UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
X Annual Report Pursuant to Section 13 or 15(d) of the Securities
- -------
Exchange Act of 1934
For the fiscal year ended December 31, 2001
OR
______ Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from _____ to _____
Commission File Number 1-8180
TECO ENERGY, INC.
-----------------
(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
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
--------------------------- ------------------------
Common Stock, $1.00 par value New York Stock Exchange
Common Stock Purchase Rights New York Stock Exchange
Equity Security Units 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. _______
The aggregate market value of the voting stock held by nonaffiliates of the
registrant as of February 28, 2002 was $3,488,215,711.
The number of shares of the registrant's common stock outstanding as of February
28, 2002 was 139,752,232.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Definitive Proxy Statement relating to the 2002 Annual Meeting
of Shareholders of the registrant are incorporated by reference into Part III.
Index to Exhibits appears on page 74
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 directly, or through its subsidiary TECO
Diversified, Inc., 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 575,000 customers in West Central
Florida with a net system generating capability of 3,899 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 TECO Energy
acquisition of Lykes Energy, Inc. With more than 272,000 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 2001 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 throughout the southeast.
For financial information regarding TECO Energy's significant business
segments, see Notes to the Consolidated Financial Statements -- Note K, Segment
Information.
TECO Energy and its subsidiaries had 6,315 employees as of Dec. 31, 2001.
TAMPA ELECTRIC--Electric Operations
Tampa Electric Company was incorporated in Florida in 1899 and was
reincorporated in 1949. Tampa Electric Company is a public utility operating
within the state of Florida. Through its Tampa Electric division, it is engaged
in the generation, purchase, transmission, distribution and sale of electric
energy. The retail territory served comprises an area of about 2,000 square
miles in West Central Florida, including Hillsborough County and parts of Polk,
Pasco and Pinellas Counties, and has an estimated population of over one
million. The principal communities served are Tampa, Winter Haven, Plant City
and Dade City. In addition, Tampa Electric engages in wholesale sales to
utilities and other resellers of electricity. It has three electric generating
stations in or near Tampa, one electric generating station in southwestern Polk
County, Florida and two electric generating stations (one of which is on long-
term standby) located near Sebring, a city located in Highlands County in South
Central Florida.
Tampa Electric had 2,823 employees as of Dec. 31, 2001, of which 984 were
represented by the International
2
Brotherhood of Electrical Workers (IBEW) and 298 by the Office and Professional
Employees International Union (OPEIU).
In 2001, approximately 47 percent of Tampa Electric's total operating
revenue was derived from residential sales, 29 percent from commercial sales, 9
percent from industrial sales and 15 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) 2001 2000 1999
-------- -------- ------
Residential $ 659.8 $ 613.3 $ 557.4
Commercial 409.7 377.1 345.5
Industrial-Phosphate 57.0 61.6 54.2
Industrial-Other 71.8 62.6 56.2
Other retail sales of electricity 103.0 95.0 86.8
Sales for resale 82.4 109.1 86.1
Deferred revenues -- -- (11.9)
Other 29.0 35.1 25.5
-------- -------- --------
$1,412.7 $1,353.8 $1,199.8
======== ======== ========
Megawatt-hour Sales
(thousands) 2001 2000 1999
------- -------- ------
Residential 7,594 7,369 6,967
Commercial 5,685 5,541 5,336
Industrial 2,329 2,390 2,224
Other retail sales of electricity 1,368 1,338 1,278
Sales for resale 1,499 2,564 2,160
-------- -------- --------
18,475 19,202 17,965
======== ======== ========
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
significant 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 2001 base revenues.
Tampa Electric's business is not highly seasonal, but winter peak loads are
experienced due to electric heating 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.
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
3
practices. See Utility Regulation -- Regional Transmission Organization section.
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 sells transportation services, and TECO Power Services sells
generating capacity and energy 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 section.) 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 the TECO Power
Services section.
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. For independent power producers, this Act
removed 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, Standard Costs, Open Access Same-time Information
System (OASIS) and Standards of Conduct. This rule works 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 to take transmission service under their own transmission
tariffs.
FERC requires transmission system owners 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. FERC's authority over this requirement was recently
upheld by the Supreme Court. 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 FERC filings in October 2000 and December 2000, Tampa Electric
agreed with the other IOUs operating in Florida 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 other utilities in
peninsular Florida that choose to join. The FERC tentatively approved
GridFlorida in March 2001, but has not finally ruled on a May 2001 compliance
filing of the applicants.
In May 2001, the FPSC questioned the prudence of the three filing utilities
joining GridFlorida as conditionally approved by FERC. The three utilities
requested and the FPSC granted the opening of an accelerated docket regarding
the prudence of GridFlorida. In December 2001, the FPSC ruled that, while the
three IOUs were prudent in their actions to set up GridFlorida, the FPSC was not
satisfied with the transmission owning features of GridFlorida nor with the
proposal that any of the filing utilities transfer ownership of their assets to
GridFlorida. Accordingly, the FPSC ordered the three IOUs to file a revised
version of GridFlorida which was filed with the FPSC in late March 2002. Tampa
Electric plans to take an active role in monitoring and influencing the
development of other possible RTOs in the southeast region.
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 completed its efforts and
published its final report in December 2001. The Study Commission's final
recommendations include, among other things, elimination of barriers to entry
for
4
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 as early as the 2002 legislative session. It is unclear at this time if
this proposed legislation would pass.
Fuel
Approximately 96 percent of Tampa Electric's generation for 2001 was coal-
fired, with oil and natural gas each representing 2 percent. Tampa Electric
used its generating units to meet approximately 84 percent of the system load
requirements with the remaining 16 percent coming from purchased power. A
slightly lower level of coal generation as a percentage of total generation is
anticipated for 2002.
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: 2001 2000 1999 1998 1997
--------------- ----- ----- ---- ---- ----
Coal $ 2.06 $ 1.92 $ 2.00 $ 1.99 $ 1.97
Oil $ 5.79 $ 5.33 $ 3.09 $ 3.14 $ 3.76
Gas (Natural) $ 4.84 $ 5.49 -- -- --
Composite $ 2.19 $ 2.07 $ 2.03 $ 2.03 $ 2.01
Average cost per ton
--------------------
of coal burned $47.53 $44.36 $44.63 $44.44 $44.50
--------------
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, petroleum coke and coal of
a somewhat higher sulfur content; Polk Power Station burns high-sulfur coal,
which is gasified and subjected 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 7.3 million tons of coal during
2001 and estimates that its coal consumption will be about 7.1 million tons for
2002. During 2001, Tampa Electric purchased approximately 44 percent of its
coal under long-term contracts with five suppliers, and 56 percent of its coal
in the spot market. 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 or under intermediate-term purchase
agreements. Tampa Electric expects to obtain approximately 60 percent of its
coal requirements in 2002 under long-term contracts with five suppliers and the
remaining 40 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 10 and
11 and TECO Coal on page 11.
In 2001, about 63 percent of Tampa Electric's coal supply was deep-mined,
approximately 33 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.
Oil. Tampa Electric had supply agreements through Dec. 31, 2002 for No. 2
fuel oil and No. 6 fuel oil for its Polk and Phillips stations, and its
combustion turbine units at prices based on Gulf Coast Cargo spot prices.
Natural Gas. As of December 2001, Tampa Electric had no committed 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 give Tampa Electric rights to the use of
rights of way and other public property to place its facilities, and are
irrevocable and 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. 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;
otherwise, based on judicial precedent, Tampa Electric is able to keep its
facilities in place subject to reasonable rules and regulations imposed by the
municipalities.
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.
5
Franchise fees payable by Tampa Electric, which totaled $24.3 million in
2001, are calculated using a formula based primarily on electric revenues.
Utility operations in Hillsborough, Pasco, Pinellas and Polk Counties
outside of incorporated municipalities are conducted in each case under one or
more permits to use state or county rights-of-way granted by the Florida
Department of Transportation or 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 Polk and Pasco
counties expire in 2004 and 2033, respectively.
Environmental Matters
Tampa Electric Company is a party to a consent decree with the
Environmental Protection Agency (EPA) and the U.S. Department of Justice,
effective Oct. 5, 2000, and a consent final judgement with the Florida
Department of Environmental Protection (FDEP) effective December 7, 1999.
Pursuant to these consent decrees, allegations of violations of New Source
Review requirements of the Clear Air Act were resolved, provision was made for
environmental controls and pollution reductions, and Tampa Electric is committed
to a comprehensive program that will dramatically decrease emissions from the
company's power plants.
The emission reduction plan included specific detail with respect to the
availability of the scrubbers and earlier incremental NOx reduction efforts on
Big Bend Units 1, 2 and 3 and the repowering of the company's coal-fired Gannon
Station to natural gas. Engineering for the repowering project began in January
2000, and Tampa Electric anticipates that commercial operation for the first
repowered unit is expected by May 1, 2003. The repowering of the second unit is
scheduled for completion 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
generation.
In November 2000, the FPSC approved recovery through the Environmental Cost
Recovery Clause of costs incurred to improve the availability and removal
efficiency for Tampa Electric's Big Bend 1, 2 and 3 scrubbers, to reduce
particulate matter emissions, and to reduce NOx emissions. The approved cost
recovery for these various environmental projects through customers' bills
started in January 2001.
Tampa Electric Company is one of several potentially responsible parties
for certain superfund sites and, through its Peoples Gas System division, for
certain superfund and 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.
Expenditures. During the five years ended Dec. 31, 2001, Tampa Electric
spent $141.0 million on capital additions to meet environmental requirements.
Tampa Electric spent an estimated $11.6 million in 2001 on environmental
projects.
Environmental expenditures are estimated at $11.5 million for 2002, and
$21.7 million during the years 2003 through 2006. Approximately half of the
$21.7 million is for the development of technologies for further reduction of
NOx emissions at Big Bend Station beginning in 2006. The balance of the
estimated expenditures are for continued improvement of electrostatic
precipitators for particulate matter emissions reductions, and continued
improvements of the scrubber systems for SO2 reductions as required by the EPA
consent decree.
To date Tampa Electric has spent approximately $26.1 million for compliance
with the EPA consent decree at Big Bend Station for reduction of NOx and
particulate matter emissions and to improve the scrubber systems to reduce SO2
emissions. Tampa Electric has also spent $260.2 million excluding allowance for
funds used during construction (AFUDC), on projects leading to the repowering of
the company's coal-fired Gannon Station to fire natural gas, to meet the EPA
consent decree condition of eliminating coal firing at Gannon Station.
PEOPLES GAS SYSTEM--Gas Operations
Peoples Gas System (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.
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 over 272,000 customers. The system includes
approximately 9,000 miles of mains and over 4,400 miles of service lines.
In 2001, the total throughput for PGS was 1.1 billion therms. Of this
total throughput, 17 percent was gas purchased and resold to retail customers by
PGS, 74 percent was third party supplied gas delivered for retail customers, and
9 percent was gas sold off-system. Industrial and power generation customers
consumed approximately 67 percent of PGS' annual therm volume. Commercial
customers used approximately 28 percent, with the balance consumed by
residential customers.
While the residential market represents only a small percentage of total
therm volume, residential operations generally
6
comprise 25 percent of total revenues. New residential construction including
natural gas 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 296 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) 2001 2000 1999 2001 2000 1999
------ ------ ------ ------- ------- -------
Residential $ 88.2 $ 73.2 $ 59.0 58.8 57.6 52.1
Commercial 163.6 145.8 125.5 308.9 292.1 273.5
Industrial 50.4 51.7 29.3 346.5 374.1 331.9
Power Generation 11.6 10.7 10.4 403.5 418.6 405.2
Other revenues 39.1 33.0 27.5 - - -
------ ------ ------ ------- ------- -------
Total $352.9 $314.4 $251.7 1,117.7 1,142.4 1,062.7
====== ====== ====== ======= ======= =======
PGS had 639 employees as of Dec. 31, 2001. A total of 89 employees in six
of the company's 15 operating divisions are represented by various union
organizations.
Regulation
The operations of PGS are regulated by the FPSC separate from the
regulation of Tampa Electric's electric operations. The FPSC has jurisdiction
over rates, service, issuance of 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. For a description
of the most recent adjustment, see the Utility Regulation - Cost Recovery
Clauses section.
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 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.
See the Utility Regulation - Utility Competition-Gas section.
PGS had over 8,000 transportation customers as of Dec. 31, 2001. PGS
continues to receive its base rate for distribution regardless of whether a
customer decided to opt for transportation-only 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.
7
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 NaturalChoice
Transportation Service (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
delivery by PGS to its customers.
Gas is delivered by Florida Gas Transmission Company (FGT) through more
than 54 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
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. Several franchises contain purchase options with respect to
the purchase of PGS' property located in the franchise area, if the franchise is
not renewed; otherwise, based on judicial precedent, PGS is able to keep its
facilities in place subject to reasonable rules and regulations imposed by the
municipalities.
PGS' franchise agreements with the incorporated municipalities within its
service area have various expiration dates ranging from September 2002 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 several hearings have been held. 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 proceedings. PGS is continuing
to serve under substantially
8
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
$4.5 million of total revenue to PGS' results in 2001.
Franchise fees payable by PGS, which totaled $8.9 million in 2001, 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 state or county rights-
of-way granted by the Florida Department of Transportation or 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 one of several potentially responsible parties
for certain superfund sites and, through its Peoples Gas System division, for
certain superfund and former manufactured gas plant sites. See the previous
discussion in the Environmental Matters section of Tampa Electric - Electric
Division on page 6.
Expenditures. During the five years ended Dec. 31, 2001, PGS has not
incurred any material capital additions to meet environmental requirements, nor
are any anticipated for 2002 through 2006.
TECO POWER SERVICES
TECO Power Services (TPS) through its subsidiaries, has 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 309 employees as of Dec. 31, 2001.
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. A 75-megawatt
simple-cycle combustion turbine expansion at the Hardee Power Station was
completed in May 2000. The added capacity from this expansion serves Tampa
Electric through 2012.
In 2000, TPS increased its ownership to 100 percent of Central Generadora
Electrica San Jose, Ltda. (CGSE), the owner of a project located in Guatemala,
which consists of a single-unit pulverized-coal baseload facility (the San Jose
Power Station), including port modifications to accommodate the importation of
coal. This facility is the first coal-fueled plant in Central America and meets
environmental standards set by the World Bank. The San Jose Power Station has a
U.S. dollar-denominated power sales agreement with Empresa Electrica de
Guatemala, S.A. (EEGSA), to provide 120 megawatts of capacity for 15 years
beginning in 2000. Political risk insurance has been obtained for currency
inconvertibility, expropriation and political violence covering up to 100
percent of TPS' equity investment and economic returns.
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 from the Alborada Power Station to EEGSA for a 15-year period ending
in 2010. EEGSA is responsible for providing the fuel for the plant, with TPS
providing assistance in fuel administration. TPS has obtained $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 from
The Overseas Private Investment Corporation (OPIC).
EEGSA is private distribution and generation company formed in 1994 serving
more than 630,000 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.
TM Power Ventures LLC (TMPV) was created by TPS and Mosbacher Power
Partners, Ltd. (Mosbacher Power), an independent power company headquartered in
Houston, 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
9
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.
TPS, through TMPV, has a 95-percent interest in the Commonwealth Chesapeake
Power Station, a 312-megawatt power plant on the Delmarva Peninsula of Virginia.
The first phase of 134 megawatts went into service in the third quarter of 2000,
and the second phase went into service in August 2001.
TPS is a 50-percent owner 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.
In the first quarter of 2001, TPS sold its minority interest in Energia
Global International, Ltd. (EGI), a Bermuda based energy development firm. As
part of the sale TPS took an after tax charge of $6.1 million ($9.3 million pre-
tax), to adjust the asset valuation of this investment.
In September 2000, TPS provided 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 Texas (ERCOT) market. The projects were
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 from GenPower LLC full ownership of two
independent power projects being developed in Arkansas and Mississippi. The
combined capacity of the two projects are planned to be nearly 1,200 megawatts.
TPS' equity investment in the projects is expected to be approximately $412
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. Financing for these plants is expected to be completed in 2002. Dell
and McAdams are expected to begin commercial operations in May 2003.
In November 2000, TPS announced a joint venture with Panda to build, own
and operate two natural gas power plants located in El Dorado, Arkansas and Gila
Bend, Arizona. After taking into account the preferred return, TPS' economic
interest in the project is estimated at 75 percent. The 2,200-megawatt Union
plant in El Dorado, Arkansas 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 also under construction. The first phase is expected to begin
commercial operation in the first quarter of 2003 with commercial operation of
the entire facility in the third quarter of 2003. Electricity from this 2,145-
megawatt plant, which is located southwest of Phoenix, is planned to be sold in
Arizona, southern California, Nevada and New Mexico. In February 2002, TPS
entered into an agreement requiring TPS to purchase 100 percent of the Panda
Partners interest in the joint venture in 2007 unless Panda chooses to remain a
partner by cancelling the agreement and paying a cancellation fee.
In June 2001, TPS and Panda closed on a bank financing for the Union and
Gila River power stations. This $2.175 billion bank financing included $1.675
billion in five-year non-recourse debt and $500 million in equity bridge loans
guaranteed by TECO Energy. Equity contributions from the joint venture, which
TECO Energy has guaranteed, will be required to fund additional construction
costs of up to approximately $657 million. The equity bridge financing must be
repaid in four equal installments coincident with Phase 2 and Phase 4 completion
of each facility, and the equity contributions must be made over the period that
ends with commercial operation of Phase 4 of the projects. The TPS equity
investment in these projects at commercial operation is expected to be
approximately $1.2 billion.
In March 2001, TPS acquired American Electric Power's (AEP) Frontera Power
Station, located near McAllen, Texas. Frontera is a 477-megawatt natural gas-
fired combined-cycle plant. 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. TPS expects to
finance the acquisition in 2002.
The Enron bankruptcy creates uncertainty for four TPS generation projects
because an Enron subsidiary, NEPCO, is the engineering, procurement and
construction (EPC) contractor for the four projects. NEPCO has continued
construction and engineering work on these power plants and currently
construction of all four plants is on schedule. See the discussion in the Enron
Exposure section.
For financial information about geographic areas, see Note K to the
Consolidated Financial Statements.
See the discussion of the risks applicable to TPS in the Investment
Considerations section.
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 TECO Ocean Shipping, Inc. (Ocean Shipping, previously
Gulfcoast Transit Company), TECO Barge Line, Inc. (TECO Barge, previously Mid-
South Towing Company), TECO Bulk Terminal, LLC (Bulk
10
Terminal, previously Electro-Coal Transfer, LLC) and TECO Towing Company. TECO
Transport currently owns no operating assets.
TECO Transport and its subsidiaries had 1,066 employees as of Dec. 31,
2001.
TECO Transport's subsidiaries perform substantial services for Tampa
Electric. In 2001, approximately 55 percent of TECO Transport's revenues were
from third-party customers and 45 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 and international movements of other
dry-bulk commodities and domestic phosphate movements. 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, coal
and petroleum coke customers, and participation in the U.S. Department of
Agriculture's cargo preference program.
Ocean Shipping transports products in the Gulf of Mexico and worldwide, and
TECO Barge operates on the Mississippi, Ohio and Illinois rivers and their
tributaries. 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. Ocean Shipping
is the largest US flag coastwise bulk operator based on capacity, while Teco
Barge is in the top ten based on number of barges of companies in its business.
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.
Bulk Terminal operates the largest 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 three other land-based terminals.
Competition within TECO Transports markets is based primarily on geographic
markets served, pricing, and service level. The majority of the ocean and all of
the river business is subject to the Jones Act which prohibits the use of non-US
flag vessels for movement between US ports.
The business of TECO Transport's subsidiaries, taken as a whole, is not
subject to significant seasonal fluctuation, but is sensitive to economic
conditions.
The Interstate Commerce Act exempts from regulation water transportation of
certain dry-bulk commodities. In 2001, 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
2001, TECO Transport spent $.1 million for environmental compliance.
Environmental expenditures are estimated at $.3 million in 2002, primarily for
work on solid waste disposal and storm water drainage at the Bulk Terminal
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 594 employees as of Dec. 31, 2001.
In 2001, TECO Coal subsidiaries sold 10.1 million tons of coal, with
approximately 99 percent, or 9.9 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, 3.2 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 produced and sold 2.3 million
tons of coal in 2001.
In January 2000, TECO Coal purchased synthetic fuel (synfuel) facilities
which were relocated to the Premier Elkhorn and Clintwood Elkhorn mines. The
3.2 million tons of synfuel produced in 2001 replaced some of TECO Coal's
conventional coal production in 2001. Synthetic fuel production for 2002 is
expected to increase modestly from 2001 levels. 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. TECO Coal received a Private Letter Ruling from the Internal
Revenue Service confirming that the facilities produce a qualified fuel eligible
for Section 29 tax credits available for the production of such non-conventional
fuels.
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
11
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 2001,
approximately $3.7 million was spent on environmental protection and reclamation
programs. TECO Coal expects to spend a similar amount in 2002 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
of underground and surface coal mined, respectively, to create a fund for
reclaiming land and water adversely affected by past coal mining. Other
provisions establish standards for the control of environmental effects and
reclamation of surface coal mining and the surface effects of underground coal
mining and requirements for federal and state inspections.
TECO 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 2001, TECO Coalbed
Methane had interests in 743 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 fuels 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 2001, domestic oil prices did not exceed the
$48 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 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), Prior Energy
Corporation (Prior Energy), TECO Gas Services, Inc. (TECO Gas Services), TECO
Properties, TECO Propane Ventures (TPV) and TECO Partners, with total employees
of 706 as of Dec. 31, 2001.
TECO BGA is an engineering energy services company headquartered in Tampa.
It has 9 offices in Florida and one in California. It provides engineering,
construction management and energy services to more than 300 customers,
including public schools, universities, health care facilities and other
governmental facilities throughout Florida and California. In 2001, BGA
increased its presence in the south Florida market with an asset acquisition of
an energy services division of AMSI, Inc., and the acquisition of a district
cooling business from FPL Energy Services.
BCH is a mechanical contracting firm headquartered in Largo, Florida, and
has offices in Cocoa Beach and Ft. Lauderdale. 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 2000.
In 2001, TECO Solutions acquired Prior Energy. Prior Energy, established
in 1987, handles all facets of natural gas energy management services, including
natural gas supply management, transportation management, asset management and
consulting services. Prior Energy services customers throughout the Southeast
Prior Energy is headquartered in Mobile, Alabama.
TECO Gas Services provides gas management and marketing services similar to
Prior Energy for large municipal, industrial, commercial and cogeneration
facilities. TECO Gas Services has provided 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. TECO Gas
Services owns no operating assets.
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 which was the largest independent propane distributor in
Florida. In 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. Later in 2000, US Propane combined 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.
12
Under the agreements, US Propane sold its propane business to Heritage
Propane for approximately $181 million in cash and limited partnership units in
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 transactions, 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. TPV has a 38 percent interest in the general partner that
manages Heritage Propane Partners. After Heritage Propane Partners issued new
equity to the public in 2001, US Propane continued to own all of the general
partner interest and its limited partner interest was reduced to 29 percent.
TPV 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, 2001, Tampa Electric had five electric generating plants and
four combustion turbine units in service with a total net winter generating
capability of 3,899 megawatts, including Big Bend (1,825-MW capability from four
coal units), Gannon (1,220-MW capability from six coal units), Hookers Point
(90-MW capability from five oil units), Phillips (36-MW capability from two
diesel units), Polk (315-MW capability from one integrated gasification combined
cycle (IGCC) unit) and four combustion turbine units located at the Big Bend,
Polk and Gannon stations (357 MWs). Additionally, Tampa Electric has 56-MW of
generating capability from various distributive generation units located at
Hookers Point and the City of Tampa. 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 2000 (see the
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 186 substations having an aggregate transformer
capacity of 17,216,269 KVA. The transmission system consists of approximately
1,210 pole miles of high voltage transmission lines, and the distribution system
consists of 6,987 pole miles of overhead lines and 3,030 trench miles of
underground lines. As of Dec. 31, 2001, there were 583,942 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.
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 13,400 miles of pipe, including approximately
9,000 miles of mains and over 4,400 miles of service lines. Mains and service
lines are maintained under rights-of-way, franchises or permits.
PGS' operating divisions are located in fourteen markets throughout
Florida. While most of the operations, storage and administrative facilities are
owned, a small number are leased.
TECO POWER SERVICES
13
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.
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.
Frontera Generation L.P. owns 40 acres of land in Hidalgo County, Texas on
which the 477-megawatt gas-fired combined cycle electric generation plant is
located.
TPS has a 50% ownership interest in TECO-Panda Generating Company, LP,
which owns two projects: Union Power Partners LP and Panda Gila River, LP.
Union Power Partners owns 330 acres of land in Union County, Arkansas, on which
the approximately 2200 MW gas-fired combined-cycle electric generation plant is
under construction. Panda Gila River, LP owns approximately 1,099 acres of land
in Maricopa County, Arizona, on which the approximately 2145 MW gas-fired
combined-cycle electric generation plant is under construction.
TECO TRANSPORT
TECO Bulk Terminal's storage and transfer terminal is on a 1,070-acre site
fronting on the Mississippi River, approximately 40 miles south of New Orleans.
Bulk Terminal owns 342 of these acres in fee, with the remainder held under
long-term leases.
TECO Barge operates a fleet of 18 towboats and over 710 river barges, over
70 percent 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. TECO Barge 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, TECO Barge performs fleeting and supply activities at leased
facilities in Cairo, Illinois.
As of Dec. 31, 2001, 33,500 short ton Ocean Shipping owned and operated a
fleet of 12 ocean-going tug/barge units, a ocean-going ship, a 40,900 short ton
ocean-going ship, and a 41,100 short ton ocean-going ship, with a combined cargo
capacity of over 450,000 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 90 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 38 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
14
proven reserves. Perry County owns and operates a coal preparation plant and
rail tipple facilities.
15
TECO COALBED METHANE
TECO Coalbed Methane has majority ownership interests and royalty interests
in proven gas reserves which at Dec. 31, 2001 was independently estimated to be
167 billion cubic feet for 682 economically feasible wells.
TECO Coalbed Methane's gas production for 2001 was 15.0 billion cubic feet.
Item 3. LEGAL PROCEEDINGS.
None.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matter was submitted during the fourth quarter of 2001 to a vote of TECO
Energy's security holders, through the solicitation of proxies or otherwise.
16
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 57 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. (diversified energy company),
Fairfax, Virginia.
William N. Cantrell 49 President of TECO Solutions, September 2000 to
date and President of Peoples Gas System June
1997 to date; Director of Peoples Gas Transition
Team, January 1997 to June 1997.
Royston K. Eustace 60 Senior Vice President-Business Development, April
1998 to date; and prior thereto, Vice President-
Strategic Planning and Business Development.
Gordon L. Gillette 42 Senior Vice President-Finance and Chief Financial
Officer, April 2001 to date; Vice President-
Finance and Chief Financial Officer, April 1998
to April 2001; Vice President-Regulatory Affairs,
April 1997 to April 1998; Vice President-
Regulatory and Business Strategy of Tampa
Electric Company, April 1996 to April 1997.
Richard Lehfeldt 50 Senior Vice President-External Affairs, November
1999 to date; and prior thereto, Vice President
and Assistant General Counsel of Edison Mission
Energy (independent power company), Irvine,
California.
Richard E. Ludwig 56 President of TECO Power Services Corporation,
1992 to date.
Sheila M. McDevitt 55 Senior Vice President-General Counsel, April 2001
to date; Vice President-General Counsel, January
1999 to April 2001; and prior thereto, Vice
President-Assistant General Counsel.
John B. Ramil 46 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 55 President of TECO Transport Corporation, October
1987 to date.
J. J. Shackleford 55 President of TECO Coal, March 1986 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
17, 2002, and until such officer's successor is elected and qualified.
17
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
------- ------- ------- -------
2001
----
High $32.125 $32.970 $31.650 $28.300
Low $26.100 $28.780 $25.530 $24.750
Close $29.960 $30.500 $27.100 $26.240
Dividend $ 0.335 $ 0.345 $ 0.345 $ 0.345
2000
----
High $20.625 $23.125 $28.750 $33.188
Low $17.250 $19.188 $20.188 $26.563
Close $19.438 $20.063 $28.750 $32.375
Dividend $ 0.325 $ 0.335 $ 0.335 $ 0.335
___________________
The approximate number of shareholders of record of common stock of TECO
Energy as of Feb. 28, 2002 was 22,989.
TECO Energy's primary source of funds to pay dividends to its common
stockholders 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 2001.
In addition, if TECO Energy exercises its rights to defer payments on its
subordinated notes issued in connection with the issuances of trust preferred
securities by TECO Capital Trust I and II, TECO Energy will be prohibited from
paying cash dividends on its common stock until the unpaid distributions on the
subordinated notes are made.
18
- --------------------------------------------------------------------------------
Item 6. SELECTED FINANCIAL DATA
- ------------------------------------------------------------------------------------------------------------------------------------
(Millions, except per
share amounts) Year ended Dec. 31, 2001 2000 1999 1998 1997
-------------------------------------------------------------------------------------------------------------
Revenues $ 2,648.6 $ 2,294.6 $ 1,978.3 $ 1,950.7 $ 1,858.0
Net income from continuing operations $ 303.7 $ 250.9 $ 200.9 (1) $ 204.2 (2) $ 211.5 (3)
Net loss from discontinued operations -- -- (2.5) (3.8) (6.6)
Gain (loss) on disposal of discontinued
operations -- -- (12.3) 6.1 (3.0)
-------------------------------------------------------------------------------------------------------------
Net income $ 303.7 $ 250.9 $ 186.1 (1) $ 206.5 (2) $ 201.9 (3)
-------------------------------------------------------------------------------------------------------------
Total assets $ 6,722.1 $ 5,734.3 $ 4,690.1 $ 4,179.3 $ 3,960.4
Long-term debt $ 1,842.5 $ 1,374.6 $ 1,207.8 $ 1,279.6 $ 1,080.2
Earnings per share (EPS) - basic
From continuing operations $ 2.26 $ 1.99 $ 1.53 (1) $ 1.55 (2) $ 1.62 (3)
From discontinued operations -- -- (0.02) (.03) (0.05)
Disposal of discontinued operations -- -- (0.09) .05 (0.03)
-------------------------------------------------------------------------------------------------------------
EPS basis $ 2.26 $ 1.99 $ 1.42 (1) $ 1.57 (2) $ 1.54 (3)
-------------------------------------------------------------------------------------------------------------
Dividends paid per common share/(4)/ $ 1.37 $ 1.33 $ 1.285 $ 1.225 $ 1.165
- ------------------------------------------------------------------------------------------------------------------------------------
(1) Includes the effect of charges discussed in Note L, which reduced net income
by $19.6 million and earnings per share by $0.15 in 1999.
(2) Includes the effect of charges, 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) Dividend paid on TECO Energy common stock.
- --------------------------------------------------------------------------------
Item 7. MANAGEMENT'S DISCUSSION & ANALYSIS OF FINANCIAL CONDITION & 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. Any forward-looking
statement speaks only as of the date on which it was made, and the company
undertakes no obligation to update any forward-looking statement to reflect
subsequent developments or circumstances other than as may be required by law.
- --------------------------------------------------------------------------------
FINANCIAL SUMMARY
TECO Energy's revenues increased by 15% in 2001 to $2.6 billion; revenues
in 2000 increased 16% to $2.3 billion. Basic earnings were $2.26 per share in
2001 compared with $1.99 per share in 2000. Earnings were $1.42 per share in
1999, which included charges of $.11 per share for discontinued operations.
- ------------------------------------------------------------------------------------------------------------------------------------
2001 Change 2000 Change 1999(3)
- ------------------------------------------------------------------------------------------------------------------------------------
Consolidated revenues (millions) $ 2,648.6 15.4% $ 2,294.6 16.0% $ 1,978.3
- ------------------------------------------------------------------------------------------------------------------------------------
Earnings per share - basic Continuing operations $ 2.26 13.6% $ 1.99 30.1% $ 1.53
Discontinued operations -- -- -- -- (.11)
---------------------------------------------------------------------------------------------
Earnings per share $ 2.26 13.6% $ 1.99 40.1% $ 1.42
====================================================================================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
Earnings per share - diluted Continuing operations $ 2.24 13.7% $ 1.97 28.8% $ 1.53
Discontinued operations -- -- -- -- (.11)
---------------------------------------------------------------------------------------------
Earnings per share $ 2.24 13.7% $ 1.97 38.7% $ 1.42
====================================================================================================================================
- ------------------------------------------------------------------------------------------------------------------------------------
Net income from continuing operations (millions) $ 303.7 21.0% $ 250.9 24.9% $ 200.9
- ------------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------------
Average common shares outstanding Basic (millions) 134.5 (2) 6.8% 125.9 (1) - 3.9% 131.0 (1)
Diluted (millions) 135.4 (2) 7.2% 126.3 (1) - 3.7% 131.2 (1)
- ------------------------------------------------------------------------------------------------------------------------------------
Return on average common equity from continuing operations
Including charges 17.0% 16.6% 13.3%
Without charges 17.0% 16.6% 14.5%
====================================================================================================================================
(1) Average shares outstanding reflects the repurchase of 1.6 million shares
in 2000 and 5.4 million shares between September and December 31, 1999.
(2) Average shares outstanding for 2001 reflects the issuance of 8.625
million shares in March and 3.5 million shares in October.
(3) Earnings in 1999 were affected by certain events and adjustments that
were unusual in nature and resulted in charges that are not expected to
recur in future periods. These charges are described in the Non-Operating
Items Impacting Net Income section.
15
- -------------------------------------------------------------------------------
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 businesses at TECO Solutions; to grow its TECO Power
Services (TPS) independent power operations; and to use the returns of its
family of other profitable unregulated businesses to continue its growth.
Execution of this strategy has allowed TECO Energy to achieve earnings per
share growth of 14 percent in 2001 and 18 percent in 2000 from continuing
operations, excluding charges in 1999. In January 2002, management stated that
2002 is a transition year with the focus on completing the four independent
power projects currently under construction at TPS and the first phase of the
Gannon to Bayside repowering project at Tampa Electric. It indicated at that
time that earnings per share growth for 2002, targeted at 5 percent, is expected
to be driven by continued growth from the Florida operations, a return to more
normal shipping patterns at TECO Transport, higher earnings from improved
pricing and higher production at TECO Coal, and a full year of operations from
capacity additions during 2001 at TPS.
TECO Energy benefits from deriving the majority of net income from its
regulated businesses, Tampa Electric and PGS, operating in one of the best
utility markets in the nation. Growth is expected in Florida in 2002 because the
State's economy with its small industrial base is not expected to be impacted by
the economic slowdown to the same degree as some other areas of the country that
are based on manufacturing. Growth is expected in the residential and commercial
sectors in 2002 and beyond.
In 2003, a significant earnings driver will be the four new independent
power projects that TPS announced in late 2000 which are expected to be placed
in service in 2003. These projects have increased the number of net megawatts
operating or under construction from approximately 1,000 megawatts at the end of
1999 to almost 6,600 megawatts at the end of 2001.
In 2001, future wholesale power prices declined significantly in markets
across the country due to the combination of the U.S. economic slowdown and the
amount of new generating capacity under construction and expected to come online
in 2002 and 2003. The outlook for weaker earnings from new independent power
projects, however, has caused some developers to cancel or delay projects. While
future wholesale power prices have declined, TPS expects to enter into
negotiated contracts for much of the output of its facilities at higher prices,
reflecting the value-added services it can provide. TECO Energy remains
committed to the completion of the four projects under construction by TPS. See
Operating Results - TECO Power Services for a current schedule of in-service
dates for these projects.
In light of the capital requirements for committed regulated and
unregulated projects and the accelerated project equity commitments for the
Union and Gila River projects under the bank financing plan at TPS (see Enron
Exposure section), TECO Energy has taken several steps to strengthen its balance
sheet. During 2001, the company issued new common equity on two occasions
totaling $331 million of proceeds. In January 2002, the company issued $449
million of mandatorily convertible equity units which will convert to TECO
Energy common shares in January 2005. (See Financing Activity section.) In
addition, the company has reduced its capital expenditure forecast for 2002
through 2004 by approximately $700 million, primarily by delaying for an
extended period generation projects that are not yet under construction for TPS
and Tampa Electric, including the Bayside Units 3 and 4 repowering projects
announced in the fall of 2001. Resumption of work on those projects will be
evaluated periodically as market conditions evolve.
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 estimated 2.3 percent and 5 percent rates of customer growth,
respectively. Earnings growth in 2002 is expected to be driven by higher AFUDC
associated with the Gannon to Bayside repowering project and energy sales growth
at Tampa Electric, which is expected to exceed customer growth due to a more
favorable customer mix.
At TPS in 2002, growth is expected from a full-year of operations of both
the Frontera Power Station in Texas and Phase II of the Commonwealth Chesapeake
Power Station in Virginia. In addition, TPS' 2001 results included a $6.1
million charge associated with the termination of its investment in EGI. (See
Operating Results - TECO Power Services section.)
At TECO Transport, earnings growth in 2002 is expected from increased
phosphate shipments and a return to a more normal pattern for U.S. government
grain shipments. Long-term growth is expected from increased asset utilization,
particularly at TECO Barge Line (formerly known as Mid-South Towing), and asset
additions at both TECO Ocean Shipping (formerly known as Gulfcoast Transit) and
TECO Barge Line.
TECO Coal expects to benefit primarily from improved prices for steam and
metallurgical coals and modestly higher production of synthetic fuel and coal in
2002. Production of synthetic fuel at TECO Coal qualifies for Section 29 tax
credits for non-conventional fuel production.
The company expects higher borrowing levels in 2002 associated primarily
with the TPS generation projects and the Gannon to Bayside repowering project at
Tampa Electric.
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.)
- -------------------------------------------------------------------------------
CRITICAL ACCOUNTING POLICIES
Management's Discussion and Analysis of Financial Condition & Results of
Operations are based on TECO Energy's consolidated financial statements, which
have been prepared in accordance with United States generally accepted
accounting principles. The preparation of these financial statements requires
management to make estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues and expenses. These estimates and assumptions are
based on historical experience and on various other factors that are believed to
be reasonable under the circumstances, the results of which form the basis for
making judgments about the carrying values of assets and liabilities that are
not readily apparent from other sources. Actual results may differ from these
estimates and judgments under different assumptions or conditions.
The following critical accounting policies, among others discussed
throughout the Management's Discussion and Analysis and the Notes to the
Consolidated Financial Statements, involve the more significant estimates and
judgments used in the preparation of TECO Energy's consolidated financial
statements.
Revenue Recognition
TECO Energy and its subsidiaries recognize revenues in accordance with the
Securities and Exchange Commission's Staff Accounting Bulletin (SAB) 101,
Revenue Recognition in Financial Statements. Generally, TECO Energy and its
subsidiaries recognize revenues when earned, and the risks and rewards of
ownership have transferred to the buyer.
The regulated utilities' retail business and the prices charged to
customers are regulated by the Florida Public Service Commission (FPSC); Tampa
Electric's wholesale business is regulated by the Federal Energy Regulatory
Commission (FERC) (see the Utility Regulation section). As a result, the
regulated utilities qualify for the application of Financial Accounting Standard
(FAS) 71, Accounting for the Effects of Certain Types of Regulation. This
statement recognizes that the rate actions of a regulator can provide reasonable
assurance of the existence of an asset and requires the capitalization of
incurred costs that would otherwise be charged to expense where it is probable
that future revenue will be provided to recover these costs. The impact of FAS
71 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. The assumptions and judgments used by regulatory
authorities continue to have an impact on the recovery of costs, the rate earned
on invested capital and the timing and amount of assets to be recovered by
rates.
Deferred Income Taxes
TECO Energy uses the liability method in the measurement of deferred income
taxes. Under the liability method, the company estimates its current tax
exposure and assesses the temporary differences resulting from differing
treatment of items, such as depreciation, for financial statement and tax
purposes. These differences are reported as deferred taxes measured at current
rates in the consolidated financial statements. The company then assesses the
likelihood that deferred tax assets will be recovered from future taxable income
and to the extent recovery of some portion or all of the deferred tax asset is
not believed to be likely, establishes a valuation allowance.
At Dec. 31, 2001, TECO Energy had deferred income tax assets of $242
million attributable primarily to alternative minimum tax credit carryover of
Sec. 29 non-conventional fuel credits and property related items. The carrying
value of the Company's deferred income tax assets assumes that the Company will
be able to realize this asset as an offset to future income taxes payable. The
Company periodically reviews its deferred income tax assets and, to the extent
it determines that recovery is not likely, increases its valuation reserve as a
charge to income.
Derivative Instruments and Hedging
Effective Jan. 1, 2001, the company adopted FAS 133, Accounting for
Derivative Instruments and Hedging Activities. As discussed in the Accounting
Standards section, FAS 133 requires the company to recognize derivatives as
either assets or liabilities in the financial statements, to measure these
instruments at fair value, and to reflect the changes in fair value of those
instruments as components of comprehensive income or in net income. The
determination of fair value is dependent upon certain assumptions and judgments.
The methods used to determine fair value are also discussed in the Accounting
Standards section. The Company's fair value determination assumptions are
primarily based on regulated exchange based prices.
In addition, the company has certain derivative transactions that are
marked-to-market under the Financial Accounting Standards Board's (FASB)
Emerging Issues Task Force (EITF) release Issue 98-10, Accounting for Contracts
Involved in Energy Trading and Risk Management Activities. These transactions
are also discussed in the Accounting Standards section.
Impairment Testing
TECO Energy and its subsidiaries periodically assess whether there has been
a permanent impairment of its long-lived assets in accordance with FAS 121,
Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be
Disposed of, and beginning in 2002, with FAS 144, Accounting for the Impairment
or Disposal of Long-Lived Assets. Long-lived assets are tested for impairment
periodically using a non-discounted cash flow test. Tests are also performed
when industry, regulatory or other significant changes cause a change in the
projected level of income or cash flow to be earned from an asset.
In June 2001, the Financial Accounting Standards Board issued FAS 142,
Goodwill and Other Intangible Assets. With the adoption of FAS 142, effective
Jan. 1, 2002, goodwill is no longer subject to amortization, however goodwill
and other intangible assets are subject to annual assessments for impairment by
applying fair-value-based tests.
FAS 144 and FAS 142 are discussed in the Accounting Standards section.
As discussed below under Enron Exposure, certain of the Company's assets
are affected by the Enron bankruptcy. The Company does not presently anticipate
any material asset impairment charges as a result of its Enron exposure, but
subsequent developments could affect this judgment.
Unconsolidated Affiliates
The Company has investments in unconsolidated affiliates that are accounted
for using the equity method of accounting as discussed in Note A to the
Consolidated Financial Statements. 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 a majority ownership or exercise control.
Future changes in accounting standards regarding consolidations or changes in
the nature of the Company's investment in the unconsolidated affiliates could
result in these investments being consolidated, with resulting impact on the
Company's recorded assets and liabilities, and on its results of operations.
OPERATING RESULTS
TECO Energy's Net Income
Net income in 2001 was $303.7 million, up 21 percent from $250.9 million in
2000. These results reflect continued customer growth and increased energy usage
in the Florida operations, higher AFUDC at Tampa Electric, an 18 percent
increase in net income at TPS from the new generation projects acquired or
brought on line in 2000 and 2001 and improved results from the Guatemalan
operations, higher average gas price at TECO Coalbed Methane, and higher
conventional coal production and prices and increased synthetic fuel production
at TECO Coal. These improvements were partially offset by higher interest
expense associated with increased borrowing levels.
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. These
improvements were partially offset by higher interest expense associated with
increased borrowing levels.
The following table shows the unconsolidated revenues, net income and
earnings per share contribution from continuing operations of the significant
business segments, excluding charges in 1999 described in the Non-Operating
Items Impacting Net Income section. (For additional detail, refer to the Notes
to Consolidated Financial Statements -Footnote K, Segment Information.)
16
- -----------------------------------------------------------------------------------------------
CONTRIBUTIONS BY OPERATING GROUP (unconsolidated)
- -----------------------------------------------------------------------------------------------
(millions) 2001 Change 2000 Change 1999
- -----------------------------------------------------------------------------------------------
Revenues
Regulated companies
Tampa Electric $1,412.7 4.3% $1,353.8 12.8% $ 1,199.8 (1)
Peoples Gas System 352.9 12.2% 314.5 24.9% 251.7
- -----------------------------------------------------------------------------------------------
Total Regulated $1,765.6 5.8% $1,668.3 14.9% $ 1,451.5
- -----------------------------------------------------------------------------------------------
Unregulated companies
TECO Power Services $ 287.1 44.3% $ 199.0 86.3% $ 106.8
TECO Transport 274.9 1.9% 269.8 7.1% 251.9
TECO Coal 303.4 30.3% 232.8 -1.9% 237.3
Other unregulated businesses 267.2 74.2% 153.4 42.3% 107.8
- -----------------------------------------------------------------------------------------------
Total Unregulated $1,132.6 32.5% $ 855.0 21.5% $ 703.8
- -----------------------------------------------------------------------------------------------
Net Income (2)(3)
Regulated companies
Tampa Electric $ 154.0 6.6% $ 144.5 4.1% $ 138.8
Peoples Gas System 23.1 6.0% 21.8 10.1% 19.8
- -----------------------------------------------------------------------------------------------
Total Regulated $ 177.1 6.5% $ 166.3 4.9% $ 158.6
- -----------------------------------------------------------------------------------------------
Unregulated companies
TECO Power Services $ 26.9 18.0% $ 22.8 145.2% $ 9.3
TECO Transport 27.5 -5.8% 29.2 11.4% 26.2
TECO Coal 59.0 76.1% 33.5 157.7% 13.0
Other unregulated businesses 35.1 24.9% 28.1 18.6% 23.7
- -----------------------------------------------------------------------------------------------
Total Unregulated $ 148.5 30.7% $ 113.6 57.3% $ 72.2
- -----------------------------------------------------------------------------------------------
Financing/Other $ (21.9) 24.4% $ (29.0) -181.6% $ (10.3)
- -----------------------------------------------------------------------------------------------
Net Income Total $ 303.7 21.0% $ 250.9 13.8% $ 220.5
- -----------------------------------------------------------------------------------------------
Earnings per Share - Basic (2)
Regulated companies
Tampa Electric $ 1.15 -- $ 1.15 9.5% $ 1.05
Peoples Gas System .17 -- .17 13.3% .15
- -----------------------------------------------------------------------------------------------
Total Regulated 1.32 -- 1.32 10.0% 1.20
- -----------------------------------------------------------------------------------------------
Unregulated companies
TECO Power Services .20 11.1% .18 157.1% .07
TECO Transport .20 -13.0% .23 15.0% .20
TECO Coal .44 63.0% .27 170.0% .10
Other unregulated businesses .26 18.2% .22 22.2% .18
- -----------------------------------------------------------------------------------------------
Total Unregulated $ 1.10 22.2% $ .90 63.6% $ .55
- -----------------------------------------------------------------------------------------------
Financing/Other $ (.16) 30.4% $ (.23) -228.6% $ (.07)
- -----------------------------------------------------------------------------------------------
EPS from continuing operation,
before charges $ 2.26 13.6% $ 1.99 18.4% $ 1.68
- -----------------------------------------------------------------------------------------------
Non-operating items impacting
net income -- -- -- -- (.15)
- -----------------------------------------------------------------------------------------------
EPS from continuing operations $ 2.26 13.6% $ 1.99 30.1% $ 1.53
- -----------------------------------------------------------------------------------------------
(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 Non-Operating
Items Impacting Net Income section.
(2) From continuing operations, excluding the charges described in the Non-
Operating Items Impacting Net Income section.
(3) Beginning in 2001, segment net income was reported on a basis that included
internally allocated financing costs. Prior period net income has been
restated to reflect estimated internally allocated financing costs that
would have been attributable to such prior periods. Internally allocated
finance costs for 2001, 2000 and 1999 were at pretax rates of 7%, 6.75% and
6.75%, respectively, based on the average investment in each subsidiary.
- --------------------------------------------------------------------------------
TAMPA ELECTRIC - ELECTRIC OPERATIONS
Tampa Electric Results
Tampa Electric's net income increased almost 7 percent in 2001, reflecting
good customer growth, slightly higher residential and commercial per-customer
energy usage, and a favorable customer mix partially offset by higher
operations, maintenance and depreciation expenses. In addition, allowance for
funds used during construction (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),
primarily from the Gannon to Bayside Units 1 and 2 repowering project increased
to $9.2 million compared with $2.3 million in 2000.
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 2 in service.
- -------------------------------------------------------------------------------
SUMMARY OF OPERATING RESULTS
- -------------------------------------------------------------------------------
(millions) 2001 Change 2000 Change 1999
- -------------------------------------------------------------------------------
Revenues $1,412.7 4.3% $1,353.8 12.8% $ 1,199.8 (1)
Operating expenses 1,124.6 6.1% 1,060.3 13.3% 935.9
- -------------------------------------------------------------------------------
Operating income $ 288.1 -1.9% $ 293.5 11.2% $ 263.9
- -------------------------------------------------------------------------------
Net Income $ 154.0 6.6% $ 144.5 4.1% $ 138.8
- -------------------------------------------------------------------------------
(1) Includes $11.9 million of deferred revenues. This amount is before the $7.9-
million deferred revenue benefit recognized under the regulatory agreements
in place at that time related to the charge for tax settlements, described
in the Non-Operating Items Impacting Net Income section.
Tampa Electric Operating Revenues
The economy in Tampa Electric's service area continued to grow in 2001, with
increased employment from the local economy aided by corporate relocations and
expansions. The Tampa metropolitan area's employment grew 2 percent in 2001,
ranking it first in job growth among metropolitan areas in a study by the U.S.
Department of Labor.
The economy slowed somewhat in the second half of the year as the U.S.
economic slowdown impacted the area. The unemployment rate rose to 4.0 percent
in December 2001, from a low of 2.4 percent in December 2000, compared to 5.7
percent for the State of Florida and 5.8 percent for the nation. This trend was
accelerated by a marked slowdown in tourism-related businesses following
September 11th. The impact on Tampa Electric's sales was minimal, because the
areas served are not as sensitive to changes in the tourist industry as some
other areas of the state.
Retail megawatt sales rose 2 percent in 2001 primarily from increased
residential and commercial sales from higher numbers of customers and slightly
higher per-customer usage. Combined residential and commercial customer growth
was 2.8 percent with combined energy usage growing 2.9 percent.
Sales to the low-margin industrial customers in the phosphate industry
declined 10.9 percent due to temporary facility closures during the year and the
permanent closure of one facility. The phosphate industry experienced its second
year of a worldwide slowdown due to over capacity and reduced usage. Late in the
year there was an increase in demand from these customers as demand for
phosphate fertilizers increased overseas and some previously idled facilities
were returned to service. According to phosphate industry sources, the market is
expected to improve modestly in 2002 with stable domestic prices and increased
fertilizer demand primarily in China. Revenues from phosphate sales represented
slightly less than 3 percent of base revenues in 2001 and 2000. Non-phosphate
industrial sales increased in 2001 and 2000, primarily reflecting continued
economic growth in the area.
Sales to other utilities for resale declined in 2001 primarily as a result of
lower coal-fired
17
generating unit availability due to higher planned maintenance outages.
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. In 2000, combined residential and commercial
megawatt sales increased 5 percent from the addition of more the 16,000 new
customers and a return to more normal weather.
Based on expected growth reflecting continued population increases and
business expansion, Tampa Electric expects retail energy sales growth of
approximately 2.6 percent annually over the next five years, with combined
energy sales growth in the residential and commercial sectors of more than 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 even in
the current national economic climate, normal weather and certain other factors.
(See the Investment Considerations section.)
- --------------------------------------------------------------------------------
MEGAWATT-HOUR SALES
- --------------------------------------------------------------------------------
(thousands) 2001 Change 2000 Change 1999
- --------------------------------------------------------------------------------
Residential 7,594 3.1% 7,369 5.8% 6,967
Commercial 5,685 2.6% 5,541 3.8% 5,336
Industrial 2,329 -2.6% 2,390 7.5% 2,224
Other 1,368 2.2% 1,338 4.7% 1,278
- --------------------------------------------------------------------------------
Total retail 16,976 2.0% 16,638 5.3% 15,805
Sales for resale 1,499 -41.5% 2,564 18.7% 2,160
- --------------------------------------------------------------------------------
Total energy sold 18,475 -3.8% 19,202 6.9% 17,965
- --------------------------------------------------------------------------------
Retail customers (average) 575.8 2.8% 560.1 3.0% 543.7
- --------------------------------------------------------------------------------
Tampa Electric Operating Expense
Operating expenses increased 6 percent in 2001, reflecting higher fuel costs
from higher coal prices, increased purchased power costs due to lower unit
availability, higher maintenance expenses associated with increased planned
outages on coal-fired generating units, and higher depreciation from normal
plant additions to serve increased numbers of customers.
Operating expenses increased 13 percent in 2000 reflecting increased costs
associated with the Big Bend Units 1 and 2 flue gas desulfurization system
placed in service in December 1999, the expiration of the U.S. Department of
Energy (DOE) credits for Polk Unit 1 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.)
Non-fuel operations and maintenance expenses in 2002 are expected to increase
at a rate slightly above inflation primarily due to increased costs associated
with health care benefits.
- --------------------------------------------------------------------------------
OPERATING EXPENSES
- --------------------------------------------------------------------------------
(millions) 2001 Change 2000 Change 1999
- -------------------------------------------------------------------------------
Other operating expenses $ 190.7 1.3% $188.3 15.1% $ 163.6
Maintenance 99.5 3.5% 96.1 10.3% 87.1
Depreciation 173.4 7.3% 161.6 9.5% 147.6
Taxes, other than income 104.8 6.2% 98.7 -0.1% 98.8
- -------------------------------------------------------------------------------
Non-fuel operating expenses 568.4 4.4% 544.7 9.6% 497.1
- -------------------------------------------------------------------------------
Fuel 346.5 7.1% 323.5 6.4% 304.0
Purchased power 209.7 9.2% 192.1 42.5% 134.8
- -------------------------------------------------------------------------------
Total fuel expense 556.2 7.9% 515.6 17.5% 438.8
- -------------------------------------------------------------------------------
Total operating expenses $1,124.6 6.1% $1,060.3 13.3% $ 935.9
- -------------------------------------------------------------------------------
Depreciation expense increased in both 2001 and 2000 reflecting normal plant
additions to serve the growing customer base and maintain generating system
reliability. In addition, Polk Unit 2, a 180-megawatt combustion turbine placed
in service in mid-2000, accelerated depreciation associated with coal-related
assets at the Gannon Station, and a flue gas desulfurization system added in
1999 to serve Big Bend Units 1 and 2 have all increased depreciation.
Depreciation expense is projected to increase in 2002, as well as in the
future from normal plant additions, 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 7 percent in 2001 reflecting primarily increased coal
costs during the year. Coal prices increased early in the year, as did oil and
natural gas. Coal prices have since dropped from the peak prices experienced in
the first quarter but remain above 2000 levels. Average coal costs, on a
cents-per-million Btu basis, increased 7 percent in 2001 after a slight decrease
in 2000.
Fuel costs increased 6 percent in 2000 reflecting increased generation and
increased use of more expensive oil and natural gas at Polk Unit 2, Hookers
Point and combustion turbines at the Big Bend Power Station.
Purchased power expense increased in 2001 due to lower unit availability,
primarily the result of planned maintenance outages on base load generating
units and unplanned outages during peak load periods. Purchased power expense
increased in 2000 due to lower unit availability, primarily the result of a
generator failure at Gannon Unit 6.
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 at Bayside is
scheduled to begin operating on natural gas. See the Environmental Compliance
section. On a total energy supply basis, company generation accounted for 84
percent, 92 percent and 83 percent of the total system energy requirements in
2001, 2000 and 1999, respectively.
________________________________________________________________________________
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 more than 270,000 customers in all of the major metropolitan
areas of Florida.
PGS net income rose 6 percent in 2001 from 4 percent customer growth and
increased gas transported for off-system sales. The high cost of gas earlier in
2001 had a negative impact on sales to larger interruptible and power generation
customers, many of whom have the ability to switch to alternative fuels or to
alter consumption patterns. In the second half of the year, the price
differential between natural gas and alternative fuels once again favored
natural gas, causing customers to return to natural gas as alternative fuel
inventories are exhausted and contractual commitments expire.
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.
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 not previously served and within areas
currently served.
18
- --------------------------------------------------------------------------------
SUMMARY OF OPERATING RESULTS
- --------------------------------------------------------------------------------
(millions) 2001 Change 2000 Change 1999
- --------------------------------------------------------------------------------
Revenues $ 352.9 12.2% $ 314.5 24.9% $ 251.7
Cost of gas sold 186.4 18.7% 157.0 45.8% 107.7
Operating expenses 115.4 4.4% 110.5 9.6% 100.8
- --------------------------------------------------------------------------------
Operating income $ 51.1 8.7% $ 47.0 8.8% $ 43.2
- --------------------------------------------------------------------------------
Net Income $ 23.1 6.0% $ 21.8 10.1% 19.8
- --------------------------------------------------------------------------------
Therms sold (millions) - by customer segment
Residential 58.8 2.1% 57.6 10.6% 52.1
Commercial 308.9 5.8% 292.1 6.8% 273.5
Industrial 346.5 -7.4% 374.1 12.7% 331.9
Power generation 403.5 -3.6% 418.6 3.3% 405.2
- --------------------------------------------------------------------------------
Total 1,117.7 -2.2% 1,142.4 7.5% 1,062.7
- --------------------------------------------------------------------------------
Therms sold (millions) - by sales type
System supply 292.2 -8.9% 320.6 6.9% 300.0
Transportation 825.5 0.4% 821.8 7.7% 762.7
- --------------------------------------------------------------------------------
Total 1,117.7 -2.2% 1,142.4 7.5% 1,062.7
- --------------------------------------------------------------------------------
Customers (thousands) - average 266.6 4.1% 256.2 3.9% 246.7
- --------------------------------------------------------------------------------
Residential and commercial therm sales increased again in 2001 from more than
4 percent residential customer growth and increased per-customer usage.
Commercial therm sales increased primarily from increased per-customer use.
Residential therm sales increased in 2000, the result of 4 percent
residential customer growth and cold weather late in the year. Commercial therm
sales increased in 2000 reflecting good customer growth and a strong economy.
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 early 2001.
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. At year-end 2001, 8,000 customers had elected to take
service under this program. 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.
Operation and maintenance expenses were essentially unchanged from 2000
levels, while depreciation expense increased 8 percent, in line with the
increased capital expenditures that have been made over the past several years
to expand the system. Operating expenses increased in 2000, in line with
customer growth and system expansion.
PGS expects to invest an average of $60 million for each of the next five
years to grow the business and maintain system reliability. PGS expects
increases in sales volumes and corresponding revenues in 2002, and continued
customer additions and related revenues from the expansion efforts throughout
the state.
These growth projections assume continued local area economic growth, normal
weather and other factors. (See the Investment Considerations section.)
- --------------------------------------------------------------------------------
TECO POWER SERVICES
Net income increased 18 percent in 2001 to $26.9 million from higher earnings
from the Hamakua and Commonwealth Chesapeake stations, the Guatemalan generating
stations and higher returns on TPS's investment in the Panda Texas Independent
Energy (TIE) projects. The improved operating performance was partially offset
by weak results at the Frontera Station, which was acquired in 2001, due to low
power prices in the Texas market, increased financing costs, higher development
costs and a $6.1-million after-tax valuation reserve recognized in the sale of
TPS' minority interest in Energia Global International, Ltd. (EGI), which owns
small generating projects in Central America.
In 2000, TPS net income of $22.8 million was more than double the 1999 level
driven by 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 the 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. 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, began commercial
operation in May 2000, and is supplying power to Tampa Electric under a
long-term contract. 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 312-megawatt
Commonwealth Chesapeake electric generating facility in Virginia began
commercial operation in September 2000. The final phase of this project began
commercial service in August 2001.
The Enron bankruptcy creates uncertainty for four TPS generation projects
because an Enron subsidiary, NEPCO, is the engineering, procurement and
construction (EPC) contractor for the four projects. NEPCO has not filed for
bankruptcy, and has continued construction and engineering work on these power
plants and currently the construction of all four plants is on schedule. (See
Enron Exposure section.)
19
- ---------------------------------------------------------------------------------------------------
TPS PROJECT SUMMARY
- ---------------------------------------------------------------------------------------------------
TPS TPS In Service/
Economic Net Participation
Project Location Size MW Interest (%) Size MW Date
- ---------------------------------------------------------------------------------------------------
Operating:
Hardee Power Station Florida 370 100% 370 1/93, 5/00
Alborada Power Station Guatemala 78 96% 75 9/95
Empresa Electrica de
Guatemala S.A.(EEGSA)
(a distribution utility) Guatemala 24% 9/98
San Jose Power Station Guatemala 120 100% 120 1/00
Hamakua Energy Project Hawaii 60 50% 30 8/00, 12/00
Frontera Power Station Texas 477 100% 477 5/00, 3/01
Commonwealth Chesapeake
Power Station Virginia 312 95% 296 9/00, 8/01
Odessa/Guadalupe Texas 2,000 (1) 750 12/00 10/01
- ---------------------------------------------------------------------------------------------------
Sub-total operating 3,417 2,118 MW
- ---------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------
Under Construction:
Dell Arkansas 599 100% 599 1/03
McAdams Mississippi 599 100% 599 1/03
Union Arkansas 2,200 (2) 1,650 4Q02-3/03
Gila River Arizona 2,145 (2) 1,609 2/03-8/03
- ---------------------------------------------------------------------------------------------------
Sub-total construction 5,543 4,457
- ---------------------------------------------------------------------------------------------------
Total 8,960 6,575
- ---------------------------------------------------------------------------------------------------
(1) Currently in the form of a loan, represents the potential economic interest
estimated at 75 percent of Panda's 50-percent interest in these projects.
(2) Based on the effect of the preferred return, estimated at 75 percent over
the life of the project.
Construction and Development Activities
In 2000, TPS refocused its development efforts on domestic energy projects.
During the second half of 2000 and early 2001, TPS announced seven major
projects representing a net ownership interest increase of almost 5,700
megawatts of new capacity operating or under construction. (See the Investment
Considerations section.)
TPS has projects operating or under construction with a net ownership
interest in almost 6,600 megawatts. Upon completion, the domestic projects will
provide TPS with the opportunity to sell wholesale power in 18 states, ranging
from Hawaii to Florida to Virginia. The new projects are in historically high-
growth areas, with good access to fuel supply and electric transmission systems.
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 in the future for an effective economic interest estimated at 75
percent, of Panda's 50-percent interest in these projects (approximately 1,000
MW). The interest earned on the loan to TIE contributed to fourth quarter
earnings in 2000 and full-year earnings in 2001. Under certain circumstances,
among which are additional capital investments by TPS, this loan could give TPS
an ownership interest in these projects in late 2002.
In October 2000, TPS announced the acquisition of two 599-megawatt, natural
gas-fired, combined-cycle projects, Dell and McAdams located in Arkansas and
Mississippi, respectively. Construction commenced on these projects in 2001 and
is continuing. These projects are now expected to begin commercial operation in
the first quarter of 2003. The Dell project was originally scheduled to be
placed in service in the fourth quarter of 2002, but a delay in the completion
of a natural gas compressor station by the pipeline owner has moved the
completion date to early in 2003. The McAdams project was rescheduled to match
the in-service date of the Dell project. These projects are being constructed by
NEPCO and were in the process of being financed with non-recourse project
financing at the time of the Enron bankruptcy. The financing was delayed pending
resolution of the Union and Gila River project funding. (See Enron Exposure
section.) Financing activities for these projects have resumed. TECO Energy has
continued to fund the construction since commencement.
In November 2000, TPS announced a 50/50 joint venture with Panda to build,
own and operate the 2,200-megawatt Union plant (formerly known as El Dorado) in
Arkansas and the 2,145-megawatt Gila River Power Station in Arizona. TPS earns a
preferred return on the investment in these projects, which gives it an
effective economic interest estimated at 75 percent over the life of the
project. Construction commenced on these projects in 2001, and remains on
schedule. Each of these projects will begin commercial operation in four phases,
beginning with the first 550-megawatt phase of Union expected in late 2002 and
ending with the 540-megawatt final phase of Gila River expected in the summer of
2003. The TPS investment in these projects was $624 million at Dec. 31, 2001,
and at commercial operation it is expected to be $1.1 billion. During the
suspension of bank construction funding caused by the Enron Bankruptcy, TECO
Energy continued to fund the construction, which has continued uninterrupted.
NEPCO has not filed for bankruptcy and has continued to perform under the
contracts. (See Enron Exposure Section.) The bank construction funding of these
two plants resumed in mid-January 2002.
In February 2002, the TPS and Panda affiliates that comprise the joint
venture that owns the Union and Gila River projects entered into an arrangement
providing for TPS to purchase and for Panda to sell Panda's interest in the
joint venture in 2007 for $60 million. Panda has the right to cancel the
purchase arrangement by paying TPS $20 million, or a lesser amount under certain
circumstances. The purchase arrangement can result in TPS's purchase of the
interest prior to 2007 under certain circumstances, including Panda's default
under a bank loan made to Panda using the purchase arrangement as collateral.
In March 2001, TPS acquired American Electric Power's (AEP) Frontera Power
Station located near McAllen, Texas. This 477-megawatt, natural gas-fired,
combined-cycle plant, originally developed by CSW Energy (CSW), began combined-
cycle operation in May 2000 and has a 150-megawatt transmission connection to
the Federal Electricity Commission of Mexico (CFE).
In February 1999, TPS formed an alliance with Energia Global International,
Ltd. (EGI), a company with energy interests in Latin America. 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. In
the first quarter 2001, TPS recognized a $6.1 million after-tax charge as part
of the sale of its interest in EGI. The sale was completed, and TPS no longer
has any ownership interest in EGI.
Energy Markets
The power plants that TPS is operating and constructing are located in
markets that have a history of high load growth. In 2001, the general U. S.
economic slowdown and the perception that excess generating capacity is being
built in many of these markets caused future wholesale power prices to drop
significantly. Current forward curve prices for the 2003 period would make the
2003 returns from many of the projects under construction by TPS and others
unattractive. The current forward curve prices represent prices for spot-market
power that a seller would expect to receive if future capacity was sold today
and do not represent the prices that TPS believes would be paid under negotiated
contracts where capacity payments and ancillary services are included and there
is a premium for physical assets. In addition, spot markets setting prices for
power a year in advance of the time of sale are not liquid markets and do not
necessarily provide accurate indications of future power prices.
TPS' strategy for selling the output of these plants is to enter into three
to five year contracts with load serving entities, or ultimate customers where
it is allowed, for up to 50 percent of the
20
output of the plants. TPS expects to contract another 25 percent of the output
in the shorter term (less than one year market) with the remaining 25 percent
sold in the spot market. TPS has retained experienced power marketers, such as
Mirant for Commonwealth Chesapeake and Aquila for the Dell and McAdams stations,
to market the 25 percent of the output planned for the spot market.
To optimize the value of the generating assets TPS in 2001, activated its
TECO EnergySource (TES) subsidiary to enter into power marketing and fuel
procurement transactions. TES is actively seeking contracts with purchasers for
the output from the four projects under construction and the Frontera Station.
TES expects to enter into contracts to procure the fuel for the generating
plants and sell the fuel to them, and it expects to enter into contracts to
purchase the output from the generating plants for resale to wholesale power
purchasers. TES will present a single face to the energy markets for TPS.
TES expects to provide these services by entering into contracts to purchase
or supply electricity and natural gas, primarily at specified delivery points
and specified future dates (i.e., fixed-price forward sales and purchase
contracts). In some cases TES will utilize financial instruments such as futures
and options contracts traded on the NYMEX and swaps and other types of financial
instruments traded in the over-the-counter markets to manage its exposure to
electricity and natural gas price fluctuations.
The use of these types of contracts is expected to allow TES to manage and
hedge its contractual commitments and to reduce its exposure relative to the
volatility of cash market prices. TES activities utilizing futures, options,
swaps or other financial instruments was minimal in 2001 due to the start up
nature of the business.
TES will normally balance its fixed-price physical and financial fuel
purchase and energy sales contracts in terms of contract volumes and the timing
of performance and delivery obligations. Net open positions may exist due to the
origination of new transactions. When net open positions exist, TES will be
exposed to fluctuating market prices.
In addition to price risk, credit risk is inherent in TES' risk management
activities. The trading and marketing business may be exposed to counterparty
credit risk from a counterparty not fulfilling its obligations. Credit policies
with regard to counterparties attempt to limit overall credit risk. The
company's credit procedures include a thorough review of potential
counterparties' financial position, collateral requirements under certain
circumstances, monitoring net exposure to each counterparty and the use of
standardized agreements.
The credit and overall risk management policies are monitored and
administered by a function within TECO Energy independent of the trading and
marketing activities.
Significant factors that could influence results at TPS include successful
financing, construction of its new projects, weather, domestic economic
conditions and commodity price changes. (See the Investment Considerations
section.)
________________________________________________________________________________
TECO TRANSPORT
Net income declined 6 percent in 2001. Increased phosphate and other product
shipments, higher revenue from outside services at TECO Barge Line, and lower
fuel prices were more than offset by lower U.S. government grain program
shipments, higher costs primarily related to depreciation, and lower shipments
of steel-related products handled by TECO Bulk Terminal (formerly known as
Electro-Coal Transfer L.L.C.). Results for 2000 included an after-tax gain of
approximately $1.5 million associated with the disposition of an ocean-going
asset.
Net income at TECO Transport increased 11 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.
In 2001, TECO Transport's ocean-going subsidiary, TECO Ocean Shipping (TOS)
acquired a 40,000-ton geared vessel at auction at a price well below the
replacement value. The ship was reflagged with the U.S. flag and is now in U.S.
coastwise trade serving customers along the Gulf, East and West coasts. The
ship, which entered service in the summer of 2001, contributed to 2001 results
and is expected to add to earnings in 2002. The ship's speed, reduced weather
sensitivity and cargo handling flexibility from the on-board cranes are expected
to enhance TOS' operation.
TECO Transport expects a return to more normal patterns of U.S. government
grain shipments and a modest improvement in phosphate product shipment volumes
in 2002. In 2001, a delay of several months was experienced in the start of the
U.S. government grain programs due to the change of the administration in
Washington D.C. following the 2000 presidential election. Northbound river
shipments of steel-related products are not expected to improve until the U.S.
economy improves. In the meantime, TECO Transport expects to move increased
volumes of fertilizers, imported coal and petroleum coke northbound on the river
system.
The phosphate fertilizer industry continued to experience worldwide
oversupply and low prices through the first half of 2001. By the second half of
2001, demand for phosphate products had improved and shipments of raw phosphate
rock between Tampa and Louisiana resumed. The outlook is for stable phosphate
prices and demand in 2002.
TECO Transport expects to continue diversifying into new markets and cargoes.
Future growth at TECO Transport is dependent on higher asset utilization,
particularly at TECO Barge Line with north-and southbound cargoes, and asset
additions at both the river and ocean-going businesses. Significant factors that
could influence results include weather, bulk commodity prices, fuel prices and
domestic and international economic conditions. (See the Investment
Considerations section.)
________________________________________________________________________________
TECO COAL
Net income increased 76 percent in 2001, driven primarily by better margins
and higher synthetic fuel (synfuel) production, increased coal production from
Perry County Coal, Inc.'s mining facilities acquired in late 2000, and higher
metallurgical coal prices in the second half of the year. 2001 was the first
full year of production for the synfuel production facilities which entered
service late in the second quarter of 2000. Production of synthetic fuel at TECO
Coal qualifies for Section 29 tax credits for non-conventional fuel production.
Production of synfuel increased to 3.2 million tons in 2001 from more than
1.9 million tons in 2000. The net benefit increased to approximately $56 million
in 2001 from approximately $30 million in 2000. Synfuel production displaced
some of the conventional coal production in 2001 and 2000.
In November 2001, TECO Coal received a private letter ruling from the
Internal Revenue Service regarding the production of synthetic fuel from its
facilities. The private letter ruling confirms that the facilities produce a
qualified fuel eligible for Section 29 tax credits available for the production
of such non-conventional fuels through 2007.
TECO Coal's net income more than doubled in 2000 to $33.5 million, driven
primarily by the sale of fuel produced from the synthetic fuel facilities
acquired in early 2000.
In 2001, coal sales, including synfuel, increased to 10.1 million tons from
7.9 million tons in 2000 and 7.2 million tons in 1999. In 2002, both coal and
synfuel volumes are expected to increase modestly from improved efficiencies and
new mines at several facilities. While TECO Coal may sell coal to Tampa Electric
on a spot-market basis, it has no contract with Tampa Electric.
Metallurgical coal contracts, which normally renew in the first quarter of
the year, resulted in improved prices in 2001 and prices are expected to remain
strong in 2002. Steam coal pricing improved in the first quarter of 2001, due to
better supply and demand balance. TECO Coal contracts much of its steam coal
production for the coming year late in the preceding year and
21
was not able to take full advantage of the higher 2001 prices. However, contract
renewals for 2002 were achieved at prices above 2001 levels.
In November 2000, TECO Coal purchased Perry County Coal, Inc. 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 synfuel facilities from Headwaters
Technologies, Inc. which were relocated to the company's Premier Elkhorn and
Clintwood Elkhorn mines in Kentucky, and were producing by the second quarter of
2000. These facilities produce synfuel from coal, coal fines and waste coal
using a technology licensed from Headwaters.
Significant factors that could influence results include weather, general
economic conditions, commodity price changes, continued generation of section 29
tax credits which expire after 2007, and changes in laws or regulations. (See
the Investment Considerations section.)
________________________________________________________________________________
OTHER UNREGULATED COMPANIES
Net income for the other unregulated companies increased 25 percent, driven
primarily by higher gas prices at TECO Coalbed Methane and a full year of
operation of BCH Mechanical, which was acquired in September 2000.
TECO Coalbed Methane's 2001 net income increased as a result of higher gas
prices which more than offset naturally declining production. Effective gas
prices, net of all hedging, increased 33 percent to $3.66 per thousand cubic
feet (Mcf). Production at 15 billion cubic feet (Bcf) declined 4 percent, about
half the natural decline rate as a result of well restimulation efforts, in
2001. Proven reserves were estimated at 167 Bcf at Dec. 31, 2001, and 182 Bcf
and 159 Bcf in 2000 and 1999, respectively.
Net income increased in 2000 as a result of higher gas prices which more than
offset lower production. Effective gas prices, net of all hedging, increased to
$2.75 per Mcf on production of 15.7 Bcf in 2000. Production in 1999 was 16.6
Bcf.
Production is expected to decline 8 percent in 2002, 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 $1.06 per
million Btu in 2000, $1.04 in 1999 and is expected to be $1.06 for 2001. This
rate escalates with inflation but could be limited by domestic oil prices. In
2001, domestic oil prices would have had to exceed $48 per barrel for this
limitation to have been effective. TECO Coalbed Methane is part of an industry
alliance seeking to extend the section 29 tax credits through 2007, coincident
with the expiration of other tax credits under this section. In 2001, TECO
Coalbed Methane's Section 29 tax credits were $16.1 million.
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 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), BCH
Mechanical, Inc. and its affiliated companies (BCH), TECO Gas Services, TECO
Properties, Prior Energy Corp., TECO Propane Ventures and TECO Partners.
TECO BGA, an energy services company headquartered in Tampa with nine offices
throughout Florida and one in California 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.
TECO 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 October 2001, TECO BGA acquired a district cooling business from FPL
Energy Services. The acquisition included a 12,000-ton design capacity, 3,500-
ton installed capacity, cooling plant in Miami and a franchise agreement with
the city. The plant serves the American Airlines Arena and a large international
Internet/telecommunications center in Miami. The acquisition increases TECO
BGA's presence in the Miami market and the plant has potential for increased
capacity in the future for additional capital investment.
In April 2001, TECO BGA acquired the assets of the energy services division
of AMSI Inc., a diversified contracting company located in Ft. Lauderdale,
Florida. This acquisition expands TECO BGA's presence in the South Florida
market, which accounts for more than 30 percent of the energy services market in
Florida.
TECO Solutions combines TECO BGA's proven project development and design
capabilities with BCH's construction, operations and maintenance capabilities.
This combination allows both companies to improve their performance on
comprehensive turnkey projects because of in-house skills for the entire
project.
In November 2001, TECO Solutions acquired Prior Energy Corporation. Prior
Energy is a leading natural gas management company in North America, serving
customers throughout the Southeast. Prior Energy handles all facets of natural
gas energy management services for large commercial, industrial, power
generation, municipal and other governmental agency customers, including natural
gas acquisition and supply management, transportation management, asset
management and consulting services.
Prior Energy's activities typically consist of: contracting to purchase
specific volumes of gas from producers, pipelines and other suppliers at various
points of receipt; aggregating gas supplies and arranging for the transportation
of these gas supplies; negotiating to sell specific volumes of gas over a
specific period of time to other wholesale marketers and end users; trading gas
volumes to optimize storage facilities and other asset management strategies;
and providing related risk-management services to its customers.
TECO Gas Services, Inc. provides gas management and marketing services
similar to Prior Energy for large municipal, industrial, commercial and power
generation customers primarily in Florida.
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.
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.
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 $180 million in cash and limited partnership units of
Heritage Propane Partners.
22
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.
TPV recorded an $8.3-million after-tax gain from this series of transactions
in 2000. TPV has a 38 percent interest in the general partner that manages
Heritage Propane Partners.
After Heritage Propane Partners issued new equity to the public in 2001, US
Propane continued to own all of the general partner and were diluted down to an
approximate 29 percent limited partnership interest of Heritage Propane
Partners.
________________________________________________________________________________
NON-OPERATING ITEMS
Non-Operating Items Impacting Net Income
2001 Items
In 2001, TECO Energy's results included charges to adjust asset valuations
totaling $7.2 million after tax. The adjustments included a $6.1-million after-
tax adjustment related to the sale of TECO Power Services' (TPS) minority
interests in Energia Global International, Ltd. which owns smaller power
generation projects in Central America, and a $1.1-million after-tax charge
related to the sale of leveraged leases at TECO Investments.
2000 Items
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 Items
Unusual and non-recurring 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 Florida Public Service
Commission 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.
Tampa Electric also recorded an after-tax charge of $3.5 million,
representing management's estimate of additional expenses to resolve 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.
Discontinued Operations
In November 1999, the assets of TeCom, the company's advanced energy
management technology subsidiary, were sold. 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.
Other Income (Expense)
Other income (expense) in 2001 included income recognized on equity
investments in generation projects and EEGSA at TPS and income from the
investment in TPV, offset by a $9.9 million pretax charge ($6.1 million after-
tax) for TPS' sale of its minority interest in EGI. 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 in 2000 was a charge of $8.1 million to adjust the value of certain
leveraged lease investments.
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.
AFUDC was $6.6 million in 2001, $1.6 million in 2000 and $1.3 million in
1999. AFUDC is expected to increase to an estimated $20 million in 2002 and
remain at that level in 2003, primarily reflecting Tampa Electric's growing
investment in the Gannon to Bayside repowering.
Interest Charges
Interest charges at TECO Energy were $166.4 million in 2001 compared to
$167.6 million in 2000 and $123.7 million in 1999. The slight decline in 2001
was primarily because of lower short-term debt rates. The increase in 2000 was
primarily because of higher borrowing levels associated with the company's
business development activities and higher short-term interest rates.
Income Taxes
Income tax expense decreased in 2001, reflecting higher taxable income offset
by a substantial increase in tax credits associated with the production of non-
conventional fuels. In 2000, income tax expense decreased from the prior year
reflecting lower taxable income and the effect of increased tax credits over
1999. Income tax expense as a percentage of income from continuing operations
before taxes was -3 percent in 2001, 7 percent in 2000 and 30 percent in 1999.
The cash payment for income taxes, as required by the Alternative Minimum Tax
Rules, was $52.4 million, $83.9 million and $62.1 million in 2001, 2000 and
1999, 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. This tax credit totaled $102.3 million in 2001, $68.3 million in 2000 and
$17.2 million in 1999. These tax credits are generated annually on qualified
production at TECO Coalbed Methane through December 31, 2002 and at TECO Coal
through December 31, 2007, subject to changes in law, regulation or
administration that could impact the qualification of Section 29 tax credits.
The tax credit is determined annually and was $1.04 per million Btu in 1999,
$1.06 per million Btu in 2000 and is expected to be $1.06 for 2001. This rate
escalates with inflation but could be limited by domestic oil prices. In 2001,
domestic oil prices would have had to exceed $48 per barrel for this limitation
to have been effective.
In 2001 and 2000, the decreased income tax expense also reflected the impact
of increased overseas operations with deferred U.S. tax structures. The decrease
related to these deferrals was $7.2 million, $9.3 million and $1.4 million for
2001, 2000, and 1999, 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 included $5.0 million for charges described above
in 1999 items, 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.
23
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ACCOUNTING STANDARDS
Accounting for Derivative Instruments and Hedging
Effective Jan. 1, 2001, the company adopted Financial Accounting Standard
(FAS) 133, Accounting for Derivative Instruments and Hedging. 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. At adoption, the company had derivatives in place at TECO Coalbed
Methane that qualified for cash flow hedge accounting treatment under FAS 133,
and recorded an opening swap liability of $19.0 million and an after-tax
reduction to other comprehensive income of $12.6 million.
At the time derivative contracts are entered into, the company determines
whether the derivative is subject to the requirements of FAS 133 or meets
criteria for exclusion such as for certain normal purchases and sales activity.
All contracts requiring FAS 133 accounting are designated as a cash flow hedge,
fair value hedge or as a trading instrument, and formal documentation of
relationships between hedging instruments and the hedged items, hedging
objective and strategy, and methods for assessing hedge effectiveness both at
the hedge's inception and on an ongoing basis is completed.
From time to time, TECO Energy enters into futures, swaps and options
contracts to hedge the future selling price for its physical production at TECO
Coalbed Methane, to limit exposure to gas price fluctuations for future
purchases at Peoples Gas System and at Prior Energy, to limit exposure to
interest rate fluctuations at TECO Energy and other affiliates, to limit
exposure to electricity and other commodity fluctuations at TECO Power Services,
and to limit exposure to fuel price increases on future purchases at TECO
Transport. As such, most of the company's derivative activity that cannot be
excluded from the requirements of FAS 133 receives cash flow hedge accounting
treatment.
Cash Flow Hedges: For the year ended Dec. 31, 2001, the company recognized a
loss of $19.7 million for the cash flow hedges that were settled. Of this
amount, $6.5 million was reported as a reduction to revenue related to hedges of
future sales at TECO Coalbed Methane, and $13.2 million was reported as
operating expenses related to hedges of future gas purchases at Peoples Gas and
Prior Energy. As of Dec. 31, 2001, the company had open hedging transactions
that qualify for cash flow hedge accounting treatment at Prior Energy, TECO
Coalbed Methane, Peoples Gas and TECO Transport with a net pretax liability fair
value of $29.5 million. Of this total, $28.2 million is expected to be
reclassified to earnings within the next twelve months on instruments with
maturity dates throughout 2002 when the related future transactions take place.
Unrealized after tax losses on all open cash flow hedges of $8.1 million were
recorded as a reduction to other comprehensive income, with an additional $17.4
million representing open cash flow hedges prior to the Nov. 1, 2001 acquisition
of Prior Energy, were recorded as a deferred charge.
The company, through its TECO Power Services subsidiary, has an equity
investment in a partnership with Panda Energy. The partnership utilizes interest
rate swap agreements to effectively convert a portion of its floating rate debt
to a fixed rate basis, thereby reducing the impact of interest rate changes on
construction costs and future income. On the interest rate swap agreements, the
partnership pays a fixed rate and receives a variable rate based on London
Interbank Offered Rates (LIBOR), with terms ranging from 2 to 5 years. At Dec.
31, 2001 the company recorded $11.2 million for its equity portion of the
unrealized losses on these cash flow hedge swaps reflecting the sharp decline in
floating interest rates since the inception of the swap agreements as a
reduction to other comprehensive income and a corresponding reduction to the
investment account.
Fair Value Hedges: For the year ended Dec. 31, 2001, the company recognized
losses of $0.1 million as operating expenses for changes in the fair value of
derivatives classified as fair value hedges. As of Dec. 31, 2001, the company
had open hedging transactions against gas storage inventory at Prior Energy that
qualify for fair value hedge accounting treatment with a net derivative asset
pretax value of $0.9 million, all of which is expected to be reclassified to
earnings within the next twelve months.
Trading Derivatives: The company has entered into a limited number of
financial derivatives at its TECO Power Services and Prior Energy affiliates
which do not qualify for hedge accounting treatment under FAS 133. TECO Power
Services has a capacity call option, which is marked-to-market. The fair value
of these options is determined using an industry standard model from the
Financial Engineering Association which is based on the Black-Scholes valuation
model and evaluates current prices, volatility of prices and time to expiration
of the options. For the year ended Dec. 31, 2001, the company recognized a
pretax loss of $0.8 million for the decrease in fair value on these options. As
of Dec. 31, 2001, the $1.5 million fair value of these options is included in
current assets, all of which is expected to be realized within the next twelve
months. As of Dec. 31, 2001, Prior Energy had several open swap and option
positions where they acted as the counterparty to the transactions. These
contracts are marked-to-market under FASB's Emerging Issues Task Force (EITF)
release Issue 98-10, Accounting for Contracts Involved in Energy Trading and
Risk Management Activities. The fair value for these derivatives is determined
using the Henry Hub Natural Gas futures prices as actively quoted on the New
York Mercantile Exchange (NYMEX). For the year ended Dec. 31, 2001, the company
recognized $0.7 million in pretax losses related to these derivatives. As of
Dec. 31, 2001, $7.5 million of pretax fair value of open liability positions is
offset by $7.4 million of open asset positions, all of which is expected to be
realized within the next twelve months.
The following tables summarize the changes in and the fair value balances of
trading derivative assets (liabilities) for the year ended Dec. 31, 2001.
- ------------------------------------------------------------------------------------------------------
CHANGES IN FAIR VALUE OF TRADING DERIVATIVES (millions)
- ------------------------------------------------------------------------------------------------------
Net fair value of contracts outstanding at Dec. 31, 2000 $ --
Contracts realized or otherwise settled during the period 1.5
Fair value of new contracts when entered into during the period 2.4
Fair value of contracts acquired as a result of business combination (1.0)
Changes in fair valued attributable to changes in valuation techniques and assumptions --
Other changes in fair values due to prices (1.5)
- -----------------------------------------------------------------------------------------------------
Net fair value of contracts outstanding at Dec. 31, 2001 $ 1.4
=====================================================================================================
- -----------------------------------------------------------------------------------------------------
NET FAIR VALUE OF TRADING DERIVATIVE ASSETS (LIABILITIES)
- -----------------------------------------------------------------------------------------------------
Fair Value of Contracts at Period-End
Maturity Maturity Maturity Total fair
(millions) in 2002 in 2003 after 2003 value
- -----------------------------------------------------------------------------------------------------
Prices actively quoted $ -- $ (0.1) -- $ (0.1)
Prices provided by other external sources -- -- -- --
Prices based on models and other valuation methods 1.5 -- -- 1.5
- -----------------------------------------------------------------------------------------------------
Net fair value at Dec. 31, 2001 $ 1.5 $ (0.1) -- $ 1.4
=====================================================================================================
Business Combinations, Goodwill and Other Intangible Assets
On June 30, 2001, the Financial Accounting Standards Board finalized FAS 141,
Business Combinations, and FAS 142, Goodwill and Other Intangible Assets. FAS
141 requires all business combinations initiated after June 30, 2001, to be
accounted for using the purchase method of accounting. With the adoption of FAS
142 effective Jan. 1, 2002, goodwill is no longer subject to amortization.
Rather, goodwill will be subject to at least an annual assessment for impairment
by applying a fair-value-based test. Under the new rules, an acquired intangible
asset should be separately recognized if the benefit of the intangible asset is
obtained through con-
tractual or other legal rights, or if the intangible asset can be sold,
transferred, licensed, rented, or exchanged, regardless of the acquirer's intent
to do so. These intangible assets will be required to be amortized over their
useful lives. As of Dec. 31, 2001, TECO Energy had $166 million of goodwill, net
of accumulated amortization of $10 million. Adoption of FAS 142 effective Jan.
1, 2002 will result in the elimination of approximately $5 million of annual
amortization, subject to the identification of separately recognized intangibles
which would continue to be amortized under the new rules. TECO Energy is
beginning the initial impairment testing of all goodwill, and does not
anticipate an initial impairment charge upon adoption of FAS 142.
Accounting for Asset Retirement Obligations
In July 2001, the Financial Accounting Standards Board finalized FAS 143,
Accounting for Asset Retirement Obligations, which requires the recognition of a
liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the carrying amount of the
related long-lived asset is correspondingly increased. Over time, the liability
is adjusted to its present value and the related capitalized charge is
depreciated over the useful life of the asset. FAS 143 is effective for fiscal
years beginning after June 15, 2002. The company is currently reviewing the
impact that FAS 143 will have on its results.
Accounting for the Impairment or Disposal of Long-Lived Assets
In August 2001, the Financial Accounting Standards Board issued FAS 144,
Accounting for the Impairment or Disposal of Long-Lived Assets. FAS 144
addresses accounting and reporting for the impairment or disposal of long-lived
assets, including the disposal of a segment of a business, and supersedes FAS
121, Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to
be Disposed of. FAS 144 is effective for fiscal years beginning after December
15, 2001. 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, and beginning in 2002 with FAS 144. The
company does not anticipate that the adoption of FAS 144 will have a significant
impact on its financial statements.
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ENRON EXPOSURE
On Dec. 2, 2001, Enron Corp., a large energy trading and services company,
filed for protection under the U.S. Bankruptcy Code. TECO Energy believes that
its exposure in operations from trade payables and other trading positions due
to the Enron bankruptcy totals $3.5 million or less after tax at its
subsidiaries, TPS, PGS and Prior Energy, its new gas marketing subsidiary.
An Enron subsidiary, NEPCO, is currently serving as the construction
contractor for four merchant power stations in which TPS has interests. Enron
guaranteed certain of NEPCO's obligations under the construction contracts.
Two of the projects for which NEPCO is the contractor, the Union and Gila
River power stations, which are sponsored by a joint venture of TPS and Panda
Energy, have financing in place with a syndicate of banks. The other two
projects, the Dell and McAdams power stations, are 100 percent owned by TPS and
were in the process of being financed at the time of the Enron bankruptcy.
As part of Enron's centralized cash management procedure, NEPCO's cash was
swept by Enron before being applied to pay project costs. As a result of these
cash sweeps, net of NEPCO profit and contingency amounts, there appears to be a
potential aggregate capital cost overrun for the four projects of approximately
$80 million, of which, as described below, $63 million relates to the Union and
Gila River projects. To date, NEPCO has continued construction and engineering
work on these power plants and the construction of all four plants is on
schedule.
TPS and Panda have reached a series of agreements with NEPCO for the
projects. These agreements are designed to permit the construction of the four
plants to continue on schedule and within the estimated total construction cost
amounts including project contingencies. These revisions allow TPS to make
direct payments to subcontractors and suppliers, and provide for no profit or
markup to NEPCO.
Enron's bankruptcy permitted the project lenders to stop funding construction
costs for the Union and Gila River projects until the condition was cured or
waived. TPS received approval from the project lenders on a plan that allowed
funding to resume. The plan involves TECO Energy replacing Enron as the
guarantor of certain of NEPCO's obligations under the construction contracts for
these two projects, including payment by the company of any project cost
overruns (currently estimated at $63 million, against which TECO Energy could
offset any of the unused construction contingency amount remaining after
completion of construction). The plan also provided for TECO Energy to replace
the letter of credit furnished by Enron that had been drawn upon and
acceleration of $200 million of project cash commitments to mid-year 2002, with
the result that TECO's total investment of $1.1 billion is expected by October
2002 rather than mid-2003 as originally planned. Although TECO Energy is not
directly obligated by the project financing, it has commitments to the lenders
to make additional cash contributions to the projects of $493 million in
addition to the $624 million, including the $500 million equity bridge loan, it
has already made.
NEPCO has not filed for bankruptcy, but has told TPS that it may do so in
order to accomplish a sale of substantially all of its assests, pursuant to
Section 363 of the Bankruptcy Code. In the event of such a sale, TPS expects
that it would enter into new contracts with the purchaser of such assets
effective upon approval of the sale by the bankruptcy court. If NEPCO had to be
replaced as contractor (as a result of a sale of its assets or otherwise), it is
possible that there would be delays in the project schedules and additional
project costs. A new contractor would also have to be reasonably satisfactory to
the project lenders for the Union and Gila River projects.
Financing activities for the other two projects, the Dell and McAdams power
stations, resumed shortly after the bank approval was received for the
resumption of funding for the Union and Gila River power stations. Financing for
these plants is expected to be completed in 2002.
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ENVIRONMENTAL COMPLIANCE
Tampa Electric Company is a party to a consent decree with the EPA and a
consent final judgement with the U.S. Department of Justice, effective Oct. 5,
2000, and the Florida Department of Environmental Protection (FDEP) effective
December 7, 1999. Pursuant to these consent decrees, allegations of violations
of New Source Review requirements of the Clear Air Act were resolved, provision
was made for environmental controls and pollution reductions, and Tampa Electric
is committed to a comprehensive program that will dramatically decrease
emissions from the company's power plants.
The emission reduction plan included specific detail with respect to the
availability of the scrubbers and earlier incremental NOx reduction efforts on
Big Bend Units 1, 2 and 3 and the repowering of the company's coal-fired Gannon
Station to fire natural gas. Engineering for the repowering project began in
January 2000, and Tampa Electric anticipates that commercial operation for the
first repowered unit is expected by May 1, 2003. The repowering of the second
unit is scheduled for completion 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 generation.
In November 2000, the FPSC approved recovery through the Environmental Cost
Recovery Clause of costs incurred to improve the availability and removal
efficiency for its Big Bend 1, 2 and 3 scrubbers, to reduce particulate matter
emissions, and to reduce NOx emissions. The approved cost recovery for these
various environmental projects through customers' bills started in January 2001.
Tampa Electric Company is a potentially responsible party for certain
superfund sites and,
25
through its Peoples Gas System division, for certain superfund and 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 expected environmental remediation costs
associated with these sites are not expected to have a significant impact on
customer prices.
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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 Florida's 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 1 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 and refunds to
customers totaling $50 million during the period October 1996 through December
1998 while Tampa Electric was allowed recovery of the capital costs incurred for
the Polk Unit 1 project.
As part of its series of agreements with OPC and FIPUG, Tampa Electric 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 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. In February 2001, OPC
protested the FPSC's decision. The protest claimed that the stipulations did not
allow for the inclusion of the interest expenses on income tax positions in the
refund calculations. The FPSC held hearings on the issue in August 2001 and
upheld its decision that the original refund amount plus interest was
appropriate under the agreements. In January 2002, the OPC filed a motion with
the FPSC asking for reconsideration of its decision, alleging the FPSC relied on
erroneous information. Tampa Electric will begin making refunds to customers
when the decision can no longer be appealed.
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 expects to
continue earning within its allowed ROE range.
Cost Recovery Clauses
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, 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 and ending in December 2002.
In September 2001, 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 2002 through December 2002. In November, the
FPSC approved Tampa Electric's requested changes. Accordingly, Tampa Electric's
residential customer rate per 1,000-kilowatt hours increased by $6.18 to $93.94.
These rates include projected costs associated with environmental projects
required under the U.S. EPA Consent Decree and the FDEP Consent Final Judgment
with Tampa Electric. They also include higher coal prices expected for 2002 and
additional purchased power costs for 2001 and 2002, which reflect higher natural
gas and oil prices and increases in the volumes of purchased power.
In January 2001, PGS notified the FPSC that it anticipated that its purchased
gas adjustment 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. In April, and again in June, PGS
lowered the purchased gas adjustment factor as gas prices declined from their
winter time highs.
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 submitted its final recommendation to Governor Bush in
December 2001 which included, among other things, 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 as early as the 2002 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.
26
The activities resulted in the peninsular Florida investor-owned utilities
making joint RTO filings at FERC in October and December 2000. In the filing,
Tampa Electric agreed with the other Florida investor-owned utilities to form an
RTO to be known as GridFlorida LLC. GridFlorida would independently control the
transmission assets of the filing utilities, as well as other utilities in the
region that choose to join. The RTO would be an independent, investor-owned
organization that would have control of the planning and operations of the bulk
power transmission systems of the utilities within peninsular Florida. In
addition, GridFlorida was proposed to be a transmission company (or transco)
that would own transmission assets. Tampa Electric planned to contribute its
transmission assets to GridFlorida in exchange for a passive interest. The three
filing utilities represent almost 80 percent of the aggregate net energy load in
the region for the year 2000.
In March 2001 FERC conditionally approved GridFlorida, which led to a May
2001 compliance filing by the three filing utilities at FERC addressing the
changes FERC required in their approval before GridFlorida could move ahead.
FERC has not yet acted on this latest filing.
In May 2001, the FPSC questioned the prudence of the three filing utilities
joining GridFlorida as conditionally approved by FERC. Upon the request of the
three utilities, the FPSC granted the opening of an accelerated docket regarding
the prudence of GridFlorida. Hearings were held in October 2001, and the FPSC
ruled that, while the companies were prudent in forming GridFlorida, the FPSC
was not satisfied with the transmission-owning features of the GridFlorida
filing nor with the proposal that any of the filing utilities transfer ownership
of their assets to GridFlorida. Accordingly, the FPSC ordered the companies to
develop a new RTO model which was filed at the FPSC in late March 2002 that
addresses its concerns. Tampa Electric plans to take an active role in
monitoring and influencing the development of possible RTOs in the southeast
region.
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.
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 counterclaims and after a series of hearings the core issues
of the case relating to the City's rights to purchase the system have still not
been heard. Due to further motions and the potential for appeals, resolution
through the courts is not expected for many months. 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 agreement in the absence of other rules and regulations being,
adopted by the City. The Lakeland franchise contributed about $4.5 million of
net revenue to PGS results in 2001.
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CAPITAL INVESTMENTS
- --------------------------------------------------------------------------------
Actual Forecast
----------------------------------------------
$ (millions) 2001 2002 2003 2004 - 2006 2002 - 2006 Total
- --------------------------------------------------------------------------------
Florida Operations $ 533 $ 603 $ 359 $ 761 $ 1,723
Independent Power 554 514 352 -- 866
Transportation (4) 20 24 55 99
Other 23 46 29 46 121
- --------------------------------------------------------------------------------
Total $1,106 $1,183 $ 764 $ 862 $ 2,809
- --------------------------------------------------------------------------------
TECO Energy's 2001 capital investment of $1,106 million included $426 million
for Tampa Electric (including AFUDC), $73 million for Peoples Gas System and
$573 million for the unregulated companies. Tampa Electric's capital investments
in 2001 were $225 million for equipment and facilities to meet its growing
customer base and generating equipment maintenance, $183 million for the
repowering and conversion of the coal-fired Gannon Station to the natural
gas-fired Bayside Station (see the Environmental Compliance section) and $18
million for the construction of Polk Unit 3 which is a natural gas and No. 2
oil-fired combustion turbine. Capital expenditures for Peoples Gas System were
approximately $54 million for system expansion and approximately $19 million for
maintenance of the existing system. TECO Transport invested $39 million in 2001
for equipment additions and normal equipment replacement, offset by $43 million
in proceeds from a sale/lease back transaction at TECO Ocean Shipping. (See
Financing Activity section). TECO Coal spent $26 million, which includes $9
million for the expansion of production at Perry County and Clintwood, and the
balance for normal equipment replacements. TECO Power Services' capital
investments totaled $784 million related to the Commonwealth Chesapeake Power
Station, the Union, Gila River, Dell and McAdams power stations and the purchase
of the Frontera Power Station. The $554 million, shown for independent power in
the table above, is net of $197 million of non-recourse financing and is net of
the proceeds from the sale of EGI received in 2001.
TECO Energy estimates net capital investments for ongoing operations to be
$1.2 billion for 2002, $800 million for 2003 and $900 million during the
2004-2006 period.
For 2002, Tampa Electric expects to spend $541 million, consisting of $330
million for the repowering project at the Gannon Station, $16 million in
construction costs on Polk Unit 3 and $195 million to support system growth and
generation reliability. At the end of 2001, Tampa Electric had outstanding
commitments of about $453 million for the Gannon Station repowering project and
Polk Unit 3. Tampa Electric's total capital expenditures over the 2003-2006
period are projected to be $878 million, including $131 million for the
repowering project.
Capital expenditures for Peoples Gas System are expected to be about $62
million in 2002 and $242 million during the 2003-2006 period. Included in these
amounts are approximately $42 million annually for projects associated with
customer growth and system expansion. The remainder represents capital
expenditures for ongoing maintenance and system safety.
TECO Power Services expects to invest $514 million in 2002, net of $500
million of non-recourse project financing expected for the Dell, McAdams,
Frontera and Commonwealth Chesapeake power stations, and $320 million in 2003
for the completion of the Gila River, Union, Dell and McAdams power stations.
Estimates for TPS include net contributions to projects of unconsolidated
affiliates and other investments of $984 million. These amounts, consisting of
equity investments in the Union and Gila River Power Stations, are estimated at
$664 million in 2002 and $320 million in 2003. The 2002 amounts are net of $460
million of non-recourse project construction for the Union and Gila River power
stations, (see Financing Activity section) and include $125 million of TPS
equity investment upon completion of the first phase of the Union Power Station.
Capital investment estimates reflect committed projects and do not take into
account future opportunities that may emerge.
27
TPS had contractual commitments of $1.1 billion at the end of 2001, primarily
for the construction of the Union, Gila River, Dell and McAdams power stations
and are reflected in the capital investments table above.
The other unregulated companies expect to invest $66 million in 2002 and $154
million during the 2003-2006 period. Included in these amounts is normal renewal
and replacement capital including coal mining equipment.
See the Liquidity, Capital Resources section for a description of TECO
Energy's plans to finance these capital investments.
- --------------------------------------------------------------------------------
INVESTMENT ACTIVITY
At Dec. 31, 2001, TECO Energy had $120.2 million in cash, cash equivalents
and short-term investments, compared to $99.6 million at year-end 2000.
Year-end cash balances were higher than normal in both years. At the end
of 2001, cash balances included the proceeds from a sale-leaseback transaction
at TECO Transport, which were applied to short-term debt balances in early 2002.
At the end of 2000, cash balances included the proceeds from a TPS lease
transaction, which were applied to short-term debt balances in early 2001. (See
Financing Activity section.)
Other investments of $303 million included notes receivable from
unconsolidated affiliates and investments in leveraged leases; $93 million of
the notes receivable mature within one year. Other Investments decreased $103
million in 2001, reflecting repayments from the proceeds of the TPS/Panda Energy
project financing of amounts advanced by TECO Energy to the projects. The
balance is expected to decrease during the fourth quarter of 2002 as these notes
mature.
Investments in unconsolidated affiliates of $172.9 million at Dec. 31, 2001
decreased from $195.9 million at Dec. 31, 2000. The balances at Dec. 31, 2001
include TPS's ownership interest in EEGSA, TECO Propane Ventures' 38-percent
interest in US Propane and TECO Properties interests in real estate projects.
Activity in 2001 was largely associated with TPS' sale of its minority interest
in EGI.
The continuing investment in leveraged leases was $15.6 million at Dec. 31,
2001, down from $22 million last year, reflecting the sale of commuter aircraft
leases in 2001.
- --------------------------------------------------------------------------------
FINANCING ACTIVITY
TECO Energy's 2001 year-end capital structure, excluding the effect of
unearned compensation, was 59.6 percent debt, 3.6 percent trust preferred
securities and 36.8 percent common equity. TECO Power Services typically
finances its power projects with non-recourse project debt. Excluding this
non-recourse debt of $238.4 million, the year-end capital structure was 57.8
percent debt, 3.8 percent trust preferred securities and 38.4 percent common
equity.
Taking into account the January 2002 issuance of mandatorily convertible
equity units, TECO Energy's 2001 year-end capital structure, on a pro forma
basis, excluding the effect of unearned compensation, was 51.6 percent debt,
11.6 percent trust preferred and mandatorily convertible equity units and 36.8
percent common equity. Excluding this non-recourse project debt of $238.4
million, the year-end capital structure was 49.5 percent debt, 12.1 percent
trust preferred and mandatorily convertible equity units and 38.4 percent common
equity.
- --------------------------------------------------------------------------------
CREDIT RATINGS/SENIOR UNSECURED DEBT
- --------------------------------------------------------------------------------
Fitch Moody's Standard & Poor's
- --------------------------------------------------------------------------------
Tampa Electric A+ A1 A
TECO Finance / TECO Energy A- A3 A-
- --------------------------------------------------------------------------------
In 2000 and 2001, Moody's Investor Services, Inc., Standard & Poor's Ratings
Service and Fitch Investor Services, Inc. lowered the ratings on the debt
securities of TECO Energy and Tampa Electric. The outlook assigned by each
agency is negative. The ratings 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, the uncertainties related to industry restructuring
and the additional risks and obligations undertaken by TECO Energy with respect
to various TPS projects. These downgrades and any further downgrades, may affect
the company's ability to borrow and increase its financing cost which may
decrease earnings.
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 investment-grade credit ratings that provide the
companies with continued access to the commercial paper markets.
Financing activity by company
TECO Energy:
In January 2002, TECO Energy sold 17.965 million units of mandatorily
convertible equity units in the form of 9.5% equity units at $25 per unit
resulting in $436 million of net proceeds. Each equity unit consisted of $25 in
principal amount of a trust preferred security of TECO Capital Trust II, a
Delaware business trust formed by TECO Energy, with a stated liquidation amount
of $25 and a contract to purchase shares of common stock of TECO Energy in
January 2005 at a price per share of between $26.29 and $30.10 based on the
market price at that time. The equity units represent an indirect interest in a
corresponding amount of TECO Energy subordinated debt. The net proceeds from the
offering were used to repay short-term debt and for general corporate purposes.
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. In October 2001, Standard & Poor's (S&P) announced the inclusion of
TECO Energy shares in the S&P 500 index effective as of the market close on Oct.
9, 2001. On Oct. 12, 2001, the company issued 3.5 million additional common
shares as a result of the increased demand for its shares on its inclusion in
the S&P 500 index. The net proceeds were $26.72 per share or approximately $93
million. The proceeds from the sale of these common shares were used to repay
short-term debt and for general corporate purposes.
In May 2001, the company issued $400 million principal amount of 7.20% notes
due May 1, 2011. These notes are redeemable at the option of the company, in
whole or in part, from time to time, at a redemption price equal to the greater
of 100% of the principal amount of the notes then outstanding to be redeemed or
the sum of the present value of the remaining scheduled payments of principal
and interest on the notes then outstanding to be redeemed, discounted at an
adjusted treasury rate plus 25 basis points to the redemption date. Net proceeds
of $396 million were used to repay short-term debt and for general corporate
purposes. In September 2001, the company issued an additional $200 million
principal amount of this note series. Net proceeds of $206 million were used to
effect a debt for debt exchange of $150 million of bonds issued in 1998, and to
repay short-term debt and for general corporate purposes.
In May 2001, the company sold $400 million principal amount of one-year,
floating rate notes in a private placement. The notes were issued at an initial
rate of 5.203%, and are callable at par on Nov. 15, 2001, and monthly
thereafter. Rates on these securities are reset quarterly at a spread of 110
basis points over three-month LIBOR. Net proceeds of $399 million were used to
repay short-term debt and for general corporate purposes.
In December 2000, TECO Energy issued $200 million of retail trust preferred
securities (TRuPS). 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
28
callable at par after Dec. 20, 2005. These securities represent an indirect
interest in a corresponding amount of TECO Energy subordinated debt.
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, at which time they will be remarketed or
redeemed. 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.
Tampa Electric:
In June 2001, Tampa Electric issued $250 million principal amount of 6.875%
notes due on June 15, 2012. The notes are redeemable at the option of Tampa
Electric, in whole or in part, from time to time, at a redemption price equal to
the greater of 100% of the principal amount of the notes then outstanding to be
redeemed or the sum of the present value of the remaining scheduled payments of
principal and interest on the notes then outstanding to be redeemed, discounted
at an adjusted treasury rate plus 25 basis points to the redemption date. Net
proceeds of $248.9 million were used to repay short-term debt and for general
corporate purposes.
In August 2000, Tampa Electric 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's
then-current credit spread above United States Treasury Notes with 10 years to
maturity.
TECO Transport:
In April 2001, TECO Bulk Terminal, a wholly-owned subsidiary of TECO
Transport, converted $110.6 million of tax-exempt debt related to its docks and
wharves from commercial paper mode to a fixed rate mode with a coupon rate of
5.0%. These securities, which mature in 2007, are guaranteed by TECO Energy.
In December 2001, TECO Transport sold to a third party and leased back four
vessels at its TECO Ocean Shipping subsidiary in a transaction structured as an
operating lease with a term of 12 years, with an early termination option after
year five. The $42.6 million of proceeds were used to repay short-term debt and
for general corporate purposes.
TECO Power Services:
In June 2001, TECO Power Services and its joint venture partner, Panda
Energy, closed on a $2.175-billion syndicated bank financing for the
construction of the Gila River and Union power stations. The financing includes
$1.675 billion in five-year non-recourse debt and $500 million in equity bridge
loans guaranteed by TECO Energy. Pricing for the non-recourse segment is 162.5
basis points over LIBOR during the construction period (first two years) and
will increase to 175 basis points for year one of operation and 200 basis points
for years two and three. If the projects secure an investment-grade rating the
pricing will be reduced by 12.5 basis points. The equity bridge financing is
repayable in four equal installments coincident with Phase 2 and Phase 4
completion of each project. The joint venture is a 50 percent owned
unconsolidated affiliate; accordingly the debt is not included in TECO Energy's
financial statements.
The equity bridge financing includes two financial covenants, debt to capital
and interest coverage requirements on a TECO Energy consolidated basis. The debt
to capital as defined in the agreements must not exceed 65 percent at the end of
each quarter and interest coverage as defined must equal or exceed 3.0 times for
the twelve-month period ended each quarter. At Dec. 31, 2001, debt to capital
was 62.2 percent and interest coverage was 4.2 times. In addition, this
financing requires that TECO Energy maintain senior unsecured credit ratings not
less than one rating of BBB and one rating of BBB-. Failure to meet these
covenants would constitute a default event and the equity bridge financing would
become due and payable.
In March 2001, TPS converted the third-party construction financing for the
Hamakua Power Station into a synthetic equipment operating lease with a term of
five years. The lessor is an unaffiliated entity. As part of the transaction an
unconsolidated affiliate of TPS loaned the lessor $12.8 million.
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).
In December 2000, TPS sold to a third party, and entered into a synthetic
operating lease for certain non-integral equipment at its Hardee Power Station
with a 12-year term. The lessor is an unaffiliated entity.
- --------------------------------------------------------------------------------
FINANCIAL EXPOSURES
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% increase in TECO
Energy's weighted average interest rate on its variable rate debt and required
refinancings in 2002 would have an estimated $3.2 million impact on TECO
Energy's earnings over the next fiscal year.
A hypothetical 10% 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,
2001.
Based on policies and procedures approved by the company's 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.
TECO Power Services' energy marketing and trading subsidiary, TECO
EnergySource, utilizes futures, swaps and option contracts in connection with
the marketing of power in order to reduce the variability of electricity selling
prices and to maximize the profitability of TPS' merchant power plant portfolio.
Prior Energy Corporation, acquired by TECO Solutions in November 2001 (see TECO
Solutions), and Peoples Gas services make use of physical and financial futures,
swaps and options contracts in the normal course of its business.
TECO Energy does not use derivatives or other financial instruments for
speculative purposes.
________________________________________________________________________________
OFF BALANCE SHEET FINANCING
Unconsolidated affiliates in which TECO Power Services has a 50% ownership
interest or less have non-recourse project debt balances as follows at Dec. 31,
2001. This debt is recourse only to the unconsolidated affiliate, and TECO
Energy has no debt payment obligations with respect to these financings.
- --------------------------------------------------------------------------------
Affiliate Affiliate Debt Balance (millions) TPS Ownership Interest
- --------------------------------------------------------------------------------
Union & Gila River $683 50%
EEGSA $200 24%
Hamakua $ 86 50%
- --------------------------------------------------------------------------------
29
The TECO/Panda debt balance is expected to reach $1.17 billion by the end of
2002 and $1.4 billion upon completion of construction of the Union and Gila
River power stations.
In addition, TECO Energy has guaranteed a $500 million equity bridge loan of
the unconsolidated TECO/Panda affiliate, a TPS turbine lease financing facility
of $69 million, and other debt-related items totaling $25 million. These
facilities are not included in liabilities on TECO Energy's consolidated balance
sheet, but do represent payment obligations of the company.
At Dec. 31, 2001, TECO Energy had bank credit lines of $700 million, and
Tampa Electric had bank credit lines of $300 million, all of which were undrawn
and available. TECO Energy credit lines include a $250 million sublimit for
letters of credit capacity. In January and February 2002, $141.7 million of
letters of credit were issued against these lines, primarily related to the
construction of the Union and Gila River power stations. These letters of credit
of $69.5 million and $67.6 million for Union and Gila River, respectively, were
replacements for the letters of credit posted by Enron and drawn by the
TPS/Panda joint venture following Enron's bankruptcy filing. In addition, at
Dec. 31, 2001 TECO Energy and its subsidiaries had $22 million of letters of
credit outside of its bank credit line facility.
TECO Energy guarantees certain current obligations of its operating companies
in the normal course of business, the effects of which are included in the
consolidated financial statements. At Dec. 31, 2001, such guarantees amounted to
$173 million, primarily related to gas purchase and energy management activities
of Prior Energy, TECO Gas Services, and TECO Power Services. As TPS' plants come
on line, guarantees associated with gas purchases and power sales activities are
expected to increase.
The following table summarizes the letters of credit and guarantees
outstanding, that are not included in the Summary of Cash Obligations table,
except for the guarantees by TECO Energy for the performance of unconsolidated
affiliates related to the construction of the Union and Gila River power
stations estimated at $63 million (see Enron Exposure section).
- ------------------------------------------------------------------------------------------------
SUMMARY OF COMMERCIAL COMMITMENTS
- ------------------------------------------------------------------------------------------------
Amount of Commitment Expiration Per Period
Expires Expires Expires Expires
(millions) Total (1) 2002 2003 2004 - 2006 After 2006
- ------------------------------------------------------------------------------------------------
Letters of Credit $181.3 (1)(2) $ 17.3 $116.7 $ 20.3 $ 27.0
Guarantees:
Debt related 24.7 -- -- -- 24.7
Fuel purchase related 148.1 4.0 -- -- 144.1
Energy management/other 25.2 3.5 0.3 2.6 18.8
Turbine agreements 69.0 69.0 (3) -- -- --
Contingent purchase obligations 60.0 -- -- -- 60.0
- -------------------------------------------------------------------------------------------------
(1) Expected final expiration date with annual renewals
(2) Includes the expected maximum value of $154.3 million for letters of credit
issued in January 2002
(3) May be renewed
- --------------------------------------------------------------------------------
LIQUIDITY, CAPITAL RESOURCES
TECO Energy and its operating companies met cash needs during 2001 with a mix
of internally generated funds, proceeds from the sale of equity and short- and
long-term borrowings. It met cash needs during 2000 with a balance of internally
generated funds, short- and long-term borrowings and retail trust preferred
securities.
In light of the accelerated equity commitments for the Union and Gila River
projects under the bank financing plan, as discussed in the Enron Exposure
section, and the capital requirements for committed regulated and unregulated
projects, TECO Energy is exploring various options to strengthen its balance
sheet. As a first step, the company has reduced its capital expenditure forecast
for 2002 through 2004 by about $700 million primarily by delaying for an
extended period generation projects that are not yet under construction for TPS
and Tampa Electric, including the Bayside Units 3 and 4 repowering projects
announced in the fall of 2001. Resumption of work on those projects will be
evaluated periodically as market conditions evolve.
TECO Energy estimates its incremental financing requirements, excluding non-
recourse project debt at TPS, at approximately $650 million in 2002, and has
debt maturities in 2002 totaling $788 million. The company issued $450 million
of mandatorily convertible equity units in January 2002, (see Financing Section)
and expects to issue common equity late in the year and long-term debt
securities during the year. The company does not anticipate additional
incremental financing requirements in the 2003 through 2004 period; however it
expects to issue common equity in that time frame to reduce leverage. Notes
payable, representing commercial paper with maturities up to 50 days, totaled
$639 million at Dec. 31, 2001. The company reduced these balances to
approximately $300 million in early 2002 with the proceeds of the mandatorily
convertible securities issuance.
TECO Energy provides short-term liquidity for its non-regulated operating
companies primarily through its commercial paper program. Tampa Electric Company
also issues commercial paper. These programs are backed by the bank credit line
facilities.
The company has identified in this Management's Discussion and Analysis
(including in Investment Considerations below), several factors that could cause
its operating cash flow to be lower than forecasted. Among these factors is the
margins the company may realize for production from its merchant power
facilities. Because of the company's recent expansion in the merchant power
business, the company's cash flow has become increasingly dependent upon power
margins. As a result, a decrease in these margins could result in external
financing requirements that are higher than those forecasted above.
The following table lists the obligations of TECO Energy and its subsidiaries
for cash payments to repay debt, lease payments and unconditional commitments
related to capital expenditures.
- --------------------------------------------------------------------------------
SUMMARY OF CASH OBLIGATIONS
- --------------------------------------------------------------------------------
Payments Due by Period
(millions) Total 2002 2003 2004 - 2006 After 2006
- --------------------------------------------------------------------------------
Long-term debt $2,597.0 $ 785.9 $ 104.6 $ 102.3 $ 1,604.2
Capital lease obligations 27.6 2.3 25.3 -- --
Operating leases/rentals 156.1 12.0 15.3 45.5 83.3
Unconditional purchase
obligations/commitments 1,595.0 1,221.1 373.9 -- --
Other long-term obligstions 200.0 -- -- -- 200.0
- --------------------------------------------------------------------------------
Total cash obligations $4,575.7 $2,021.3 $ 519.1 $ 147.8 $ 1,887.5
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
TRANSACTIONS WITH RELATED AND CERTAIN OTHER PARTIES
TECO Energy has interests in unconsolidated affiliates, which are discussed
in the TECO Power Services, Other Unregulated Companies and Financing Activity
sections. TECO Energy has certain transactions with its Directors and Officers
that are reported in TECO Energy's annual proxy statement and Tampa Electric's
annual regulatory filings. There are no material transactions of this type where
the payments are in excess of those that would be paid under an arms-length
transaction.
30
- --------------------------------------------------------------------------------
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 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' investment in EEGSA is 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.
With a single winter peak period, Peoples Gas System is more weather
sensitive than Tampa Electric, with both summer and winter peak periods. Mild
winter weather in Florida can be expected to negatively impact results at
Peoples Gas System.
Variations in weather conditions also affect the demand and prices for the
commodities sold by TECO Coalbed Methane and TECO Coal, as well as 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 FPSC, and Tampa Electric's wholesale power sales and
transmission services are subject to regulation by the FERC. 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 law, regulation or
administration could impact TECO Coal's quantity of qualified synfuel
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.
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.
Results at TECO Power Services are impacted by changes in the market price
for electricity. The profitability of merchant power plants is heavily dependent
on the price for power in the markets they serve. Wholesale power prices are set
by the market assuming a cost for the input energy and conversion efficiency but
the fixed costs may not be reflected in the price for spot, or excess power.
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 unregulated companies, changes in gas, oil and coal prices directly
affect the margins at TECO Power Services, TECO Coalbed Methane, TECO Coal, and
TECO Transport. 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 $4
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.
Natural gas prices recently have been increasingly volatile, and thus the
earnings from TECO Coalbed Methane are increasingly difficult to predict.
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 8 percent annually. Actual production
levels may be different than those assumed.
31
Tax Credits. TECO Energy derives a portion of its net income from non-
conventional fuels tax credits. The realization of these tax credits are
dependent on TECO Energy generating sufficient taxable income against which to
use the credits, and these credits could be impacted by changes in law,
regulation or administration.
Business growth opportunities. Part of the company's business strategy is to
grow its unregulated businesses. Much of its 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 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 and Development Risks. Tampa Electric currently has new power
plants under construction and existing facilities under conversion and, TECO
Power Services has new power plants under construction. The development of
independent power plants involves considerable risks, including successful
siting, permitting, financing and construction, contracting for necessary
services, fuel supplies and power sales and performance by project partners. The
construction of these plants, as well as future construction projects involves
risks, such as shortages and inconsistent qualities of equipment; material and
labor; engineering problems; work stoppages; unanticipated cost increases and
environmental or geological problems.
Exposure to Enron. On December 2, 2001, Enron Corp., a large energy trading
and services company, filed for protection under the U.S. Bankruptcy Code. TECO
Energy believes that its exposure in operations from trade payables and other
trading positions due to the Enron bankruptcy totals $3.5 million or less after
tax at its subsidiaries, TECO Power Services (TPS), Peoples Gas System and Prior
Energy, its new gas marketing subsidiary.
An Enron subsidiary, NEPCO, is currently serving as the construction
contractor for four merchant power stations in which TPS has interests.
If NEPCO had to be replaced as contractor, it is likely that there would be
delays in the project schedules and substantial additional project costs,
including payment of added fees to a new contractor. A new contractor would also
have to be reasonably satisfactory to the project lenders for the Union and Gila
River projects.
Merchant Power Plants. TPS 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, TPS will also have no guarantee that it will recover
its initial investment in these plants. The company's forecast assumes that TPS
will avoid losses associated with these risks by building in well-established
markets that enable the company to use established hedging mechanisms, hiring
experienced power marketers, entering into negotiated contracts with offtak-ers
resulting in higher revenues than the spot market for capacity payment and
ancillary services for a significant portion of the plant's output, avoiding
selling short and entering into non-energy related sales to offset potential
operational risks.
Operational Risks. Each of the company's subsidiaries is subject to various
operational risks, including accidents or equipment breakdown or failure, and
operations below expected levels of performance of efficiency. As operators of
power generation facilities, Tampa Electric and TECO Power Services could incur
problems such as the breakdown or failure of power generation equipment,
transmission lines, pipelines or other equipment or processes which would result
in performance below normal levels of output or efficiency. The company's
forecast assumes normal operations and normal maintenance periods for its
subsidiaries' facilities.
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 the equity and capital markets on satisfactory terms
to fund growth opportunities, including acquisition and development
opportunities and independent power projects.
Increased Debt Levels. To support its growth, the company has significantly
expanded the amount of its indebtedness, increased its debt-to-equity ratio and
lowered its interest coverage. This increase in debt levels has increased the
amount of fixed charges the company is obligated to pay. The level of the
company's indebtedness and restrictive covenants contained in existing or future
financings could limit its ability to finance the acquisition and development of
additional projects.
In 2000 and 2001, Moody's Investor Services, Inc., Standard & Poor's Ratings
Service and Fitch Investor Services, Inc. lowered the ratings on the debt
securities of TECO Energy and Tampa Electric. The outlook assigned by each
agency is negative. The ratings 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, the uncertainties related to industry restructuring
and the additional risks and obligations undertaken by TECO Energy with respect
to various TPS projects. These downgrades and any further downgrades, may affect
the company's ability to borrow and increase its financing cost which may
decrease earnings.
Certain of the company's debt obligations contain financial covenants related
to debt to equity ratios and interest coverage that could prevent the repayment
of subordinated debt and the payment of dividends if such payments would cause a
violation of the covenants. In addition, certain of the company's subsidiaries
have indebtedness with restrictive covenants which, if violated, could prevent
them from making distributions to TECO Energy. As a holding company, TECO Energy
is dependent on cash flow from its subsidiaries.
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 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. TECO Ocean Shipping is exposed to operational risks
in international ports, primarily in the form of suitable labor and equipment to
safely discharge its cargoes in a timely manner. The company's forecast assumes
that TECO Ocean Shipping will avoid losses associated with these risks through a
variety of risk mitigation measures, including retaining agents with local
knowledge and experience in successfully discharging cargoes and vessels similar
to those used.
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 in the INVESTMENT CONSIDERATIONS
sectio, and in the FINANCING ACTIVITY section.
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 fluctuations for future
purchases at Peoples Gas System and Prior Energy, to limit exposure to fuel
price increases on future purchases at TECO Transport, or to limit exposure to
electricity, and other commodity price fluctuations at TPS.
See the discussions of commodity price risks in the INVESTMENT
CONSIDERATIONS -- COMMODITY PRICE CHANGES section.
TECO Energy and its affiliates do not currently use derivatives or other
financial products for speculative purposes.
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, 2001 and 2000 42
Consolidated Statements of Income for the years ended Dec. 31, 2001, 2000 and 1999 43
Consolidated Statements of Cash Flows for the years ended Dec. 31, 2001, 2000 and 1999 44
Consolidated Statements of Equity for the years ended Dec. 31, 2001, 2000 and 1999 45
Notes to Consolidated Financial Statements 46-69
Financial Statement Schedule II - Valuation and Qualifying Accounts for the years
ended Dec. 31, 2001, 2000 and 1999 72
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.
32
- --------------------------------------------------------------------------------
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, 2001 and 2000,
and the results of their operations and their cash flows for each of the three
years in the period ended Dec. 31, 2001, 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 and financial statement
schedule 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.
PricewaterhouseCoopers LLP
Tampa, Florida
Jan. 11, 2002, except for the information in Note O as to which the dates are
Jan. 23, 2002, Feb. 1, 2002 and Feb. 7, 2002
- --------------------------------------------------------------------------------
CONSOLIDATED BALANCE SHEETS
- ----------------------------------------------------------------------------------------------------------------------------
ASSETS (millions) Dec. 31, 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------
Current assets
Cash and cash equivalents $ 120.2 $ 99.6
Receivables, less allowance for uncollectibles 348.1 360.3
Current notes receivable 92.7 223.1
Inventories, at average cost
Fuel 87.3 67.3
Materials and supplies 83.2 77.2
Prepayments and other current assets 44.4 22.4
------------------------------------------------------------------------------------
Total current assets 775.9 849.9
- ----------------------------------------------------------------------------------------------------------------------------
Property, plant and equipment Utility plant in service
Electric 4,861.1 4,523.1
Gas 699.4 632.1
Construction work in progress 897.0 332.2
Other property 1,086.0 1,073.0
------------------------------------------------------------------------------------
Property, plant and equipment, at original cost 7,543.5 6,560.4
Accumulated depreciation 2,705.2) (2,590.3)
------------------------------------------------------------------------------------
Total property, plant and equipment (net) 4,838.3 3,970.1
- ----------------------------------------------------------------------------------------------------------------------------
Other assets Other investments 210.4 182.9
Investment in unconsolidated affiliates 172.9 195.9
Goodwill 165.8 93.1
Deferred income taxes 242.0 174.4
Deferred charges and other assets 316.8 268.0
------------------------------------------------------------------------------------
Total other assets 1,107.9 914.3
- ----------------------------------------------------------------------------------------------------------------------------
Total assets $ 6,722.1 $ 5,734.3
- ----------------------------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------------------------
LIABILITIES AND CAPITAL (millions) Dec. 31, 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------
Current liabilities Long-term debt due within one year $ 788.8 $ 237.3
Notes payable 638.9 1,208.9
Accounts payable 267.4 274.8
Current derivative liability 33.5 --
Customer deposits 86.3 82.4
Interest accrued 35.6 41.9
Taxes accrued 71.7 54.5
------------------------------------------------------------------------------------
Total current liabilities 1,922.2 1,899.8
- ----------------------------------------------------------------------------------------------------------------------------
Other liabilities Deferred income taxes 498.7 503.3
Investment tax credits 32.3 36.9
Regulatory liability - tax related 1.7 10.0
Other deferred credits 253.1 202.8
Long-term debt, less amount due within one year 1,842.5 1,374.6
Preferred securities Redeemable preferred securities 200.0 200.0
Common equity Common equity (400 million shares authorized) 2,015.9 1,559.5
Unearned compensation (44.3) (52.6)
- ----------------------------------------------------------------------------------------------------------------------------
Total liabilities and capital $ 6,722.1 $ 5,734.3
============================================================================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
33
- -------------------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
- -------------------------------------------------------------------------------------------------------------------------------
(millions, except per share amounts) Year Ended Dec. 31, 2001 2000 1999
- -------------------------------------------------------------------------------------------------------------------------------
Revenues $ 2,648.6 $ 2,294.6 $ 1,978.3
- -------------------------------------------------------------------------------------------------------------------------------
Expenses Operation 1,611.8 1,322.1 1,053.0
Maintenance 151.3 140.0 125.3
Depreciation 298.0 268.2 232.2
Taxes, other than income 165.0 151.2 148.9
Total expenses 2,226.1 1,881.5 1,559.4
- -------------------------------------------------------------------------------------------------------------------------------
Income from operations 422.5 413.1 418.9
- -------------------------------------------------------------------------------------------------------------------------------
Other income (expense) Allowance for other funds
used during construction 6.6 1.6 1.3
Other income (expense) 38.6 13.9 (11.8)
Earnings from equity investments 6.7 7.7 3.2
Total other income (expense) 51.9 23.2 (7.3)
- -------------------------------------------------------------------------------------------------------------------------------
Income before interest and income taxes 474.4 436.3 411.6
- --------------------------------------------------------------------------------------------------------------------------------
Interest charges Interest expense 166.4 167.6 124.2
Distribution on preferred securities 17.0 - -
Allowance for borrowed funds used
during construction (2.6) (0.7) (0.5)
Total interest charges 180.8 166.9 123.7
- --------------------------------------------------------------------------------------------------------------------------------
Income before provision for income taxes 293.6 269.4 287.9
Provision (benefit) for income taxes (10.1) 18.5 87.0
- -------------------------------------------------------------------------------------------------------------------------------
Net income from continuing operations 303.7 250.9 200.9
Net loss from discontinued operations, net of income tax benefit of $1.4 million for 1999 - - (2.5)
Net loss on disposal of discontinued operations, net of income tax benefit of $7.4 million
for 1999 - - 12.3)
- -------------------------------------------------------------------------------------------------------------------------------
Net income $ 303.7 $ 250.9 186.1
- -------------------------------------------------------------------------------------------------------------------------------
Average common shares outstanding during year
- Basic 134.5 125.9 131.0
- Diluted 135.4 126.3 131.2
- -------------------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------------------
Earnings per average common share outstanding From continuing operations
- Basic $ 2.26 $ 1.99 $ 1.53
- Diluted $ 2.24 $ 1.97 $ 1.53
Net income
- Basic $ 2.26 $ 1.99 $ 1.42
- Diluted $ 2.24 $ 1.97 $ 1.42
- -------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of the consolidated financial
statements.
34
- ------------------------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
- ------------------------------------------------------------------------------------------------------------------------------------
(millions) Year Ended Dec. 31, 2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------------
Cash flows from operating activities Net income $ 303.7 $ 250.9 $ 186.1
Adjustments to reconcile net income to net cash from
operating activities:
Depreciation 298.0 268.2 232.2
Deferred income taxes (102.9) (77.6) (15.3)
Investment tax credits, net (4.9) (4.8) (5.0)
Allowance for funds used during construction (9.2) (2.3) (1.8)
Amortization of unearned compensation 9.7 9.2 9.1
Gain on propane business disposal/sale, pretax -- (13.6) --
Loss on disposal of discontinued operations, pretax -- -- 19.8
Equity in earnings of unconsolidated affiliates (3.1) (7.6) 1.2
Asset valuation adjustment, pretax 11.1 14.2 --
Deferred revenue -- -- 11.9
Deferred recovery clause (19.0) (68.7) (38.2)
Refund to customers -- (13.2) --
Charges (discussed in Note L) -- -- 21.1
Receivables, less allowance for uncollectibles 52.0 (92.1) (25.3)
Inventories (22.8) 7.5 5.0
Taxes accrued 16.4 17.6 31.7
Interest accrued (6.3) 25.5 (7.2)
Accounts payable (51.3) 42.6 (25.3)
Other 41.7 30.5 (18.7)
----------------------------------------------------------------------------------------------
Cash flows from operating activities 513.1 386.3 381.3
- ------------------------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities Capital expenditures (965.9) (688.4) (426.1)
Allowance for funds used during construction 9.2 2.3 1.8
Purchase of minority interest -- (52.6) (49.1)
Purchase of business (315.8) (31.3) --
Net proceeds from sale of assets 43.2 61.3 1.0
Investment in unconsolidated affiliates 27.6 (7.7) 0.2
Other non-current investments 95.7 (333.4) (32.7)
----------------------------------------------------------------------------------------------
Cash flows from investing activities (1,106.0) (1,049.8) (504.9)
- ------------------------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities Dividends (184.2) (167.4) (168.8)
Common stock 348.4 18.3 0.3
Purchase of treasury stock -- (29.9) (114.8)
Proceeds from long-term debt 1,255.9 394.9 28.0
Repayment of long-term debt (236.5) (145.6) (35.2)
Net increase (decrease) in short-term debt (570.1) 395.3 494.7
Issuance of redeemable preferred securities -- 200.0 --
----------------------------------------------------------------------------------------------
Cash flows from financing activities 613.5 665.6 204.2
----------------------------------------------------------------------------------------------
Net increase in cash and cash equivalents 20.6 2.1 80.6
Cash and cash equivalents at beginning of year 99.6 97.5 16.9
----------------------------------------------------------------------------------------------
Cash and cash equivalents at end of year $ 120.2 $ 99.6 $ 97.5
- ------------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------------
Supplemental disclosure of cash flow
information Cash paid during the year for
Interest (net of amounts capitalized) $ 178.1 $ 166.7 $ 116.9
Income taxes $ 52.4 $ 83.9 $ 62.1
- ------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of the consolidated financial
statements.
35
- --------------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF COMMON EQUITY
- --------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------------------------------
Additional Accumulated Other
Shares(1) Common Paid-in Treasury Retained Comprehensive Unearned Total Common
(millions) Stock Capital Stock Earnings Income (Loss) Compensation Equity
- --------------------------------------------------------------------------------------------------------------------------------
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,
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
Net income for 2001 303.7 303.7
Other comprehensive income
(loss), after tax (18.9) (18.9)
Common stock issued 13.3 6.3 203.2 144.7 (5.8) 348.4
Cash dividends declared (184.2) (184.2)
Amortization of unearned
compensation 9.7 9.7
Tax benefits-ESOP dividends and
stock options 0.2 1.4 1.6
Performance shares 4.4 4.4
- --------------------------------------------------------------------------------------------------------------------------------
Balance, Dec. 31, 2001 139.6 $139.6 $600.7 $ -- $1,298.0 $(22.4) $(44.3) $1,971.6
================================================================================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
(1) TECO Energy had 400 million shares of $1 par value common stock authorized
in 2001, 2000 and 1999.
36
- --------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
A. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The significant accounting policies for both utility and diversified
operations are as follows:
Principles of Consolidation
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
power, 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 incurred and 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. In February
1995, the FPSC authorized the recovery of this 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 2001, 2000 and 1999, $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 from 1996 through 1999 and
securing fair earnings opportunities during this period were accomplished
through a series of agreements entered into in 1996 with Florida's 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 1 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 and refunds to
customers totaling $50 million during the period October 1996 through December
1998 while Tampa Electric was allowed recovery of the capital costs incurred for
the Polk Unit 1 project.
As part of its series of agreements with OPC and FIPUG, Tampa Electric 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 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 decision. The protest claimed that the stipulations did not
allow for the inclusion of the interest expenses on income tax positions in the
refund calculations. The FPSC held hearings on the issue in August 2001 and
upheld its decision that the original refund amount plus interest was
appropriate under the agreements. In January 2002, the OPC filed a motion with
the FPSC asking for reconsideration of their decision alleging the Commission
relied on erroneous information. Tampa Electric will begin making refunds to
customers when the decision can no longer be appealed.
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 expects to
continue earning within its allowed ROE.
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 4.2% for 2001, 4.1% for 2000 and 4.0% for 1999.
The original cost of utility plant retired or otherwise disposed of and the
cost of removal less salvage are charged to accumulated depreciation.
Goodwill and Intangible Assets
Goodwill represents the excess of acquisition costs over the fair value of
the net assets acquired in purchase transactions. Goodwill has been amortized on
a straight-line basis over various periods not exceeding 40 years. On June 30,
2001, the Financial Accounting Standards Board finalized FAS 141, Business
Combinations, and FAS 142, Goodwill and Other Intangible Assets. FAS 141
requires all business combinations initiated after June 30, 2001, to be
accounted for using the purchase method of accounting. With the adoption of FAS
142 effective Jan. 1,
37
2002, goodwill is no longer subject to amortization. Rather, goodwill will be
subject to at least an annual assessment for impairment by applying a
fair-value-based test. Under the new rules, an acquired intangible asset should
be separately recognized if the benefit of the intangible asset is obtained
through contractual or other legal rights, or if the intangible asset can be
sold, transferred, licensed, rented, or exchanged, regardless of the acquirer's
intent to do so. These intangible assets will be required to be amortized over
their useful lives.
The amount of goodwill included on the consolidated balance sheets at Dec.
31, 2001 and 2000, respectively, was $165.8 million and $93.1 million, net of
accumulated amortization of $9.5 million and $4.7 million. Additions to goodwill
in 2001 of $77.5 million resulted primarily from the acquisition of the Frontera
Power Station and the purchase of Prior Energy.
Amortization of goodwill included in the consolidated statements of income in
2001, 2000 and 1999 was $4.8 million, $2.7 million and $0.6 million,
respectively. Adoption of FAS 142 effective Jan. 1, 2002 will result in the
elimination of approximately $5 million of annual amortization. Under FAS 142,
initial impairment testing should be completed within six months of adoption.
TECO Energy is beginning the initial impairment testing of all goodwill, and
does not anticipate an initial impairment charge upon adoption of FAS 142.
The amount of intangible assets included in deferred charges and other assets
on the consolidated balance sheet at Dec. 31, 2001 was $28.5 million, net of
accumulated amortization of $12.3 million. This represents the value of customer
backlog, supply agreements and the open cash flow hedges as of Nov. 1, 2001,
related to the Prior Energy acquisition in November 2001 (see Note N). The
company is amortizing the intangibles over the periods expected to benefit from
these agreements, and recorded amortization expense of $12.3 million in 2001.
Amortization expense for the remaining intangible value at Dec. 31, 2001 is
expected to be $27.2 million in 2002 and $1.3 million in 2003. There were no
intangible assets at Dec. 31, 2000.
Asset Impairment
In August 2001, the Financial Accounting Standards Board issued FAS 144,
Accounting for the Impairment or Disposal of Long-Lived Assets, which supersedes
FAS 121, Accounting for the Impairment of Long-Lived Assets and Long-Lived
Assets to be Disposed of. FAS 144 addresses accounting and reporting for the
impairment or disposal of long-lived assets, including the disposal of a segment
of a business. FAS 144 is effective for fiscal years beginning after December
15, 2001.
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, and beginning in 2002 with FAS 144. The
company does not anticipate that the adoption of FAS 144 will have a significant
impact on its financial statements. In 2001, TECO Energy recorded after-tax
charges of $7.2 million to adjust asset valuations. These adjustments included a
$6.1 million after-tax charge recorded by TECO Power Services (TPS) related to
the subsequent sale of TPS' minority interests in Energia Global International,
Ltd. (EGI) which owns smaller power projects in Central America, and a $1.1
million after-tax charge to adjust the carrying value of leveraged leases at
TECO Investments. In 2000, TECO Properties recorded an after-tax charge of $3.8
million to adjust property values. 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 financial statements. The company has reported accumulated other
comprehensive income in its Consolidated Statements of Common Equity. TECO
Energy reported the following comprehensive income (loss) in 2001, 2000 and 1999
related to changes in the fair value of cash flow hedges and adjustments to the
minimum pension liability associated with the company's supplemental executive
retirement plan:
- --------------------------------------------------------------------------------
COMPREHENSIVE INCOME (LOSS)
- --------------------------------------------------------------------------------
(millions) 2001 2000 1999
- --------------------------------------------------------------------------------
Minimum pension liability $ 0.3 $ 2.0 $ (5.5)
Cash flow hedges (19.2) -- --
- --------------------------------------------------------------------------------
Other comprehensive income (loss) (18.9) 2.0 (5.5)
Net income 303.7 250.9 186.1
- --------------------------------------------------------------------------------
Total comprehensive income $284.8 $252.9 $180.6
================================================================================
Reporting on the Costs of Start-up Activities
In 1998, the AICPA issued Statement of Position (SOP) 98-5, Reporting on the
Costs of Startup Activities. It requires costs of start-up activities and
organization costs to be expensed as incurred. Start-up 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. Start-up costs, as
defined by SOP 98-5, are expensed as incurred.
Accounting for Asset Retirement Obligations
In July 2001, the Financial Accounting Standards Board finalized FAS 143,
Accounting for Asset Retirement Obligations, which requires the recognition of a
liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the carrying amount of the
related long-lived asset is correspondingly increased. Over time, the liability
is accreted to its present value and the related capitalized charge is
depreciated over the useful life of the asset. FAS 143 is effective for fiscal
years beginning after June 15, 2002. The company is currently reviewing the
impact that FAS 143 will have on its results.
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 2001, 2000 and 1999 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.
38
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 2001, 2000 and 1999. Total AFUDC for 2001, 2000 and 1999
was $9.2 million, $2.3 million and $1.8 million, respectively. 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. TECO Energy
capitalized $23.0 million, $6.5 million and $2.7 million of interest costs in
2001, 2000 and 1999, respectively.
Cash Equivalents
Cash equivalents are highly liquid, high-quality debt instruments purchased
with an original maturity or three months or less. The carrying amount of cash
equivalents approximated fair market value because of the short maturity of
these instruments.
Other Investments
Other investments include longer-term passive investments. Other investments
at Dec. 31, 2001 and 2000 were as follows:
- --------------------------------------------------------------------------------
Due
(millions) Rate Date 2001 2000
- --------------------------------------------------------------------------------
Notes receivable from:
Panda Energy 12% 12/31/02 $ 92.7 $ 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
Mosbacher Power Partners L.P. 12% 8/1/08 13.1 13.0
Mosbacher Power Partners L.P. 9% 8/1/08 21.1 20.4
Mosbacher Power Partners L.P. 12% 10/4/06 6.2 4.8
EEGSA 7.89% (1) 9/11/07 10.9 10.9
TECO-Panda Generating Company, L.P. 7.33% (1) 11/30/04 37.5 --
TECO-Panda Generating Company, L.P. 6.65% (1) 11/30/04 86.7 --
Investment in Energy Center Kladno
Generating (ECKG) (2) -- -- 18.2 18.2
Continuing Investments in
Leveraged Leases -- -- 15.6 22.1
Other investments -- -- 1.1 0.8
- --------------------------------------------------------------------------------
303.1 406.0
Current notes receivable 92.7 223.1
- --------------------------------------------------------------------------------
Other non-current investments $210.4 $182.9
================================================================================
(1) Current rate at 12/31/01.
(2) 13.35% ownership interest in an electric generating power project in the
Czech Republic.
These financial investments 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, 2001, these investments included TECO Propane
Ventures' 38 percent ownership interest in US Propane, TPS' 24 percent ownership
interest in EEGSA, the Guatemalan electric utility, TPS' 50 percent voting
interest in the TECO-Panda Generating Company L.P., TPS' 50 percent ownership
interest in the Hamakua Power Station in Hawaii and TECO Properties' 50 percent
ownership interest in six real estate projects. At Dec. 31, 2000, the investment
in unconsolidated affiliates included the US Propane, EEGSA, Hamakua and real
estate investments as well as TPS' 33.68 percent ownership interest in EGI.
Summary financial information for TECO-Panda Generating Company, L.P., a
development stage enterprise, as of Dec. 31, 2001 and 2000 is presented in the
following table. There were no revenues for the year ended Dec. 31, 2001 and for
the period of inception through Dec. 31, 2000. Results from operations were not
material for these periods.
- --------------------------------------------------------------------------------
(millions) Dec. 31, 2001 Dec. 31, 2000
- --------------------------------------------------------------------------------
Current assets $ 102.6 $ 1.3
Non-current assets $1,857.4 $ 217.9
Current liabilities $ 209.6 $ 231.9
Non-current liabilities $1,844.0 $ --
- --------------------------------------------------------------------------------
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 producing wells at Dec. 31, 2001 and
2000 were $220.8 million and $216.2 million, respectively. Net proven reserves
at Dec. 31, 2001 and 2000 were as follows:
- --------------------------------------------------------------------------------
NET PROVEN RESERVES - COALBED METHANE GAS
- --------------------------------------------------------------------------------
(billion cubic feet) 2001 2000
- --------------------------------------------------------------------------------
Proven reserves, beginning of year 181.7 159.1
Production (15.0) (15.7)
Revisions of previous estimates 0.4 38.3
- --------------------------------------------------------------------------------
Proven reserves, end of year 167.1 181.7
- --------------------------------------------------------------------------------
Number of wells 682 700
- --------------------------------------------------------------------------------
Accounting for Derivative Instruments, Hedging and Energy Trading
Effective January 1, 2001, the company adopted Financial Accounting Standard
(FAS) 133, Accounting for Derivative Instruments and Hedging. 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. At adoption, the company had derivatives in place at TECO Coalbed
Methane that qualified for cash flow hedge accounting treatment under FAS 133,
and recorded an opening swap liability of $19.0 million and an after-tax
reduction to other comprehensive income of $12.6 million.
39
At the time derivative contracts are entered into, the company determines
whether the derivative is subject to the requirements of FAS 133 or meets
criteria for exclusion such as for certain normal purchases and sales activity.
All contracts requiring FAS 133 accounting are designated as a cash flow hedge,
fair value hedge or as a trading instrument, and formal documentation of
relationships between hedging instruments and the hedged items, hedging
objective and strategy, and methods for assessing hedge effectiveness both at
the hedge's inception and on an ongoing basis is completed.
From time to time, TECO Energy enters into futures, swaps and options
contracts to hedge the future selling price for its physical production at TECO
Coalbed Methane, to limit exposure to gas price fluctuations for future
purchases at Peoples Gas System and at Prior Energy, to limit exposure to
interest rate fluctuations at TECO Energy and other affiliates, to limit
exposure to electricity and other commodity fluctuations at TECO Power Services,
and to limit exposure to fuel price increases on future purchases at TECO
Transport. As such, most of the company's derivative activity that cannot be
excluded from the requirements of FAS 133 receives cash flow hedge accounting
treatment.
Cash Flow Hedges: For the year ended Dec. 31, 2001, the company recognized a
loss of $19.7 million for the cash flow hedges that were settled. Of this
amount, $6.5 million was reported as a reduction to revenue related to hedges of
future sales at TECO Coalbed Methane, and $13.2 million was reported as
operating expenses related to hedges of future gas purchases at Peoples Gas and
Prior Energy. As of Dec. 31, 2001, the company had open hedging transactions
that qualify for cash flow hedge accounting treatment at Prior Energy, TECO
Coalbed Methane, Peoples Gas and TECO Transport with a net pretax liability fair
value of $29.5 million. Of this total, $28.2 million is expected to be
reclassified to earnings within the next twelve months on instruments with
maturity dates throughout 2002 when the related future transactions take place.
Unrealized after tax losses on all open cash flow hedges of $8.1 million were
recorded as a reduction to other comprehensive income. An additional $17.4
million representing open cash flow hedges prior to the Nov. 1, 2001 acquisition
of Prior Energy were recorded as a deferred charge.
The company, through its TECO Power Services subsidiary, has an equity
investment in a partnership with Panda Energy. The partnership utilizes interest
rate swap agreements to effectively convert a portion of its floating rate debt
to a fixed rate basis, thereby reducing the impact of interest rate changes on
construction costs and future income. On the interest rate swap agreements, the
partnership pays a fixed rate and receives a variable rate based on London
Interbank Offered Rate (LIBOR), with terms ranging from 2 to 5 years. At Dec.
31, 2001, the company recorded $11.2 million for its equity portion of the
unrealized losses on these cash flow hedge swaps reflecting the sharp decline in
floating interest rates since the inception of the swap agreements as a
reduction to other comprehensive income and a corresponding reduction to the
investment account.
Fair Value Hedges: For the year ended Dec. 31, 2001, the company recognized
gains of $0.1 million as operating expenses for changes in the fair value of
derivatives classified as fair value hedges. As of Dec. 31, 2001, the company
had open hedging transactions against gas storage inventory at Prior Energy that
qualify for fair value hedge accounting treatment with a net derivative asset
pretax value of $0.9 million, all of which is expected to be reclassified to
earnings within the next twelve months.
Trading Derivatives: The company has entered into a limited number of
financial derivatives at its TECO Power Services and Prior Energy affiliates
which do not qualify for hedge accounting treatment under FAS 133. TECO Power
Services has a capacity call option, which is marked-to-market. The fair value
of these options is determined using an industry standard model from the
Financial Engineering Association which is based on the Black-Scholes valuation
model and evaluates current prices, volatility of prices, and time to expiration
of the options. For the year ended Dec. 31, 2001, the company recognized a
pretax loss of $0.8 million for the decrease in fair value on these options. As
of Dec. 31, 2001, the $1.5 million fair value of these options is included in
current assets, all of which is expected to be realized within the next twelve
months. As of Dec. 31, 2001, Prior Energy had several open swap and option
positions where they acted as the counterparty to the transactions. These
contracts are marked-to-market under FASB's Emerging Issues Task Force (EITF)
release Issue 98-10, Accounting for Contracts Involved in Energy Trading and
Risk Management Activities. The fair value of these derivatives is determined
using the Henry Hub Natural Gas futures prices as actively quoted on New York
Mercantile Exchange (NYMEX). For the year ended Dec. 31, 2001, the company
recognized $0.7 million in pretax losses related to these derivatives. As of
Dec. 31, 2001, $7.5 million of pretax fair value of open liability positions is
offset by $7.4 million of open asset positions, all of which are expected to be
realized within the next twelve months.
Reclassifications
Certain prior year amounts were reclassified to conform with current year
presentation.
- --------------------------------------------------------------------------------
B. COMMON STOCK
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"), and no additional grants will be made under the 1990 Plan. The rights of
the holders of outstanding options under the 1990 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 2001, under the 1996 Plan, 1,268,486 stock options were granted, with a
weighted average option price of $31.39 and a maximum term of 10 years. In
addition, 183,260 shares of restricted stock were awarded, each with a weighted
average fair value of $31.575. Compensation expense recognized for stock grants
awarded under the 1996 Plan was $2.8 million, $4.6 million and $1.6 million in
2001, 2000 and 1999, respectively. The stock grants awarded in 2001, 2000 and
1999 are primarily performance shares, 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. Adjustments are made currently to
reflect contingent shares which could be issuable based on current period
results. The consolidated balance sheets at Dec. 31, 2001 and 2000 reflected a
$1.1 million and a $5.5 million liability respectively, 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 April 2001, the shareholders approved an amendment to the 1996 Plan, 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 and
the 1990 Plan (collectively referred to as the "Equity Plans") are summarized as
follows:
40
- --------------------------------------------------------------------------------
STOCK OPTIONS - EQUITY PLANS
- --------------------------------------------------------------------------------
Option Shares Weighted Avg.
(thousands) Option Price
- --------------------------------------------------------------------------------
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
Granted 1,268 $31.39
Exercised (605) $21.53
Cancelled (32) $26.88
- --------------------------------------------------------------------------------
Balance at Dec. 31, 2001 5,190 $24.79
================================================================================
Exercisable at Dec. 31, 2001 2,068 $21.88
Available for future grant at Dec. 31, 2001 6,262
- --------------------------------------------------------------------------------
As of Dec. 31, 2001, the 5.2 million options outstanding under the Equity
Plans are summarized below.
- --------------------------------------------------------------------------------
STOCK OPTIONS OUTSTANDING AT DEC. 31, 2001
- --------------------------------------------------------------------------------
Option Shares Range of Weighted Avg. Weighted Avg. Remaining
(thousands) Option Prices Option Price Contractual Life
- --------------------------------------------------------------------------------
2,566 $18.84-$22.48 $21.08 7 Years
744 $23.55-$25.97 $24.05 4 Years
1,880 $27.56-$31.58 $30.15 8 Years
================================================================================
In April 1997, the Shareholders approved the 1997 Director Equity Plan (the
"1997 Plan"), as an amendment and restatement of the 1991 Director Stock Option
Plan (the "1991 Plan"). The 1997 Plan supersedes the 1991 Plan, and no
additional grants will be made under the 1991 Plan. The rights of the holders of
outstanding options under the 1991 Plan will not be affected. The purpose of the
1997 Plan is to attract and retain highly qualified non-employee directors of
the company and to encourage them to own shares of TECO Energy common stock. The
1997 Plan is administered by the Board of Directors. The 1997 Plan amended the
1991 Plan to increase the number of shares of common stock subject to grants by
250,000 shares, expanded the types of awards available to be granted and
replaced the current fixed formula grant by giving the Board discretionary
authority to determine the amount and timing of awards under the Plan.
In 2001, 35,000 options were granted, with a weighted average option price
of $31.26. Transactions during the last three years under the 1997 Plan are
summarized as follows:
- --------------------------------------------------------------------------------
STOCK OPTIONS - DIRECTOR EQUITY PLANS
- --------------------------------------------------------------------------------
Option Shares Weighted Avg.
(thousands) Option Price
- --------------------------------------------------------------------------------
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
Granted 35 $31.26
Exercised (91) $19.12
Cancelled -- --
- --------------------------------------------------------------------------------
Balance at Dec. 31, 2001 202 $24.49
================================================================================
Exercisable at Dec. 31, 2001 142 $22.27
Available for future grant at Dec. 31, 2001 302
- --------------------------------------------------------------------------------
41
As of Dec. 31, 2001, the 202,000 options outstanding under the 1997 Plan
with option prices of $18.53-$31.575, had a weighted average option price of
$24.49 and a weighted average remaining contractual life of six 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.
- --------------------------------------------------------------------------------
2001 2000 1999
- --------------------------------------------------------------------------------
Net Income from As reported $303.7 $250.9 $200.9
continuing operations (millions) Pro forma $298.6 $247.8 $198.5
- --------------------------------------------------------------------------------
Net Income (millions) As reported $303.7 $250.9 $186.1
Pro forma $298.6 $247.8 $183.7
- --------------------------------------------------------------------------------
Net Income from
continuing operations As reported $ 2.26 $ 1.99 $ 1.53
- - EPS basic Pro forma $ 2.22 $ 1.97 $ 1.52
- --------------------------------------------------------------------------------
Net Income As reported $ 2.26 $ 1.99 $ 1.42
- - EPS basic Pro forma $ 2.22 $ 1.97 $ 1.40
- --------------------------------------------------------------------------------
Assumptions
Risk-free interest rate 4.86% 6.24% 5.26%
Expected lives (in years) 6 6 6
Expected stock volatility 27.45% 22.93% 19.14%
Dividend yield 5.46% 5.15% 4.55%
- --------------------------------------------------------------------------------
Dividend Reinvestment Plan
In 1992, TECO Energy implemented a Dividend Reinvestment and Common Stock
Purchase Plan (DRP). TECO Energy raised $8.6 million and $8.1 million of common
equity from this plan in 2001 and 2000, respectively. In 1999 the DRP purchased
shares of TECO Energy common stock on the open market for plan participants.
Common Stock and Treasury Stock
In September 1999, TECO Energy began a program to repurchase up to $150
million of its outstanding common stock. Shares acquired constituted treasury
shares. In 1999 and 2000, the company 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.
On March 12, 2001, the company completed a public offering of 8.625 million
common shares at $27.75 per share, 7.0 million shares of which were reissued
from Treasury shares. On Oct. 4, 2001, Standard and Poor's (S&P) announced the
inclusion of TECO Energy shares in the S&P 500 index effective as of the market
close on Oct. 9, 2001. On Oct. 12, 2001, TECO Energy issued 3.5 million
additional common shares at $26.72 per share. The sales of the common shares
resulted in total net proceeds to TECO Energy of $325.5 million in 2001, which
were used to fund capital expenditures, for working capital requirements,
general corporate purposes and to repay short-term debt.
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 $5.6 million, $6.8 million,
and $7.5 million in 2001, 2000 and 1999, 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) 2001 2000 1999
- --------------------------------------------------------------------------------
Interest expense $ 5.2 $ 6.0 $ 6.9
Compensation expense 7.4 6.9 7.5
Dividends (8.5) (8.5) (8.4)
- --------------------------------------------------------------------------------
Net ESOP expense $ 4.1 $ 4.4 $ 6.0
================================================================================
Compensation expense was determined by the shares allocated method.
At Dec. 31, 2001, the ESOP had 3.4 million allocated shares, 0.2 million
committed-to-be-released shares, and 2.6 million unallocated shares. Shares are
released to provide employees with the company match in accordance with the
terms of the TECO Energy Group Retirement Savings Plan and in lieu of dividends
on allocated ESOP shares. The dividends received by the ESOP are used to pay
debt service.
For financial statement purposes, the unallocated shares of TECO Energy
stock are reflected as a reduction of common equity, classified as unearned
compensation. Dividends on all ESOP shares are recorded as a reduction of
retained earnings, as are dividends on all TECO Energy common stock. The tax
benefit related to the dividends paid to the ESOP for allocated shares is a
reduction of income tax expense and for unallocated shares is an increase in
retained earnings. All ESOP shares are considered outstanding for earnings per
share computations.
- --------------------------------------------------------------------------------
C. 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. Distributions
are payable quarterly in arrears on January 31, April 30, July 31, and October
31 of each year. Distributions were $17.0 million in 2001. No distributions were
made in 2000.
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.
- -----------------------------------------------------------------------------------------------------------------------------------
E. LONG-TERM DEBT (millions) December 31, Due 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------------
TECO Energy Medium-term notes payable: 5.31% (1)(2) 2002 $ 200.0 $ 200.0
Medium-term notes payable: 7.20% (3) 2011 600.0 --
Medium-term notes payable: 5.35% (1) 2001 -- 150.0
Floating rate notes: 5.2% for 2001 (1)(4) 2002 400.0 --
----------------------------------------------------------------------------------------------------
1,200.0 350.0
- -----------------------------------------------------------------------------------------------------------------------------------
Tampa Electric First mortgage bonds (issuable in series):
7.75% 2022 75.0 75.0
6.125% 2003 75.0 75.0
Installment contracts payable (5):
5.75% 2007 22.5 22.9
7.875% Refunding bonds (6) 2021 25.0 25.0
8% Refunding bonds (6) 2022 100.0 100.0
6.25% Refunding bonds (7) 2034 86.0 86.0
5.85% 2030 75.0 75.0
Variable rate: 1.45% for 2001 and 3.77% for 2000 (1) 2025 51.6 51.6
Variable rate: 1.47% for 2001 and 3.90% for 2000 (1) 2018 54.2 54.2
Variable rate: 1.52% for 2001 and 3.96% for 2000 (1) 2020 20.0 20.0
Medium-term notes payable: 5.11% (1) 2001 -- 38.0
Medium-term notes payable: 5.86% (1)(8) 2002 100.0 100.0
Medium-term notes payable: 6.875% (3) 2012 210.0 --
----------------------------------------------------------------------------------------------------
894.3 722.7
- -----------------------------------------------------------------------------------------------------------------------------------
Peoples Gas System Senior Notes (9)
10.35% 2007 5.0 5.6
10.33% 2008 6.4 7.2
10.3% 2009 7.8 8.4
9.93% 2010 8.0 8.6
8.0% 2012 27.5 29.0
Medium-term notes payable: 5.11% (1) 2001 -- 12.0
Medium-term notes payable: 5.86% (1)(8) 2002 50.0 50.0
Medium-term notes payable: 6.875% (3) 2012 40.0 --
----------------------------------------------------------------------------------------------------
144.7 120.8
- -----------------------------------------------------------------------------------------------------------------------------------
Diversified Companies Dock and wharf bonds, fixed rate of 5.0% for 2001,
variable rate of 3.79% for 2000 (1)(5) 2007 110.6 110.6
Non-recourse secured facility notes, Series A: 7.8% 2002-2012 118.5 125.5
Non-recourse secured facility notes: 9.875% 2002-2008 17.1 19.5
Non-recourse secured facility notes, variable rate:
5.43% for 2001 and 9.55% for 2000 (1) 2002-2007 57.9 65.0
Non-recourse secured facility notes: 10.1% 2002-2009 16.9 17.0
Non-recourse secured facility notes: 9.629% 2002-2010 28.0 31.2
Capital lease: implicit rate of 8.5% 2002-2003 27.6 29.7
Construction financing, 7.82% 2001 -- 10.1
----------------------------------------------------------------------------------------------------
376.6 408.6
- -----------------------------------------------------------------------------------------------------------------------------------
TECO Finance Medium-term notes payable, various rates:
7.54% for 2001 and 2000 (1) 2002 9.0 9.0
- -----------------------------------------------------------------------------------------------------------------------------------
Unamortized debt premium (discount), net 6.7 0.8
- -----------------------------------------------------------------------------------------------------------------------------------
2,631.3 1,611.9
- -----------------------------------------------------------------------------------------------------------------------------------
Less amount due within one year (10) 788.8 237.3
- -----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt $1,842.5 $1,374.6
===================================================================================================================================
(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 redemption in whole or in part, at any time, at
the option of the company.
(4) These notes are callable at par on or after Nov. 15, 2001.
(5) Tax-exempt securities.
(6) 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.
(7) 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.
(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) Of the amount due in 2002, $0.8 million may be satisfied by the
substitution of property in lieu of cash payments.
43
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, 2001:
- --------------------------------------------------------------------------------
Year ended Dec. 31: Amount (millions)
- --------------------------------------------------------------------------------
2002 $ 4.6
2003 25.8
- --------------------------------------------------------------------------------
Total minimum lease payments 30.4
Less: Amount representing interest 2.8
- --------------------------------------------------------------------------------
Present value of net minimum lease payments,
including current maturities of $2.3 million $ 27.6
================================================================================
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 2003, 2004,
2005 and 2006 are $129.9 million, $31.6 million, $34.2 million and $36.5
million, respectively. Of these amounts $0.8 million per year for 2003 through
2006 may be satisfied by the substitution of property in lieu of cash payments.
At Dec. 31, 2001, total long-term debt had a carrying amount of $1,842.5
million and an estimated fair market value of $1,966.0 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 1.99% and 6.53%, at Dec. 31, 2001 and 2000, respectively. The
carrying amount of notes payable approximated fair market value because of the
short maturity of these instruments.
The company has in place a $1 billion syndicated line of credit facility,
comprised of $700 million for TECO Energy and $300 million for Tampa Electric
Company. There were no borrowings outstanding at Dec. 31, 2001. These lines of
credit require commitment fees ranging from .08% to .13% on the unused balances.
Within this $1 billion facility, TECO Energy has $250 million of capacity to
issue letters of credit. See Note O for January and February 2002 activity
related to these letters of credit.
- --------------------------------------------------------------------------------
G. EMPLOYEE POSTRETIREMENT BENEFITS
Pension Benefits
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. On 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.,
were largely unchanged. This amendment resulted in decreased pension expense of
approximately $.8 million and $2.0 million in 2001 and 2000, respectively, and a
reduction of benefit obligation of $6.2 million and $14.4 million at Sept. 30,
2001 and Dec. 31, 2000, respectively.
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 60 percent of plan assets were invested in common stock and 40
percent in fixed income investments at Sept. 30, 2001.
Amounts shown also include the unfunded obligations for the supplemental
executive retirement plans, non-qualified, non-contributory defined benefit
retirement plans available to certain senior management. TECO Energy reported
$0.3 million and $2 million of comprehensive income in 2001 and 2000,
respectively, 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 2001, TECO Energy elected to change the measurement date for pension
obligations and plan assets from Dec. 31 to Sept. 30. The effect of this
accounting change is not material.
Other Postretirement Benefits
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 who retired after Jan. 1, 1990
and before July 1, 2001, is limited to a defined dollar benefit based on years
of service. On 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, including a change in the company's
commitment for future retirees combined with a grandfathering provision for
current retired participants, resulted in a reduction in the benefit obligation
of $1.4 million in 2001 and an increase of $22.9 million in 2000. 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.
In 2001, TECO Energy elected to change the measurement date for benefit
obligations from Dec. 31 to Sept. 30. The effect of this accounting change is
not material.
44
The following charts summarize the income statement and balance sheet impact,
as well as the benefit obligations, assets, funded status and rate assumptions
associated with the pension and other postretirement benefits.
- -----------------------------------------------------------------------------------------------------------------------------
Pension Benefits
(millions) 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------------------------
Components of net periodic benefit expense Service cost (benefits earned during the period) $ 11.2 $ 10.7 $ 12.9
Interest cost on projected benefit obligations 27.9 27.5 27.2
Expected return on assets (42.0) (40.8) (34.6)
Amortization of:
Transition obligation (asset) (1.1) (1.0) (0.9)
Prior service cost (benefit) (0.5) 0.2 1.2
Actuarial (gain) loss (4.4) (5.6) 5.2
--------------------------------------------------------------------------------
Pension expense (8.9) (9.0) 11.0
Special termination benefit charge -- 1.1 --
Additional amounts recognized -- -- --
--------------------------------------------------------------------------------
Net pension (benefit) expense recognized in the
Consolidated Statements of Income $ (8.9) $ (7.9) $ 11.0
- -----------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------
Other Postretirement Benefits
(millions) 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------------------------
Components of net periodic benefit expense Service cost (benefits earned during the period) $ 3.4 $ 3.0 $ 3.6
Interest cost on projected benefit obligations 10.9 8.9 6.9
Expected return on assets -- -- --
Amortization of:
Transition obligation (asset) 2.7 2.7 2.7
Prior service cost (benefit) 2.0 1.7 0.6
Actuarial (gain) loss 0.4 (0.2) 0.2
--------------------------------------------------------------------------------
Pension expense 19.4 16.1 14.0
Special termination benefit charge -- 0.2 --
Additional amounts recognized -- 0.9 --
--------------------------------------------------------------------------------
Net pension (benefit) expense recognized in the
Consolidated Statements of Income $ 19.4 $ 17.2 $ 14.0
- -----------------------------------------------------------------------------------------------------------------------------
The projected benefit obligation, accumulated benefit obligation and fair
value of plan assets for non-qualified pension plans with accumulated benefit
obligations in excess of plan assets were $27.3 million, $23.5 million and $0
respectively as of Sept. 30, 2001 and $26.1 million, $23.0 million and $0 as of
Dec. 31, 2000.
- ------------------------------------------------------------------------------------------------------------------------------
Pension Benefits
(millions) 2001 2000
- ------------------------------------------------------------------------------------------------------------------------------
Change in benefit obligation Net benefit obligation at prior measurement date $379.9 $360.4
Change in benefit obligation due to:
Service cost 11.2 10.7
Interest cost 27.9 27.5
Plan participants' contributions -- --
Actuarial (gain) loss (8.7) 17.8
Plan amendments (6.2) (14.4)
Special termination benefits -- 1.1
Gross benefits paid (21.8) (23.2)
----------------------------------------------------------------------------
Net benefit obligation at measurement date $382.3 $379.9
- ------------------------------------------------------------------------------------------------------------------------------
Change in plan assets Fair value of plan assets at prior measurement date $493.8 $512.1
Change in plan assets due to:
Actual return on plan assets (43.7) 6.2
Employer contributions 2.1 1.6
Plan participants' contributions -- --
Gross benefits paid (including expenses) (24.2) (26.1)
----------------------------------------------------------------------------
Fair value of plan assets at measurement date $428.0 $493.8
- ------------------------------------------------------------------------------------------------------------------------------
Funded status Funded status at measurement date $ 45.7 $113.9
Net contributions after measurement date 0.4 N/A
Unrecognized net actuarial (gain) loss (44.0) (127.8)
Unrecognized prior service cost (benefit) (9.0) (3.3)
Unrecognized net translation obligation (asset) (3.6) (4.7)
----------------------------------------------------------------------------
Accrued liability at end of year $(10.5) $(21.9)
- ------------------------------------------------------------------------------------------------------------------------------
Assumptions used in determining actuarial Discount rate to determine projected benefit
valuations obligation 7.5% 7.5%
Rate of increase in compensation levels 4.7% 4.7%
Plan asset growth rate through time 9.0% 9.0%
- ------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------------
Other Postretirement Benefits
(millions) 2001 2000
- ------------------------------------------------------------------------------------------------------------------------------------
Change in benefit obligation Net benefit obligation at prior measurement date $ 130.8 $ 93.1
Change in benefit obligation due to:
Service cost 3.4 3.0
Interest cost 10.9 8.9
Plan participants' contributions 0.9 1.1
Actuarial (gain) loss 11.6 8.5
Plan amendments (1.4) 22.9
Special termination benefits -- 0.2
Gross benefits paid (6.0) (6.9)
----------------------------------------------------------------------------------
Net benefit obligation at measurement date $ 150.2 $ 130.8
- ------------------------------------------------------------------------------------------------------------------------------------
Change in plan assets Fair value of plan assets at prior measurement
date $ -- $ --
Change in plan assets due to:
Actual return on plan assets -- --
Employer contributions 5.1 5.8
Plan participants' contributions 0.9 1.1
Gross benefits paid (including expenses) (6.0) (6.9)
----------------------------------------------------------------------------------
Fair value of plan assets at measurement date $ -- $ --
- ------------------------------------------------------------------------------------------------------------------------------------
Funded status Funded status at measurement date $(150.2) $(130.8)
Net contributions after measurement date 1.7 N/A
Unrecognized net actuarial (gain) loss 16.9 5.6
Unrecognized prior service cost (benefit) 24.3 27.7
Unrecognized net translation obligation (asset) 30.1 32.8
Accrued liability at end of year $ (77.2) $ (64.7)
- ------------------------------------------------------------------------------------------------------------------------------------
Assumptions used in determining actuarial Discount rate to determine projected benefit
valuations obligation 7.5% 7.5%
Rate of increase in compensation levels
Plan asset growth rate through time
- ------------------------------------------------------------------------------------------------------------------------------------
45
The assumed health care cost trend rate for medical costs prior to age 65 was
5.5% in 2001 and decreases to 5.0% in 2002 and thereafter. The assumed health
care cost trend rate for medical costs after age 65 was 5.3% in 2001 and
decreases to 5.0% in 2002 and thereafter.
A 1 percent increase in the medical trend rates would produce an 8 percent
($1.1 million) increase in the aggregate service and interest cost for 2001 and
an 8 percent ($12.0 million) increase in the accumulated postretirement benefit
obligation as of Sept. 30, 2001.
A 1 percent decrease in the medical trend rates would produce a 5 percent
($0.7 million) decrease in the aggregate service and interest cost for 2001 and
a 4 percent ($6.3 million) decrease in the accumulated postretirement benefit
obligation as of Sept. 30, 2001.
- --------------------------------------------------------------------------------
H. INCOME TAX EXPENSE
Income tax expense consists of the following components:
- --------------------------------------------------------------------------------
(millions) Federal State Total
- --------------------------------------------------------------------------------
2001
Currently payable $ 77.8 $ 19.9 $ 97.7
Deferred (95.5) (7.4) (102.9)
Amortization of investment tax credits (4.9) -- (4.9)
- --------------------------------------------------------------------------------
Total income tax expense $ (22.6) $ 12.5 $ (10.1)
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
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)
- --------------------------------------------------------------------------------
Income tax benefit from discontinued
operations (8.0) (0.8) (8.8)
- --------------------------------------------------------------------------------
Total income tax expense $ 64.9 $ 13.3 $ 78.2
- --------------------------------------------------------------------------------
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, 2001 2000
- --------------------------------------------------------------------------------
Deferred income tax assets (1)
Property related $ 87.7 $ 77.6
Basis differences in oil and gas producing properties 1.2 1.2
Alternative minimum tax credit carry forward 105.5 58.1
Other 47.6 37.5
- --------------------------------------------------------------------------------
Total deferred income tax assets 242.0 174.4
- --------------------------------------------------------------------------------
Deferred income tax liabilities (1)
Property related (522.8) (499.4)
Basis differences in oil and gas producing properties (8.9) (11.0)
Other 33.0 7.1
- --------------------------------------------------------------------------------
Total deferred income tax liabilities (498.7) (503.3)
- --------------------------------------------------------------------------------
Accumulated deferred income taxes $ (256.7) $ (328.9)
- --------------------------------------------------------------------------------
(1) Certain property related assets and liabilities have been netted.
46
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) 2001 2000 1999
- --------------------------------------------------------------------------------
Net income from continuing operations $ 303.7 $ 250.9 $ 200.9
Total income tax provision (benefit) (10.1) 18.5 87.0
- --------------------------------------------------------------------------------
Income from continuing operations
before income taxes $ 293.6 $ 269.4 $ 287.9
- --------------------------------------------------------------------------------
Income taxes on above
at federal statutory rate of 35% $ 102.8 $ 94.3 $ 100.8
Increase (Decrease) due to
State income tax, net of federal income tax 8.1 7.8 9.2
Amortization of investment tax credits (4.9) (4.9) (5.2)
Non-conventional fuels tax credit (102.3) (68.3) (17.2)
Permanent reinvestment-foreign income (7.2) (9.3) (1.4)
Other (6.6) (1.1) 0.8
- --------------------------------------------------------------------------------
Total income tax provision
from continuing operations $ (10.1) $ 18.5 $ 87.0
- --------------------------------------------------------------------------------
Provision for income taxes as a percent of
income from continuing operations,
before income taxes (3.4%) 6.9% 30.2%
- --------------------------------------------------------------------------------
The provision for income taxes as a percent of income from discontinued
operations was 37.5% for 1999. There was no income from discontinued operations
in 2001 or 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 as required by the alternative minimum tax rules in 2001,
2000, and 1999 was $52.4 million, $83.9 million and $62.1 million, respectively.
- --------------------------------------------------------------------------------
I. DISCONTINUED OPERATIONS
TeCom
On Nov. 4, 1999, TECO Energy completed the sale of the assets of TeCom,
Inc. for $1.0 million in cash. 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 for the year ended Dec. 31, 1999. 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 for the year ended Dec. 31, 1999. There were no revenues in 2001 or
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") to American Resources Offshore, Inc. (ARO) 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 2001, 2000 or 1999.
47
- --------------------------------------------------------------------------------
J. EARNINGS PER SHARE
In 1997, the Financial Accounting Standards Board issued FAS 128, Earnings
per Share, which requires disclosure of basic and diluted earnings per share and
a reconciliation (where different) of the numerator and denominator from basic
to diluted earnings per share. The reconciliation of basic and diluted earnings
per share is shown below:
- -------------------------------------------------------------------------------
Year ended December 31, 2001 2000 1999
- -------------------------------------------------------------------------------
Numerator
Net Income from continuing operations, basic $ 303.7 $ 250.9 $ 200.9
Effect of contingent performance shares - (1.9) -
- -------------------------------------------------------------------------------
Net Income from continuing operations, diluted $ 303.7 $ 249.0 $ 200.9
===============================================================================
Net Income, basic $ 303.7 $ 250.9 $ 186.1
Effect of contingent performance shares - (1.9) -
- -------------------------------------------------------------------------------
Net Income, diluted $ 303.7 $ 249.0 $ 186.1
===============================================================================
- -------------------------------------------------------------------------------
Denominator
Average number of shares outstanding - basic 134.5 125.9 131.0
Plus: Incremental shares for assumed conversions:
Stock options at end of period and
contingent performance shares 4.2 3.3 2.3
Less: Treasury shares which
could be purchased (3.3) (2.9) (2.1)
- -------------------------------------------------------------------------------
Average number of shares outstanding - diluted 135.4 126.3 131.2
===============================================================================
- -------------------------------------------------------------------------------
Earnings per shares from continuing operations
Basic $ 2.26 $ 1.99 $ 1.53
Diluted $ 2.24 $ 1.97 $ 1.53
- -------------------------------------------------------------------------------
Earnings per share
Basic $ 2.26 $ 1.99 $ 1.42
Diluted $ 2.24 $ 1.97 $ 1.42
===============================================================================
- -------------------------------------------------------------------------------
K. 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. Information presented here for 1999 excludes
TeCom's results, which are reflected in the consolidated financial statements as
discontinued operations.
48
- ------------------------------------------------------------------------------------------------------------------------------------
SEGMENT INFORMATION Capital
Net Assets Expenditures
(millions) Revenues (1)(2) Income (1)(3) Depreciation (1) at Dec. 31, for the Year
- ------------------------------------------------------------------------------------------------------------------------------------
2001 Tampa Electric $ 1,412.7 (4) $ 154.0 $ 173.4 $ 3,274.2 $ 426.3
Peoples Gas System 352.9 23.1 27.9 528.9 73.0
TECO Power Services 287.1 (5) 26.9 28.4 1,935.4 (9)(10) 397.5
TECO Transport 274.9 (6) 27.5 24.1 333.1 38.8
TECO Coal 303.4 (7) 59.0 28.3 258.5 25.8
Other diversified businesses 267.2 (8) 35.1 15.9 373.3 (11)(12) 4.5
---------------------------------------------------------------------------------------------------------------------
2,898.2 325.6 298.0 6,703.4 965.9
Other and eliminations (249.6) (21.9) -- 18.7 --
---------------------------------------------------------------------------------------------------------------------
TECO Energy consolidated $ 2,648.6 $ 303.7 $ 298.0 $ 6,722.1 $ 965.9
- ------------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------------
2000 Tampa Electric $ 1,353.8 (4) $ 144.5 $ 161.6 $ 2,957.1 $ 267.1
Peoples Gas System 314.5 21.8 25.8 513.3 82.2
TECO Power Services 199.0 (5) 22.8 18.5 1,350.6 (9)(10) 243.5
TECO Transport 269.8 (6) 29.2 22.0 311.3 21.1
TECO Coal 232.8 (7) 33.5 26.9 246.3 64.0
Other diversified businesses 153.4 (8) 28.1 13.4 294.6 (11)(12) 10.6
---------------------------------------------------------------------------------------------------------------------
2,523.3 279.9 268.2 5,673.2 688.5
Other and eliminations (228.7) (29.0) -- 61.1 (0.1)
---------------------------------------------------------------------------------------------------------------------
TECO Energy consolidated $ 2,294.6 $ 250.9 $ 268.2 $ 5,734.3 $ 688.4
- ------------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------------
1999 Tampa Electric $ 1,199.8 (4)(13)(14) $ 138.8 (16) $ 147.6 $ 2,827.3 $ 228.7
Peoples Gas System 251.7 19.8 23.1 433.1 84.5
TECO Power Services 106.8 (5) 9.3 9.3 700.4 (9)(10) 68.5
TECO Transport 251.9 (6) 26.2 21.9 312.0 18.6
TECO Coal 237.3 (7) 13.0 16.1 193.2 23.4
Other diversified businesses 107.8 (8) 23.7 14.2 223.0 (12) 3.1
---------------------------------------------------------------------------------------------------------------------
2,155.3 230.8 232.2 4,689.0 426.8
Other and eliminations (177.0) (15) (29.9) (17) -- 1.1 (0.7)
---------------------------------------------------------------------------------------------------------------------
TECO Energy consolidated $ 1,978.3 $ 200.9 $ 232.2 $ 4,690.1 $ 426.1
- ------------------------------------------------------------------------------------------------------------------------------------
(1) From continuing operations.
(2) Revenues for all periods have been restated to reflect the
reclassification of earnings from equity investments from Revenues to
Other Income. There was no impact to net income.
(3) Beginning in 2001, segment net income is reported on a basis that
includes internally allocated financing costs. Prior period net income
has been restated to reflect estimated internally allocated financing
costs that would have been attributable to such prior periods.
Internally allocated costs for 2001, 2000 and 1999 were at pretax
rates of 7%, 6.75% and 6.75% respectively, based on the average
investment in each subsidiary.
(4) Revenues from sales to affiliates were $32.6 million, $32.4 million
and $24.8 million in 2001, 2000 and 1999, respectively.
(5) Revenues from sales to affiliates were $65.0 million, $67.6 million
and $35.5 million in 2001, 2000 and 1999, respectively.
(6) Revenues from sales to affiliates were $123.2 million, $118.0 million
and $101.0 million in 2001, 2000 and 1999, respectively.
(7) Revenues from sales to affiliates were $5.1 million, $4.3 million and
$23.1 million in 2001, 2000 and 1999, respectively.
(8) Revenues from sales to affiliates were $23.7 million, $6.5 million and
$0.6 million in 2001, 2000 and 1999, respectively.
(9) Total assets include investments in unconsolidated affiliates of
$120.4 million, $145.5 million and $103.3 million at Dec. 31, 2001,
2000 and 1999, respectively. Total assets also includes $286.4 million
and $383.1 million in other non-current equity investments at Dec. 31,
2001 and 2000, respectively.
(10) Total assets include $129.4 million, $65.7 million and $40.9 million
in goodwill net of amortization at Dec. 31, 2001, 2000 and 1999,
respectively.
(11) Total assets include $52.5 million and $50.4 million in investments in
unconsolidated affiliates at Dec. 31, 2001 and 2000, respectively.
(12) Total assets include $36.4 million, $27.4 million and $1.9 million in
goodwill net of amortization at Dec. 31, 2001, 2000 and 1999,
respectively.
(13) Revenues shown for 1999 exclude a $7.9 million credit resulting from a
charge. See Note L.
(14) Revenues shown for 1999 are after the revenue deferral of $11.9
million.
(15) Revenues include a pretax benefit of $7.9 million in 1999. See Note L.
(16) Net income excludes after-tax charges totaling $13.7 million in 1999.
See Note L.
(17) Net income includes after-tax charges totaling $19.6 million in 1999,
which included $13.7 million of charges recorded at Tampa Electric.
See Note L.
Tampa Electric Company provides retail electric utility services to almost
584,000 customers in West Central Florida. Its Peoples Gas System division is
engaged in the purchase, distribution and marketing of natural gas for more than
272,000 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, these
subsidiaries began operating synthetic fuel processing facilities, whose
production qualifies for the non-conventional fuels tax credit. TECO Coal's
subsidiaries sell their coal production to third parties.
TECO Power Services Corporation (TPS) has subsidiaries that have interests in
independent power projects in Florida, Virginia, Texas, Arkansas, Mississippi,
Arizona, 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 businesses are engaged in natural gas
production from coalbeds, the marketing of natural gas, and energy services and
engineering. Also included is the company's investment in the propane business.
Foreign Operations
TPS has independent power operations and investments in Guatemala.
TPS, through its subsidiaries, has a 96 percent ownership interest 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, 2001, 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 80.9 percent interest in
EEGSA.
Total assets at Dec. 31, 2001, 2000 and 1999 included $454.2 million, $442.6
million and $379.4 million, respectively, related to these Guatemalan operations
and investments. Revenues included $79.9 million, $69.0 million and $19.5
million for the years ended Dec. 31, 2001, 2000 and 1999, respectively, and
operating income included $38.0 million, $23.7 million and $10.1 million for the
years ended Dec. 31, 2001, 2000 and 1999, respectively, from these Guatemalan
operations and investments.
________________________________________________________________________________
L. OTHER NON-OPERATING ITEMS AFFECTING NET INCOME
2001
In the first quarter of 2001, TECO Energy recorded $7.2 million of after-tax
charges ($11.1 million pretax) to adjust asset valuations. The adjustments
included a $6.1 million after-tax adjustment ($9.3 million pretax) related to
the sale of TPS' minority interests in Energia Global International, Ltd. (EGI)
which owned smaller power generation projects in Central America, and a $1.1
million after-tax adjustment ($1.8 million pretax) to adjust the carrying value
of leveraged leases at TECO Investments.
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. Because of the offsetting nature of these
items, there was no significant effect on earnings in 2000.
1999
In 1999, TECO Energy's results included charges totaling $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 litigation filed by
the United States Environmental Protection Agency, which was then pending.
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.
49
________________________________________________________________________________
M. COMMITMENTS AND CONTINGENCIES
TECO Energy has made certain commitments in connection with its continuing
capital improvements program. At Dec. 31, 2002, these commitments totaled
approximately $1.6 billion, with $1.2 billion related to 2002 and $0.4 billion
related to the 2003 - 2006 period. TECO Energy estimates that net capital
investments for ongoing businesses will be about $1.2 billion in 2002, $764
million in 2003 and approximately $862 million for the years 2004 through 2006,
as summarized below.
- --------------------------------------------------------------------------------
FORECASTED-CAPITAL INVESTMENTS
- --------------------------------------------------------------------------------
(millions) 2002 2003 2004 - 2006 Total 2002-2006
- --------------------------------------------------------------------------------
Florida Operations $ 603 $ 359 $761 $1,723
Independent Power 514 352 -- 866
Transportation 20 24 55 99
Other 46 29 46 121
- --------------------------------------------------------------------------------
$1,183 $ 764 $862 $2,809
================================================================================
For 2002, Tampa Electric expects to spend $541 million, consisting of $330
million for the repowering project at the Gannon Station, $16 million in
construction costs on Polk Unit 3 and $195 million to support system growth and
generation reliability. Tampa Electric's estimated capital expenditures over the
2003-2006 period are projected to be $878 million, including $131 for the Gannon
repowering project. At the end of 2001, Tampa Electric had outstanding
commitments of about $453 million for the Gannon repowering project and Polk
Unit 3.
Capital expenditures for Peoples Gas System are expected to be about $62
million in 2002 and $242 million during the 2003-2006 period. Included in these
amounts are approximately $42 million annually for projects associated with
customer growth and system expansion. The remainder represents capital
expenditures for ongoing maintenance and system safety.
TPS expects to invest $514 million in 2002, which is net of $500 million of
non-recourse project financing expected for the Dell, McAdams, Frontera and
Commonwealth Chesapeake power stations, and $352 million in 2003, mainly for the
completion of the Gila River, Union, Dell and McAdams power stations. At the end
of 2001, TPS had outstanding commitments of about $1.1 billion on these
projects.
Estimates for TPS include net contributions to projects of unconsolidated
affiliates and other investments of $984 million. These amounts, consisting
primarily of the net investments in the Union and Gila River power stations, are
estimated at $664 million in 2002 and $320 million in 2003. The 2002 amounts are
net of $460 million of non-recourse project construction financing for the Union
and Gila River power stations, and include $125 million of TPS equity investment
upon completion of the first phase of the Union Power Station.
The other unregulated companies expect to invest $66 million in 2002 and $154
million during 2003 through 2006, mainly for normal renewal and replacement
capital.
Tampa Electric Company is a potentially responsible party for certain
superfund sites and, through its Peoples Gas System division, for certain
superfund and 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, three ocean-going barges
and one ocean-going tug boat at TECO Transport, and certain equipment at TPS'
Hardee Power Station. On Dec. 21, 2001, TECO Transport sold three ocean-going
barges and one ocean-going tug boat in a sales-leaseback transaction to be
accounted for as an operating lease. The lease term is 12 years with an early
buyout option in January 2007. TPS completed a transaction on Dec. 29, 2000,
where certain equipment at its Hardee Power Station was sold to a third party
and leased back under a 12-year operating lease. Total rental expense for these
operating leases, included in the Consolidated Statements of Income for the
years ended Dec. 31, 2001, 2000 and 1999 was $20.4 million, $17.6 million and
$12.8 million, respectively. The following is a schedule of future minimum lease
payments at Dec. 31, 2001 for all operating leases with noncancelable lease
terms in excess of one year:
- --------------------------------------------------------------------------------
Year ended Dec. 31: Amount (millions)
- --------------------------------------------------------------------------------
2002 $ 12.0
2003 15.3
2004 15.6
2005 15.0
2006 14.9
Later Years 83.3
- --------------------------------------------------------------------------------
Total minimum lease payments $156.1
================================================================================
The company has outstanding letters of credit of $22.4 million at Dec. 31,
2001, which guarantee performance to third parties related to debt service,
major maintenance requirements and various trade activities. The company also
has financial guarantees of $265.1 million at Dec. 31, 2001, primarily for
construction related debt for projects in which TPS is a participant.
In addition, TECO Energy has guaranteed a $500 million equity bridge loan of
the unconsolidated TECO/Panda Affiliate for the construction of the Gila River
and Union power stations. The TPS equity bridge financing includes two financial
covenants, debt to capital and interest coverage requirements on a TECO Energy
consolidated basis. The debt to capital as defined in the agreements must not
exceed 65 percent at the end of each quarter and interest coverage as defined
must equal or exceed 3.0 times for the twelve-month period ended each quarter.
At Dec. 31, 2001 debt to capital was 62.1 percent and interest coverage was 4.3
times. In addition, this financing requires that TECO Energy maintain senior
unsecured credit ratings better or equal to one rating of BBB and one rating of
BBB-. Failure to meet these covenants would constitute a default event and the
financing would become due and payable.
- --------------------------------------------------------------------------------
N. MERGERS, ACQUISITIONS AND DISPOSITIONS
In November 2001, TECO Solutions acquired Prior Energy Corporation, a leading
natural gas management company serving customers in Alabama, Florida, Georgia,
Louisiana, Mississippi, North Carolina, South Carolina, Tennessee and Texas.
Prior Energy handles all facets of natural gas energy management services,
including natural gas purchasing and marketing. The company has an established
market base in the Southeast and one of the top customer service reputations in
the region. The acquisition was accounted for by the purchase method of
accounting and, accordingly, the results of operations of Prior Energy are
included as part of TECO Solutions' results beginning Nov. 1, 2001. The total
cost of the acquisition was $23.0 million, plus a net working capital payment of
$6.0 million. Goodwill of $8.2 million was recorded, representing the excess of
purchase price over the fair market value of assets acquired. Under FAS 141,
effective for all business combinations initiated after June 30, 2001, goodwill
is no longer subject to amortization. Net intangible assets of $40.8 million
were recorded, representing the value of customer backlog and supply agreements
as well as the open cash flow hedges as of Nov. 1, 2001, which are being
amortized over 2001 through 2004. The purchase price allocation is subject to
revision in 2002, based on the final determination of appraised and other fair
values. A summary of the estimated assets acquired and liabilities assumed is
summarized below:
- --------------------------------------------------------------------------------
millions
- --------------------------------------------------------------------------------
Other current assets $ 45.9
Property, plant and equipment 0.1
Goodwill 8.2
Intangible assets 40.8
Long-term derivative assets 1.4
Current derivative liabilities (29.8)
Other current liabilities (35.1)
Long-term derivative liability (2.5)
- --------------------------------------------------------------------------------
Net assets acquired $ 29.0
- --------------------------------------------------------------------------------
In March 2001, TPS acquired the Frontera Power Station located near McAllen,
Texas, accounting for the transaction using the purchase method of accounting.
This 477-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 FERC required CSW to divest its
ownership in this facility. The total cost of the acquisition was $265.3
million. Goodwill of $70.4 million, representing the excess of purchase price
over the fair market value of assets acquired, was recorded, and was amortized
on a straight-line basis over 40 years until the requirements of FAS 141 became
effective on Jan. 1, 2002 (See Note A). The results of operations of Frontera
Power Station are included as part of TPS' results beginning March 16, 2001.
A summary of the assets acquired and liabilities assumed is summarized below:
- --------------------------------------------------------------------------------
millions
- --------------------------------------------------------------------------------
Current assets $ 6.0
Property, plant and equipment 180.9
Goodwill 70.4
Other assets 8.7
Current liabilities (0.7)
- --------------------------------------------------------------------------------
Net assets acquired $265.3
================================================================================
The following pro forma disclosures include Prior Energy and the Frontera
Power Station as if they had been included in TECO Energy's financial statements
for the years ended Dec. 31, 2001 and 2000, and include Prior Energy for the
year ended Dec. 31, 1999.
- --------------------------------------------------------------------------------
Pro forma, year ended Dec. 31, 2001 2000 1999
- --------------------------------------------------------------------------------
Revenues (millions) $ 3,250.3 $ 2,856.2 $ 2,163.9
Net income (millions) $ 300.3 $ 253.9 $ 201.6
Earnings per share - basic $ 2.23 $ 2.02 $ 1.54
- --------------------------------------------------------------------------------
This pro forma information is not necessarily indicative of the operating
results that would have occurred had the acquisitions been completed as of the
dates indicated, nor are they indicative of future operating results.
50
In October 2001, TECO BGA, a unit of TECO Solutions, purchased a district
cooling business from FPL Energy Services, a subsidiary of FPL Group. The
acquisition includes a 12,000-ton design capacity cooling plant located in
downtown Miami. This acquisition provides TECO BGA with a stronger presence in
the growing South Florida energy market, long-term contract business, a
franchise agreement with the city of Miami and the potential for expansion. The
acquisition was accounted for by the purchase method of accounting and,
accordingly, its results of operations are included as part of TECO BGA's
results beginning Oct. 25, 2001. The total cost of the acquisition was $12.5
million. No goodwill was recorded for the acquisition. The acquisition was not
material to the financial statements; no pro forma disclosures are presented.
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 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.
In September 2000, TECO Energy 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 $34.8 million, comprised of $26.1 million in cash, $2.9 million in
notes, and 233,819 shares of TECO Energy common stock. Goodwill of $25.9 million
representing the excess of purchase price over the fair market value of assets
acquired was recorded, and was amortized on a straight-line basis over 20 years,
until the requirements of FAS 141 became effective on Jan. 1, 2002 (See Note A).
The result of operations of BCH are included as part of TECO Energy's results
beginning Sept. 1, 2000. BCH is included within the Other diversified businesses
segment.
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
Partners, TECO Propane Ventures, TECO Gas Services, Prior Energy and TECO
Properties.
In February 2000, TECO Energy 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 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 pretax
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.
- --------------------------------------------------------------------------------
O. SUBSEQUENT EVENTS
On January 23, 2002, TECO Energy sold 17.965 million units of mandatorily
convertible securities in the form of 9.5% mandatorily convertible equity units
at $25 per unit. Each security unit consisted of $25 in principal amount of a
trust preferred security of TECO Capital Trust II, a Delaware business trust
formed by TECO Energy, with a stated liquidation amount of $25 and a contract to
purchase shares of common stock of TECO Energy in January 2005 at a price per
share of between $26.29 and $30.10 based on the market price at the time. The
equity units represent an indirect interest in a corresponding amount of TECO
Energy subordinated debt. The $436 million net proceeds from the offering were
used to repay short-term debt and for general corporate purposes.
As part of its $1 billion line of credit facility, TECO Energy has the
capacity to issue up to $250 million in letters of credit with a syndicate of
banks. In January and February 2002, TECO Energy issued $141.7 million in
letters of credit under this facility, primarily related to construction support
for the Gila River and Union power stations.
On February 7, 2002, TPS entered into an agreement for TPS to purchase and
for Panda Energy International Inc. (Panda) to sell its interest in TECO-Panda
Generating Company L.P., the joint venture formed to build, own and operate the
Gila River and Union power stations, in 2007 for up to $60 million. Panda has
the right to cancel the transaction for $20 million. The purchase agreement can
be triggered earlier under certain default conditions under a bank loan made to
Panda using the purchase agreement as collateral.
51
- --------------------------------------------------------------------------------
P. QUARTERLY DATA (unaudited)
Financial data by quarter is as follows: (unaudited)
Quarter ended March 31 June 30 Sept. 30 Dec. 31
- -------------------------------------------------------------------------------------------------------------------
2001 Revenues (1) $ 671.1 $ 641.9 $ 677.8 $ 657.8
Income from operations (1) $ 109.4 $ 105.9 $ 136.5 $ 70.7
Net income (1) $ 69.7 $ 71.9 $ 97.3 $ 64.8
Earnings per share (EPS)- basic $ 0.54 $ 0.53 $ 0.72 $ 0.47
Earnings per share (EPS) - diluted $ 0.53 $ 0.52 $ 0.71 $ 0.47
Dividends paid per common share (2) $ 0.335 $ 0.345 $ 0.345 $ 0.345
Stock price per common share (3)
High $ 32.125 $ 32.970 $ 31.650 $ 28.300
Low $ 26.100 $ 28.780 $ 25.530 $ 24.750
Close $ 29.960 $ 30.500 $ 27.100 $ 26.240
===================================================================================================================
- -------------------------------------------------------------------------------------------------------------------
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 [GRAPH APPEARS
Earnings per share (EPS)- basic $ 0.42 $ 0.46 $ 0.65 $ 0.46 HERE]
Earnings per share (EPS) - diluted $ 0.42 $ 0.46 $ 0.65 $ 0.44
Dividends paid per common share (2) $ 0.325 $ 0.335 $ 0.335 $ 0.335
Stock price per common share (3)
High $ 20.625 $ 23.125 $ 28.750 $ 33.188
Low $ 17.250 $ 19.188 $ 20.188 $ 26.563
Close $ 19.438 $ 20.063 $ 28.750 $ 32.375
==================================================================================================================
(1) Millions.
(2) Dividend paid on TECO Energy common stock.
(3) Trading prices for common shares.
52
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
During the period Jan. 1, 2000 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 2
through 3 of TECO Energy's definitive proxy statement, dated March 4, 2002,
for its Annual Meeting of Shareholders to be held on April 17, 2002 (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.
(C) The information required by Item 10 concerning Section 16(a) Beneficial
Ownership Reporting Compliance is included under that caption on page 14 of
the Proxy Statement and is incorporated herein by reference.
Item 11. EXECUTIVE COMPENSATION.
The information required by Item 11 is included in the Proxy Statement
beginning on page 6 and ending on page 13, 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 1 of the Proxy Statement and is incorporated herein by
reference.
70
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
3. Exhibits - See index beginning on page 73
(b) Reports on Form 8-K
The registrant filed the following reports on Form 8-K during the last
quarter of 2001.
The registrant filed a Current Report on Form 8-K dated Oct. 9, 2001
under "Item 5. Other Events" and "Item 7. Financial Statements, Pro
------------ -------------------------
Forma Financial Statements and Exhibits", 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. 333-61758).
The registrant filed a Current Report on Form 8-K dated Dec. 7, 2001
under "Item 5. Other Events", reporting TECO Energy's exposure
------------
relating to Enron Corp.
The registrant filed the following reports on Form 8-K subsequent to Dec.
31, 2001.
The registrant filed a Current Report on Form 8-K dated Jan. 9, 2002,
under "Item 5. Other Events" reporting on TECO Energy's 2001
------------
financial results and providing updated information on the Company's
2002 outlook, its capital spending plans and reporting on the status
of bank financing for the construction of two power plants for TECO
Power Services.
The registrant filed a Current Report on Form 8-K dated Jan. 9, 2002,
under "Item 5. Other Events" and "Item 7. Financial Statements, Pro
------------ -------------------------
Forma Financial Statements and Exhibits", 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. 333-61758).
The registrant filed a Current Report on Form 8-K dated Jan. 15, 2002,
under "Item 5. Other Events" and "Item 7. Financial Statements, Pro
------------ -------------------------
Forma Financial Statements and Exhibits", 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. 333-61758).
The registrant filed a Current Report on Form 8-K dated Jan. 15, 2002,
under "Item 5. Other Events" and "Item 7. Financial Statements, Pro
------------ -------------------------
Forma Financial Statements and Exhibits", 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. 333-61758).
The registrant filed a Current Report on Form 8-K dated Jan. 24, 2002,
under "Item 5. Other Events" reporting that Moody's Investors Service
------------
announced that it had changed the outlooks of the long-term ratings of
TECO Energy, Inc. and Tampa Electric Company to negative.
(c) The exhibits filed as part of this Form 10-K are listed on the Exhibit
Index immediately preceding such Exhibits. The Exhibit Index is
incorporated herein by reference.
71
Schedule II
TECO Energy, Inc.
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years ended Dec. 31, 2001, 2000 and 1999
(millions)
Balance at Additions Balance at
----------------------
Beginning Charged to Other End of
of Period Income Charges Deductions(1) Period
--------- ---------- ------- ------------- ------
Allowance for Uncollectible Accounts:
2001 $8.7 $ 8.0 $(0.3) $9.4 $7.0
2000 $3.5 $10.2 $ 0.2(2) $5.2 $8.7
1999 $2.6 $ 6.2 $ 0.4(2) $5.7 $3.5
- -----------------------------
(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.
72
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, 2002.
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, 2002:
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 Senior 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
J. L. FERMAN, JR.* Director J. T. TOUCHTON* Director
-------------------- -----------------
J. L. FERMAN, JR. J. T. TOUCHTON
L. GUINOT, JR.* Director J. A. URQUHART* Director
-------------------- -----------------
L. GUINOT, JR. J. A. URQUHART
I. D. HALL* Director J. O. WELCH, JR.* Director
-------------------- -----------------
I.D. HALL J. O. WELCH, JR.
T. L. RANKIN* Director
--------------------
T. L. RANKIN
*By: /s/ G. L. GILLETTE
--------------------------------
G. L. GILLETTE, Attorney-in-fact
73
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 (Exhibit 3.2, Form 10-K for 2000
of TECO Energy, Inc.). *
4.1 Indenture of Mortgage among Tampa Electric Company, State Street Trust
Company and First Savings & Trust Company of Tampa, dated as of Aug.
1, 1946 (Exhibit 7-A to Registration Statement No. 2-6693). *
4.2 Thirteenth Supplemental Indenture, dated as of Jan. 1, 1974, to Exhibit 4.1
(Exhibit 2-g-1, Registration Statement No. 2-51204). *
4.3 Sixteenth Supplemental Indenture, dated as of Oct. 30, 1992, to Exhibit 4.1
(Exhibit 4.1, Form 10-Q for the quarter ended Sept. 30, 1992 of TECO Energy,
Inc.). *
4.4 Eighteenth Supplemental Indenture, dated as of May 1, 1993, to Exhibit 4.1
(Exhibit 4.1, Form 10-Q for the quarter ended June 30, 1993 of TECO Energy,
Inc.). *
4.5 Installment Purchase and Security Contract between the Hillsborough County
Industrial Development Authority and Tampa Electric Company, dated as of
March 1, 1972 (Exhibit 4.9, Form 10-K for 1986 of TECO Energy, Inc.). *
4.6 First Supplemental Installment Purchase and Security Contract, dated as of
Dec. 1, 1974 (Exhibit 4.10, Form 10-K for 1986 of TECO Energy, Inc.). *
4.7 Third Supplemental Installment Purchase Contract, dated as of May 1, 1976
(Exhibit 4.12, Form 10-K for 1986 of TECO Energy, Inc.). *
4.8 Installment Purchase Contract between the Hillsborough County Industrial
Development Authority and Tampa Electric Company, dated as of Aug. 1,
1981 (Exhibit 4.13, Form 10-K for 1986 of TECO Energy, Inc.). *
4.9 Amendment to Exhibit A of Installment Purchase Contract, dated April 7, 1983
(Exhibit 4.14, Form 10-K for 1989 of TECO Energy, Inc.). *
4.10 Second Supplemental Installment Purchase Contract, dated as of June 1, 1983
(Exhibit 4.11, Form 10-K for 1994 of TECO Energy, Inc.). *
4.11 Third Supplemental Installment Purchase Contract, dated as of Aug. 1, 1989
(Exhibit 4.16, Form 10-K for 1989 of TECO Energy, Inc.). *
4.12 Installment Purchase Contract between the Hillsborough County Industrial
Development Authority and Tampa Electric Company, dated as of Jan. 31,
1984 (Exhibit 4.13, Form 10-K for 1993 of TECO Energy, Inc.). *
4.13 First Supplemental Installment Purchase Contract, dated as of Aug. 2, 1984
(Exhibit 4.14, 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
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. 20, 2000 (Exhibit 4.20, Form 10-K for 2000 of TECO Energy, Inc.). *
4.21 Amended and Restated Reimbursement Agreement between TECO Energy, Inc. and
Electro-Coal Transfer LLC, dated as of Apr. 5, 2001 (Exhibit 4.1, Form 8-K date
Apr. 5, 2001 of TECO Energy, Inc.). for 1988 of TECO Energy, Inc.). *
4.22 Indenture between Tampa Electric Company and The Bank of New York, as trustee,
dated as of Jul. 1, 1998 (Exhibit 4.1, Registration Statement No. 333-55873) *
4.23 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). *
4.24 Third Supplemental Indenture between Tampa Electric Company and The Bank of New
York, as trustee, dated as of June 15, 2001 (Exhibit 4.2, Form 8-K dated June 25,
2001 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 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.). *
4.27 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.). *
4.28 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.). *
4.29 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.). *
4.30 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.). *
4.31 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.). *
4.32 Fourth Supplemental Indenture dated as of Apr. 30, 2001 between TECO Energy,
Inc. and The Bank of New York, as trustee (Exhibit 4.28, Form 8-K dated May 1, 2001
of TECO Energy, Inc.). *
4.33 Fifth Supplemental Indenture dated as of Sept. 10, 2001 between TECO Energy, Inc.
and The Bank of New York, as trustee (Exhibit 4.16, Form 8-K dated Sept. 26,
2001 of TECO Energy, Inc.). *
4.34 Sixth Supplemental Indenture dated as of Jan. 15, 2002 between TECO Energy, Inc.
and The Bank of New York, as trustee (Exhibit 4.28, Form 8-K dated Jan. 15, 2002
of TECO Energy, Inc.). *
4.35 Purchase Contract Agreement between TECO Energy, Inc. and The Bank of New York, as
Purchase Contract Agent, dated as of Jan. 15, 2002 (Exhibit 4.29, Form 8-K dated
Jan. 15, 2002 of TECO Energy, Inc.). *
4.36 Amended and Restated Trust Agreement of TECO Capital Trust II among TECO Funding
Company II, LLC, The Bank of New York and The Bank of New York (Delaware), dated
as of Jan. 15, 2002 (Exhibit 4.31, Form 8-K dated Jan. 15, 2002 of TECO Energy, Inc.). *
4.37 Amended and Restated Limited Liability Agreement of TECO Funding Company II, LLC,
dated as of Jan. 15, 2002 (Exhibit 4.33, Form 8-K dated Jan. 15, 2002 of TECO Energy,
Inc.). *
4.38 Guarantee Agreement by and between TECO Energy, Inc., as Guarantor and The Bank of
75
New York, dated as of Jan. 15, 2002 (Exhibit 4.35, Form 8-K dated Jan. 15, 2002 of
TECO Energy, Inc.). *
4.39 Form of Remarketing Agreement by and between TECO Energy, Inc. and the Remarketing
Agent (Exhibit 4.37, Form 8-K dated Jan. 15, 2002 of TECO Energy, Inc.). *
4.40 Pledge Agreement among TECO Energy, Inc., The Bank of New York, as Collateral Agent,
Custodial Agent and Securities Intermediary and The Bank of New York, as Purchase
Contract Agent dated as of Jan. 15, 2002 (Exhibit 4.38, Form 8-K dated Jan. 15, 2002
of TECO Energy, Inc.). *
4.41 Credit Agreement dated Nov. 14, 2001, among TECO Energy, Inc., as borrower, Citibank, N.A.,
as Administrative Agent, Salomon Smith Barney, Inc. and Banc of America Securities,
LLC, as Co-Lead Arrangers, Bank of America, N.A., as Syndication Agent, The Bank of
Nova Scotia, BNP Paribas and Sun Trust Bank, as Co-Documentation Agents, and JP Morgan
Chase Bank, as LC issuing bank. [ ]
10.1 TECO Energy Group Supplemental Executive Retirement Plan, as amended and
restated as of July 1, 1998, as further amended as of July 15, 1998. [ ]
10.2 TECO Energy Group Supplemental Retirement Benefits Trust Agreement, as
amended and restated as of Jan. 1, 1998 as further amended as of July 15, 1998. [ ]
10.3 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.). *
10.4 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.). *
10.5 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.). *
10.6 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.). *
10.7 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.). *
10.8 TECO Energy Group Deferred Compensation Plan (previously the TECO Energy Group Retirement
Savings Excess Benefit Plan), as amended and restated effective as of Oct. 17, 2001. [ ]
10.9 TECO Energy, Inc. 1996 Equity Incentive Plan as amended Apr. 18, 2001 (Exhibit 10.1,
Form 10-Q for the quarter ended March 31, 2001 of TECO Energy, Inc.). *
10.10 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.). *
10.11 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.). *
10.12 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.). *
10.13 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.). *
10.14 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.). *
10.15 TECO Energy, Inc. 1997 Director Equity Plan (Exhibit 10.1, Form 8-K dated
April 16, 1997 of TECO Energy, Inc.). *
10.16 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.). *
10.17 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.). *
10.18 Supplemental Executive Retirement Plan for R. D. Fagan as amended (Exhibit 10.1,
Form 10-Q for the quarter ended June 30, 2001 of TECO Energy, Inc.). *
10.19 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.). *
10.20 Nonstatutory Stock Option granted to R. D. Fagan, dated as of May 24, 1999, under the
TECO Energy, Inc. 1996 Equity Incentive Plan (Exhibit 10.3, Form 10-Q for the
quarter ended June 30, 1999 of TECO Energy, Inc.). *
10.21 Restricted Stock Option granted to R. D. Fagan, dated as of May 24, 1999
76
(Exhibit 10.4, Form 10-Q for the quarter ended June 30, 1999 of TECO Energy,
Inc.). *
10.22 Severance Agreement between TECO Energy, Inc. and R.D. Fagan, as amended
(Exhibit 10.2, form 10-Q for the quarter ended June 30, 2001 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 2002 Amendment to TECO Performance Shares Agreements between TECO
Energy, Inc., and certain officers under the TECO Energy Inc. 1996 Equity
Incentive Plan. [ ]
10.26 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.). *
10.27 Equity Contribution Guaranty Agreement between TECO Energy, Inc., and Citibank,
N.A., as Administrative Agent under the Union Power Project Credit Agreement
(Exhibit 10.4, Form 10-Q for the quarter ended June 30, 2001 of TECO Energy, Inc.). *
10.28 Equity Bridge Guaranty Agreement between TECO Energy, Inc., and Citibank, N.A.,
as Administrative Agent under the Union Power Project Bridge Loan Agreement
(Exhibit 10.5, form 10-Q for the quarter ended June 30, 2001 of TECO Energy, Inc.). *
10.29 Contingent Equity Contribution Guaranty Agreement between TECO Energy, Inc., and
Citibank, N.A., as Administrative Agent under the Gila River Project Credit Agreement
(Exhibit 10.6, Form 10-Q for the quarter ended June 30, 2001 of TECO Energy, Inc.). *
10.30 Equity Bridge Guaranty Agreement between TECO Energy, Inc., and Citibank, N.A.,
as Administrative Agent under the Gila River Project Credit Agreement (Exhibit 10.7,
Form 10-Q for the quarter ended June 30, 2001 of TECO Energy, Inc.). *
10.31 Equity Bridge Guaranty Agreement between TECO Energy, Inc., and Citibank, N.A.,
as Administrative Agent under the Gila River Bridge Loan Agreement (Exhibit 10.8,
Form 10-Q for the quarter ended June 30, 2001 of TECO Energy, Inc.). *
10.32 Construction contract undertaking by TECO Energy, Inc. in favor of Union Power
Partners, L.P., as borrower, and Citibank, N.A., as Administrative Agent under the
Union Power Project Credit Agreement, dated as of Jan. 16, 2002. [ ]
10.33 Construction contract undertaking by TECO Energy, Inc. in favor of Panda Gila River,
L.P., as borrower, and Citibank, N.A., as Administrative Agent under the Gila River
Project Credit Agreement, dated as of Jan. 16, 2002. [ ]
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.
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.
77
Executive Compensation Plans and Arrangements
Exhibits 10.1 through 10.5 and 10.7 through 10.26 above are management
contracts or compensatory plans or arrangements in which executive officers or
directors of TECO Energy, Inc. participate.
78