ 1.70
Charges -- -- (.15) -- (.15)
------- ------- ------- ------- -------
EPS from continuing operations $ 1.99 30.1% $ 1.53 -1.3% $ 1.55
======= ======= ======= ======= =======
---------------
(1) Includes $11.9 million of deferred revenues. This amount is before the
$7.9-million deferred revenue benefit recognized under the regulatory
agreement related to the charges for tax settlements, described in the
CHARGES TO EARNINGS section.
(2) Includes the recognition of previously deferred revenues totaling $38.3
million offset by temporary base rate reductions of $20.8 million,
described in the UTILITY REGULATION - RATE STABILIZATION STRATEGY section.
(3) From continuing operations, excluding the charges described in the Charges
to Earnings section.
(4) Includes items that were reclassified for consolidated financial statement
purposes. The principal items are the non-conventional fuels tax credit
related to coalbed methane production and synthetic fuel production at
TECO Coal and interest expense on the limited-recourse debt related to
TPS's 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.
(5) Beginning in 2001, segment net income will be reported on a basis that
will include internally allocated financing costs.
TAMPA ELECTRIC - ELECTRIC OPERATIONS
------------------------------------
TAMPA ELECTRIC RESULTS
Tampa Electric's net income increased 4 percent in 2000, reflecting
good customer growth, higher per-customer energy usage, a favorable customer
mix and more normal weather, partially offset by higher operations and
maintenance expense.
In July 2000, Tampa Electric placed its new, 180-megawatt combustion
turbine Polk Unit Two in service. The $54-million, oil or gas-fired peaking
unit was constructed on an accelerated schedule to meet peak summer demand.
Tampa Electric's 1999 net income, before charges described in the
CHARGES TO EARNINGS section, declined about 2 percent from 1998. Results in
1999 included the deferral of $11.9 million of revenues excluding an offsetting
non-recurring pretax benefit of $7.9 million of deferred revenues recognized
under the then current regulatory agreement related to the charge for tax
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settlements. The results in 1998 reflected the recognition of $38.3 million of
previously deferred revenues partially offset by a $20.8-million temporary base
rate reduction.
SUMMARY OF OPERATING RESULTS
(millions) 2000 CHANGE 1999 CHANGE 1998
-------- ------ -------- ------ --------
Revenues $1,353.8 12.8% $1,199.8(1) -2.8% $1,234.6(2)
Operating expenses 1,060.3 13.3% 935.9 -2.0% 954.9(3)
-------- -------- --------
Operating income $ 293.5 11.2% $ 263.9 -5.6% $ 279.7
======== ======== ========
Net Income $ 144.5 4.1% $ 138.8 -1.7% $ 141.2
======== ======== ========
---------------
(1) Includes $11.9 million of deferred revenues. This amount is before the
$7.9-million deferred revenue benefit recognized under the regulatory
agreement related to the charge for tax settlements, described in the
CHARGES TO EARNINGS section.
(2) Includes the recognition of previously deferred revenues totaling $38.3
million offset by temporary base rate reductions of $20.8 million,
described in the UTILITY REGULATION - RATE STABILIZATION STRATEGY section.
(3) Excludes a pretax charge of $9.6 million for treatment of a wholesale
contract, described in the CHARGES TO EARNINGS section.
TAMPA ELECTRIC OPERATING REVENUES
The economy in Tampa Electric's service area continued to grow in
2000, with increased employment from the strong local economy aided by
corporate relocations and expansions. The Tampa metropolitan area's employment
grew over 5 percent in 2000, placing it fourth for job growth among
metropolitan areas in the U.S.
Tampa Electric's 2000 operating revenues increased 13 percent from 3
percent customer growth, more normal winter weather and increased per-customer
energy usage. The customer mix continued to shift toward higher margin
residential and commercial customers in 2000.
Tampa Electric's 1999 operating revenues decreased 3 percent,
primarily because the company deferred revenues in 1999, while in 1998 it
benefited from the recognition of revenues deferred in prior years. The company
experienced customer growth of 2.5 percent in 1999, while retail energy sales
were 1.4 percent lower.
In 2000, combined residential and commercial megawatt sales increased
5 percent from the addition of more than 16,000 new customers and a return to
more normal weather. These sales increased slightly in 1999, as the addition of
almost 13,000 customers more than offset the effects of mild weather that year.
Non-phosphate industrial sales increased in 2000 and 1999, reflecting
continued economic growth and the shift of some commercial customers to the
industrial classification to take advantage of favorable tax law changes for
electricity used in manufacturing. This shift does not affect Tampa Electric
total revenues.
Sales to phosphate customers increased in 2000 as producers brought
back into service mining and production facilities idled in 1998 and 1999.
Sales to the phosphate industry declined in 1999 due to mine closures in 1998
and 1999. The phosphate industry continues to experience lower pricing due to
worldwide oversupply. According to phosphate industry sources, the market is
expected to remain in this downturn in early 2001 and then start a recovery
later in 2001 with improvement continuing in 2002. Revenues from phosphate
sales represented slightly less than 3 percent of base revenues in 2000 and in
1999.
Based on expected growth reflecting continued population increases and
business expansion, 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. Retail demand growth is expected to average 100 megawatts of
capacity per year for the next five years.
These growth projections assume continued local area economic growth,
normal weather and certain other factors. See the INVESTMENT CONSIDERATIONS
section.
MEGAWATT-HOUR SALES
(thousands) 2000 CHANGE 1999 CHANGE 1998
------ ------ ------ ------- ------
Residential 7,369 5.8% 6,967 -1.2% 7,050
Commercial 5,541 3.8% 5,336 3.2% 5,173
Industrial 2,390 7.5% 2,224 -11.7% 2,520
Other 1,338 4.7% 1,278 -0.5% 1,284
------ ---- ------ ------ ------
Total retail 16,638 5.3% 15,805 -1.4% 16,027
Sales for resale 2,564 18.7% 2,160 -13.1% 2,486
------ ---- ------ ------ ------
Total energy sold 19,202 6.9% 17,965 -3.0% 18,513
====== ==== ====== ====== ======
Retail customers (average) 560.1 3.0% 543.7 2.5% 530.3
====== ==== ====== ====== ======
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TAMPA ELECTRIC OPERATING EXPENSES
Overall operating expenses increased 13 percent in 2000 reflecting
increased costs associated with the Big Bend Units One and Two flue gas
desulfurization system placed in service in December 1999, the expiration of
the DOE credits for Polk Unit One at the end of 1999, increased generating
system maintenance to improve summer availability and costs associated with
organizational streamlining. Costs associated with the flue gas desulfurization
system are recovered through the Environmental Cost Recovery Clause (ECRC). See
the UTILITY REGULATION section.
Overall expenses were down 2 percent in 1999, reflecting lower fuel
consumption and lower operations and maintenance expense than in 1998.
Partially offsetting these reductions were property tax settlements and
environmental study costs associated with the state environmental settlement
described below and in the ENVIRONMENTAL COMPLIANCE section.
Non-fuel operations and maintenance expenses decreased 4 percent in
1999, the result of effective cost management and improved efficiency
throughout the company.
Tampa Electric's 250-megawatt, clean coal technology Polk Unit One was
placed into service in late 1996. Between 1996 and 1999, the last year of
eligibility, a total of approximately $29 million was received from the U.S.
Department of Energy (DOE) to partially offset the unit's non-fuel operations
and maintenance expenses.
Non-fuel operations and maintenance expenses in 2001 are expected to
increase at or below the rate of inflation over the next several years.
OPERATING EXPENSES
(Millions) 2000 CHANGE 1999 CHANGE 1998
-------- ------ -------- ------ -------
Other operating expenses $ 188.3 15.1% $ 163.6 -1.3% $ 165.7
Maintenance 96.1 10.3% 87.1 -7.9% 94.6
Depreciation 161.6 9.5% 147.6 1.0% 146.1
Taxes, other than income 98.7 -0.1% 98.8 1.6% 97.2
-------- -------- -------
Operating expenses 544.7 9.6% 497.1 -1.3% 503.6
-------- -------- -------
Fuel 323.5 6.4% 304.0 -17.1% 366.6
Purchased power 192.1 42.5% 134.8 59.1% 84.7
-------- -------- -------
Total fuel expense 515.6 17.5% 438.8 -2.8% 451.3
-------- -------- -------
Total operating expenses $1,060.3 13.3% $ 935.9 -2.0% $ 954.9
======== ======== =======
Depreciation expense increased 9 percent in 2000 reflecting normal
plant additions to serve the growing customer base and the addition of the Big
Bend Units One and Two flue gas desulfurization system. The 1 percent increase
in 1999 reflected normal plant additions to serve customer growth and maintain
generating system reliability. Depreciation expense is projected to increase in
2001 from normal plant additions and rise for the next several years due to an
additional combustion turbine at the Polk Power Station in 2002 and the first
phase of the Gannon repowering project entering service in 2003. See the
ENVIRONMENTAL COMPLIANCE section.
Fuel costs increased 6 percent in 2000 reflecting increased generation
and increased use of more expensive oil and natural gas at Polk Unit Two,
Hookers Point and combustion turbines at the Big Bend Power Station. Average
coal costs, on a cents-per-million BTU basis, decreased slightly in 2000 after
a slight increase in 1999. Fuel expense decreased in 1999 from 1998 due to
lower energy sales and a higher reliance on purchased power attributable to
lower unit availability.
Purchased power expense increased in 2000 due to lower unit
availability, primarily the result of a generator failure at Gannon Unit Six.
Purchased power increased in 1999 due to lower unit availability, the provision
of replacement power for certain wholesale power sales contracts and an
explosion at the Gannon plant in April 1999.
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
comprised of coal until 2003 when the first of two repowered units is scheduled
to begin operating on natural gas. See the ENVIRONMENTAL COMPLIANCE section. On
a total energy supply basis, company generation accounted for 86 percent and 84
percent of the total system energy requirement in 2000 and 1999, respectively.
On April 8, 1999, an explosion at Tampa Electric's Gannon Station Unit
Six, which was off line for scheduled spring maintenance, resulted in damage to
the unit, the temporary shut down of the other five units at the station and
injuries to 45 employees and contractors, including three fatalities. The cost
of replacement fuel and purchased power totaled $5 million; $1.8 million was
approved by the FPSC for recovery through Tampa Electric's fuel and purchased
power clause with little impact on customer rates, and the balance was
recovered from interruptible customers. The costs resulting from the accident
were substantially covered by insurance. The impact on 1999 operation and
maintenance expenses was approximately $2 million.
PEOPLES GAS SYSTEM
Peoples Gas System is the largest investor-owned gas distribution
utility in Florida, with about 70 percent of the investor-owned local
distribution company market . It serves almost 260,000 customers in all of the
major metropolitan areas of Florida.
PGS achieved net income growth of 10 percent in 2000 from customer
growth, increased gas transported for off-system sales to electric power
generators and interruptible customers and colder weather late in the year.
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Net income grew 28 percent in 1999, with the increase due primarily to
new customer additions from system expansion and lower operating expenses. The
benefits of customer growth for the year were partially offset by the less
favorable weather patterns during 1999.
Historically the natural gas market in Florida has been underserved
with the lowest market penetration in the southeastern U.S. PGS is expanding
its gas distribution system into areas of Florida previously not served and
expanding its system within areas currently served.
SUMMARY OF OPERATING RESULTS
(Millions) 2000 CHANGE 1999 CHANGE 1998
-------- -------- -------- -------- -------
Revenues $ 314.5 24.9% $ 251.7 -0.4% $ 252.8
Cost of gas sold 157.0 45.8% 107.7 -6.7% 115.4
Operating expenses 110.5 9.6% 100.8 -0.8% 101.6
-------- -------- -------
Operating income $ 47.0 8.8% $ 43.2 20.7% $ 35.8
======== ======== =======
Net Income $ 21.8 10.1% $ 19.8 27.7% $ 15.5
======== ======== =======
Therms sold (millions)
by Customer Segment
Residential 57.6 10.6% 52.1 -1.1% 52.7
Commercial 292.1 6.8% 273.5 2.8% 266.0
Industrial 374.1 12.7% 331.9 8.8% 305.0
Power Generation 418.6 3.3% 405.2 40.5% 288.3
-------- -------- -------
Total 1,142.4 7.5% 1,062.7 16.5% 912.0
======== ======== =======
Therms sold (millions)
by Sales Type
System Supply 320.6 6.9% 300.0 -6.5% 320.8
Transportation 821.8 7.7% 762.7 29.0% 591.2
-------- -------- -------
Total 1,142.4 7.5% 1,062.7 16.5% 912.0
======== ======== =======
Customers (thousands) - average 256.2 3.9% 246.7 3.0% 239.6
======== ======== =======
Residential therm sales increased in 2000, the result of 4 percent
residential customer growth and colder weather late in the year. Commercial
therm sales increased in 2000 reflecting good customer growth and a strong
economy.
Residential therm sales decreased slightly in 1999, the result of less
favorable weather patterns in the first quarter offset in part by new customer
additions. Therm sales to commercial customers increased in 1999, reflecting a
growing number of higher-margin customers.
Operating revenues from residential and commercial customers increased
24 percent and 16 percent, respectively, in 2000 from higher gas prices,
customer growth, and increased usage due to colder weather late in the year .
Gas prices per therm were 36 percent higher in 2000 compared to the prior year.
The actual cost of gas and upstream transportation purchased and
resold to end-use customers is recovered through a Purchased Gas Adjustment
(PGA) clause approved by the Florida Public Service Commission. The company
files for mid-period adjustments to the PGA in times of gas price volatility,
as was experienced in 2000 and into 2001.
Revenues from residential customers increased 2 percent in 1999.
Revenue from commercial customers decreased 9 percent, while revenues from
industrial and power generation customers were up approximately 33 percent.
In November 2000, PGS instituted its "NaturalChoice" program, which
unbundles gas services for all non-residential customers, affording these
customers the opportunity to purchase the commodity gas from any provider. The
net result of this unbundling is a shift from commodity sales to transportation
sales. Because commodity sales are included in operating revenues at the cost
of the gas on a pass-through basis, there is no net financial impact to the
company of transportation only sales.
Operating expenses increased in 2000, in line with customer growth and
system expansion. Operating expenses decreased in 1999, reflecting cost savings
associated with management's decision in mid-1998 to exit the appliance sales
and service business.
PGS expects to invest an average of $60 million for each of the next
five years to grow the business and maintain system reliability.
In 1998, PGS announced plans to expand into the Southwest Florida
market to provide service to Fort Myers, Naples, Cape Coral and surrounding
areas. In 1999, the company began connecting customers and delivering gas to
North Fort Myers and completed the long-haul portion of this extension of its
distribution system in April 2000. In the first eight months of operation, the
project connected 195 commercial customers representing annual consumption of
approximately 5.8 million therms. External sources predict that more than
100,000 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.
PGS expects increases in sales volumes and corresponding revenues in
2001, and continued customer additions and related revenues from the Southwest
Florida expansion and other expansion efforts throughout the state.
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These growth projections assume continued local area economic growth,
normal weather and other factors. See the INVESTMENT CONSIDERATIONS section.
TECO POWER SERVICES
In 2000, TECO Power Services' (TPS) net income of $36.9 million was
more than double the 1999 level from new investments, projects placed in
commercial operation in 2000, improved results at Empresa Electrica de
Guatemala, S.A. (EEGSA), the Guatemalan distribution utility in which TPS
acquired a 24 percent interest in 1998, and increased earnings from the
expansion of Hardee Power Station.
In 2000, TPS recorded $5.4 million of other income related to an
insurance claim settlement at the San Jose Power Station for mechanical damage
and loss of business from a turbine oil system failure, and other turbine
problems. Repairs to the turbine were completed and the unit has operated
reliably since September.
The 120-megawatt San Jose Power Station began commercial operation in
January 2000. TPS increased its ownership interest in this project to 67
percent in December 1999 and acquired the remaining ownership interest in
February 2000. TPS has a 15-year power supply agreement with EEGSA.
The 75-megawatt expansion of the Hardee Station in Florida, announced
in September 1999, began commercial operation in May 2000, and is serving the
needs of Tampa Electric. The first phase of the Hamakua project in Hawaii began
commercial operation in August 2000 and the final phase began commercial
operation in December 2000. The 135-megawatt first phase of the planned
312-megawatt Commonwealth Chesapeake electric generating facility in Virginia
began commercial operation in September 2000 and construction is proceeding on
the second phase, with commercial operation expected by June 2001.
In 1999, TPS recorded significantly higher income compared to 1998,
reflecting contributions from new initiatives in 1999 and growing contributions
from existing operating projects and investments. Capitalization of development
costs and interest during construction on the San Jose Power Station also
contributed to the improved results for the year. EEGSA had better results in
1999 as operational improvements and customer additions favorably impacted
earnings.
DEVELOPMENT ACTIVITIES
In 2000, TPS refocused its development efforts on domestic energy
projects and took steps to achieve the major growth outlined in the TECO ENERGY
STRATEGY AND OUTLOOK section. During the second half of 2000 and early 2001,
TPS announced eight major projects representing a net ownership interest
increase of more than 6,000 megawatts of new merchant capacity operating, under
construction or in final stages of development. See the INVESTMENT
CONSIDERATIONS section. TPS expects these projects to begin making
contributions to earnings in 2001, with significantly higher contributions
expected in 2003.
TPS now has a pipeline of projects operating, under construction or in
the final stages of development with a net ownership interest in more than
7,000 megawatts. Upon completion, the domestic projects will provide TPS with
the opportunity to sell wholesale power in 18 states from Hawaii to Florida to
Virginia and to Mexico. The new projects are in high-growth areas, with good
access to fuel supply and electric transmission systems.
In September, TPS announced a $93-million investment in the form of a
loan related to Panda Energy International's (Panda) Texas Independent Energy
Projects (TIE). This investment, under certain circumstances, gives TPS an
opportunity for an effective economic interest, estimated at 75-percent, in
Panda's 1,000-megawatt interest in these projects. Interest from TIE
contributed to 2000 earnings and will increase in 2001.
In October, TPS announced the acquisition of two generating plants
being developed by GenPower LLC. TPS acquired 100 percent ownership of the two
599-megawatt, natural gas-fired, combined cycle Dell and McAdams projects
located in Arkansas and Mississippi, respectively. These projects are expected
to begin commercial operation in the fourth quarter of 2002. The TPS equity
investment in these projects at commercial operation is expected to total about
$330 million.
In November, TPS announced a joint venture with Panda to build, own
and operate the 2,220-megawatt El Dorado plant in Arkansas and the
2,350-megawatt Gila River Power Station in Arizona. TPS earns a preferred
return on the investment in these projects, which gives it an effective
75-percent economic interest. These projects will begin commercial operation in
phases, with the first phase of El Dorado expected in the second half of 2002
and the final phase of Gila River expected by the middle of 2003. The TPS
equity investment in these projects at commercial operation is expected to
total more than $1 billion.
Also in November, TPS announced the signing of a memorandum of
understanding relating to the exclusive rights to develop a petroleum coke (pet
coke) gasification project at the CITGO refinery in Lake Charles, Louisiana.
The memorandum contemplates that TPS will be a 50-percent owner of this
670-megawatt project that will gasify the pet coke provided by CITGO to produce
a clean burning synthesis gas for use in a combustion turbine. The project will
sell steam and hydrogen to CITGO with excess electric power sold in the
Louisiana wholesale power market. The project is expected to begin commercial
operation in early 2005.
In March 2001, TPS acquired American Electric Power's (AEP) Frontera
Power Station located near McAllen, Texas. This 500-megawatt, natural
gas-fired, combined-cycle plant, originally developed by CSW Energy (CSW),
began combined-cycle operation in May 2000. As a condition of the merger of
Central & South West Corporation, CSW's parent company, with AEP the company
was required by the Federal Energy Regulatory Commission to divest its
ownership of this facility. The TPS equity investment in this acquisition is
expected to be about $120 million in 2001.
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In February 1999, TPS formed an alliance with Energia Global
International, Ltd. (EGI), a company with energy interests in Latin America.
EGI has investments in six power projects in operation or under construction in
Chile, Costa Rica and Guatemala, and an electric distribution company in El
Salvador. TPS initially committed $25 million in the form of a loan, which
became an equity interest at the end of 2000. The interest income from the EGI
loan contributed to TPS' net income in 1999 and 2000. TPS made an additional
loan of $20 million in 2000.
Significant factors that could influence results at TPS are successful
financing and construction of its new projects, weather, domestic economic
conditions and commodity price changes. See the INVESTMENT CONSIDERATIONS
section.
TPS PROJECT SUMMARY
TPS ECONOMIC IN SERVICE/
PROJECT LOCATION SIZE INTEREST (%) PARTICIPATION DATE
------- -------- ---- ------------ ------------------
Hardee Power Station Florida 370 MW 100% Jan.1993, May 2000
Alborada Power Station Guatemala 78 MW 96% Sept. 1995
San Jose Power Station Guatemala 120 MW 100% Jan. 2000
Hamakua Energy Project Hawaii 60 MW 50% Aug. 2000, Dec. 2000
Frontera Power Station Texas 500 MW 100% May 2000/Feb. 2001
Commonwealth Chesapeake Power Station Virginia 312 MW 95% Sept. 2000, June 2001
Energy Center Kladno Generating (ECKG) Czech Republic 344 MW 13% Jan. 2000
Panda TIE Texas 1,000 MW (1) Dec. 2000, 2001
Dell Arkansas 599 MW 100% 4th Quarter 2002
McAdams Mississippi 599 MW 100% 4th Quarter 2002
El Dorado Arkansas 2,220 MW (2) Oct. 2002-Mar. 2003
Gila River Arizona 2,350 MW (2) 1st Half 2003
CITGO Louisiana 670 MW 50% Jan. 2005
Empresa Electrica de Guatemala S.A.(EEGSA) Guatemala 580,000 retail 24% Sept. 1998
(a distribution utility) electric customers
(1) Estimated at 75 percent.
(2) Based on the effect of the preferred return, estimated at 75 percent.
TECO TRANSPORT
Net income at TECO Transport increased 10 percent in 2000 reflecting a
strong export grain market, higher levels of coal moved for Tampa Electric,
increased movements of steel-related products northbound on the river systems
and a gain on the disposition of an ocean-going asset. Partially offsetting
these improvements were higher fuel prices, continued weakness in the export
coal market and lower phosphate shipments, as producers curtailed production to
bring supply and demand in balance.
TECO Transport recorded 10 percent higher net income in 1999,
primarily from a strong export grain market, increased northbound movements of
steel-related products on the river system and lower fuel and depreciation
expense. Improvements were partially offset by a weak export coal market and
lower shipments of coal for Tampa Electric.
In October 2000, TECO Transport signed a long-term contract with a
major phosphate fertilizer producer to move all of that producer's raw
phosphate rock production between Tampa and its facilities on the Mississippi
River. Under the contract, TECO Transport's ocean-going subsidiary, Gulfcoast
Transit, purchased two vessels used to serve this customer.
TECO Transport expects Tampa Electric coal shipments to be at normal
levels in 2001. It expects continued enhancements of northbound river business
and strong grain shipments in 2001, reflecting continued support of the U.S.
government sponsored grain export program.
The phosphate fertilizer industry continued to experience worldwide
oversupply and low prices, and expects the weakness to continue into 2001. This
condition reduced shipment of raw phosphate rock in 2000 and is expected to
have a similar impact in early 2001.
Continued weakness in the export coal market is anticipated in 2001,
primarily due to the strength of the U.S. dollar relative to other currencies
and excess coal production capacity worldwide.
TECO Transport expects to continue diversifying into new markets and
cargoes. Future growth at TECO Transport is dependent on higher asset
utilization, particularly at the river business with north-and southbound
cargoes, and asset additions at both the river and ocean-going businesses.
Significant factors that could influence results are weather, bulk commodity
prices, fuel prices and domestic and international economic conditions. See the
INVESTMENT CONSIDERATIONS section.
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TECO COAL
TECO Coal's net income more than doubled in 2000 to $37.5 million
driven primarily by the sale of fuel produced from the synthetic fuel
production facilities acquired this year and the associated tax credits for the
production of non-conventional fuels. For segment reporting purposes, the tax
credit is shown as an offset to expense for operating income calculation
purposes but is included in provision for income taxes in the TECO Energy
Consolidated Statements of Income.
TECO Coal's net income decreased almost 9 percent in 1999, excluding
the effect of a $13.6 million charge in 1998 described in the CHARGES TO
EARNINGS section . Lower 1999 operating income reflected lower Tampa Electric
volumes and weak prices in the metallurgical and steam markets, partially
offset by higher third-party volumes and cost efficiencies.
Coal sales, including synthetic fuels, increased to 7.9 million tons
in 2000 from 7.2 million tons in 1999 and 6.8 million tons in 1998. Volumes in
2001 are expected to be more than 10 million tons. This increase is driven by
production from the Perry County Coal mines described below.
Steam coal pricing improved in 2000, but at a lower percentage than
other energy prices. Metallurgical coal prices were weak in 2000 due to a
general weakness in the steel industry, but are expected to improve in 2001.
TECO Coal's contract with Tampa Electric expired at the end of 1999
and was not renewed. Tampa Electric shipments represented 2 percent of TECO
Coal's volume in 2000 and 7 percent of spot coal purchases in 1999.
In November 2000, TECO Coal purchased the Perry County Coal Co. Under
this purchase, TECO Coal acquired 23 million tons of proven low-sulfur
reserves, a preparation plant and two load-out facilities on the CSX railroad.
There are an additional 80 million tons of high-quality reserves already under
lease located on adjacent land.
In January 2000, TECO Coal purchased two synthetic fuel (synfuel)
facilities from Covol Technologies, Inc. which were relocated to the company's
Premier Elkhorn and Clintwood Elkhorn mines in Kentucky, and were operational
by the second quarter of 2000. These facilities produce synthetic fuels from
coal using a patented and proprietary process developed by Covol.
More than 1.9 million tons of synfuel were produced in 2000 resulting
in a net benefit of approximately $30 million. Synfuel production replaced some
of the conventional coal production in 2000. Production is expected to increase
somewhat in 2001.
Sales of the fuel processed through these types of facilities are
eligible for non-conventional fuels tax credits under Section 29 of the
Internal Revenue Code, which are available through 2007.
During the fourth quarter, the U.S. Treasury suspended advance rulings
by the Internal Revenue Service with respect to synthetic fuel production
facilities to permit the Treasury and the Service time to review certain
specified legal issues regarding the application of this credit. Taxpayers were
given the opportunity to provide the Treasury with comments regarding the
administration of the synthetic fuel tax credit program. While no retroactive
interpretation of qualification under the program is expected, the requirements
for obtaining advance rulings could include some production-limiting factors.
Significant factors that could influence results are weather, general
economic conditions, commodity price changes and changes in laws or
regulations. See the INVESTMENT CONSIDERATIONS section.
OTHER UNREGULATED COMPANIES
TECO COALBED METHANE'S 2000 net income increased as a result of higher
gas prices which more than offset lower production. Effective gas prices, net
of all hedging, increased to $2.72 per thousand cubic feet (Mcf). Production
declined 5 percent to 15.7 billion cubic feet (BCF) in 2000, less than the
natural decline rate, due to effective well-restimulation efforts. Proven
reserves were estimated at 182 BCF at Dec. 31, 2000, reflecting the well
restimulation efforts and higher gas prices. Proven reserves were estimated at
159 BCF and 162 BCF in 1999 and 1998, respectively.
In 1999, net income declined 13 percent from production and price
decreases that were only partially offset by reduced operating costs.
Production declined to 16.6 BCF in 1999 from 17.6 BCF in 1998. Effective gas
prices, including the results of hedging, fell $.12 per Mcf in 1999.
Production is expected to decline 6 to 8 percent in 2001, reflective
of the normal declining production profile for these types of gas wells.
Production from TECO Coalbed Methane's reserves are eligible for
Section 29 non-conventional fuels tax credits through 2002. The credit was
$1.05 per Mcf in 1998, $1.04 per Mcf in 1999 and is expected to be $1.05 for
2000. The tax credit declined in 1999 due to a reformulation of the calculation
of the GDP price deflator index used for determining the increase in the tax
credits. This rate escalates with inflation but could be limited by domestic
oil prices. In 2000, domestic oil prices would have had to exceed $47 per
barrel for this limitation to have been effective.
All gas produced is sold under contract at spot market prices.
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.
TECO PROPANE VENTURES (TPV) is the subsidiary in which the company's
propane business investment is held. This business was formerly known as
Peoples Gas Company, the unregulated propane gas business acquired in the 1997
Peoples Gas companies merger, which was the largest independent propane
distributor in Florida.
In February 2000, TECO Energy entered into an agreement to form US
Propane L.P. to combine its Peoples Gas Company propane operations with the
propane operations of Atmos Energy Corporation, AGL Resources, Inc. and
Piedmont Natural Gas Company, Inc.
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In June 2000, US Propane announced that it would combine with Heritage
Holdings, Inc., the general partner of Heritage Propane Partners, L.P.
(NYSE:HPG), to create the fourth largest retail propane distributor in the
United States.
Under the agreements, US Propane sold its propane business to Heritage
Propane for approximately $181 million in cash and limited partnership units of
Heritage Propane Partners. US Propane purchased all of the ownership interest
of Heritage Holdings, the general partner of Heritage Propane Partners, for
$120 million. Upon closing of the transaction, US Propane owned all of the
general partner and an approximate 34 percent limited partnership interest in
Heritage Propane Partners, the master limited partnership. Interests in the
general partner of US Propane are held proportionately among the four companies
that created US Propane.
The US Propane and Heritage Propane transactions transformed four
local propane operations into a major regional company and then into a larger
national operation that now markets over 300 million gallons of propane
annually to nearly 500,000 customers in 28 states. The transactions created a
significant market presence that allows pursuit of national accounts, balances
seasonal and weather related demand fluctuations on a broader scale and
provides a larger opportunity for growth.
TPV recorded an $8.3-million after-tax gain from this series of
transactions in the third quarter of 2000. TPV has a 38 percent interest in the
general partner that manages Heritage Propane Partners.
TECO SOLUTIONS was formed to support TECO Energy's strategy of
offering customers a comprehensive and competitive package of energy services
and products with its Florida operations focus. Operating companies under TECO
Solutions include TECO BGA, Inc. (formerly Bosek, Gibson and Associates) (TECO
BGA), BCH Mechanical, Inc. and its affiliated companies (BCH), TECO Gas
Services, TECO Properties, and TECO Partners.
TECO BGA, an energy services company headquartered in Tampa with nine
offices throughout Florida and one in California, was acquired by TECO Energy
in 1996. It provides design, engineering and construction services to more than
300 customers, including public schools, universities, health care
organizations and commercial businesses throughout Florida and California.
BGA continues growing its business infrastructure and project
portfolio to better compete with the larger energy service companies in the
diversified energy service field. Several significant project development
efforts are under way. These efforts include providing energy efficiency
turnkey services for public and private sector markets, power reliability
solutions and district cooling/chilled water plants.
In September 2000, TECO Energy purchased BCH. BCH is one of the
leading mechanical contracting firms in Florida.
TECO Solutions combines BGA's proven project development and design
capabilities with BCH's construction, operations and maintenance capabilities.
This combination is expected to allow the companies to improve their price and
performance on comprehensive turnkey projects because of in-house skills for
the entire project scope.
TECO GAS SERVICES, INC. is another unregulated business acquired in
the Peoples Gas companies merger. It provides gas management and marketing
services for large municipal, industrial, commercial and power generation
customers.
This company's focus is on increasing its customer base while
continuing to provide gas management services for three large cogeneration
facilities. TECO Gas Services is expected to provide gas management services
for an increasing customer base as Peoples Gas System makes its "NaturalChoice"
option for unbundled service available to more non-residential customers.
In 2000, TECO Properties recorded a $3.8-million, after-tax charge to
adjust certain properties to reflect their market value.
NON-OPERATING ITEMS
DISCONTINUED OPERATIONS
TECOM, INC.
In November 1999, the assets of TeCom, the company's advanced energy
management technology subsidiary, were sold to Invensys Intelligent Building
Systems. TeCom was sold because it was unable to develop the right distribution
channels to effectively reach the market.
In connection with the exit of this business, an after-tax charge of
$12.9 million was recorded in 1999, representing the write-off of all
capitalized development costs, severance and other exit costs partially offset
by sale proceeds.
TECO OIL & GAS, INC.
In 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.
In 1998, TECO Oil & Gas sold its offshore assets to American Resources
Offshore (ARO).
OTHER INCOME (EXPENSE)
Other income (expense) in 2000 included a pretax gain of $13.6 million
associated with the US Propane and Heritage Propane transactions, $5.4 million
from an insurance settlement at TPS, and interest income from the TPS
investments made in the form of loans. Also included was a charge of $8.1
million to adjust the value of certain leveraged lease investments.
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Other income (expense) in 1999 included charges of $3.5 million to
provide for Tampa Electric's expected costs of settling an EPA lawsuit, $10.5
million for a regulatory decision limiting the utility's regulatory equity
ratio to 58.7 percent for 1997 and 1998, and $6.0 million to adjust the
carrying value of certain leveraged lease investments.
Other income (expense) in 1998 included a charge of $7.3 million at
Tampa Electric reflecting an FPSC decision denying recovery of certain coal
expenses from an affiliate. These 1999 and 1998 charges are described in the
Charges to Earnings section.
Allowance for other funds used during construction (AFUDC) was $1.6
million in 2000 and $1.3 million in 1999; no AFUDC was recorded in 1998. AFUDC
is expected to increase to an estimated $8 million in 2001 and more than double
to an estimated $19 million in 2002, reflecting Tampa Electric's growing
investment in the Gannon repowering and generation expansion activities.
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 the equity funds used for construction.
INTEREST CHARGES
Interest charges at TECO Energy were $167.6 million in 2000 compared
to $123.7 million in 1999 and $104.3 million in 1998. Interest expense was
higher in 2000, primarily because of higher borrowing levels associated with
the company's business development activities and higher short-term interest
rates.
In 1999, a charge for income tax settlements and provisions, discussed
in the Changes to Earnings section, included $9 million of interest expense and
accounted for approximately half of the increase over 1998. Higher borrowing
levels associated with new investments in the operating businesses also
increased interest expense.
INCOME TAXES
Income tax expense decreased in 2000 reflecting lower taxable income,
a substantial increase in tax credits for the production of non-conventional
fuels and increased foreign operations with deferred tax structures. In 1999,
income tax expense increased reflecting higher taxable income and the effect of
recording income tax provisions and settlements related to prior years' tax
returns. In 1998, income taxes were lower due to lower taxable income resulting
from $23.2 million of charges. Income tax expense as a percent of income from
continuing operations before taxes was 7 percent in 2000, 30 percent in 1999
and 29 percent in 1998.
The actual cash paid for income taxes was $83.9 million, $62.1 million
and $66.2 million in 2000, 1999 and 1998, respectively. Total income tax
expense was reduced by the federal tax credit related to the production of
non-conventional fuels, under Section 29 of the Internal Revenue Code. These
tax credits are generated annually on qualified production at TECO Coalbed
Methane through Dec. 31, 2002 and at TECO Coal through Dec. 31, 2007, subject
to changes in law, regulation or administration that could impact the
qualification of Section 29 tax credits.
This tax credit totaled $68.3 million in 2000, $17.2 million in 1999
and $18.9 million in 1998. In 2000, $52.1 million of the Section 29 tax credits
related to the production of synthetic fuel at TECO Coal; $16.2 million of 2000
tax credits and all prior-year amounts reflect the tax credits related to the
production of natural gas from coal seams at TECO Coalbed Methane.
The tax credit for production at TECO Coalbed Methane and TECO Coal
was $1.05 per million BTU in 1998, $1.04 per million BTU in 1999 and is
expected to be $1.05 for 2000. This rate escalates with inflation but could be
limited by domestic oil prices. In 2000, domestic oil prices would have had to
exceed $47 per barrel for this limitation to have been effective.
In 2000, the decrease in income tax expense also reflects the impact
of increased overseas operations with deferred tax structures. The decrease
related to these deferrals was $9.3 million, $1.4 million and $1.0 million for
2000, 1999 and 1998, respectively.
The income tax effect of gains and losses from discontinued operations
is shown as a component of results from discontinued operations.
Income tax expense for 1999 includes $5.0 million for charges
described in the Changes to Earnings section reflecting corporate income tax
provisions and settlement expenses related to prior years' tax returns. These
adjustments, including interest of $9.0 million, were recorded at Tampa
Electric, TECO Investments and at the TECO Energy corporate level.
ACCOUNTING STANDARDS
REPORTING COMPREHENSIVE INCOME
In 1999, the company adopted Financial Accounting Standard (FAS) 130,
Reporting Comprehensive Income. This standard requires that comprehensive
income, which includes net income as well as certain other changes in assets
and liabilities recorded in common equity, be reported in the financial
statements. TECO Energy reported $2.0 million of other comprehensive income in
2000 and $5.5 million of other comprehensive loss in 1999 related to
adjustments to the minimum pension liability associated with the company's
supplemental executive retirement plan. There were no components of
comprehensive income other than net income for the year ended Dec. 31, 1998.
The company has reported accumulated other comprehensive income in its
Consolidated Statements of Common Equity.
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REPORTING ON THE COSTS OF START-UP ACTIVITIES
In 1999, the company adopted AICPA Statement of Position (SOP) 98-5,
Reporting on the Costs of Startup Activities. It requires costs of startup
activities and organization costs to be expensed as incurred. Startup
activities are broadly defined as those one-time activities related to events
such as opening a new facility, conducting business in a new territory and
organizing a new entity. Some costs, such as the costs of acquiring or
constructing long-lived assets and bringing them into service, are not subject
to SOP 98-5. The costs expensed in 2000 and 1999 in accordance with SOP 98-5
were not significant.
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING
In 1998, the Financial Accounting Standards Board (FASB) issued FAS
133, Accounting for Derivative Instruments and Hedging. This standard is
effective for fiscal years beginning after June 15, 2000. The company will
adopt the new standard effective Jan. 1, 2001. The new standard requires the
company to 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 in net income, depending on the types of those
instruments.
The company has completed the review and documentation of its
derivative contracts, and found that such activity has been minimal and
relatively short term in duration. From time to time, the company has entered
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, and to limit exposure to fuel price increases at TECO Transport.
As of Dec. 31, 2000, the company had hedging transactions in place to
protect against selling price variability at TECO Coalbed Methane which will
qualify for cash flow hedge accounting treatment under FAS 133. Upon adoption,
the company expects to report a reduction in other comprehensive income of
approximately $19.0 million before tax to record the swap liability as of Jan.
1, 2001.
The company has not used derivatives or other financial products for
speculative purposes. Management will continue to document all current, new and
possible uses of derivatives particularly as it relates to the expanding
merchant power projects at TECO Power Services, and develop procedures and
methods for measuring them.
ENVIRONMENTAL COMPLIANCE
Tampa Electric met the environmental compliance requirements for 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 flue gas desulfurization, or scrubber, system
with Unit Three, implementing operational modifications and purchasing emission
allowances. For Phase II, which began Jan. 1, 2000, further reductions in sulfur
dioxide (SO2) and nitrogen oxide (NOx) emissions were required. To comply with
the Phase II SO2 requirements, Tampa Electric installed a new scrubber system at
Big Bend Units One and Two and will rely less on fuel blending and SO2 allowance
purchases. The $83-million scrubber was placed in service on Dec. 30, 1999 and
has significantly reduced the amount of SO2 emitted by Tampa Electric's Big Bend
Units One and Two. As a result of this project, all of the units at Big Bend
Station, Tampa Electric's largest generating station, are equipped with scrubber
technology. In order to comply with the Phase II NOx emission limits on a system
wide average, Tampa Electric has implemented combustion optimization projects at
Big Bend and Gannon stations.
On Feb. 29, 2000, Tampa Electric Company, the EPA and the U.S.
Department of Justice announced they had resolved the federal agencies' pending
enforcement actions filed in 1999 against Tampa Electric. The resolution was in
the form of a consent decree, which became effective Oct. 5, 2000 and has
resulted in full and final settlement of the federal litigation and notice of
violation alleging violations of New Source Review requirements of the Clear
Air Act.
The consent decree is substantially the same as Tampa Electric's
earlier agreement with the Florida Department of Environmental Protection
(FDEP) with respect to environmental controls and pollution reductions reached
on Dec. 7, 1999; however, it contains specific detail with respect to the
availability of the scrubbers and earlier incremental NOx reduction efforts on
Big Bend Units One, Two and Three. Under the consent decree, Tampa Electric is
committed to a comprehensive cleanup program that will dramatically decrease
emissions from the company's power plants.
A significant component of the emission reduction plan is the
repowering of the company's coal-fired Gannon Station with natural gas.
Engineering for the repowering project began in January 2000, and
Tampa Electric anticipates that commercial operation for the first repowered
unit will occur by May 1, 2003. The repowering of additional units is scheduled
to be completed by May 1, 2004. When these units are repowered, the station
will be renamed the Bayside Power Station and will have total station capacity
of about 1,800 megawatts (nominal) of natural gas-fueled electric energy.
Tampa Electric filed petitions with the FPSC to seek cost recovery for
various environmental projects required by the consent decree. The petition
sought cost recovery through the Environmental Cost Recovery Clause for costs
incurred to improve the availability and removal efficiency for its Big Bend
One, Two and Three scrubbers, to reduce particulate matter emission, and to
reduce NOx emissions. In November, the FPSC approved the recovery of these
types of costs through customers' bills starting January 2001.
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
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presents the potential for significant response costs, Tampa Electric Company
estimates its ultimate financial liability at approximately $22 million over
the next 10 years. The environmental remediation costs associated with these
sites are not expected to have a significant impact on customer prices.
UTILITY REGULATION
RATE STABILIZATION STRATEGY
Tampa Electric's objectives of stabilizing prices from 1996 through
1999 and securing fair earnings opportunities during this period were
accomplished through a series of agreements entered into in 1996 with the
Florida Office of Public Counsel (OPC) and the Florida Industrial Power Users
Group (FIPUG) which were approved by the Florida Public Service Commission
(FPSC). Prior to these agreements, the FPSC approved a plan submitted by Tampa
Electric to defer certain 1995 revenues.
In general, under these agreements Tampa Electric was allowed to defer
revenues in 1995 and 1996 during the construction of Polk Unit One and
recognize these revenues in 1997 and 1998 after commercial operation of the
unit. Other components of the agreements were: a base rate freeze through 1999;
refunds to customers totaling $50 million during the period October 1996
through December 1998; and recovery of the capital costs incurred for the Polk
Unit One project.
Under these agreements Tampa Electric's allowed return on equity (ROE)
was established at an 11.75 percent midpoint with a range of 10.75 percent to
12.75 percent. Revenues were deferred for use by the company in 1997 and 1998
according to sharing formulas that varied by year. In 1998, all revenues above
the top of the ROE range were required to be held for refund to customers.
For 1995 and 1996, Tampa Electric deferred $51 million and $37 million
of revenues under this plan, respectively. The deferred revenues accrued
interest at the 30-day commercial paper rate as specified in the Florida
Administrative Code. These amounts and interest (less $25 million of refunds)
provided $62 million for recognition as income by the company for 1997 and
1998. Revenues in 1997 and 1998 were lower by $5 million and $20 million,
respectively, as a result of a temporary base rate reduction that was a
component of the stipulation.
Based on FPSC decisions, the company reversed $27 million for 1997 and
$34 million for 1998 of the revenues deferred from 1995 and 1996. After
including $10 million of interest accrued over the deferral period, the FPSC
ordered $11 million plus interest to be refunded to customers. In November
1999, FIPUG protested the FPSC decisions for both 1997 and 1998 and requested a
hearing to review a wide range of costs incurred by the company over the
two-year period. Accordingly, the FPSC ordered that the $11 million refund be
withheld with interest until the protest was heard and resolved.
In August 2000, the FPSC approved a stipulation entered into between
Tampa Electric, FIPUG and OPC that provided for a $13 million refund to
customers from September through December 2000. This amount generally
represented the $11 million refund amount previously determined plus interest.
As part of its series of agreements with OPC and FIPUG, Tampa Electric
also agreed to refund 60 percent of 1999 revenues that contributed to an ROE in
excess of 12 percent, as calculated and approved by the FPSC.
In October 2000, the FPSC staff recommended a 1999 refund of $6.1
million including interest, to be refunded to customers beginning January 1,
2001. OPC objected to certain interest expenses recognized in 1999 that were
associated with prior tax positions and used to calculate the amount to be
refunded. Following a review by the FPSC staff, the FPSC agreed in December
2000 that the original $6.1 million was to be refunded to customers. On Feb. 7,
2001 OPC protested the FPSC's refund decision. The protest claims that the
stipulations do not allow for the inclusion of the interest expenses on income
tax positions in the refund calculations. OPC suggests that an additional $8.3
million should be refunded. Hearing dates to resolve the 1999 refund amount are
scheduled for August 2001. Tampa Electric believes its positions relative to
the inclusion of the interest expenses are reasonable and are likely to be
upheld.
The regulatory arrangements described above covered periods that ended
on Dec. 31, 1999. Tampa Electric's rates and its allowed ROE range of 10.75
percent to 12.75 percent with a midpoint of 11.75 percent will continue in
effect until such time as changes are occasioned by an agreement approved by
the FPSC or other FPSC actions as a result of rate or other proceedings
initiated by Tampa Electric, FPSC staff or other interested parties. Tampa
Electric believes that its currently allowed ROE range is reasonable based on
the current interest rate environment and previous FPSC rulings.
COST RECOVERY CLAUSES
In September 2000, Tampa Electric filed with the FPSC for approval of
fuel and purchased power, capacity, environmental and conservation cost
recovery clause rates for the period January 2001 through December 2001. In
November, the FPSC approved Tampa Electric's requested changes. Accordingly,
Tampa Electric's residential customer rate per 1,000 kilowatt hours increased
only by 2 cents to $84.47. These rates include projected costs associated with
environmental projects required under the U.S. Environmental Protection
Agency's Consent Decree and the Florida Department of Environmental Protection
Consent Final Judgment with Tampa Electric. See the Environmental Compliance
section. They also include additional purchased power costs for 2000 and 2001,
which reflect higher natural gas and oil prices and increases in the volumes of
purchased power.
In February 2001, Tampa Electric notified the FPSC that it anticipated
that the fuel factors approved in December 2000 for 2001 were understated by
approximately $86 million due to significantly higher natural gas and oil
prices, and accordingly,
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purchased power costs. In March 2001, the FPSC approved Tampa Electric's request
to increase rates to cover the $86 million beginning in April 2001.
In January 2001, PGS notified the FPSC that it anticipated that its
PGA factors approved in December 2000 for 2001 were understated by
approximately $63 million due to significantly higher natural gas prices. In
February 2001, the FPSC approved PGS' request to increase rates to cover the
$63 million under-recovery beginning in March 2001.
LONG-RANGE POWER SUPPLY PLANNING
In 1999, as part of the FPSC's assessment of Florida's electric
reliability for future years, the FPSC ordered a generic investigation into the
aggregate reserve margins planned for peninsular Florida. Tampa Electric, along
with Florida Power & Light and Florida Power Corp. submitted a proposed
stipulation to the FPSC to voluntarily adopt a minimum 20-percent reserve
margin planning criteria from the then current 15-percent criteria over a
transition period of four years. In December 1999, the FPSC approved the
proposed stipulation.
Tampa Electric accelerated the in-service date of its next two
180-megawatt combustion turbines from January 2001 to September 2000 and from
January 2003 to May 2002. The September 2000 combustion turbine was
subsequently accelerated to begin actual commercial operation in July 2000.
Tampa Electric also entered into a 12-year purchased power agreement
with Hardee Power Partners for a 75-megawatt combustion turbine that entered
service in May 2000.
In August 2000, Tampa Electric presented a revised 10-year site plan
to the FPSC which further enhances system reliability and improves economic and
environmental benefits to customers. Under this revised plan, the capacity of
the Gannon Station repowering project was increased by 235 megawatts. The
increased capacity increased Tampa Electric's projected 2004 summer reserve
margin from 23 percent to 27 percent at a lower cost than previous repowering
plans.
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 alternatives through various initiatives,
including legislative and/or regulatory changes that would permit competition
at the retail level. Tampa Electric intends to retain and expand its retail
business by managing costs and providing high-quality service to retail
customers.
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. However, the Florida Power Plant Siting Act, which
sets the state's electric energy/environmental policy and governs the building
of new generation involving steam capacity of 75 megawatts or more, requires
that applicants demonstrate that a plant is needed prior to receiving
construction and operating permits.
In 2000, Florida Governor Jeb Bush established the 2020 Energy Study
Commission to address the following issues by December 2001: current and future
reliability of electric and natural gas supply; emerging energy supply and
delivery options; electric industry competition; environmental impacts of
energy supply; energy conservation and fiscal impacts of energy supply options
on taxpayers and energy providers. TECO Energy has been supportive of the
process. The Study Commission recently endorsed an interim recommendation on
wholesale competition that, if enacted into law, would afford the company the
opportunity to compete effectively in the Florida market.
The Study Commission's recommendation to Governor Bush includes, among
other provisions, elimination of barriers to entry for merchant power
generators, an open competitive wholesale electric market, transfer of
regulated generating assets to unregulated affiliates or sale to others,
Florida electric system reliability and consumer protection. A proposal is
expected to be forwarded to the legislature by the governor for possible action
in the 2001 legislative session. It is unclear at this time if this proposed
legislation would pass.
REGIONAL TRANSMISSION ORGANIZATION (RTO)
In December 1999, the Federal Energy Regulatory Commission (FERC)
issued Order No. 2000, dealing with RTOs. This rule is driven by the FERC's
continuing effort to effect open access to transmission facilities in large,
regional markets. The rule provides guidelines to utilities for joining RTOs by
December 2001. These guidelines specify minimum characteristics and functions.
In anticipation of the FERC activity, the FPSC held workshops in 1999
to discuss transmission issues within peninsular Florida. Potentially affected
parties and the FPSC agreed that a national one-size-fits-all approach is not
appropriate. With the encouragement of the FPSC, Tampa Electric worked with
utilities in the state and others to develop a peninsular Florida solution.
The activities resulted in the peninsular Florida investor-owned
utilities making joint RTO filings at FERC in October and December 2000. The
filing included elements related to governance, pricing, planning, operations
and market design. Tampa Electric and other stakeholders are seeking a market
design in the collaborative process, which at a minimum addresses each of the
FERC criteria in Order 2000
In the filing, Tampa Electric agreed with the other Florida
investor-owned utilities to form an RTO to be known as GridFlorida LLC. As
proposed, the RTO would independently control the transmission assets of the
filing utilities, as well as
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other utilities in the region that choose to join. The RTO will be an
independent, investor-owned organization that will have control of the planning
and operations of the bulk power transmission systems of the utilities within
peninsular Florida. The three filing utilities represent almost 80 percent of
the aggregate net energy load in the region for the year 2000.
On January 10, 2001, FERC issued preliminary rulings on certain aspects
of the governance structure of the RTO. In order to guarantee the right to
participate in the selection of the RTO board of directors, parties were
required to declare, within 30 days of the January 10 order, their intention to
contribute their transmission assets to the RTO. Tampa Electric has filed to
inform the FERC that it planned to contribute its transmission assets to the
RTO.
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, including electricity.
In November 2000, PGS implemented its "NaturalChoice" program that
offers unbundled transportation service to all non-residential customers. This
means that non-residential customers can purchase commodity gas from a third
party but continue to pay PGS for the transportation of the gas. Because PGS
earns margins on the distribution of gas, but not on the commodity itself, this
program is not expected to negatively impact PGS results.
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, by transporting gas through other
facilities, thereby bypassing PGS facilities. In response to this competition,
various programs have been developed including the provision of transportation
services at discounted rates.
In general, PGS faces competition from other energy source suppliers
offering fuel oil, electricity and in some cases, propane. PGS has taken
actions to retain and expand its commodity and transportation business,
including managing costs and providing high-quality service to customers.
In March 2000, the franchise agreement between the city of Lakeland
(City) and PGS expired. The city has initiated legal proceedings seeking a
declaration of the city's rights to acquire the PGS facilities under the
franchise. PGS has filed defenses and counter claims and a hearing is scheduled
for May 2001. While PGS believes it is best suited to serve these customers,
it cannot at this time predict the ultimate outcome of these activities.
PGS is continuing to serve under substantially the same terms as
contained in the franchise in the absence of other rules and regulations being
adopted by the city. The Lakeland franchise contributed about $4 million of net
revenue to PGS results in 2000.
CAPITAL INVESTMENTS
TECO Energy's 2000 capital expenditures of $688 million included $267
million for Tampa Electric, $82 million for Peoples Gas System and $339 million
for the unregulated companies. Tampa Electric invested $164 million in 2000 for
equipment and facilities to meet its growing customer base and generating
equipment maintenance, $50 million for the repowering and conversion of the
coal-fired Gannon to the natural gas-fired Bayside Station (see the
Environmental Compliance section) and $53 million toward the construction of
Polk Units Two and Three, which are natural gas and No. 2 oil-fired combustion
turbines. Capital expenditures for Peoples Gas System were approximately $64
million for system expansion, including approximately $21 million related to
its Southwest Florida expansion, and approximately $18 million for maintenance
of the existing system. TECO Transport invested $21 million in 2000 for
equipment additions and normal equipment replacement. TECO Coal spent $64
million, which includes $40 million for the acquisition and relocation of two
synthetic fuel production plants, $20 million for the acquisition of the Perry
County Coal Company assets and the balance for normal equipment replacements.
TECO Power Services' capital expenditures totaled $243 million related to the
Commonwealth Chesapeake Power Station, the Dell and McAdams Power Stations and
the expansion of the Hardee Power Station. These amounts do not include
expenditures associated with investments in and loans to unconsolidated
affiliates of $327 million, which are described in Investment Activity.
TECO Energy estimates total capital investments for ongoing operations
to be $1.3 billion for 2001 and $2.7 billion during the 2002-2005 period.
For 2001, Tampa Electric expects to spend $373 million, consisting of
$167 million for the repowering project at the Gannon Station, $20 million in
construction costs on Polk Unit Three and $186 million to support system growth
and generation reliability. At the end of 2000, Tampa Electric had outstanding
commitments of about $300 million for the repowering project. Tampa Electric's
total capital expenditures over the 2002-2005 period are projected to be $1.1
billion, including $19 million for generation expansion and $459 million for
the repowering project.
Capital expenditures for Peoples Gas System are expected to be about
$73 million in 2001 and $251 million during the 2002-2005 period. Included in
these amounts are approximately $45 million annually for revenue-producing
projects associated with normal system growth and expansion. The remainder
represents expenditures for ongoing maintenance capital.
TECO Power Services expects to invest $833 million in 2001 for
construction of Phase 2 of the Commonwealth Chesapeake Power Station, the
construction of the Dell and McAdams Power Stations and the acquisition of the
Frontera Power
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Station. Commitments of $475 million at the end of 2000 were mainly for the
construction of the Dell and McAdams Power Stations. A significant amount of
the capital expenditures for TPS is expected to be financed with non-recourse
project financing.
Estimates for TPS include equity contributions to projects of
unconsolidated affiliates. These amounts, consisting primarily of equity
investments in the El Dorado and Gila River Power Stations, are estimated at
$1.1 billion for 2001 - 2005, which includes commitments of $796 million at the
end of 2000. Capital investment estimates reflect committed projects and do not
take into account future opportunities that may emerge.
The other unregulated companies expect to invest $68 million in 2001
and $191 million during the 2002-2005 period. Included in these amounts is
normal renewal and replacement capital including coal mining equipment and
river barges.
See the LIQUIDITY, CAPITAL RESOURCES section for a description of TECO
Energy's plans to finance these capital investments.
INVESTMENT ACTIVITY
At Dec. 31, 2000, TECO Energy had $99.6 million in cash, cash
equivalents and short-term investments, compared to $97.5 million at year-end
1999.
Year-end cash balances were higher than normal in both years. At the
end of 2000, cash balances included the proceeds from TPS Dec. 29, 2000 lease
transaction, which were applied to short-term debt balances in 2001. See
Financing Activity section. Cash was higher at the end of 1999 to fund cash
needs for the first several weeks of 2000 in anticipation of "Y2K" related
tight credit markets.
Other investments of $414 million include notes receivable from
unconsolidated affiliates and investments in leveraged leases; $223 million of
the notes receivable mature within one year. Notes receivable from
unconsolidated affiliates increased $327 million in 2000, mainly due to the
Panda Energy Projects at TPS. These amounts are expected to increase during the
first quarter of 2001 until project financing is completed and the advances are
repaid.
Investments in unconsolidated affiliates of $187.5 million at Dec. 31,
2000 increased from $103.3 million last year. The balances include TPS
ownership interests in EEGSA and EGI, and TECO Propane Ventures' 38 percent
interest in US Propane. Activity in 2000 was largely associated with the EGI
and US Propane transactions.
The continuing investment in leveraged leases was $22 million at Dec.
31, 2000, down from $49 million last year, reflecting the sale of several
leases in 2000 and the adjustment of residual equipment values. The company has
made no investment in leveraged leases since 1989 and is considering selling
additional leveraged lease positions.
FINANCING ACTIVITY
TECO Energy's 2000 year-end capital structure, excluding the effect of
unearned compensation, was 62 percent debt, 4 percent trust preferred
securities and 34 percent common equity. TECO Power Services typically finances
its power projects at commercial operation with non-recourse project debt.
Excluding this non-recourse debt of $258 million, the year-end capital
structure was 60 percent debt, 5 percent trust preferred securities and 35
percent common equity.
CREDIT RATINGS/SENIOR DEBT (as of March 27, 2001)
FITCH MOODY'S STANDARD & Poor's
----- ------- -----------------
Tampa Electric AA Aa3 A
TECO Finance / TECO Energy A A3 A-
In July and October 2000, Fitch Investor Services, Inc. and Standard &
Poor's Ratings Services, respectively, lowered the ratings on the debt
securities of TECO Energy and Tampa Electric. Each rating agency indicated that
the rating outlook remained negative.
On Mar. 27, 2001, Moody's Investor Services, Inc. lowered the long-term
ratings on the debt securities of TECO Energy and Tampa Electric to the rates
indicated above, and lowered the short-term rating of TECO Finance to P-2 from
P-1. This action concluded a review begun in November 2000.
The ratings actions were attributed to increased debt levels and
changing risk profile associated with the expansion of TECO Energy's independent
power development activities, as well as the required capital outlays of Tampa
Electric and the uncertainties related to industry restructuring.
Execution of the company's business strategy will increase the
proportion of unregulated power generation in TECO Energy's business mix. The
company continues to evaluate the financial policies required for this more
competitive business environment in order to maintain appropriate credit
ratings for both Tampa Electric and TECO Energy. The objective for both TECO
Energy and Tampa Electric is to maintain strong credit ratings that provide the
companies with continued access to the commercial paper markets.
In November 2000, TECO Energy filed a shelf registration statement for
the issuance of up to $1.2 billion of debt, equity and hybrid securities. Of
the total amount, $200 million reflects the unused balance from a prior
registration statement.
35
36
In March 2001, the company completed a public offering of 8.625 million
common shares, resulting in net proceeds to the company of approximately $232
million. The proceeds from the sale of these shares were used primarily to
reduce commercial paper balances and for general corporate purposes. The company
expects to issue additional common equity and/or hybrid securities during the
next three to four years.
In December 2000, TECO Energy issued $200 million of retail trust
preferred securities (TRuPS) to strengthen its capital structure. These
securities were issued at a $25 per share par value and an 8.5% coupon with
distribution payable quarterly. These securities have a January 31, 2041
maturity date but are callable at par after December 20, 2005.
In September 2000, TECO Energy issued $200 million of remarketed
notes, due 2015. The notes, which bear an initial coupon rate of 7.0%, are
subject to mandatory tender on Oct. 1, 2002. Net proceeds were $206.3 million,
which included a premium paid to TECO Energy by the remarketing agent for the
right to purchase and remarket the notes in 2002. If this right is exercised,
for the following 10 years the notes will bear interest at 5.86% plus a premium
based on TECO Energy's then-current credit spread above United States Treasury
Notes with 10 years to maturity.
In August 2000, Tampa Electric Company issued $150 million of
remarketed notes, due 2015. The notes, which bear an initial coupon rate of
7.37% are subject to mandatory tender on Sept. 1, 2002, at which time they will
be remarketed or redeemed. Net proceeds were $154.2 million, which included a
premium paid to Tampa Electric by the remarketing agent for the right to
purchase and remarket the notes in 2002. If this right is exercised, for the
following 10 years the notes will bear interest at 5.75% plus a premium based
on Tampa Electric Company's then-current credit spread above United States
Treasury Notes with 10 years to maturity.
In February 2001, Tampa Electric Company filed a shelf registration
statement for the issuance of up to $500 million of debt securities.
TPS on Dec. 29, 2000, sold to a third party and leased back certain
non-integral equipment at its Hardee Power Station in a transaction structured
as an operating lease with a term of 12 years.
In October 2000, TPS converted the construction debt relating to its
San Jose project to $82 million of non-recourse financing, and issued $32
million of 10-year notes with a coupon rate of 9.63%. These notes are
guaranteed by the Overseas Private Investment Corp. (OPIC).
Proceeds from these issues were used to repay short-term debt and for
general corporate purposes.
In September 1999, TECO Energy announced a program for the repurchase
of up to $150 million of its outstanding common stock. During 1999, the company
acquired 5.4 million shares at a cost of $114.8 million. In 2000, the company
acquired an additional 1.6 million shares for $29.9 million. The average price
per share paid for the 7.0 million shares repurchased was $20.55.
TECO Energy is exposed to changes in interest rates primarily as a
result of its borrowing activities. Based on the financing plans discussed in
the LIQUIDITY, CAPITAL RESOURCES section, a hypothetical 10-percent increase in
TECO Energy's weighted average interest rate on its variable rate debt would
have an estimated $2 million impact on TECO Energy's earnings over the next
fiscal year.
A hypothetical 10-percent change in interest rates would not have a
significant impact on the estimated fair value of TECO Energy's long-term debt
at Dec. 31, 2000.
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, to hedge the selling price
for its physical production at TECO Coalbed Methane, to limit exposure to gas
price increases at the regulated natural gas utility and to limit exposure to
fuel price increases at TECO Transport. 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.
As TECO Power Services develops its merchant power plant portfolio,
the company may utilize futures, swaps and option contracts in connection with
the marketing of power in order to reduce the variability of electricity
selling prices.
TECO 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 2000
with a balance of internally generated funds, short- and long-term borrowings
and retail trust preferred securities. Cash needs in 1999 were met with
internally generated funds and short-term borrowings.
TECO Energy anticipates that internally generated funds will
substantially meet its capital requirements for ongoing operations and
commitments in the 2001-2005 period, excluding the TECO Power Services projects
announced in 2000. TECO Power Services expects to finance the construction of
the Dell, McAdams, El Dorado and Gila River projects with approximately 60
percent non-recourse debt. Recourse project debt will fund the balance of
construction, to be repaid at or before commercial operation with a combination
of TECO Energy debt, equity or hybrid securities. Bridge financing of $337
million was funded in March 2001 for the El Dorado and Gila River to be used
until construction financing is received. See the INVESTMENT CONSIDERATIONS
section.
In March 2001, the company completed a public offering of 8.625 million
common shares resulting in net proceeds to the company of approximately $232
million. The proceeds from the sale of these shares were used primarily to
reduce commercial paper balances and for general corporate purposes. The company
expects to issue additional common equity and/or hybrid securities during the
next three to four years.
36
37
Notes payable, representing commercial paper with maturities up to 75
days, totaled $1.2 billion at Dec. 31, 2000. The company expects to reduce
these balances to approximately $300 million in early 2001 with the proceeds of
the common equity issuance, project construction financing and longer term debt
issues for TECO Energy and Tampa Electric.
At Dec. 31, 2000, TECO Energy had bank credit lines of $485 million,
all of which are undrawn and available. The company expects to expand the size
of its credit facility in 2001.
INVESTMENT CONSIDERATIONS
The following are certain factors that could affect TECO Energy's
future results. They should be considered in connection with evaluating
forward-looking statements contained in this report and otherwise made by or on
behalf of TECO Energy, since these factors could cause actual results and
conditions to differ materially from those projected in these forward-looking
statements.
GENERAL 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 Peoples Gas System's 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 System's expected
performance.
The activities of the unregulated businesses, particularly TECO
Transport, TECO Coal and TECO Power Services are also affected by general
economic conditions in the respective industries and geographic areas they
serve, both nationally and internationally. TPS' investments in international
distribution companies are dependent on growth in the service areas and
forecasts for annual energy sales growth.
WEATHER VARIATIONS. Most of TECO Energy's businesses are affected by
variations in general weather conditions and unusually severe weather. Tampa
Electric's, Peoples Gas System's and TECO Power Services' 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 is 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 System.
Variations in weather conditions also affect the demand and prices for
the commodities sold by TECO Coalbed Methane and TECO Coal and electric power
sales from TECO Power Services' merchant power plants. 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 affect 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 gas distribution industry has been subject to competitive forces
for several years. Gas services provided by Peoples Gas System are now
unbundled for all non-residential customers. Because Peoples Gas System earns
margins on distribution of gas, but not on the commodity itself, unbundling has
not negatively impacted Peoples Gas System results. However, future structural
changes cannot be predicted and could adversely affect Peoples Gas System.
REGULATORY ACTIONS. Tampa Electric and Peoples Gas System operate in
highly regulated industries. Their retail operations, including the prices
charged, are regulated by the Florida Public Service Commission, and Tampa
Electric's wholesale power sales and transmission services are subject to
regulation by Federal Energy Regulatory Commission. Changes in regulatory
requirements or adverse regulatory actions could have an adverse effect on
Tampa Electric's or Peoples Gas System's performance by, for example,
increasing competition or costs, threatening investment recovery or impacting
rate structure.
The merchant plants being developed by TECO Power Services will
require authorization from FERC for market-based rates. In granting such a
request, FERC typically requires a showing that the plant's owners and
affiliates lack market power in the relevant generation and transmission
markets and in markets for related commerce such as fuel. Obtaining FERC
authority for market-based rates would also require a showing by the seller
that there is no opportunity for abusive affiliate transactions involving any
of TECO Power Services' regulated affiliates. TECO Power Services does not
anticipate any material difficulties in obtaining these authorizations, but it
cannot guarantee that they will be granted.
TECO Coal's forecast includes Section 29 tax credits related to the
production of non-conventional fuels. Future changes in tax law or
interpretative action by the U.S. Treasury could impact TECO Coal's quantity of
qualified synfuels production and therefore the amount of available tax
credits.
COMMODITY PRICE CHANGES. Most of TECO Energy's businesses are
sensitive to changes in certain commodity prices which could be brought on by
many factors. Such changes could affect the prices these businesses charge,
their operating costs and the competitive position of their products and
services.
37
38
In the case of Tampa Electric, currently fuel costs used for
generation are mostly affected by the cost of coal; future fuel costs will be
impacted by the cost of natural gas as well as 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. Regarding wholesale sales, the
ability to make sales and the margins on power sales are currently 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 System relative to electricity, other forms of energy and other
gas suppliers.
At the diversified companies, changes in gas, oil and coal prices
directly affect the margins at TECO Power Services, TECO Coalbed Methane, TECO
Coal, TECO Transport and TECO Propane Ventures. TECO Coalbed Methane is exposed
to commodity price risk through the sale of natural gas. A hypothetical 10
percent change for the year in the market price of natural gas would have an
estimated earnings impact of $3-million. TECO Coal is exposed to commodity
price risk through coal sales. A hypothetical 10 percent change in the market
price of coal in any one year would have an estimated earnings impact of
between $15 million and $20 million. TECO Transport is exposed to commodity
price risk through fuel purchases. A hypothetical 10 percent change in the
market price of fuel in any one year would have an estimated earnings impact of
$1 million.
At TECO Power Services, the price paid for natural gas is expected to
pass through to the customer. In those instances where these costs are not
passed directly to the customer, the price of gas is expected to be reflected
in the price charged to the customer for electricity.
GAS PRODUCTION LEVELS. Results at TECO Coalbed Methane are affected by
its level of production, which is naturally declining. The company's forecast
assumes that production will decline 6 to 8 percent annually. Actual production
levels may be different than those assumed.
BUSINESS GROWTH OPPORTUNITIES. Part of the company's business strategy
is to grow its unregulated business. Much of its longer-term growth is
dependent on the ability to find attractive acquisition and development
opportunities and independent power projects. The company's ability to
successfully finance and complete current and future projects on schedule and
within budget may also affect the success of this strategy. The company's
long-range outlook 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.
CONSTRUCTION RISKS. Tampa Electric currently has new power plants
under construction and existing facilities under conversion and TECO Power
Services has new power plants under development and construction. The
construction of these plants as well as future construction projects involve
risks, such as shortages and inconsistent qualities of equipment; material and
labor; engineering problems; work stoppages; unanticipated cost increases and
environmental or geological problems.
MERCHANT POWER PLANTS. TECO Power Services is currently operating,
developing, constructing and investing in merchant power plants. A merchant
plant sells power based on market conditions at the time of sale, so there can
be no certainty at present about the amount or timing of revenue that may be
received from power sales from operating plants or about the differential
between the cost of operations (in particular, natural gas prices) and merchant
power sales revenue. With no guaranteed rate of return, TECO Power Services
will also have no guarantee that it will recover its initial investment in
these plants. The company's forecasts assume that TECO Power Services will
avoid losses associated with these risks by building in well-established
markets that enables the company to use established hedging mechanisms, hiring
an experienced, investment-grade power marketer, avoiding selling short and
entering into non-energy related sales to offset potential operational risks.
INTEREST RATES AND ACCESS TO CAPITAL. Changes in interest rates can
affect the cost of borrowing for TECO Energy and its subsidiaries on variable
rate debt outstanding, on refinancing of debt maturities and on incremental
borrowing to fund new investments. Included in the company's forecasts is the
expectation that it will have access to sufficient capital on satisfactory
terms to fund growth opportunities including acquisition and development
opportunities and independent power projects.
TECO Power Services expects to finance the approximately $3 billion
required for the construction of its new merchant plants with a combination of
recourse and non-recourse construction financing and contributions from TECO
Energy. Upon commercial operation of these projects, TPS anticipates that the
non-recourse borrowings, representing approximately 60 percent of the total,
will convert to longer-term non-recourse project debt, and any recourse
borrowings will be repaid with contributions from TECO Energy. Because funding
is dependent on many factors, including the success of these plants upon
commencement of commercial operations, the company also cannot guarantee that a
portion of this debt can be funded in the future by alternate sources. The
source of these contributions is expected to be a combination of TECO Energy
debt, equity or hybrid securities. Although the company anticipates that this
funding will be available on acceptable terms, it cannot guarantee that this
will be the case.
In July and October 2000, Fitch Investor Services, Inc. and Standard &
Poors Ratings Services, respectively, lowered the ratings on the debt securities
of TECO Energy and Tampa Electric. Each rating agency indicated that the rating
outlook remained negative. On Mar. 27, 2001 Moody's Investor Services, Inc.
lowered the long-term ratings on the debt securities of TECO Energy and Tampa
Electric, and lowered the short-term rating of TECO Finance to P-2 from P-1.
This action concluded a review begun in November 2000. These actions were
attributed to increased debt levels and the changing risk profile associated
with the expansion of TECO Energy's independent power development activities, as
well as the required capital outlays of Tampa Electric and the uncertainties
related to industry restructuring. These downgrades and any further downgrades,
may affect the company's ability to borrow and increase its financing cost which
may decrease earnings.
38
39
INTERNATIONAL RISKS. TECO Power Services is involved in several
international projects. 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 financial forecast assumes that TECO
Power Services will avoid losses associated with these risks through a variety
of risk mitigation measures, including specific contractual provisions, teaming
with strong international and local partners, obtaining non-recourse financing
and obtaining political risk insurance where appropriate.
ENVIRONMENTAL MATTERS. TECO Energy's businesses are subject to
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 the INVESTMENT CONSIDERATIONS
section on pages 37 through 38, and in the Financing Activity section on pages
35 and 36.
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, TECO Coal is exposed to commodity price risk through coal
sales, and TPS is exposed to commodity price risk through electricity and
capacity sales, and heating oil purchases for its merchant plants.
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
the regulated natural gas utility, to limit exposure to fuel price increases at
TECO Transport, or to limit exposure to electricity, capacity and fuel price
fluctuations at TPS.
See the discussions of commodity price risks in the INVESTMENT
CONSIDERATIONS -- COMMODITY PRICE CHANGES section on page 38.
TECO Energy and its affiliates do not currently use derivatives or
other financial products for speculative purposes.
39
40
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PAGE
NO.
Report of Independent Certified Public Accountants 41
Consolidated Balance Sheets, Dec. 31, 2000 and 1999 42
Consolidated Statements of Income for the years ended
Dec. 31, 2000, 1999 and 1998 43
Consolidated Statements of Cash Flows for the years ended
Dec. 31, 2000, 1999 and 1998 44
Consolidated Statements of Equity for the years ended
Dec. 31, 2000, 1999 and 1998 45
Notes to Consolidated Financial Statements 46-67
Financial Statement Schedule II - Valuation and
Qualifying Accounts for the years ended
Dec. 31, 2000, 1999 and 1998 68
All other 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.
40
41
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To the Board of Directors and Shareholders of Teco Energy, Inc.,
In our opinion, the consolidated financial statements listed in the
accompanying index present fairly, in all material respects, the financial
position of TECO Energy, Inc. and its subsidiaries at Dec. 31, 2000 and 1999,
and the results of their operations and their cash flows for each of the three
years in the period ended Dec. 31, 2000, in conformity with accounting
principles generally accepted in the United States of America. In addition, in
our opinion, the financial statement schedule listed in the accompanying index
presents fairly, in all material respects, the information set forth therein
when read in conjunction with the related consolidated financial statements.
These financial statements and financial statement schedule are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements and financial statement schedule based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, 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 our opinion.
/s/ PricewaterhouseCoopers LLP
Tampa, Florida
Jan. 12, 2001, except for the information in Note P as to which the dates are
Mar. 12, 2001 and Mar. 15, 2001.
42
CONSOLIDATED BALANCE SHEETS
(millions)
DEC. 31,
2000 1999
-------- --------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 99.6 $ 97.5
Receivables, less allowance for uncollectibles 360.3 261.9
Current notes receivable 223.1 --
Inventories, at average cost
Fuel 67.3 84.0
Materials and supplies 77.2 69.5
Prepayments 22.4 18.9
-------- --------
Total current assets 849.9 531.8
-------- --------
PROPERTY, PLANT AND EQUIPMENT (AT ORIGINAL COST)
Utility plant in service
Electric 4,523.1 4,140.9
Gas 632.1 590.0
Construction work in progress 332.2 291.1
Other property 1,073.0 1,042.4
-------- --------
6,560.3 6,064.4
Accumulated depreciation (2,590.3) (2,436.6)
-------- --------
Total property, plant and equipment (net) 3,970.1 3,627.8
-------- --------
OTHER ASSETS
Other investments 191.3 117.2
Investment in unconsolidated affiliates 187.5 103.3
Deferred income taxes 116.3 106.8
Deferred charges and other assets 361.1 203.2
-------- --------
Total other assets 856.2 530.5
-------- --------
Total assets $5,676.2 $4,690.1
======== ========
LIABILITIES AND CAPITAL
CURRENT LIABILITIES
Long-term debt due within one year $ 237.3 $ 155.8
Notes payable 1,208.9 813.7
Accounts payable 274.8 218.1
Customer deposits 82.4 80.7
Interest accrued 41.9 16.4
Taxes accrued 54.5 36.9
-------- --------
Total current liabilities 1,899.8 1,321.6
OTHER LIABILITIES
Deferred income taxes 445.2 509.4
Investment tax credits 36.9 41.7
Regulatory liability - tax related 10.0 13.3
Other deferred credits 202.8 178.5
Long-term debt, less amount due within one year 1,374.6 1,207.8
REDEEMABLE PREFERRED SECURITIES 200.0 --
CAPITAL
Common equity 1,559.5 1,472.5
Unearned compensation (52.6) (54.7)
-------- --------
Total liabilities and capital $5,676.2 $4,690.1
======== ========
The accompanying notes are an integral part of the consolidated financial
statements.
42
43
CONSOLIDATED STATEMENTS OF INCOME
(millions)
YEAR ENDED DEC. 31
2000 1999 1998
--------- ---------- ----------
REVENUES $ 2,295.1 $ 1,983.0 $ 1,955.7
--------- ---------- ----------
EXPENSES
Operation 1,322.1 1,053.0 1,043.1
Maintenance 140.0 125.3 128.9
Depreciation 268.2 232.2 233.0
Taxes, other than income 151.2 148.9 149.4
--------- --------- ---------
Total expenses 1,881.5 1,559.4 1,554.4
--------- --------- ---------
INCOME FROM OPERATIONS 413.6 423.6 401.3
--------- --------- ---------
OTHER INCOME (EXPENSE)
Allowance for other funds used during construction 1.6 1.3 --
Other income (expense) 21.1 (13.3) (9.5)
--------- --------- ---------
Total other income (expense) 22.7 (12.0) (9.5)
--------- --------- ---------
INCOME BEFORE INTEREST AND INCOME TAXES 436.3 411.6 391.8
--------- --------- ---------
INTEREST CHARGES
Interest expense 167.6 124.2 104.3
Allowance for borrowed funds used during construction (0.7) (0.5) --
--------- --------- ---------
Total interest charges 166.9 123.7 104.3
--------- --------- ---------
INCOME BEFORE PROVISION FOR INCOME TAXES 269.4 287.9 287.5
PROVISION FOR INCOME TAXES 18.5 87.0 83.3
--------- --------- ---------
NET INCOME FROM CONTINUING OPERATIONS 250.9 200.9 204.2
NET LOSS FROM DISCONTINUED OPERATIONS,
NET OF INCOME TAX BENEFIT OF $1.4 MILLION AND
$2.3 MILLION FOR 1999 AND 1998, RESPECTIVELY -- (2.5) (3.8)
GAIN (LOSS) ON DISPOSAL OF DISCONTINUED OPERATIONS,
NET OF INCOME TAX BENEFIT OF $7.4 MILLION FOR 1999 AND
INCOME TAX EXPENSE OF $3.9 MILLION FOR 1998 -- (12.3) 6.1
--------- --------- ---------
NET INCOME $ 250.9 $ 186.1 $ 206.5
========= ========= =========
Average common shares outstanding during year 125.9 131.0 131.7
========= ========= =========
EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING
From continuing operations
- Basic $ 1.99 $ 1.53 $ 1.55
- Diluted $ 1.97 $ 1.53 $ 1.54
Net Income
- Basic $ 1.99 $ 1.42 $ 1.57
- Diluted $ 1.97 $ 1.42 $ 1.56
The accompanying notes are an integral part of the consolidated financial
statements.
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44
CONSOLIDATED STATEMENTS OF CASH FLOWS
(millions)
YEAR ENDED DEC. 31,
2000 1999 1998
-------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 250.9 $ 186.1 $ 206.5
Adjustments to reconcile net income to net cash
from operating activities
Depreciation 268.2 232.2 233.0
Deferred income taxes (77.6) (15.3) 14.6
Investment tax credits, net (4.8) (5.0) (5.0)
Allowance for funds used during construction (2.3) (1.8) --
Amortization of unearned compensation 9.2 9.1 7.8
Gain on propane business disposal/sale, pretax (13.6) -- --
Loss (gain) on disposal of discontinued operations, pretax -- 19.8 (10.0)
Equity in earnings of unconsolidated affiliates (6.7) 1.8 --
Asset valuation adjustment, pretax 14.2 -- --
Deferred revenue -- 11.9 (38.3)
Deferred recovery clause (68.7) (38.2) 17.4
Refund to customers (13.2) -- --
Charges (discussed in Note M) -- 21.1 31.1
Receivables, less allowance for uncollectibles (92.1) (25.3) (2.0)
Inventories 7.5 5.0 (13.5)
Taxes accrued 17.6 31.7 (8.8)
Interest accrued 25.5 (7.2) (7.7)
Accounts payable 42.6 (25.3) 47.3
Other 24.5 (19.3) 23.0
-------- -------- --------
381.2 381.3 495.4
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (688.4) (426.1) (296.1)
Allowance for funds used during construction 2.3 1.8 --
Purchase of minority interest (52.6) (49.1) --
Purchase of mechanical contracting business (26.2) -- --
Net proceeds from sale of assets 61.3 1.0 37.5
Investment in unconsolidated affiliates (5.1) (2.6) (135.1)
Other non-current investments (336.0) (29.9) 2.8
-------- -------- --------
(1,044.7) (504.9) (390.9)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock 18.3 0.3 6.7
Purchase of treasury stock (29.9) (114.8) --
Proceeds from long-term debt 394.9 28.0 201.2
Repayment of long-term debt (145.6) (35.2) (16.2)
Net increase (decrease) in short-term debt 395.3 494.7 (128.5)
Issuance of redeemable preferred securities 200.0 -- --
Dividends (167.4) (168.8) (161.4)
-------- -------- --------
665.6 204.2 (98.2)
-------- -------- --------
Net increase (decrease) in cash and cash equivalents 2.1 80.6 6.3
Cash and cash equivalents at beginning of year 97.5 16.9 10.6
-------- -------- --------
Cash and cash equivalents at end of year $ 99.6 $ 97.5 $ 16.9
======== ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the year for
Interest (net of amounts capitalized) $ 166.7 $ 116.9 $ 99.3
Income taxes $ 83.9 $ 62.1 $ 66.2
The accompanying notes are an integral part of the consolidated financial
statements.
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CONSOLIDATED STATEMENTS OF COMMON EQUITY
ADDITIONAL OTHER TOTAL
COMMON PAID_IN TREASURY RETAINED COMPREHENSIVE UNEARNED COMMON
(MILLIONS) SHARES(1) STOCK CAPITAL STOCK EARNINGS INCOME (LOSS) COMPENSATION EQUITY
--------- ------ ---------- -------- -------- ------------- ------------ --------
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
Cash 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
Net income for 1999 186.1 186.1
Other comprehensive
income (loss), after tax (5.5) (5.5)
Common stock issued 0.1 0.1 2.6 (2.4) 0.3
Treasury shares purchased (5.4) (114.8) (114.8)
Cash Dividends declared (168.8) (168.8)
Amortization of unearned
compensation 9.1 9.1
Tax benefits-ESOP dividends
and stock options 1.7 1.9 3.6
----- ------ ------ ------- - ------- ----- ------ --------
BALANCE, DEC. 31, 1999 126.7 132.1 368.9 (114.8) 1,091.8 (5.5) (54.7) 1,417.8
Net income for 2000 250.9 250.9
Other comprehensive
income (loss), after tax 2.0 2.0
Common stock issued 1.2 1.2 26.8 (3.9) 24.1
Treasury shares purchased (1.6) (29.9) (29.9)
Cash Dividends declared (167.4) (167.4)
Amortization of unearned
compensation 9.2 9.2
Tax benefits-ESOP dividends
and stock options 1.6 1.8 3.4
Performance shares (3.2) (3.2)
----- ------ ------ ------- -------- ----- ------ --------
BALANCE, DEC. 31, 2000 126.3 $133.3 $397.3 $(144.7) $1,177.1 $(3.5) $(52.6) $1,506.9
===== ====== ====== ======= ======== ===== ====== ========
---------------
(1) TECO Energy had 400 million shares of $1 par value common stock authorized
in 2000, 1999 and 1998.
The accompanying notes are an integral part of the consolidated financial
statements.
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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.
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.
The proportional share of expenses, revenues and assets reflecting
TECO Coalbed Methane's 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, 1996 and 1999. Revenues
were recognized as allowed in 1997, 1998 and 1999 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 the recovery
of prudent costs incurred plus a reasonable return on invested capital.
The use of estimates is inherent in the preparation of financial
statements in accordance with generally accepted accounting principles.
REVENUES AND FUEL COSTS
Revenues include amounts resulting from cost recovery clauses which
provide for monthly billing charges to reflect increases or decreases in fuel,
purchased capacity, conservation and environmental costs for Tampa Electric and
purchased gas, interstate pipeline capacity and conservation costs for Peoples
Gas System. These adjustment factors are based on costs projected for a
specific recovery period. Any over-recovery or under-recovery of costs plus an
interest factor are taken into account in the process of setting adjustment
factors for subsequent recovery periods. Over-recoveries of costs are recorded
as deferred credits, and under-recoveries of costs are recorded as deferred
charges.
In 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 each of the years 2000,
1999 and 1998, $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.
Tampa Electric's objectives of stabilizing prices through 1999 and
securing fair earnings opportunities during this period were accomplished
through a series of agreements entered into in 1996 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.
In general, under these agreements Tampa Electric was allowed to defer
revenues in 1995 and 1996 during the construction of Polk Unit One and
recognize these revenues in 1997 and 1998 after commercial operation of the
unit. Other components of the agreements were: a base rate freeze through 1999;
refunds to customers totaling $50 million during the period October 1996
through December 1998; elimination of the oil backout tariff as of January
1996, reducing annual revenues by approximately $12 million; and recovery of
the capital costs incurred for the Polk Unit One project.
Under these agreements Tampa Electric's allowed return on equity (ROE)
was established at an 11.75 percent midpoint with
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a range of 10.75 percent to 12.75 percent. Revenues were deferred for use by
the company in 1997 and 1998 according to formulas that varied by year based
upon the earned ROE. In 1998, all revenues above the top of the ROE range were
held for refund to customers.
For 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. For 1996, the company deferred
$37 million. This amount and the deferred revenues and interest from 1995 (less
$25 million of refunds) provided $62 million for recognition by the company for
1997 and 1998. Revenues in 1997 and 1998 were lower by $5 million and $20
million, respectively, as a result of a temporary base rate reduction that was a
component of the stipulations.
Based on FPSC decisions, the company recognized $27 million for 1997
and $34 million for 1998 of the revenues and interest deferred from 1995 and
1996. After recognizing $10 million of interest accrued over the deferral
period, the FPSC ordered $11 million plus interest to be refunded to customers
in 2000. In November 1999, FIPUG protested the FPSC decisions for both years and
requested a hearing to review a wide range of costs incurred by the company over
the two-year period. The FPSC ordered that the $11 million refund be withheld
with interest until the protest was heard and resolved.
In August 2000, the FPSC approved a stipulation entered into between
Tampa Electric, FIPUG and OPC that provided for a $13 million refund to
customers from September through December 2000. This amount generally
represented the $11 million refund amount previously determined plus interest.
As part of its series of agreements with OPC and FIPUG, Tampa Electric
also agreed to refund 60 percent of 1999 revenues that contributed to an ROE in
excess of 12 percent, as calculated and approved by the FPSC.
In October 2000, the FPSC staff recommended that Tampa Electric's 1999
refund be $6.1 million including interest, to be refunded to customers beginning
Jan. 1, 2001. OPC objected to certain Tampa Electric interest expenses
recognized in 1999 associated with prior tax positions and used to calculate the
amount to be refunded. Following a review by the FPSC staff, the FPSC agreed in
December 2000 that the original $6.1 million was to be refunded to customers.
Tampa Electric agreed to begin the refund beginning as early as February 2001.
The refund was expected by Tampa Electric and was appropriately accounted for in
1999 and 2000; however, on Feb. 7, 2001, OPC protested the FPSC's refund
decision. The protest claims that the stipulations do not allow for the
inclusion of the interest expenses on income tax positions in the refund
calculations. Hearing dates to resolve the 1999 refund are scheduled for August
2001. This refund was the last issue remaining under the deferred revenue plan.
The regulatory arrangements described above covered periods that ended
on Dec. 31, 1999. Tampa Electric's rates and its 11.75 percent allowed rate of
return on common equity midpoint will continue in effect until such time as
changes are occasioned by an agreement approved by FPSC or other FPSC actions
as a result of rate or other proceedings initiated by Tampa Electric, FPSC
staff or other interested parties. Tampa Electric believes that its currently
allowed ROE range is reasonable based on the current interest rate environment
and previous FPSC rulings.
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 2000, 4.0% for 1999 and 4.1% for 1998.
The original cost of utility plant retired or otherwise disposed of
and the cost of removal less salvage are charged to accumulated depreciation.
GOODWILL
Goodwill represents the excess of acquisition costs over the fair
value of the net assets acquired in purchase transactions. Goodwill is being
amortized on a straight-line basis over various periods not exceeding 40 years.
The amount of goodwill included in deferred charges on the consolidated balance
sheets at Dec. 31, 2000 and 1999, respectively, was $93.1 million and $42.8
million, net of accumulated amortization of $4.7 million and $2.0 million.
Significant additions to goodwill in 2000 of $53.0 million resulted primarily
from the acquisition of the remaining ownership interest in the San Jose Power
Station and the purchase of BCH Mechanical. Amortization of goodwill included
in the consolidated statements of income in 2000, 1999 and 1998 was $2.7
million, $0.6 million and $0.5 million, respectively.
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 for the Impairment of
Long-lived assets and long-lived assets to be disposed of. In 2000, TECO
Properties recorded an after-tax charge of $3.8 million to adjust property
values. In 1998, TECO Coal Corporation recorded an after-tax charge of $8.9
million to adjust asset values of certain mining operations. No write-down of
assets due to impairment was required in 1999.
REPORTING COMPREHENSIVE INCOME
In 1999, the company adopted FAS 130, Reporting Comprehensive Income.
This 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
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48
financial statements. TECO Energy reported $2.0 million of comprehensive income
in 2000 and $5.5 million of comprehensive loss in 1999 related to adjustments
to the minimum pension liability associated with the company's supplemental
executive retirement plan. There were no components of comprehensive income
other than net income for the year ended Dec. 31, 1998. The company has
reported accumulated other comprehensive income in its Consolidated Statements
of Common Equity.
REPORTING ON THE COSTS OF START-UP ACTIVITIES
In 1999, the company adopted AICPA Statement of Position (SOP) 98-5,
Reporting on the Costs of Startup Activities. It requires costs of startup
activities and organization costs to be expensed as incurred. Startup
activities are broadly defined as those one-time activities related to events
such as opening a new facility, conducting business in a new territory and
organizing a new entity. Some costs, such as the costs of acquiring or
constructing long-lived assets and bringing them into service, are not subject
to SOP 98-5. The costs expensed in 2000 and 1999 in accordance with SOP 98-5
were not significant.
ACCOUNTING FOR CONTRACTS INVOLVED IN ENERGY TRADING AND RISK MANAGEMENT
ACTIVITIES
In 1998, the FASB's Emerging Issues Task Force (EITF) released Issue
98-10, Accounting for Contracts Involved in Energy Trading and Risk Management
Activities, effective for fiscal years beginning after Dec. 15, 1998. EITF
98-10 requires contracts for the purchase and sale of energy commodities that
are determined to be trading activities or contracts as defined in the Issue,
be valued at market on the balance sheet date, and the resulting gain or loss
reflected in earnings. At Dec. 31, 2000 and 1999, the company did not have
contracts for the purchase or sale of energy that would be classified as
trading activities as defined in EITF 98-10.
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. The aggregate remeasurement
gains or losses included in net income in 2000, 1999 and 1998 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.
OTHER DEFERRED CREDITS
Other deferred credits primarily include the accrued post-retirement
benefit liability, the pension liability and minority interest.
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 2000, 1999 and 1998. Total AFUDC for 2000
and 1999 was $2.3 million and $1.8 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.
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
Cash equivalents are highly liquid, high-quality debt instruments
purchased with an original 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, 1999 was $94.2 million. There were no cash equivalents outstanding at
Dec. 31, 2000.
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OTHER INVESTMENTS
Other investments include longer-term passive investments. Other
investments at Dec. 31, 2000 and 1999 were as follows:
DUE
(MILLIONS) RATE DATE 2000 1999
---- -------- -------- --------
Notes receivable from:
Panda Energy 12% 12/31/02 $ 92.7 $ --
Panda Energy 12% 2/28/01 197.3 --
Energia Global Int'l (EGI) 15.4% 12/31/01 23.2 --
Energia Global Int'l (EGI) 15% 3/31/01 2.6 --
Energia Global Int'l (EGI) 10% 12/31/00 -- 25.0
Mosbacher Power Partners L.P. 12% 8/1/08 13.0 13.1
Mosbacher Power Partners L.P. 9% 8/1/08 20.4 --
Mosbacher Power Partners L.P. 12% 10/4/06 4.8 --
EEGSA 11.6%(1) 9/11/07 10.9 --
Investment in Energy Center Kladno
Generating (ECKG)(2) -- -- 18.2 18.0
Continuing Investments in
Leveraged Leases -- -- 22.1 49.3
Other investments(3) -- -- 9.2 11.8
-------- --------
414.4 117.2
-------- --------
Current notes receivable 223.1 --
-------- --------
Other non-current investments $ 191.3 $ 117.2
======== ========
---------------
(1) Current rate at 12/31/00. Rate based on LIBOR plus 5%.
(2) 13.35% ownership interest in an electric generating power project in the
Czech Republic.
(3) Primarily real estate development projects.
These financial instruments have no quoted market prices and,
accordingly, a reasonable estimate of fair market value could not be made
without incurring excessive costs. However, the company believes by reference
to stated interest rates and security description, the fair value of these
assets would not differ significantly from the carrying value.
INVESTMENTS IN UNCONSOLIDATED AFFILIATES
Investments in unconsolidated affiliates are accounted for using the
equity method of accounting. At Dec. 31, 2000, these investments included TECO
Propane Ventures' 38 percent ownership interest in US Propane, TECO Power
Services' (TPS') 24 percent ownership interest in EEGSA, the Guatemalan
electric utility, TPS' 33.68 percent ownership interest in EGI, and its 50
percent ownership interest in the Hamakua Power Station in Hawaii. At Dec. 31,
1999, the investment in unconsolidated affiliates included the EEGSA and
Hamakua investments.
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 using
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, 2000 and 1999 were $216.2 million and $212.5 million,
respectively. Net proven reserves at Dec. 31, 2000 and 1999 were as follows:
NET PROVEN RESERVES - COALBED METHANE GAS
(billion cubic feet) 2000 1999
----- -----
Proven reserves, beginning of year 159.1 161.8
Production (15.7) (16.6)
Revisions of previous estimates 38.3 13.9
----- -----
Proven reserves, end of year 181.7 159.1
===== =====
Number of wells 700 615
===== =====
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ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING
In 1998, the Financial Accounting Standards Board (FASB) issued
Financial Accounting Standard (FAS) 133, Accounting for Derivative Instruments
and Hedging. This standard was initially to be effective for fiscal years
beginning after June 15, 1999. In July 1999, the FASB delayed the effective
date of this pronouncement until fiscal years beginning after June 15, 2000.
The company has adopted the new standard effective Jan. 1, 2001. The new
standard requires the company to 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 in net income, depending on the types of
those instruments.
The company has completed the review and documentation of its
derivative contracts, and found that such activity has been minimal and
relatively short-term in duration. From time to time, TECO Energy has entered
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, and to limit exposure to fuel price increase at TECO Transport.
As of Dec. 31, 2000, TECO Energy had hedging transactions in place to
protect against selling price variability at TECO Coalbed Methane which will
qualify for cash flow hedge accounting treatment under FAS 133. Upon adoption,
the company expects to report a reduction in other comprehensive income of
approximately $19.0 million before tax, to record the swap liability as of Jan.
1, 2001.
TECO Energy has not used derivatives or other financial products for
speculative purposes. Management will continue to document all current, new and
possible uses of derivatives particularly as it relates to the expanding
merchant power projects at TECO Power Services, and develop procedures and
methods for measuring them.
RECLASSIFICATIONS
Certain prior year amounts were reclassified to conform with current
year presentation.
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 2000, under the 1996 Plan, 1,264,236 stock options were granted,
with a weighted average option price of $21.33 and a maximum term of 10 years.
In addition, 182,882 shares of restricted stock were awarded, each with a
weighted average fair value of $21.56. Compensation expense recognized for
stock grants awarded under the 1996 Plan was $4.6 million, $1.6 million and
$2.3 million in 2000, 1999 and 1998, respectively. The stock grants awarded in
2000 and 1999 are performance shares, primarily restricted subject to meeting
specified total shareholder return goals, vesting in three years with final
payout ranging from zero to 200% of the original grant. An adjustment was made
in December 2000 to reflect contingent shares which could be issuable based on
current period results. The consolidated balance sheet at Dec. 31, 2000
reflects a $5.5 million liability, classified as other deferred credits, for
these contingent shares. The remaining stock grants are restricted subject
generally to continued employment, with the 1998 stock grants vesting in five
years and the 1997 and 1996 stock grants vesting at normal retirement age.
In January 2001, the Board of Directors approved an amendment to the
1996 Plan, subject to shareholder approval in April 2001, to increase the
number of shares of common stock subject to grants by 6.3 million.
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:
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STOCK OPTIONS - EQUITY PLANS
OPTION SHARES WEIGHTED AVG.
(THOUSANDS) OPTION PRICE
------------- ------------
Balance at Dec. 31, 1997 2,372 $20.70
Granted 750 $27.56
Exercised (385) $17.26
Cancelled (5) $26.48
-----
Balance at Dec. 31, 1998 2,732 $23.06
Granted 1,158 $21.54
Exercised (32) $16.58
Cancelled (31) $24.32
-----
Balance at Dec. 31, 1999 3,827 $22.64
Granted 1,264 $21.33
Exercised (488) $20.15
Cancelled (44) $23.61
-----
Balance at Dec. 31, 2000 4,559 $22.54
=====
Exercisable at Dec 31, 2000 2,572 $23.41
=====
Available for future grant at Dec. 31, 2000 1,389
=====
As of Dec. 31, 2000, the 4.6 million options outstanding under the Equity Plans
are summarized below.
STOCK OPTIONS OUTSTANDING AT DEC. 31, 2000
OPTION SHARES RANGE OF WEIGHTED AVG. WEIGHTED AVG. REMAINING
(THOUSANDS) OPTION PRICES OPTION PRICE CONTRACTUAL LIFE
------------- ------------- ------------- -----------------------
735 $17.38-$20.75 $19.85 3 Years
2,817 $21.25-$23.69 $21.76 8 Years
1,007 $24.38-$27.56 $26.66 7 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 2000, 30,000 options were granted, with a weighted average option
price of $23.49. Transactions during the last three years under the 1997 Plan
are summarized as follows:
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STOCK OPTIONS - DIRECTOR EQUITY PLANS
OPTION SHARES WEIGHTED AVG.
(THOUSANDS) OPTION PRICE
------------- -------------
Balance at Dec. 31, 1997 249 $20.59
Granted 24 $27.56
Exercised (32) $21.10
Cancelled -- --
-----
Balance at Dec. 31, 1998 241 $21.22
Granted 32 $21.51
Exercised -- --
Cancelled -- --
-----
Balance at Dec. 31, 1999 273 $21.25
Granted 30 $23.49
Exercised (33) $18.57
Cancelled (12) $25.15
------
Balance at Dec. 31, 2000 258 $21.68
======
Exercisable at Dec. 31, 2000 258 $21.68
======
Available for future grant at Dec. 31, 2000 343
======
As of Dec. 31, 2000, the 258,000 options outstanding under the 1997
Plan with option prices of $17.72-$27.97, had a weighted average option price
of $21.68 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, but applies Accounting Principles
Board Opinion No. 25 and related interpretations in accounting for its plans.
Therefore, since stock options are granted with an option price greater than or
equal to the fair value on date of grant, 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. These pro forma amounts were determined using the
Black-Scholes valuation model with weighted average assumptions as shown below.
2000 1999 1998
------- ------- -------
Net Income
from continuing As reported $ 250.9 $ 200.9 $ 204.2
operations (millions) Pro forma $ 247.8 $ 198.5 $ 202.6
Net Income (millions) As reported $ 250.9 $ 186.1 $ 206.5
Pro forma $ 247.8 $ 183.7 $ 204.9
Net Income from
continuing operations As reported $ 1.99 $ 1.53 $ 1.55
- EPS basic Pro forma $ 1.97 $ 1.52 $ 1.54
Net Income As reported $ 1.99 $ 1.42 $ 1.57
- EPS basic Pro forma $ 1.97 $ 1.40 $ 1.56
Assumptions
Risk-free interest rate 6.24% 5.26% 5.64%
Expected lives (in years) 6 6 6
Expected stock volatility 22.93% 19.14% 14.01%
Dividend yield 5.15% 4.55% 4.61%
52
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DIVIDEND REINVESTMENT PLAN
In 1992, TECO Energy implemented a Dividend Reinvestment and Common
Stock Purchase Plan (DRP). TECO Energy raised $8.1 million of common equity
from this plan in 2000. In 1999 and 1998, the DRP purchased shares of TECO
Energy common stock on the open market for plan participants.
TREASURY STOCK
In September 1999, TECO Energy announced a program to repurchase up to
$150 million of its outstanding common stock. Shares acquired constitute
treasury shares. In 2000, the company acquired 1.6 million shares of its
outstanding common stock at a cost of $29.9 million; the average per share
price was $18.62. Since the program was announced, the company has acquired 7.0
million shares of its outstanding common stock at a cost of $144.7 million, or
an average per share price of $20.55. The company's share repurchase program
favorably impacted earnings in 2000 by approximately $0.06 per share. Earnings
per share results were not significantly affected in 1999 because the purchases
occurred late in the year.
SHAREHOLDER RIGHTS PLAN
In accordance with the company's Shareholder Rights Plan, a Right to
purchase one additional share of the company's common stock at a price of $90
per share is attached to each outstanding share of the company's common stock.
The Rights expire in May 2009, subject to extension. The Rights will become
exercisable 10 business days after a person acquires 10 percent or more of the
company's outstanding common stock or commences a tender offer that would
result in such person owning 10 percent or more of such stock. If any person
acquires 10 percent or more of the outstanding common stock, the rights of
holders, other than the acquiring 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 business days after
a person acquires 10 percent or more of the outstanding common stock.
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 $6.8 million, $7.5
million, and $4.3 million in 2000, 1999 and 1998, 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) 2000 1999 1998
---- ---- ----
Interest expense $4.7 $6.9 $7.3
Compensation expense 6.9 7.5 5.5
Dividends (8.5) (8.4) (8.1)
---- ---- ----
Net ESOP expense $3.1 $6.0 $4.7
==== ==== ====
Compensation expense was determined by the shares allocated method.
At Dec. 31, 2000, the ESOP had 3.1 million allocated shares, 0.1
million committed-to-be-released shares, and 3.1 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.
53
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C. REDEEMABLE PREFERRED SECURITIES
In November 2000, TECO Energy established TECO Capital Trust I (the
Trust) for the sole purpose of issuing Trust Preferred Securities (TruPS) and
using the proceeds to purchase company preferred securities from TECO Funding
I, LLC (TECO Funding). On Dec. 20, 2000, the Trust issued 8 million shares of
$25 par, 8.5% TruPS, due 2041, with an aggregate liquidation value of $200
million. Currently, all 8 million shares of the TruPS are outstanding. Each
TruPS represents an undivided beneficial interest in the assets of the Trust.
The Trust used the proceeds from the sale of the TruPS to purchase a
corresponding amount of company preferred securities of TECO Funding. TECO
Funding used the proceeds from the sale of the company preferred securities to
the Trust of $200 million and the sale of $6.2 million of its common securities
to TECO Energy, to purchase $206.2 million of 8.5% junior subordinated notes of
TECO Energy, due 2041. The junior subordinated notes are the sole assets of
TECO Funding and the company preferred securities are the sole assets of the
Trust. TECO Energy's proceeds from the sale of the junior subordinated notes
were used to reduce the commercial paper balances of TECO Finance and for
general corporate purposes. TECO Energy has guaranteed the payments to the
holders of the company preferred securities and indirectly, the payments to the
holders of the TruPS, as a result of their beneficial interest in the company
preferred securities.
The junior subordinated notes may be redeemed at the option of TECO
Energy at any time on or after Dec. 20, 2005 at 100% of their principal amount
plus accrued interest through the redemption date. If TECO Energy redeems the
junior subordinated notes in full before their maturity date, then TECO Funding
is required to redeem the company preferred securities and common securities,
in accordance with their terms. If TECO Energy redeems the junior subordinated
notes in part but not in full before their maturity date, then TECO Funding
will redeem the company preferred securities in full prior to any payment being
made on the common securities. Upon any liquidation of the company preferred
securities, holders of the TruPS would be entitled to the liquidation
preference of $25 per share plus all accrued and unpaid dividends through the
date of redemption.
D. PREFERRED STOCK
PREFERRED STOCK OF TECO ENERGY - $1 PAR
10 million shares authorized, none outstanding.
PREFERENCE STOCK OF TAMPA ELECTRIC - NO PAR
2.5 million shares authorized, none outstanding.
PREFERRED 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.
54
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E. LONG-TERM DEBT
DEC. 31,
(MILLIONS) DUE 2000 1999
--- -------- --------
TECO ENERGY
Medium-term notes payable: 5.31%(1)(2) 2002 $ 200.0 $ --
Medium-term notes payable: 9.29%(1) 2000 -- 50.0
Medium-term notes payable: 5.35%(1)(3) 2001 150.0 150.0
-------- --------
350.0 200.0
-------- --------
TAMPA ELECTRIC
First mortgage bonds (issuable in series):
7 3/4% 2022 75.0 75.0
5 3/4% 2000 -- 80.0
6 1/8% 2003 75.0 75.0
Installment contracts payable(4):
5 3/4% 2007 22.9 23.2
7 7/8% Refunding bonds(5) 2021 25.0 25.0
8% Refunding bonds(5) 2022 100.0 100.0
6 1/4% Refunding bonds(6) 2034 86.0 86.0
5.85% 2030 75.0 75.0
Variable rate: 3.77% for 2000 and 3.21% for 1999(1) 2025 51.6 51.6
Variable rate: 3.90% for 2000 and 3.46% for 1999(1) 2018 54.2 54.2
Variable rate: 3.96% for 2000 and 3.69% for 1999(1) 2020 20.0 20.0
Medium-term notes payable: 5.11%(1)(7) 2001 38.0 38.0
Medium-term notes payable: 5.86%(1)(8) 2002 100.0 --
-------- --------
722.7 703.0
-------- --------
PEOPLES GAS SYSTEM
Senior Notes(9)
10.35% 2007 5.6 6.2
10.33% 2008 7.2 8.0
10.3% 2009 8.4 8.8
9.93% 2010 8.6 9.0
8.0% 2012 29.0 30.5
Medium-term notes payable: 5.11%(1)(7) 2001 12.0 12.0
Medium-tern notes payable: 5.86%(1)(8) 2002 50.0 --
-------- --------
120.8 74.5
-------- --------
DIVERSIFIED COMPANIES
Dock and wharf bonds, variable rate: 3.79% for 2000 and 3.77% for 1999(1)(4) 2007 110.6 110.6
Non-recourse secured facility note, Series A: 7.8% 2001-2012 125.5 131.9
Non-recourse secured facility note: 9.875% 2001-2008 19.5 22.0
Non-recourse secured facility note, variable rate: 9.55% for 2000 2001-2007 65.0 --
Non-recourse secured facility note: 10.1% 2001-2009 17.0 --
Non-recourse secured facility note: 9.629% 2001-2010 31.2 --
Construction financing, variable rate: 6.97% for 1999(10) 2000 -- 73.3
Capital lease: implicit rate of 8.5% 2001-2003 29.7 31.6
Construction financing, 7.82% 2001 10.1 10.1
-------- --------
408.6 379.5
-------- --------
TECO FINANCE
Medium-term notes payable, various rates: 7.54% for 2000 and 1999(1) 2002 9.0 9.0
Unamortized debt premium (discount), net 0.8 (2.4)
-------- --------
1,611.9 1,363.6
Less amount due within one year(11) 237.3 155.8
-------- --------
TOTAL LONG-TERM DEBT $1,374.6 $1,207.8
======== ========
---------------
(1) Composite year-end interest rate.
(2) These notes are subject to mandatory tender on Oct. 1, 2002, at which time
they will be redeemed or remarketed.
(3) These notes are subject to mandatory tender on Sept. 15, 2001, at which
time they will be redeemed or remarketed.
(4) Tax-exempt securities.
55
56
(5) Proceeds of these bonds were used to refund bonds with interest rates of
11.625%-12.625%. 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.
(6) 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.
(7) These notes are subject to mandatory tender on July 15, 2001, at which
time they will be redeemed or remarketed.
(8) These notes are subject to mandatory tender on Sept. 1, 2002, at which
time they will be redeemed or remarketed.
(9) 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.
(10) This construction financing for the San Jose Power Station converted to
long-term, non-recourse financing in 2000.
(11) Of the amount due in 2001, $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 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, 2000:
YEAR ENDED DEC. 31: AMOUNT (MILLIONS)
-----------------
2001 $ 4.6
2002 4.6
2003 25.0
Total minimum lease payments 34.2
-------
Less: Amount representing interest 4.5
-------
Present value of net minimum lease payments,
including current maturities of $2.2 million $ 29.7
=======
Substantially all of the property, plant and equipment of Tampa
Electric is pledged as collateral to secure its long-term debt. TECO Energy's
maturities and annual sinking fund requirements of long-term debt for the years
2002, 2003, 2004 and 2005 are $388.8 million, $129.7 million, $171.6 million
and $34.2 million, respectively. Of these amounts $0.8 million per year for
2002 through 2005 may be satisfied by the substitution of property in lieu of
cash payments.
At Dec. 31, 2000, total long-term debt had a carrying amount of
$1,374.6 million and an estimated fair market value of $1,448.1 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.
F. SHORT-TERM DEBT
Notes payable consisted primarily of commercial paper with weighted
average interest rates of 6.53% and 6.00%, at Dec. 31, 2000 and 1999,
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, 2000 were $485 million. These lines of credit
require commitment fees ranging from .05% to .09% on the unused balances.
During 1995, TECO Finance entered into an interest rate exchange
agreement to moderate its exposure to interest rate changes. This three-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.
G. RETIREMENT PLAN
TECO Energy has a non-contributory defined benefit retirement plan
which covers substantially all employees. Benefits are based on employees' age,
years of service and final average earnings. Effective April 1, 2000, the plan
was amended to provide for benefits to be earned and payable substantially on a
lump sum basis through an age and service credit schedule for eligible
participants leaving the company on or after July 1, 2001. Other significant
provisions of the plan, such as eligibility, definitions of credited service,
final average earnings, etc., remain largely unchanged. This amendment resulted
in decreased pension expense of approximately $2.0 million in 2000 and a
reduction of benefit obligation of $14.4 million at Dec. 31, 2000.
56
57
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 68 percent of plan assets were invested in common
stock and 32 percent in fixed income investments at Dec. 31, 2000.
Amounts prior to 1999 have been restated to include the unfunded
obligations for the supplemental executive retirement plan, a non-qualified,
non-contributory defined benefit retirement plan available to certain senior
management. TECO Energy reported $2 million of comprehensive income in 2000 and
$5.5 million of comprehensive loss in 1999 related to adjustments to the
minimum pension liability associated with the supplemental executive 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 pensions and other
postretirement benefits with additional information required on changes in the
benefit obligations and fair values of plan assets.
(MILLIONS) 2000 1999 1998
------- ------- --------
COMPONENTS OF NET PENSION EXPENSE
Service cost (benefits earned during the period) $ 10.7 $ 12.9 $ 11.7
Interest cost on projected benefit obligations 27.5 27.2 26.5
Expected return on assets (40.8) (34.6) (31.5)
Amortization of:
Unrecognized transition asset (1.0) (0.9) (0.9)
Prior service cost 0.2 1.2 1.2
Actuarial (gain) loss (5.6) 5.2 1.2
------- ------- --------
Net pension expense (9.0) 11.0 8.2
Special termination benefit charge 1.1 -- 0.7
Curtailment charge -- -- (0.8)
------- ------- --------
Net pension (benefit) expense recognized in the
Consolidated Statements of Income $ (7.9) $ 11.0 $ 8.1
======= ======= ========
(MILLIONS) DEC. 31, 2000 DEC. 31, 1999
------------- -------------
RECONCILIATION OF THE FUNDED STATUS OF THE
RETIREMENT PLAN AND THE ACCRUED PENSION
PREPAYMENT/(LIABILITY)
Projected benefit obligation, beginning of year $360.4 $ 414.9
Change in benefit obligation due to:
Service cost 10.7 12.9
Interest cost 27.5 27.2
Actuarial (gain) loss 17.8 (68.1)
Plan Amendments (14.4) --
Special termination benefits 1.1 --
Gross benefits paid (23.2) (26.5)
------ -------
Projected benefit obligation, end of year 379.9 360.4
------ -------
Fair value of plan assets, beginning of year 512.1 468.7
Change in plan assets due to:
Actual return on plan assets 6.2 65.3
Employer contributions 1.6 7.6
Gross benefits paid (including expenses) (26.1) (29.5)
------ -------
Fair value of plan assets, end of year 493.8 512.1
------ -------
Funded status, end of year 113.9 151.7
Unrecognized net actuarial gain (127.8) (188.6)
Unrecognized prior service cost (3.3) 11.3
Unrecognized net transition asset (4.7) (5.7)
------ -------
Accrued pension liability $(21.9) $ (31.3)
====== =======
ASSUMPTIONS USED IN DETERMINING
ACTUARIAL VALUATIONS
Discount rate to determine projected
benefit obligation 7.50% 7.75%
Rates of increase in compensation levels 3.3-5.3% 3.3-5.3%
Plan asset growth rate through time 9% 9%
57
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H. POSTRETIREMENT BENEFIT PLAN
TECO Energy and its subsidiaries currently provide certain
postretirement health care and life insurance 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 and before July 1, 2001, is limited to a defined dollar
benefit based on years of service. Effective April 1, 2000, the company adopted
changes to this program for participants retiring from the company on or after
July 1, 2001, after age 50 that meet certain service requirements. The company
contribution toward pre-65 and post-65 health care coverage for most employees
retiring on or after July 1, 2001, is limited to a defined dollar benefit based
on an age and service schedule. The impact of this amendment includes a change
in the company's commitment for future retirees combined with a grandfathering
provision for current retired participants which results in an increase in the
benefit obligation of $22.9 million. 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. Amounts prior to 1999 have
been restated to include life insurance benefits.
(MILLIONS) 2000 1999 1998
----- ----- -----
COMPONENTS OF POSTRETIREMENT BENEFIT COST
Service cost (benefits earned during the period) $ 3.0 $ 3.6 $ 2.9
Interest cost on projected benefit obligations 8.9 6.9 6.8
Amortization of transition obligation (straight line over 20 years) 2.7 2.7 2.7
Amortization of prior service cost 1.7 0.6 0.6
Amortization of actuarial loss/(gain) (0.2) 0.2 0. 1
Special termination benefits 0.2 -- --
Additional amounts recognized 0.9 -- --
----- ----- -----
Net periodic postretirement benefit expense $17.2 $14.0 $13.1
===== ===== =====
(MILLIONS) DEC. 31, 2000 DEC. 31, 1999
------------- ------------
RECONCILIATION OF THE FUNDED STATUS OF THE POSTRETIREMENT
BENEFIT PLAN AND THE ACCRUED LIABILITY
Accumulated postretirement benefit obligation, beginning of year $ 93.1 $ 104.3
Change in benefit obligation due to:
Service Cost 30.0 3.6
Interest cost 8.9 6.9
Plan participants' contributions 1.1 0.6
Special termination benefits 0.2 --
Actuarial (gain) loss 8.5 (16.3)
Plan amendments 22.9 --
Gross benefits paid (6.9) (6.0)
------- -------
Accumulated postretirement benefit obligation, end of year 130.8 93.1
------- -------
Funded status, end of year (130.8) (93.1)
Unrecognized net loss from past experience 5.6 (2.1)
Unrecognized prior service cost 27.7 6.4
Unrecognized transition obligation 32.8 35.6
------- -------
Liability for accrued postretirement benefit $ (64.7) $ (53.2)
======= =======
ASSUMPTIONS USED IN DETERMINING ACTUARIAL VALUATIONS
Discount rate to determine projected benefit obligation 7.5% 7.75%
The assumed health care cost trend rate for medical costs prior to age
65 was 7.25% in 2000 and decreases to 5.0% in 2002 and thereafter. The assumed
health care cost trend rate for medical costs after age 65 was 6.25% in 2000
and decreases to 5.0% in 2002 and thereafter.
A 1 percent increase in the medical trend rates would produce a 10
percent ($1.2 million) increase in the aggregate service and interest cost for
2000 and a 9 percent ($11.2 million) increase in the accumulated postretirement
benefit obligation as of Dec. 31, 2000.
A 1 percent decrease in the medical trend rates would produce an 8
percent ($1.0 million) decrease in the aggregate service and interest cost for
2000 and a 7 percent ($9.7 million) decrease in the accumulated postretirement
benefit obligation as of Dec. 31, 2000.
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I. INCOME TAX EXPENSE
Income tax expense consists of the following components:
(MILLIONS) FEDERAL STATE TOTAL
------- ------- -------
2000
Currently payable $ 92.6 $ 8.4 $ 101.0
Deferred (81.1) 3.5 (77.6)
Amortization of investment tax credits (4.9) -- (4.9)
------- ------- -------
Total income tax expense $ 6.6 $ 11.9 $ 18.5
======= ======= =======
1999
Currently payable $ 89.6 $ 13.0 $ 102.6
Deferred (11.5) 1.1 (10.4)
Amortization of investment tax credits (5.2) -- (5.2)
Income tax expense from continuing operations 72.9 14.1 87.0
Currently payable (3.6) (0.3) (3.9)
Deferred (4.4) (0.5) (4.9)
------- ------- -------
Total income tax expense $ 64.9 $ 13.3 $ 78.2
======= ======= =======
1998
Currently payable $ 61.0 $ 11.4 $ 72.4
Deferred 13.1 2.8 15.9
Amortization of investment tax credits (5.0) -- (5.0)
Income tax expense from continuing operations 69.1 14.2 83.3
Currently payable 2.8 0.1 2.9
Deferred (1.5) 0.2 (1.3)
Income tax expense from discontinued operations 1.3 0.3 1.6
------- ------- -------
Total income tax expense $ 70.4 $ 14.5 $ 84.9
======= ======= =======
Deferred taxes result from temporary differences in the recognition of
certain liabilities or assets for tax and financial reporting purposes. The
principal components of the company's deferred tax assets and liabilities
recognized in the balance sheet are as follows:
(MILLIONS) DEC. 31, 2000 DEC. 31, 1999
------------- -------------
Deferred income tax assets(1)
Property related $ 77.6 $ 71.1
Basis differences in oil and gas producing properties 1.2 (2.5)
Other 37.5 38.2
---------- ----------
Total deferred income tax assets 116.3 106.8
---------- ----------
Deferred income tax liabilities(1)
Property related (499.4) (562.0)
Basis differences in oil and gas producing properties (11.0) (13.4)
Alternative minimum tax credit carry forward 58.1 35.1
Other 7.1 30.9
Total deferred income tax liabilities (445.2) (509.4)
---------- ----------
Accumulated deferred income taxes $ (328.9) $ (402.6)
========== ==========
---------------
(1) Certain property related assets and liabilities have been netted.
59
60
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) 2000 1999 1998
------ ------ ------
Net income from continuing operations $250.9 $200.9 $204.2
Total income tax provision 18.5 87.0 83.3
------ ------ ------
Income from continuing operations before income taxes $269.4 $287.9 $287.5
====== ====== ======
Income taxes on above at federal statutory rate of 35% $ 94.3 $100.8 $100.6
Increase (Decrease) due to:
State income tax, net of federal income tax 7.8 9.2 9.3
Amortization of investment tax credits (4.9) (5.2) (5.0)
Non-conventional fuels tax credit (68.3) (17.2) (18.9)
Permanent reinvestment-foreign income (9.3) (1.4) (1.0)
Other (1.1) 0.8 (1.7)
------ ------ ------
Total income tax provision from continuing operations $ 18.5 $ 87.0 $ 83.3
====== ====== ======
Provision for income taxes as a percent of income
from continuing operations, before income taxes 6.9% 30.2% 29.0%
====== ====== ======
The provision for income taxes as a percent of income from
discontinued operations was 37.5% and 35.0% for 1999 and 1998, respectively.
There was no income from discontinued operations in 2000. The total effective
income tax rate differs from the federal statutory rate due to state income
tax, net of federal income tax, the non-conventional fuels tax credit and other
miscellaneous items. The actual cash paid for income taxes in 2000, 1999, and
1998 was $83.9 million, $62.1 million and $66.2 million, respectively.
J. DISCONTINUED OPERATIONS
TECOM
On Nov. 4, 1999, TECO Energy completed the sale of the assets of
TeCom, Inc. for $1.0 million in cash to Invensys Intelligent Building Systems,
a division of the Barber-Colman Company. The company decided to exit the
automated energy management systems business because it lacked the distribution
channels necessary to effectively reach the markets for its products.
As a result of the company's intention to sell this business, all
activities of the subsidiary through Sept. 1, 1999, the measurement date, were
reported as discontinued operations on the Consolidated Statements of Income,
including amounts from prior years which have been reclassified from continuing
operations to discontinued operations. After-tax losses from discontinued
operations were $2.5 million and $3.8 million, respectively, for the years
ended Dec. 31, 1999 and 1998. The loss on the sale of the assets of TeCom,
including an estimate of activities after the measurement date, was reported as
a loss on disposal of discontinued operations. The net after-tax loss from
TeCom's disposal of discontinued operations in 1999 was $12.9 million, or 10
cents per share.
Total revenues from discontinued operations related to TeCom were $1.2
million and $2.1 million, respectively, for the years ended Dec. 31, 1999 and
1998. There were no revenues in 2000.
TECO OIL & GAS
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 1995, TECO Oil & Gas participated in joint ventures
utilizing 3-D seismic imaging in the exploration for oil and gas.
In 1998, TECO Oil & Gas sold its offshore assets for cash and a note
receivable (the "Note") and wrote off the recorded value of all assets
associated with the discontinued oil and gas operation, for a net after-tax
gain reported from disposal of discontinued operations of $6.1 million.
In March 1999, TECO Oil & Gas sold the Note to a third party for
$500,000 in cash, and in a separate transaction ARO agreed to assume disputed
joint billing payments of approximately $425,000. A $0.6 million after-tax gain
from these transactions was recognized in 1999 as a gain on disposal of
discontinued operations.
There were no significant revenues from the discontinued oil and gas
operations in 2000, 1999 or 1998.
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K. 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,
2000 1999 1998
-------- -------- --------
NUMERATOR
Net income from continuing operations, basic $ 250.9 $ 200.9 $ 204.2
Effect of contingent performance shares (1.9) -- --
-------- -------- --------
Net income from continuing operations, diluted $ 249.0 $ 200.9 $ 204.2
======== ======== ========
Net income, basic $ 250.9 $ 186.1 $ 206.5
Effect of contingent shares (1.9) -- --
-------- -------- --------
Net income, diluted $ 249.0 $ 186.1 $ 206.5
======== ======== ========
DENOMINATOR
Average number of shares outstanding - basic 125.9 131.0 131.7
Plus: incremental shares for assumed conversions:
Stock options at end of period and contingent performance shares 3.3 2.3 3.0
Less: Treasury shares which could be purchased (2.9) (2.1) (2.5)
-------- -------- --------
Average number of shares outstanding - diluted 126.3 131.2 132.2
======== ======== ========
EARNINGS PER SHARE FROM CONTINUING OPERATIONS
BASIC $ 1.99 $ 1.53 $ 1.55
DILUTED $ 1.97 $ 1.53 $ 1.54
EARNINGS PER SHARE
BASIC $ 1.99 $ 1.42 $ 1.57
DILUTED $ 1.97 $ 1.42 $ 1.56
L. SEGMENT INFORMATION
TECO Energy is an electric and gas utility holding company with
significant diversified activities. The management of TECO Energy determined
its reportable segments based on each subsidiary's contribution of revenues,
operating income, net 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.
In November 1999, TECO Energy sold the assets of TeCom, the company's advanced
energy management technology subsidiary. All prior years presented here have
been restated to exclude TeCom's results, which are now reflected in the
consolidated financial statements as discontinued operations.
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CAPITAL
INCOME FROM NET ASSETS EXPENDITURES
(MILLIONS) REVENUES(1) OPERATIONS(1) INCOME(1) DEPRECIATION(1) AT DEC. 31, FOR THE YEAR
----------- ------------- --------- --------------- -------- ------------
2000
Tampa Electric $1,353.8(2) $ 293.5 $ 144.5 $ 161.6 $2,957.1 $ 267.1
Peoples Gas System 314.5 47.0 21.8 25.8 513.3 82.2
TECO Transport 269.8(3) 51.9 28.7 22.0 311.3 21.1
TECO Coal 232.8(4) 25.2(7) 37.5 26.9 246.3 64.0
TECO Power Services 204.9(5) 31.0(8) 36.9 18.5 1,350.6(10) 243.5
Other diversified businesses 148.0(6) 27.2(9) 31.3 13.4 294.4(11) 10.6
-------- -------- -------- -------- -------- --------
2,523.8 475.8 300.7 268.2 5,673.0 688.5
Other and eliminations (228.7) (62.2) (49.8) -- 3.2 (0.1)
-------- -------- -------- -------- -------- --------
TECO Energy consolidated $2,295.1 $ 413.6 $ 250.9 $ 268.2 $5,676.2 $ 688.4
======== ======== ======== ======== ======== ========
1999
Tampa Electric $1,199.8(2)(12)(13) $ 263.9(12) $ 138.8(15) $147.6 $2,827.3 $ 228.7
Peoples Gas System 251.7 43.2 19.8 23.1 433.1 77.8
TECO Transport 251.9(3) 46.8 26.2 21.9 312.0 18.6
TECO Coal 237.3(4) 21.5 16.0 16.1 193.2 23.4
TECO Power Services 109.5(5) 17.3(8) 14.6 9.3 700.4(10) 68.5
Other diversified businesses 109.8(6) 33.0(9) 27.3 14.2 222.5 9.8
-------- -------- -------- -------- -------- --------
2,160.0 425.7 242.7 232.2 4,688.5 426.8
Other and eliminations (177.0)(14) (2.1)(14) (41.8)(16) -- 1.6 (0.7)
-------- -------- -------- -------- -------- --------
TECO Energy consolidated $1,983.0 $ 423.6 $ 200.9 $ 232.2 $4,690.1 $ 426.1
======== ======== ======== ======== ======== ========
1998
Tampa Electric $1,234.6(2)(13) $ 279.7(17) $2,705.0(15) $ 146.1 $2,705.0 $ 176.2
Peoples Gas System 252.8 35.8 15.5 21.0 375.6 55.9
TECO Transport 230.0(3) 43.2 23.8 26.6 309.7 45.6
TECO Coal 232.4(4) 23.5(18) 17.5(20) 15.4 180.0 11.2
TECO Power Services 98.7(5) 13.0(8) 9.7 9.2 412.9(10) 0.4
Other diversified businesses 110.6(6) 37.8(9) 30.8(21) 14.7 222.2 5.4
-------- -------- -------- -------- -------- --------
2,159.1 433.0 238.5 233.0 4,205.4 294.7
Other and eliminations (203.4) (31.7)(19) (34.3)(16) -- (26.1) 1.4
-------- -------- -------- -------- -------- --------
TECO Energy consolidated $1,955.7 $ 401.3 $ 204.2 $ 233.0 $4,179.3 $ 296.1
======== ======== ======== ======== ======== ========
---------------
(1) From continuing operations.
(2) Revenues from sales to affiliates were $32.4 million, $24.8 million and
$23.2 million in 2000, 1999 and 1998, respectively.
(3) Revenues from sales to affiliates were $118.0 million, $101.0 million and
$112.8 million in 2000, 1999 and 1998, respectively.
(4) Revenues from sales to affiliates were $4.3 million, $23.1 million and
$33.8 million in 2000, 1999 and 1998, respectively.
(5) Revenues from sales to affiliates were $67.6 million, $35.5 million and
$32.7 million in 2000, 1999 and 1998, respectively. Revenues include
income from unconsolidated equity investments of $5.6 million, $2.6
million, and $1.8 million in 2000, 1999 and 1998, respectively.
(6) Revenues from sales to affiliates were $6.5 million, $0.6 million and $0.8
million in 2000, 1999 and 1998, respectively.
(7) Operating income includes a non-conventional fuels tax credit of $52.1
million in 2000.
(8) Operating income includes interest cost on the non-recourse debt related
to independent power operations of $12.1 million, $10.3 million and $13.4
million in 2000, 1999 and 1998, respectively.
(9) Operating income includes a non-conventional fuels tax credit of $16.2
million, $17.2 million and $18.9 million in 2000, 1999 and 1998,
respectively.
(10) Total assets include investments in unconsolidated affiliates of $145.5
million, $103.3 million and $124.5 million at Dec. 31, 2000, 1999 and
1998, respectively. Total assets also includes $383.1 million in other
non-current equity investments at Dec. 31, 2000.
(11) Total assets include $42.0 million in investments in unconsolidated
affiliates at Dec. 31, 2000.
(12) Revenues and operating income as shown for 1999 exclude a $7.9 million
credit resulting from a charge. See Note M.
(13) Revenues shown in 1999 are after the revenue deferral of $11.9 million.
Revenues shown in 1998 include the recognition of previously deferred
revenue of $38.3 million.
(14) Revenues and operating income include a pretax benefit of $7.9 million in
1999. See Note M.
(15) Net income excludes after-tax charges totaling $13.7 million and $10.4
million in 1999 and 1998, respectively. See Note M.
(16) Net income includes after-tax charges totaling $13.7 million and $19.6
million in 1999 and 1998, respectively. See Note M.
(17) Operating income excludes a pretax charge of $9.6 million in 1998. See
Note M.
(18) Operating income excludes a pretax charge of $13.6 million in 1998. See
Note M.
(19) Operating income includes pretax charges totaling $23.2 million in 1998.
See Note M.
(20) Net income excludes an after-tax charge of $8.9 million in 1998. See
Note M.
(21) Net income excludes an after-tax charge of $0.3 million in 1998. See
Note M.
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Tampa Electric Company provides retail electric utility services to
more than 568,000 customers in West Central Florida. Its Peoples Gas System
division is engaged in the purchase, distribution and marketing of natural gas
for more than 262,000 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 bulk 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, Tennessee and Virginia. In 2000,
TECO Coal began operating two coal processing facilities, whose production
qualifies for the non-conventional fuels tax credit. TECO Coal's subsidiaries
sell its coal production to third parties and to Tampa Electric. The contract
with Tampa Electric expired at the end of 1999 and was not renewed.
TECO Power Services Corporation (TPS) has subsidiaries that have
interests in independent power projects in Florida, Virginia, Hawaii and
Guatemala, and transmission and distribution facilities in Guatemala. TPS also
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, and energy services and engineering.
FOREIGN OPERATIONS
TPS 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.
At Dec. 31, 2000, TPS, through a wholly owned subsidiary, had a 100
percent ownership interest in a 120-megawatt power station and in transmission
facilities in Guatemala. The plant provides capacity under a U.S.
dollar-denominated power sales agreement to EEGSA.
TPS, through a subsidiary, owns a 30 percent interest in a consortium
that includes Iberdrola, an electric utility in Spain, and Electricidade de
Portugal, an electric utility in Portugal. The consortium owns an 80 percent
interest in EEGSA.
Total assets at Dec. 31, 2000, 1999 and 1998 included $442.6 million,
$379.4 million and $154.1 million, respectively, related to these Guatemalan
investments. Revenues included $69.0 million, $19.5 million and $16.9 million
for the years ended Dec. 31, 2000, 1999 and 1998, respectively, and operating
income included $23.7 million, $10.1 million and $7.9 million for the years
ended Dec. 31, 2000, 1999 and 1998, respectively, from these Guatemalan
operations and investments.
M. CHARGES TO EARNINGS
2000 CHARGES
Charges of an unusual and non-recurring nature had no significant net
effect on earnings in 2000. In 2000, TECO Energy's results included an
$8.3-million, after-tax gain from the US Propane and Heritage Propane
transactions offset by after-tax charges of $5.2 million to adjust the value of
leveraged leases and $3.8 million to adjust property values at TECO Properties.
1999 CHARGES
The charges in 1999 totaled $21.1 million pretax ($19.6 million after
tax) and consisted of the following:
Tampa Electric recorded a charge of $10.5 million ($6.4 million after
tax) based on FPSC audits of its 1997 and 1998 earnings, which among other
things, limited its equity ratio to 58.7 percent, a decrease of 91 basis points
and 224 basis points from 1997's and 1998's ratios, respectively.
Tampa Electric also recorded a charge of $3.5 million after tax,
representing management's estimate of additional expense to resolve the pending
litigation filed by the United States Environmental Protection Agency.
After-tax charges totaling $6.1 million were also recognized
reflecting corporate income tax provisions and settlements related to prior
years' tax returns. These charges were recorded at Tampa Electric (a
$3.8-million net after-tax charge, after recovery under the then current
regulatory agreement), at TECO Investments (a $4.3- million after-tax charge)
and at the TECO Energy corporate level (a $2.0-million after-tax benefit). A
charge of $6.0 million ($3.6 million after tax) was recorded to adjust the
carrying value of certain investments in leveraged aircraft leases to reflect
lower anticipated residual values.
1998 CHARGES
In 1998, TECO Energy recognized charges totaling $31.1 million, pretax
($19.6 million, after tax). These charges consisted of the following:
TECO Coal recorded a charge of $13.6 million ($8.9 million after tax)
to adjust the asset values of certain mining facilities, primarily at its
Gatliff mine, to reflect their expected value after the Tampa Electric contract
expires in 1999. TECO Coal expects no further asset adjustments related to the
expiration of the Tampa Electric contract.
The FPSC in September 1997 ruled that under the regulatory agreements
effective through 1999 the costs associated with
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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 uneconomic.
One contract was terminated in 1997. As to the other contract, which expires in
2001, Tampa Electric 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 exceeded the revenues expected through
1999. To reflect this difference, Tampa Electric recorded a $9.6-million charge
($5.9 million after tax) in 1998. In November 1999, the FPSC approved a
company-proposed treatment for the remaining 14 1/2 months of the contract that
flows 100 percent of the revenues from the contract back to retail customers.
Tampa Electric also recorded a charge of $7.3 million ($4.4 million
after tax) in other expense for an FPSC decision in 1998 denying recovery of
certain BTU coal quality price adjustments for coal purchases since 1993.
TECO Energy recorded $0.4 million, after tax, of merger-related costs
in 1998 in connection with the Griffis, Inc. merger.
N. COMMITMENTS AND CONTINGENCIES
TECO Energy has made certain commitments in connection with its
continuing capital improvements program. TECO Energy estimates that capital
investments for ongoing businesses during 2001 will be about $1.3 billion and
approximately $2.7 billion for the years 2002 through 2005.
Tampa Electric's capital investments are estimated to be $186 million
in 2001 and $648 million for 2002 through 2005 for equipment and facilities to
meet customer growth and generation reliability programs. Additionally, Tampa
Electric is also expecting to spend $167 million in 2001 and $459 million
during 2002-2005 to repower the Gannon Power Station and is forecasting $20
million in 2001 and $19 million during 2002-2005 to construct additional
generation expansion. At the end of 2000, Tampa Electric had outstanding
commitments of about $300 million primarily for the repowering project at
Gannon Power Station.
Peoples Gas System's capital investments are estimated to be $73
million for 2001 and $251 million for 2002 through 2005 for infrastructure
expansion to grow the customer base and normal asset replacement.
At the diversified companies, capital investments are estimated at
$901 million for 2001 and $1.3 billion for the years 2002 through 2005,
primarily for TECO Power Services' investment in the Panda Energy, Genesis
Power (GenPower), Frontera (see Note P. Subsequent Event) and Commonwealth
Chesapeake projects and for asset replacement and refurbishment at TECO
Transport and TECO Coal. This includes outstanding commitments of about $1.3
billion at the end of 2000, mainly for the Panda Energy and GenPower projects.
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 $22 million over the next 10 years. The environmental remediation
costs associated with these sites have been recorded on the accompanying
consolidated balance sheet and are not expected to have a significant impact on
customer prices.
TECO Energy has commitments under long-term operating leases,
primarily for building space, office equipment and heavy equipment, and certain
equipment at TPS' Hardee Power Station. TPS completed a transaction on Dec. 29,
2000, where certain non-integral equipment at its Hardee Power Station was sold
to a third party and leased back under a lease arrangement. The transaction was
structured such that the lease qualifies as an operating lease with a term of
12 years. Total rental expense for these operating leases, included in the
Consolidated Statements of Income for the years ended Dec. 31, 2000, 1999 and
1998 was $18.1 million, $12.8 million and $9.4 million, respectively. The
following is a schedule of future minimum lease payments at Dec. 31, 2000 for
all operating leases with noncancelable lease terms in excess of one year:
YEAR ENDED DEC. 31: AMOUNT (MILLIONS)
----------------
2001 $ 15.3
2002 15.2
2003 11.2
2004 11.2
2005 11.2
Later Years 66.7
------
Total minimum lease payments $130.8
======
The company has outstanding letters of credit of $36.6 million at Dec.
31, 2000, which guarantee performance to third parties related to debt service,
major maintenance requirements and various trade activities. The company also
has financial guarantees of $57 million primarily for construction related debt
for projects in which TECO Power Services is a participant.
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O. MERGERS, ACQUISITIONS AND DISPOSITIONS
On Nov. 1, 2000, TECO Coal acquired all of the outstanding stock of
Perry County Coal for $14.9 million, comprised of $12.1 million in cash and
$2.8 million in notes. Perry County Coal owns or controls more than of 23
million tons of low-sulfur reserves, and operates both deep and surface
contract mines. The acquisition was accounted for by the purchase method of
accounting and, accordingly, the results of operations and assets of Perry
County Coal are included as part of TECO Coal's results beginning Nov. 1, 2000.
The assets acquired and liabilities assumed were recorded at estimated fair
values as limited by the excess of fair value over the purchase price, as
summarized below:
MILLIONS
--------
Current Assets $ 8.1
Property, Plant and Equipment, net 16.2
Other assets 3.0
Notes payable (7.9)
Other liabilities (4.5)
-----
Net Assets acquired $14.9
=====
In September 2000, TECO Energy, Inc. acquired BCH Mechanical, Inc. and
its affiliated companies ("BCH") accounting for the transaction using the
purchase method of accounting. BCH is one of the leading mechanical contracting
firms in Florida. TECO Energy purchased a combination of stock and assets of the
BCH companies for $26.1 million in cash, which included $4.6 million for net
working capital; $2.9 million in notes; and 233,819 shares of TECO Energy, Inc.
common stock. Goodwill of $25.9 million representing the excess of purchase
price over the fair market value of assets acquired was recorded, and is being
amortized on a straight-line basis over 20 years. BCH is included within the
Other diversified businesses segment. A summary of the assets acquired and
liabilities assumed is set forth below:
MILLIONS
--------
Current Assets $ 20.0
Property, Plant and Equipment, net 0.8
Goodwill 25.9
Current liabilities (11.9)
------
Net Assets acquired $ 34.8
======
In connection with this transaction, TECO Solutions was formed to
support TECO Energy's strategy of offering customers a comprehensive and
competitive package of energy services and products. Operating companies under
TECO Solutions include TECO BGA (formerly Bosek, Gibson and Associates), BCH,
TECO Gas Services and TECO Properties.
In February 2000, TECO Energy, Inc. entered into an agreement to form
US Propane, a joint venture to combine its Peoples Gas Company (PGC) propane
operations with the propane operations of Atmos Energy Corporation, AGL
Resources Inc. and Piedmont Natural Gas Company, Inc. In June 2000, US Propane
announced that it would combine its propane operations with those of Heritage
Propane Partners, L.P. to create the fourth largest retail propane distributor
in the United States that will distribute propane to over 480,000 customers in
28 states. Through a series of transactions completed Aug. 10, 2000, US Propane
sold its propane business to Heritage Propane Partners for approximately $180
million in cash and other consideration, and purchased all of the outstanding
common stock of Heritage Holdings, Inc., the general partner of Heritage
Propane Partners, for $120 million. US Propane now owns the general partner
interest and 34 percent of the limited partnership interests of Heritage
Propane Partners. TECO Energy, Inc., through its wholly owned subsidiary TECO
Propane Ventures, LLC (TPV), is accounting for its $40.8 million investment, or
approximate 38 percent interest in US Propane under the equity method of
accounting. As a result of these transactions, TPV also received $19.3 million
in cash and recognized a pre-tax gain of $13.6 million ($8.3 million after tax)
on the sale of PGC assets and liabilities to the extent acquired by US Propane
and Heritage Propane Partners.
In January 1998, the company acquired an unregulated Florida propane
business, Griffis, Inc. (Griffis) and its affiliate, in a merger transaction
accounted for as a pooling of interest and issued approximately 0.6 million
shares of its common stock. These acquired businesses were then merged into and
operated as part of Peoples Gas Company prior to the formation of US Propane.
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P. SUBSEQUENT EVENTS
On Mar. 12, 2001, the company completed a public offering of 8.625
million common shares at $27.75 per share, resulting in net proceeds to the
company of approximately $232 million. The proceeds from the sale of these
shares were used primarily to reduce the commercial paper balances of TECO
Energy's finance subsidiary and for general corporate purposes.
On Mar. 15, 2001, TPS acquired the Frontera Power Station located near
McAllen, Texas. This 500-megawatt, natural gas-fired, combined-cycle plant,
originally developed by CSW Energy (CSW), began commercial operation in May
2000. As a condition of the merger of Central &South West Corporation, CSW's
parent company, with American Electric Power Company, Inc., the company was
required by the Federal Energy Regulatory Commission to divest its ownership of
this facility. The total acquisition cost of $265 million will consist of TPS'
equity investment of $120 million with the remainder expected to be funded with
non-recourse debt. As a result of this acquisition, TPS has entered into a
financial guarantee of up to $5 million for the purchase of fuel with a
supplier.
Q. QUARTERLY DATA (UNAUDITED)
Financial data by quarter is as follows: (unaudited)
QUARTER ENDED
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
--------- --------- --------- ---------
2000
Revenues(1) $ 524.5 $ 559.5 $ 614.7 $ 596.4
Income from operations(1) $ 108.0 $ 99.7 $ 121.0 $ 84.9
Net income(1) $ 53.5 $ 57.5 $ 82.1 $ 57.8
Earnings Per Share (EPS)-basic $ 0.42 $ 0.46 $ 0.65 $ 0.46
Earnings per share (EPS)-diluted $ 0.42 $ 0.46 $ 0.65 $ 0.44
Dividends paid per common share(3) $ 0.325 $ 0.335 $ 0.335 $ 0.335
Stock price per common share(4)
High $ 20 5/8 $ 23 1/8 $ 28 3/4 $ 33 3/16
Low $ 17 1/4 $ 19 3/16 $ 20 3/16 $ 26 9/16
Close $ 19 7/16 $ 20 1/16 $ 28 3/4 $ 32 3/8
1999
Revenues(1) $ 445.7 $ 491.4 $ 555.9 $ 490.0
Income from operations(1) $ 96.1 $ 100.9 $ 138.8 $ 87.8
Net income(1)
Net income from continuing operations $ 49.5 $ 52.8 $ 55.9 $ 42.7
Net income $ 49.2 $ 51.9 $ 42.3 $ 42.7
Earnings per share (EPS) - basic
EPS from continuing operations(2) $ 0.38 $ 0.40 $ 0.42 $ 0.33
EPS $ 0.38 $ 0.39 $ 0.32 $ 0.33
Earnings per share (EPS) - diluted
EPS from continuing operations $ 0.38 $ 0.40 $ 0.42 $ 0.33
EPS $ 0.38 $ 0.39 $ 0.32 $ 0.33
Dividends paid per common share(3) $ 0.31 $ 0.325 $ 0.325 $ 0.325
Stock price per common share(4)
High $ 28 $23 13/16 $ 23 1/8 $ 22 1/2
Low $ 19 7/8 $ 19 3/4 $ 19 5/8 $ 18 3/8
Close $ 19 7/8 $ 22 3/4 $ 21 1/8 $ 18 9/16
---------------
(1) Millions.
(2) Basic EPS from continuing operations before the charges discussed in Note
M were $0.38, $0.40, $0.54 and $0.36 for the four quarters in 1999.
(3) Dividend paid for TECO Energy common stock (not restated for Peoples Gas
Companies merger).
(4) Trading prices for common shares.
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
During the period Jan. 1, 1999 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 3 of TECO Energy's definitive proxy statement, dated March 5, 2001, for
its Annual Meeting of Shareholders to be held on April 18, 2001 (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 page 16 of this report.
ITEM 11. EXECUTIVE COMPENSATION.
The information required by Item 11 is included in the Proxy Statement
beginning on page 8 and ending on page 14, and under the caption "Compensation
of Directors" on page 4, and is incorporated herein by reference.
ITEM 12. SECURITY 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 4 of the Proxy Statement and is incorporated
herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) 1. Financial Statements - See index on page 40
2. Financial Statement Schedules - See index on page 40
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SCHEDULE II
TECO ENERGY, INC.
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEARS ENDED DEC. 31, 2000, 1999 AND 1998
(millions)
Additions
Balance at ------------------------------------------ Balance at
Beginning Charged to Other End of
of Period Income Charges Deductions(1) Period
--------- ---------- ------- ------------- ----------
Allowance for Uncollectible Accounts:
2000 $ 3.5 $10.1 $ 0.2(2) $ 5.2 $ 8.6
1999 2.6 6.2 0.4(2) 5.7 3.5
1998 2.6 4.9 -- 4.9 2.6
---------------
(1) Write-off of individual bad debt accounts
(2) Includes $0.2 million and $0.3 million in 2000 and 1999, respectively, for
TeCom Discontinued Operations.
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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 Jan. 18, 2001.
*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, 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 among the Hillsborough County Industrial
Development Authority, Tampa Electric Company and NationsBank of
Florida, N.A., as trustee, dated as of Oct. 26, 1992 (Exhibit 4.2,
Form 10-Q for the quarter ended Sept. 30, 1992 of TECO Energy, Inc.).
*4.17 Loan and Trust Agreement among the Hillsborough County Industrial
Development Authority, Tampa Electric Company and NationsBank of
Florida, N.A., as trustee, dated as of June 23, 1993 (Exhibit 4.2,
Form 10-Q for the quarter ended June 30, 1993 of TECO Energy, Inc.).
*4.18 Loan and Trust Agreement among the Polk County Industrial Development
Authority, Tampa Electric Company and The Bank of New York, as
trustee, dated as of Dec. 1, 1996. (Exhibit 4.22, Form 10-K for 1996
of TECO Energy, Inc.).
*4.19 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.).
4.20 First Supplemental Installment Sales Agreement between the Plaquemines
Port, Harbor and Terminal District (Louisiana) and Electro-Coal
Transfer Corporation, dated as of Dec. 1, 2000.
*4.21 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.).
*4.22 Indenture between Tampa Electric Company and The Bank of New York, as
trustee, dated as of July 1, 1998 (Exhibit 4.1, Registration Statement
No. 333-55873).
*4.23 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.).
69
70
*4.24 Second Supplemental Indenture dated as of Aug. 15, 2000 between Tampa
Electric Company and The Bank of New York (Exhibit 4.1, Form 8-K dated
Aug. 22, 2000 of Tampa Electric Company).
*4.25 Indenture between TECO Energy, Inc. and The Bank of New York as
trustee, dated as of Aug. 17, 1998 (Exhibit 4.1, Form 8-K dated Sept.
20, 2000 of TECO Energy, Inc.).
*4.26 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.).
*4.27 Second Supplemental Indenture dated as of Sept. 15, 2000 between TECO
Energy, Inc. and The Bank of New York (Exhibit 4.1, Form 8-K dated
Sept. 28, 2000 of TECO Energy, Inc.).
*4.28 Third Supplemental Indenture dated as of Dec. 1, 2000 by and between
TECO Energy, Inc. and The Bank of New York, as trustee (Exhibit 4.21,
Form 8-K dated Dec. 21, 2000 of TECO Energy, Inc.).
*4.29 Amended and Restated Limited Liability Company Agreement of TECO
Funding Company I, LLC dated as of Dec. 1, 2000 (Exhibit 4.24, Form
8-K dated Dec. 21, 2000 of TECO Energy, Inc.).
*4.30 Amended and Restated Trust Agreement of TECO Capital Trust I among
TECO Funding Company I, LLC, The Bank of New York and The Bank of New
York (Delaware) dated as of Dec. 1, 2000 (Exhibit 4.22, Form 8-K
dated Dec. 21, 2000 of TECO Energy, Inc.).
*4.31 Guaranty Agreement between TECO Energy, Inc. and The Bank of New York,
as trustee, dated as of Dec. 1, 2000 (Exhibit 4.25, Form 8-K dated
Dec. 21, 2000 of TECO Energy, Inc.).
*4.32 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 as of Oct. 21, 1998 of TECO Energy, Inc.).
*10.1 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.).
*10.2 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.).
*10.3 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.).
*10.4 Annual Incentive Compensation Plan for TECO Energy and subsidiaries,
as revised Jan. 20, 1999. (Exhibit 10.6, Form 10-K for 1998 of TECO
Energy, Inc.).
*10.5 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.).
*10.6 Forms of Severance Agreement between TECO Energy, Inc. and certain
officers, as amended and restated as of Oct. 22, 1999 (Exhibit 10.7,
Form 10-K for 1999 of TECO Energy, Inc.).
*10.7 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.).
*10.8 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.).
*10.9 TECO Energy Group Retirement Savings Excess Benefit Plan, as amended
and restated effective as of July 15, 1998. (Exhibit 10.14, Form 10-K
for 1998 of TECO Energy, Inc.).
*10.10 TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit 10.1, Form 10-Q
for the quarter ended March 31, 1996 of TECO Energy, Inc.).
*10.11 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.).
*10.12 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.).
*10.13 Form of Nonstatutory Stock Option under the TECO Energy, Inc. 1996
Equity Incentive Plan (Exhibit 10.5, Form 10-Q for the quarter ended
June 30, 1999 of TECO Energy, Inc.).
*10.14 Form of Restricted Stock Agreement between TECO Energy, Inc. and
certain officers 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.).
*10.15 Form of Amendment to Restricted Stock Agreements, dated as of July 15,
1998, between TECO Energy, Inc. and certain officers 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.).
*10.16 TECO Energy, Inc. 1997 Director Equity Plan (Exhibit 10.1, Form 8-K
dated April 16, 1997 of TECO Energy, Inc.).
*10.17 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.).
*10.18 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.).
70
71
*10.19 Supplemental Executive Retirement Plan for R. D. Fagan as of May 24,
1999 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 1999 of
TECO Energy, Inc.).
*10.20 Terms of R. D. Fagan's employment, dated as of May 24, 1999 (Exhibit
10.2, Form 10-Q for the quarter ended June 30, 1999 of TECO Energy,
Inc.).
*10.21 Nonstatutory Stock Option granted to R. D. Fagan, dated as of May 24,
1999 (Exhibit 10.3, Form 10-Q for the quarter ended June 30, 1999 of
TECO Energy, Inc.).
*10.22 Restricted Stock Agreement between TECO Energy, Inc. and R. D. Fagan,
dated as of May 24, 1999 (Exhibit 10.4, Form 10-Q for the quarter
ended June 30, 1999 of TECO Energy, Inc.).
*10.23 Form of Replacement Performance Shares Agreement between TECO Energy,
Inc. and certain officers under the TECO Energy, Inc. 1996 Equity
Incentive Plan. (Exhibit 10.1, Form 10-Q for the quarter ended June
30, 2000 of TECO Energy, Inc.).
*10.24 Form of Performance Shares Agreement between TECO Energy, Inc. and
certain officers under the TECO Energy, Inc. 1996 Equity Incentive
Plan. (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2000 of
TECO Energy, Inc.).
*10.25 Form of Performance Shares Agreement between TECO Energy, Inc. and
certain TECO Power Services Corporation officers under the TECO
Energy, Inc. 1996 Equity Incentive Plan. (Exhibit 10.3, Form 10-Q for
the quarter ended June 30, 2000 of TECO Energy, Inc.).
12. Ratio of Earnings to Fixed Charges.
21. Subsidiaries of the Registrant.
23. Consent of Independent Certified Public Accountants.
24.1 Power of Attorney.
24.2 Certified copy of resolution authorizing Power of Attorney
-------------
* 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 10.6 and 10.8 through 10.25 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 debt
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) REPORTS ON FORM 8-K
The registrant filed the following reports on Form 8-K during the last
quarter of 2000.
The registrant filed a Current Report on Form 8-K dated Dec. 21, 2000
under "Item 5. Other Events", furnishing certain exhibit for
incorporation by reference into the Registration Statement on Form S-3
previously filed with the Securities and Exchange Commission (File No.
333-50808).
The registrant filed a Current Report on Form 8-K dated Dec. 18, 2000
under "Item 5. Other Events", furnishing certain exhibits for
incorporation by reference into the Registration Statement on Form S-3
previously filed with the Securities and Exchange Commission (File No.
333-50808).
The registrant filed a Current Report on Form 8-K dated Nov. 16, 2000
reporting under "Item 5. Other Events" announcing a TECO Power
Services project in Louisiana.
The registrant filed a Current Report on Form 8-K dated Nov. 14, 2000
reporting under "Item 5. Other Events" that TECO Power Services had
formed a joint venture with Panda Energy International to build, own
and operate two merchant power plants in Arkansas and Arizona.
71
72
The registrant filed a Current Report on Form 8-K dated Oct. 30, 2000
reporting under "Item 5. Other Events" that TECO Power Services
acquired GenPower's interest in two independent power projects in
Arkansas and Mississippi.
The registrant filed the following reports on Form 8-K subsequent to
Dec. 31, 2000.
The registrant filed a Current Report on Form 8-K dated Feb. 8, 2001,
reporting under "Item 5. Other Events" that TECO Power Services
Corporation reached an agreement to purchase American Electric Power's
Frontera Power Station located in South Texas.
The registrant filed a Current Report on Form 8-K and 8-K/A dated Feb.
20, 2001, reporting under "Item 5. Other Events" to file audited
financial statements together with the related Management's Discussion
and Analysis of Financial Condition and Results of Operations for the
years ended Dec. 31, 2000, 1999 and 1998.
The registrant filed a Current Report on Form 8-K dated Mar. 6, 2001,
under "Item 5. Other Events", furnishing certain exhibits for
incorporation by reference into the Registration Statement on Form S-3
previously filed with the Securities and Exchange Commission (File No.
333-50808).
72
73
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized on the 28th day of
March, 2000.
TECO ENERGY, INC.
By: R. D. FAGAN*
---------------------------------
R. D. FAGAN, 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 28, 2001:
Signature Title
--------- -----
R. D. FAGAN* Chairman of the Board, President,
---------------------------- Director and Chief Executive Officer
R. D. FAGAN (Principal Executive Officer)
/s/ G. L. GILLETTE Vice President-Finance
---------------------------- and Chief Financial Officer
G. L. GILLETTE (Principal Financial Officer)
S. A. MYERS* Vice President-Corporate Accounting and Tax
---------------------------- (Principal Accounting Officer)
S. A. MYERS
Signature Title Signature Title
--------- ----- --------- -----
C. D. AUSLEY* Director W. D. ROCKFORD* Director
---------------------- ----------------------
C. D. AUSLEY W. D. ROCKFORD
S. L. BALDWIN* Director W. P. SOVEY* Director
---------------------- ----------------------
S. L. BALDWIN W. P. SOVEY
H. L. CULBREATH* Director J. T. TOUCHTON* Director
---------------------- ----------------------
H. L. CULBREATH J. T. TOUCHTON
J. L. FERMAN, JR.* Director J. A. URQUHART* Director
---------------------- ----------------------
J. L. FERMAN, JR. J. A. URQUHART
L. GUINOT, JR.* Director J. O. WELCH, JR.* Director
---------------------- ----------------------
L. GUINOT, JR. J. O. WELCH, JR.
T. L. RANKIN* Director
----------------------
T. L. RANKIN
*By: /s/ G. L. GILLETTE
------------------------------------
G. L. GILLETTE, Attorney-in-fact
73
74
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 Jan. 18, 2001 [ ]
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, 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 among the Hillsborough County *
Industrial Development Authority, Tampa Electric Company and
NationsBank of Florida, N.A., as trustee, dated as of Oct.
26, 1992 (Exhibit 4.2, Form 10-Q for the quarter ended Sept.
30, 1992 of TECO Energy, Inc.).
4.17 Loan and Trust Agreement among the Hillsborough County *
Industrial Development Authority, Tampa Electric Company and
NationsBank of Florida, N.A., as trustee, dated as of June
23, 1993 (Exhibit 4.2, Form 10-Q for the quarter ended June
30, 1993 of TECO Energy, Inc.).
4.18 Loan and Trust Agreement, dated as of Dec. 1, 1996, among the *
Polk County Industrial Development Authority, Tampa Electric
Company and The Bank of New York, as trustee(Exhibit 4.22,
Form 10-K for 1996 of TECO Energy, Inc.).
74
75
4.19 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.)..
4.20 First Supplemental Installment Sales Agreement, between [ ]
Plaquemines Port, Harbor, and Terminal District (Louisiana)
and Electro-Coal Transfer Corporation, dated Dec. 1, 2000.
4.21 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.).
4.22 Indenture between Tampa Electric and The Bank of New York, as *
trustee, dated as of Jul. 1, 1998 (Exhibit 4.1, Registration
Statement No. 333-55873)
4.23 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.).
4.24 Second Supplemental Indenture dated as of Aug. 15, 2000 *
between Tampa Electric Company and The Bank of New York
(exhibit 4.1, Form 8-K dated Aug. 22, 2000 of Tampa Electric
Company).
4.25 Indenture between TECO Energy, Inc. and The Tank of New York, *
as trustee, dated as of Aug. 17, 1998 (Exhibit 4.1, Form 8-K
dated Sept. 20, 2000 of TECO Energy, Inc.).
4.26 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.).
4.27 Second Supplemental Indenture dated as of Aug. 15, 2000 *
between TECO Energy, Inc. and The Bank of New York (Exhibit
4.1, Form 8-K dated Sept. 28, 2000 of TECO Energy, Inc.).
4.28 Third Supplemental Indenture dated as of Dec. 1, 2000 between *
TECO Energy, Inc. and The Bank of New York, as trustee
(Exhibit 4.21, Form 8-K dated Dec. 21, 2000 of TECO Energy,
Inc.).
4.29 Amended and Restated Limited Liability Company Agreement of *
TECO Funding Company I, LLC dated as of Dec. 1, 2000 (Exhibit
4.24, Form 8-K dated Dec. 21, 2000 of TECO Energy, Inc.).
4.30 Amended and Restated Trust Agreement of TECO Capital Trust I *
among TECO Funding Company I, LLC, The Bank of New York and
The Bank of New York (Delaware) dated as of Dec. 1, 2000
(Exhibit 4.22, Form 8-K dated Dec. 21, 2000 of TECO Energy,
Inc.).
4.31 Guaranty Agreement between TECO Energy, Inc. and The Bank of *
New York, as trustee, dated as of Dec. 1, 2000 (Exhibit 4.25,
Form 8-K dated Dec. 21, 2000 of TECO Energy, Inc.).
4.32 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 as of Oct. 21, 1998 of TECO
Energy, Inc.).
10.1 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.).
10.2 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.)
10.3 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.).
10.4 Annual Incentive Compensation Plan for TECO Energy and *
subsidiaries, as revised Jan. 20, 1999. (Exhibit 10.6, Form
10-K for 1998 of TECO Energy, Inc.).
10.5 TECO Energy Group Supplemental Disability Income Plan, dated *
as of March 20, 1998 (Exhibit 10.22, Form 10-K for 1988 of
TECO Energy, Inc.).
10.6 Forms of Severance Agreement between TECO Energy, Inc. And *
certain officers, as amended and restated as of Oct.
22, 1999 (Exhibit 10.7, Form 10-K for 1999 of TECO Energy,
Inc.).
75
76
10.7 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.).
10.8 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.).
10.9 TECO Energy Group Retirement Savings Excess Benefit Plan, as *
amended and restated effective as of July 15, 1998. (Exhibit
10.14, Form 10-K for 1998 of TECO Energy, Inc.).
10.10 TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit 10.1, *
Form 10-Q for the * quarter ended March 31, 1996 of TECO
Energy, Inc.).
10.11 Form of Nonstatutory Stock Option under the TECO Energy, Inc. *
1996 Equity Incentive Pan (Exhibit 10.1, Form 10-Q for the
quarter ended June 30, 1996 of TECO Energy, Inc.).
10.12 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.).
10.13 Form of Nonstatutory Stock Option under the TECO Energy, Inc. *
1996 Equity Incentive Plan (Exhibit 10.5, Form 10-Q for the
quarter ended June 30, 1999 of TECO Energy, Inc.).
10.14 Form of Restricted Stock Agreement between TECO Energy, Inc. *
and certain officers 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.).
10.15 Form of Amendment to Restricted Stock Agreements, dated as of *
July 15, 1998, TECO Energy, Inc. and certain officers under
the TECO Energy, Inc. between 1996 Equity Incentive Plan
(Exhibit 10.2, Form 10-Q for the quarter ended Sept. 30, 1998
of TECO Energy, Inc.).
10.16 TECO Energy, Inc. 1997 Director Equity Plan (Exhibit 10.1, *
Form 8-K dated April 16, 1997 of TECO Energy, Inc.).
10.17 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.).
10.18 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.).
10.19 Supplemental Executive Retirement Plan for R. D. Fagan as of *
May 24, 1999 (Exhibit 10.1, Form 10-Q for the quarter ended
June 30, 1999 of TECO Energy, Inc.).
10.20 Terms of R. D. Fagan's employment dated as of May 24, 1999 *
(Exhibit 10.2, Form 10-Q for the quarter ended June 30, 1999
of TECO Energy, Inc.).
10.21 Nonstatutory Stock Option granted to R. D. Fagan, dated as of *
May 24, 1999 (Exhibit 10.3, Form 10-Q for the quarter ended
June 30, 1999 of TECO Energy, Inc.).
10.22 Restricted Stock Option granted to R. D. Fagan, dated as of *
May 24, 1999 (Exhibit 10.4, Form 10-Q for the quarter ended
June 30, 1999 of TECO Energy, Inc.).
10.23 Form of Replacement Performance Shares Agreement between TECO *
Energy, Inc. and certain officers under the TECO Energy, Inc.
1996 Equity Incentive Plan. (Exhibit 10.1, Form 10-Q for the
quarter ended June 30, 2000 of TECO Energy, Inc.).
10.24 Form of Performance Shares Agreement between TECO Energy, *
Inc. and certain officers under the TECO Energy,
Inc. 1996 Equity Incentive Plan. (Exhibit 10.7, Form 10-Q for
the quarter ended June 30, 2000 of TECO Energy, Inc.).
10.25 Form of Performance Shares Agreement between TECO Energy, *
Inc. and certain TECO Power Services Corporation officers
under the TECO Energy, Inc. 1996 Equity Incentive Plan.
(Exhibit 10.3, Form 10-Q for the quarter ended June 30, 2000
of TECO Energy, Inc.).
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12. Ratio of Earnings to Fixed Charges. [ ]
21. Subsidiaries of the Registrant. [ ]
23. Consent of Independent Certified Public Accountants. [ ]
24.1 Power of Attorney. [ ]
24.2 Certified copy of resolution authorizing Power of Attorney. [ ]
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* 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.
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