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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, 2000 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 0-23977
DUKE CAPITAL CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 51-0282142
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
526 South Church Street, Charlotte, 28202-1904
North Carolina (Zip Code)
(Address of principal executive
offices)
704-594-6200
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- -----------------------------
7 3/8% Quarterly Income Preferred Securities
issued by Duke Capital Financing Trust I and
guaranteed by Duke Capital Corporation......... New York Stock Exchange, Inc.
7 3/8% Trust Originated Preferred Securities
issued by Duke Capital Financing Trust II and
guaranteed by Duke Capital Corporation......... New York Stock Exchange, Inc.
8 3/8% Trust Preferred Securities issued by Duke
Capital Financing Trust III and guaranteed by
Duke Capital Corporation....................... New York Stock Exchange, Inc.
Securities registered pursuant to Section 12(g) of the Act:
Title of class
Common Stock, without par value
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 and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [_]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
The registrant meets the conditions set forth in General Instruction
(I)(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the
reduced disclosure format. Items 4, 10, 11, 12 and 13 have been omitted in
accordance with Instruction I(2)(c).
All of the registrant's common shares are directly owned by Duke Energy
Corporation (File No. 1-4928), which files reports and proxy material pursuant
to the Securities Exchange Act of 1934, as amended.
Estimated aggregate market value of the voting stock held by
nonaffiliates of the registrant at February 28, 2001................... None
Number of shares of Common Stock, without par value, outstanding at
February 28, 2001...................................................... 1,010
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DUKE CAPITAL CORPORATION
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2000
TABLE OF CONTENTS
Item Page
- ---- ----
PART I.
1.Business.............................................................. 1
General.............................................................. 1
Natural Gas Transmission............................................. 3
Field Services....................................................... 5
North American Wholesale Energy...................................... 6
International Energy................................................. 9
Other Energy Services................................................ 10
Duke Ventures........................................................ 11
Environmental Matters................................................ 11
Geographic Regions................................................... 12
Employees and Management............................................. 12
Recent Financing..................................................... 12
Operating Statistics................................................. 13
2.Properties............................................................ 13
3.Legal Proceedings..................................................... 15
PART II.
5.Market for Registrant's Common Equity and Related Stockholder
Matters................................................................. 16
6.Selected Financial Data............................................... 16
7.Management's Discussion and Analysis of Results of Operations and
Financial Condition..................................................... 17
7A. Quantitative and Qualitative Disclosures About Market Risk.......... 31
8.Financial Statements and Supplementary Data........................... 32
9.Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.................................................... 61
PART IV.
14.Exhibits, Financial Statement Schedules, and Reports on Form 8-K...... 61
Signatures........................................................... 63
Safe Harbor Statement Under The Private Securities Litigation Reform Act Of
1995
From time to time, the Company may make statements regarding its
assumptions, projections, expectations, intentions or beliefs about future
events. These statements are intended as "forward-looking statements" under
the Private Securities Litigation Reform Act of 1995. The Company cautions
that assumptions, projections, expectations, intentions or beliefs about
future events may and often do vary from actual results, and the differences
between assumptions, projections, expectations, intentions or beliefs and
actual results can be material. Accordingly, there can be no assurance that
the actual results will not differ materially from those expressed or implied
by the forward-looking statements. For a discussion of some factors that could
cause actual achievements and events to differ materially from those expressed
or implied in such forward-looking statements, see "Management's Discussion
and Analysis of Results of Operations and Financial Condition, Current
Issues--Forward-Looking Statements."
PART I.
Item 1. Business.
GENERAL
Duke Capital Corporation (collectively with its subsidiaries, the "Company")
is a wholly owned subsidiary of Duke Energy Corporation (Duke Energy) and
serves as the parent of certain of Duke Energy's non-utility and other
operations. The Company provides financing and credit enhancement services for
its subsidiaries and conducts its operations through six business segments.
Natural Gas Transmission provides interstate transportation and storage of
natural gas for customers primarily in the Mid-Atlantic, New England and
southeastern states. Its operations are conducted primarily through Duke
Energy Gas Transmission Corporation. The interstate natural gas transmission
and storage operations are subject to the rules and regulations of the Federal
Energy Regulatory Commission (FERC).
Field Services gathers, processes, transports, markets and stores natural
gas and produces, transports, markets and stores natural gas liquids (NGLs).
Its operations are conducted primarily through Duke Energy Field Services, LLC
(DEFS), a limited liability company that is approximately 30% owned by
Phillips Petroleum. Field Services operates gathering systems in western
Canada and 11 contiguous states that serve major natural gas-producing regions
in the Rocky Mountain, Permian Basin, Mid-Continent, East Texas-Austin Chalk-
North Louisiana, as well as onshore and offshore Gulf Coast areas.
North American Wholesale Energy's (NAWE's) activities include asset
development, operation and management, primarily through Duke Energy North
America, LLC (DENA), and commodity sales and services related to natural gas
and power, primarily through Duke Energy Trading and Marketing, LLC (DETM).
DETM is a limited liability company that is approximately 40% owned by Exxon
Mobil Corporation. The operations of the previously segregated Trading and
Marketing segment were combined by management into NAWE during 2000.
International Energy conducts its operations through Duke Energy
International, LLC (DEI). International Energy's activities include asset
development, operation and management of natural gas and power facilities and
energy trading and marketing of natural gas and electric power. This activity
is targeted in the Latin American, Asia-Pacific and European regions.
Other Energy Services is a combination of businesses that provide
engineering, consulting, construction and integrated energy solutions
worldwide, primarily through Duke Engineering & Services, Inc. (DE&S),
Duke/Fluor Daniel (D/FD) and DukeSolutions, Inc. (DukeSolutions). D/FD is a
50/50 partnership between Duke Energy and Fluor Enterprises, Inc.
Duke Ventures is comprised of other diverse businesses, primarily operating
through Crescent Resources, Inc. (Crescent), DukeNet Communications, LLC
(DukeNet) and Duke Capital Partners (DCP). Crescent develops high-quality
commercial, residential and multi-family real estate projects and manages land
holdings primarily in the southeastern U.S. DukeNet provides fiber optic
networks for industrial, commercial and residential customers. DCP, a newly
formed, wholly owned merchant finance company, provides financing, investment
banking and asset management services to wholesale and commercial energy
markets.
1
Certain terms used to describe the Company's business are explained below.
British Thermal Unit (Btu). A standard unit for measuring thermal energy or
heat commonly used as a gauge for the energy content of natural gas and other
fuels.
Cubic Foot (cf). The most common unit of measurement of gas volume; the
amount of natural gas required to fill a volume of one cubic foot under stated
conditions of temperature, pressure and water vapor.
Federal Energy Regulatory Commission (FERC). The agency that regulates the
transportation of electricity and natural gas in interstate commerce and
authorizes the buying and selling of energy commodities at market-based rates.
Gathering System. Pipeline, processing and related facilities that access
production and other sources of natural gas supplies for delivery to mainline
transmission systems.
Generation. The process of transforming other forms of energy, such as
nuclear or fossil fuels, into electricity. Also, the amount of electric energy
produced, expressed in megawatt-hours.
Greenfield Development. The development of a new power generating facility
on an undeveloped site.
Independent System Operator (ISO). Ensures non-discriminatory access to a
regional transmission system, providing all customers access to the power
exchange and clearing all bilateral contract requests for use of the electric
transmission system. Also responsible for maintaining bulk electric system
reliability.
Liquefied Natural Gas (LNG). Natural gas that has been converted to a liquid
by cooling it to -260 degrees Fahrenheit.
Local Distribution Company (LDC). A company that obtains the major portion
of its revenues from the operations of a retail distribution system for the
delivery of electricity or gas for ultimate consumption.
Natural Gas. A naturally occurring mixture of hydrocarbon and non-
hydrocarbon gases found in porous geological formations beneath the earth's
surface, often in association with petroleum. The principal constituent is
methane.
Natural Gas Liquids (NGLs). Liquid hydrocarbons extracted during the
processing of natural gas. Principal commercial NGLs include butanes, propane,
natural gasoline and ethane.
Throughput. The amount of natural gas or natural gas liquids transported
through a pipeline system.
Transmission System (Electric). An interconnected group of electric
transmission lines and related equipment for moving or transferring electric
energy in bulk between points of supply and points at which it is transformed
for delivery over a distribution system to customers, or for delivery to other
electric transmission systems.
Transmission System (Natural Gas). An interconnected group of natural gas
pipelines and associated facilities for transporting natural gas in bulk
between points of supply and delivery points to industrial customers, local
distribution companies, or for delivery to other natural gas transmission
systems.
Watt. A measure of real power production or usage equal to one joule per
second.
A discussion of the current business and operations of each of the Company's
segments follows. For further discussion of the operating outlook of the
Company and its segments, see "Management's Discussion and Analysis of Results
of Operations and Financial Condition, Introduction--Business Strategy." For
financial information concerning the Company's business segments, see Note 3
to the Consolidated Financial Statements, "Business Segments."
The Company is a Delaware corporation with its principal executive offices
located at 526 South Church Street, Charlotte, NC 28202-1904. The telephone
number is 704-594-6200.
2
NATURAL GAS TRANSMISSION
Natural Gas Transmission provides interstate transportation and storage of
natural gas through its operating subsidiaries, which include Texas Eastern
Transmission Corporation (TETCO) and Algonquin Gas Transmission Company
(Algonquin), East Tennessee Natural Gas Company (East Tennessee) and Market
Hub Partners (MHP). East Tennessee and MHP were acquired in March 2000 and
September 2000, respectively. Panhandle Eastern Pipe Line Company and
Trunkline Gas Company were also a part of Natural Gas Transmission until their
sale to CMS Energy Corporation (CMS) in March 1999. See further discussion of
the acquisitions and sale in Note 2 to the Consolidated Financial Statements,
"Business Acquisitions and Dispositions."
Investments include a 37.5% ownership interest in Maritimes & Northeast
Pipeline, which has a design capacity of 530 million cubic feet per day
(MMcf/d) in Canada and 400 MMcf/d in the U.S. Maritimes & Northeast Pipeline
was placed in service and received the first delivery of natural gas from the
Sable Offshore Energy Project near Nova Scotia in December 1999. The Company
operates the U.S. portion of the Maritimes & Northeast Pipeline.
For 2000, consolidated natural gas deliveries by Natural Gas Transmission's
interstate pipelines totaled 1,717 trillion British thermal units (TBtu),
compared to 1,565 TBtu in 1999, a 10% increase from last year. The pipelines
that were sold to CMS during 1999 also delivered 328 TBtu in 1999 prior to the
sale. A majority of Natural Gas Transmission's contracted volumes are under
long-term firm service agreements with local distribution company (LDC)
customers in the pipelines' market areas. Firm transportation services are
also provided to gas marketers, producers, other pipelines, electric power
generators and a variety of end-users. In addition, the pipelines provide both
firm and interruptible transportation to various customers on a short-term or
seasonal basis. See natural gas deliveries statistics under "Operating
Statistics." Demand for gas transmission on Natural Gas Transmission's
interstate pipeline systems is seasonal, with the highest throughput occurring
during the colder periods in the first and fourth quarters. Natural Gas
Transmission's major pipeline customers are located in Pennsylvania, New
Jersey, Connecticut, Virginia, Tennessee, Rhode Island and New York.
[MAP]
3
Natural Gas Transmission's interstate pipeline systems consist of
approximately 12,000 miles of pipe, which includes 830 miles related to the
partial ownership interest in Maritimes & Northeast Pipeline. The pipeline
systems receive natural gas from many major North American producing regions
for delivery to markets primarily in the Mid-Atlantic, southeastern and New
England states. Consistent with its growth strategy, the Company and The
Williams Companies, Inc. announced the closing on February 1, 2001 of their
joint purchase of Coastal Corporation's Gulfstream Natural Gas System LLC. The
planned 744-mile Gulfstream gas pipeline will originate near Mobile, Alabama,
and cross the Gulf of Mexico to Manatee County, Florida.
MHP owns natural gas salt cavern facilities in south Texas and Louisiana
with a total storage capacity of 23 billion cubic feet (Bcf). Utilizing these
facilities, MHP provides high deliverability firm storage services, real-time
title tracking and other interruptible storage hub services to producers, end-
users, LDCs, pipelines and natural gas marketers. TETCO and East Tennessee
also provide firm and interruptible open-access storage services. Storage is
offered as a stand-alone unbundled service or as part of a no-notice bundled
service with transportation. TETCO's storage services utilize two joint
venture storage facilities in Pennsylvania and one wholly owned and operated
storage field in Maryland. TETCO's certificated working capacity in these
three fields is 75 Bcf. TETCO also leases storage capacity. East Tennessee's
storage services utilize a liquefied natural gas (LNG) storage facility in
Tennessee which has a certificated working capacity of 1.2 Bcf. Algonquin owns
no storage fields.
Competition
The Company's interstate pipeline and storage subsidiaries compete with
other interstate and intrastate pipeline and storage facilities in the
transportation and storage of natural gas. The principal elements of
competition are rates, terms of service, and flexibility and reliability of
service.
Natural Gas Transmission competes directly with other interstate pipelines
serving the Mid-Atlantic, northeastern and southeastern states.
Natural gas competes with other forms of energy available to the Company's
customers and end-users, including electricity, coal and fuel oils. The
primary competitive factor is price. Changes in the availability or price of
natural gas and other forms of energy, the level of business activity,
conservation, legislation and governmental regulations, the capability to
convert to alternative fuels, and other factors, including weather, affect the
demand for natural gas in the areas served by the Company.
Regulation
The FERC has authority to regulate rates and charges for natural gas
transported in or stored for interstate commerce or sold by a natural gas
company in interstate commerce for resale. For further discussion of rate
matters, see Note 4 to the Consolidated Financial Statements, "Regulatory
Matters--Natural Gas Transmission." The FERC also has authority over the
construction and operation of pipeline and related facilities utilized in the
transportation, storage and sale of natural gas in interstate commerce,
including the extension, enlargement or abandonment of such facilities. TETCO,
Algonquin, East Tennessee and MHP hold certificates of public convenience and
necessity issued by the FERC, authorizing them to construct and operate the
pipelines, facilities and properties now in operation for which such
certificates are required, and to transport and store natural gas in
interstate commerce.
As required by FERC Order 636, Natural Gas Transmission's pipelines operate
as open-access transporters of natural gas, providing unbundled firm and
interruptible transportation and storage services on an equal basis for all
gas supplies, whether purchased from the pipeline or from another gas
supplier.
The FERC has implemented regulations governing access to regulated natural
gas transmission customer data by non-regulated entities and services provided
between regulated and non-regulated affiliated entities. These regulations
affect the activities of NAWE with Natural Gas Transmission.
Natural Gas Transmission is subject to the jurisdiction of the Environmental
Protection Agency (EPA) and state environmental agencies. For a discussion of
environmental regulation, see "Environmental Matters."
4
Natural Gas Transmission is also subject to the Natural Gas Pipeline Safety
Act of 1968, which regulates gas pipeline and LNG plant safety requirements,
and to the Hazardous Liquid Pipeline Safety Act of 1979, which regulates oil
and petroleum pipelines.
FIELD SERVICES
Field Services gathers, processes, transports, markets and stores natural
gas and produces, transports, markets and stores NGLs. Field Services owns and
operates approximately 57,000 miles of natural gas gathering systems,
including intrastate pipelines, and 68 natural gas processing plants in the
U.S. and Canada. Field Services also has ownership interests in 11 other
natural gas processing plants in the U.S.
Field Services gathers natural gas from production wellheads through
gathering systems in western Canada and 11 contiguous states that serve major
gas-producing regions in the Rocky Mountain, Permian Basin, Mid-Continent,
East Texas-Austin Chalk-North Louisiana, as well as onshore and offshore Gulf
Coast areas. Field Services' operations also include several intrastate
pipeline systems and one high-deliverability natural gas storage facility.
The map below includes Field Services' natural gas gathering systems,
intrastate pipelines, region offices and supply areas. The map also shows the
interstate systems of the Natural Gas Transmission segment.
[MAP]
Field Services' NGL processing operations involve the extraction of NGLs
from natural gas and, at certain facilities, the fractionation of the NGLs
into their individual components (ethane, propane, butane and natural
gasoline). The natural gas used in Field Services' processing operations is
generally gathered on its own gathering system. NGLs are sold by Field
Services to a variety of customers ranging from large, multi-national
petrochemical and refining companies to small, family-owned retail propane
distributors. Most NGL sales are
5
based upon current market-related prices. Field Services also produces helium
at the National Helium Corporation facility in Liberal, Kansas and the Ladder
Creek facility in Colorado.
Field Services' operating results are significantly impacted by changes in
NGL prices, which increased approximately 56% in 2000 compared to 1999. See
"Management's Discussion and Analysis of Results of Operations and Financial
Condition, Quantitative and Qualitative Disclosures About Market Risk" for a
discussion of Field Services' exposure to changes in commodity prices.
In March 2000, the Company, through a wholly owned subsidiary, completed the
approximately $1.7 billion transaction that combined Field Services' gas
gathering and processing business with Phillips Petroleum's Gas Gathering,
Processing and Marketing unit (Phillips) to form a new midstream company,
named DEFS. In addition to this transaction, Duke Energy transferred its
interest in Texas Eastern Products Pipeline Company (TEPPCO), the general
partner of TEPPCO Partners, LP, to the newly formed company, DEFS. For further
discussion of the Phillips transaction see Note 2 to the Consolidated
Financial Statements, "Business Acquisitions and Dispositions."
On March 31, 1999, Field Services completed the $1.35 billion acquisition of
the natural gas gathering, processing, fractionation and NGL pipeline business
from Union Pacific Resources (UPR), as well as UPR's natural gas and NGL
marketing activities (collectively, "the UPR acquisition"). For further
discussion of the UPR acquisition see Note 2 to the Consolidated Financial
Statements, "Business Acquisitions and Dispositions."
See certain operating statistics of Field Services under "Operating
Statistics." Activities of Field Services can fluctuate in response to the
seasonality affecting natural gas.
Competition
Field Services competes with major integrated oil companies, major
interstate pipelines, national and local natural gas gatherers, brokers,
marketers and distributors for natural gas supplies, in gathering and
processing natural gas and in marketing and transporting natural gas and NGLs.
Competition for natural gas supplies is primarily based on the efficiency and
reliability of operations, the availability of transportation to high demand
markets and the ability to obtain a satisfactory price for the producer's
natural gas. Competition for sales customers is based primarily upon
reliability and price of delivered natural gas and NGLs.
Regulation
The intrastate pipelines owned by Field Services are subject to state
regulation and, to the extent they provide services under Section 311 of the
Natural Gas Policy Act of 1978, are also subject to FERC regulation. However,
the majority of the natural gas gathering activities of Field Services are not
subject to regulation by the FERC.
Field Services is subject to the jurisdiction of the EPA and state
environmental agencies. For a discussion of environmental regulation, see
"Environmental Matters." Certain operations of Field Services are subject to
the jurisdiction of the Department of Transportation and certain similar state
agencies whose regulations have incorporated certain provisions of the Natural
Gas Pipeline Safety Act of 1968, the Hazardous Liquid Pipeline Safety Act of
1979, and subsequent amendments.
NAWE
NAWE's business activities include asset development, operation and
management of merchant generation facilities primarily through DENA and
commodity sales and services related to natural gas and power, primarily
through DETM, a limited liability company that is approximately 40% owned by
Exxon Mobil Corporation. NAWE conducts its business throughout the U.S. and
Canada.
6
DENA is an integrated energy business that develops, owns and manages a
portfolio of merchant generation facilities. To capture the greatest value,
DENA, through its portfolio management strategy, seeks opportunities to invest
in markets that have capacity needs and to divest assets, in whole or in part,
when significant value can be realized. DENA captures additional value by
combining its project development, commercial and risk management expertise
with the technical and operational skills of other of the Company's business
units to build and manage its projects with maximum efficiency. DENA also
supplies competitively priced energy, integrated logistics and asset
optimization services, as well as, risk management products, to wholesale
energy customers.
DENA currently owns, operates or has substantial interests in approximately
6,200 MW of gross operating generation and has approximately 7,300 MW of
projects under construction, which are slated for completion to meet summer
peak demand: 3,200 MW in 2001 and 4,100 MW in 2002. In additon to the
facilities in operation or under construction, DENA has approximately 13,500
MW in advanced development scheduled to begin operation between 2002 and 2004.
The following map includes DENA's power generation facilities.
[MAP]
DETM markets natural gas, electricity and other energy-related products to a
wide range of customers across North America. The Company owns a 60% interest
in DETM's natural gas and electric power trading operations, with Exxon Mobil
Corporation owning a 40% minority interest. The Company and Exxon Mobil
Corporation are in arbitration regarding the ownership of DETM. See
"Management's Discussion and Analysis of Results of Operations and Financial
Condition, Current Issues--Litigation and Contingencies, Exxon Mobil
Corporation" and Note 11 to the Consolidated Financial Statements,
"Commitments and Contingencies--Litigation."
DETM markets natural gas primarily to LDCs, electric power generators
(including DENA's generation facilities), municipalities, large industrial
end-users and energy marketing companies. DETM markets electricity to
investor-owned utilities, municipal power generators and other power
marketers. DETM also provides energy
7
management services, such as supply and market aggregation, peaking services,
dispatching, balancing, transportation, storage, tolling, contract negotiation
and administration, as well as energy commodity risk management products and
services. Operations are primarily in the U.S. and, to a lesser extent, in
Canada, and are serviced through three operating centers.
Natural gas marketing operations encompass both on-system and off-system
supplies. With respect to on-system supplies, DETM generally purchases natural
gas from producers who are connected to Field Services' facilities and
delivers the gas to an intrastate or interstate pipeline for redelivery to
another customer. Natural Gas Transmission's pipelines are utilized for
deliveries when prudent. With respect to off-system supplies, DETM purchases
natural gas from producers, pipelines and other suppliers not connected with
the Company's facilities for resale to customers. Substantially all of Mobil's
U.S. and Canadian natural gas production is committed to be marketed by DETM
through 2006.
With respect to electricity marketing operations, DETM purchases electricity
from third-party suppliers and from DENA's domestic generation facilities for
resale to customers.
DETM has a portfolio of short-term and long-term sales agreements with
customers, the vast majority of which incorporate market-sensitive pricing
terms. Long-term gas purchase agreements with producers, principally entered
into in connection with on-system supplies, also generally include market-
sensitive pricing provisions. Purchase and sales commitments involving
significant price and location risk are generally hedged with offsetting
commitments and commodity futures, swaps and options. For information
concerning DETM's risk-management activities, see "Management's Discussion and
Analysis of Results of Operations and Financial Condition, Quantitative and
Qualitative Disclosures About Market Risk--Commodity Price Risk" and Note 6 to
the Consolidated Financial Statements, "Risk Management and Financial
Instruments--Commodity Derivatives--Trading."
See certain operating statistics of NAWE under "Operating Statistics."
Activities of DETM can fluctuate in response to the seasonality affecting both
electricity and natural gas.
Competition
DETM competes with major integrated oil companies, major interstate
pipelines and their marketing affiliates, brokers, marketers and distributors,
and electric utilities and other electric power marketers for natural gas
supplies and in marketing natural gas, electricity and other energy-related
commodities. Competition in the energy marketing business is driven by the
price of commodities and services delivered, along with the quality and
reliability of services provided.
DENA experiences substantial competition from existing utility companies as
well as other merchant electric generation companies in the U.S.
Regulation
The energy marketing activities of NAWE may, in certain circumstances, be
subject to the jurisdiction of the FERC. Current FERC policies permit NAWE's
trading and marketing entities to market natural gas, electricity and other
energy-related commodities at market-based rates, subject to FERC
jurisdiction.
Most of DENA's operations are not subject to rate regulation. However, to
the extent that DENA's generating stations in California sell electricity
under "reliability must run" agreements to the California Independent System
Operator, such sales are made at FERC regulated rates.
As described in Note 11 to the Consolidated Financial Statements,
"Commitments and Contingencies--California Issues," a number of investigations
have commenced to determine the causes of higher wholesale electric prices in
California in 2000. During March 2001, the FERC ordered several electricity
suppliers,
8
including DETM, to (i) refund or offset prices that were bid for power in
California during Stage 3 emergencies in January and February 2001, to the
extent such prices exceeded a FERC-approved market-clearing price or
(ii) submit information supporting the prices that were bid. During the months
of January and February 2001, DETM's bids included a commercially-based credit
premium to cover the substantial risk of nonpayment that existed at the time.
The credit premiums were responsible for the bids of DETM exceeding the FERC-
approved market-clearing prices for January and February 2001. Although DETM
believes that the credit premiums were appropriate, in a compliance filing
with the FERC on March 23, 2001, DETM elected to offset the credit premium
amounts against the bid prices, provided it was paid what it was owed based on
the FERC-approved market-clearing price. Pursuant to such filing, the amount
that DETM will offset totals approximately $20 million in the aggregate. It is
expected that the FERC will issue additional orders with respect to sales in
California covering the period from October 2 through December 31, 2000, and
periods following February 2001. Various parties have expressed differing
views on the FERC's actions in this area, and such actions may be subject to
reconsideration or appeal. Although this matter is in its earliest stage,
management believes this matter will not have a material effect on the
Company's consolidated results of operations, cash flows or financial
position.
NAWE is subject to federal, state and local environmental regulations. For a
discussion of environmental regulation, see "Environmental Matters."
INTERNATIONAL ENERGY
International Energy develops, owns and operates energy-related facilities
worldwide. These facilities provide natural gas and power development and
operations, as well as energy trading and marketing. International Energy
conducts its operations primarily in Latin America, Asia Pacific and Europe,
through DEI.
Liberalization of energy markets abroad is providing substantial
opportunities for International Energy to grow through acquisitions,
construction of greenfield projects and expansion of existing facilities.
International Energy is an active participant in international competitive
energy-related markets, which include natural gas pipelines, power generation,
energy trading and marketing and other services. International Energy owns,
operates or has substantial interests in approximately 5,000 MW of generation
and approximately 1,100 miles of pipeline systems.
International Energy continues to focus on its regional target areas in
Latin America, Asia Pacific and Europe for further expansion opportunities. In
January 2000, DEI completed a series of transactions to purchase, for
approximately $1.03 billion, an approximate 95% interest in Companhia de
Geracao de Energia Eletrica Paranapanema (Paranapanema), an electric
generating company in Brazil. From August 1999 through April 2000, DEI
acquired Dominion Resources, Inc.'s portfolio of hydroelectric, natural gas
and diesel power generation businesses in Argentina, Belize, Bolivia and Peru
for approximately $405 million. Also, during 2000, DEI acquired 100% of Mobil
Europe Gas Inc. (MEGAS) from Mobil Corporation. MEGAS is a gas marketing
company located in the Netherlands. For additional information on significant
business acquisitions see "Management's Discussion and Analysis of Results of
Operations and Financial Condition, Liquidity and Capital Resources--Investing
Cash Flows" and Note 2 to the Consolidated Financial Statements, "Business
Acquisitions and Dispositions".
9
The following map illustrates the locations of International Energy's
worldwide energy facilities, including projects under construction or under
contract.
[MAP]
Competition and Regulation
International Energy's operations are subject to country and region-specific
market and competition regulations enacted by various regulatory authorities.
Regulatory issues that are commonly addressed in various international regions
include: rules governing open and competitive access to the gas and power
transmission grids, dispatch rules for merchant power plant dispatch and
remuneration, and rules that support the emergence of competitive gas and
power trading and marketing.
International Energy's operations are subject to international environmental
regulations. For a discussion of environmental regulation, see "Environmental
Matters."
OTHER ENERGY SERVICES
Other Energy Services provides engineering, consulting, construction and
integrated energy solutions worldwide, primarily through DE&S, D/FD and
DukeSolutions.
DE&S specializes in energy and environmental projects and provides
comprehensive engineering, quality assurance, project and construction
management and operating and maintenance services for all phases of
hydroelectric, nuclear and renewable power generation, transmission and
distribution projects worldwide.
D/FD, operating through several entities, provides full service siting,
permitting, licensing, engineering, procurement, construction, start-up,
operating and maintenance services for fossil-fired plants, both domestically
and internationally. Subsidiaries of the Company and Fluor Enterprises, Inc.
each own 50% of D/FD.
DukeSolutions provides energy consulting services to large end users of
energy by first identifying and then affecting points in a customer's
operations where energy related costs are incurred, including procurement,
production and disposal. The scope of services involves providing strategic
solutions to reduce costs when customers buy energy, convert it into a usable
form, use it to manufacture products and dispose of any waste.
Other Energy Services experiences substantial competition from utilities and
other independent companies in the U.S. and abroad.
Other Energy Services is subject to the jurisdiction of the EPA and
international, state and local environmental agencies. For a discussion of
environmental regulation, see "Environmental Matters."
10
DUKE VENTURES
Duke Ventures is comprised of other diverse businesses, primarily operating
through Crescent, DukeNet and DCP.
Crescent develops high-quality commercial, residential and multi-family real
estate projects and manages land holdings primarily in the southeastern U.S.
At December 31, 2000, Crescent owned 3.8 million square feet of commercial and
industrial space, with an additional 2.3 million square feet under
construction. This portfolio included 2.9 million square feet of office space,
0.8 million square feet of warehouse space and 0.1 million square feet of
retail space. At December 31, 2000, Crescent also had approximately 175,000
acres of land under its management.
DukeNet provides fiber optic networks for industrial, commercial and
residential customers and plans to enable networks for energy services
applications. It owns and operates a 700-mile fiber optic communications
network centered in North Carolina and South Carolina that is interconnected
with a 15,500-mile, fiber optic communications network, through affiliate
agreements with third parties, that stretches from Maine to Texas. DCP, a
merchant finance company, provides financing, investment banking and asset
management services to wholesale and commercial energy markets. During
September 2000, DukeNet sold its 20% interest in BellSouth Carolina PCS to
BellSouth Corporation. See further discussion of this sale in Note 2 of the
Consolidated Financial Statements, "Business Acquisitions and Dispositions."
ENVIRONMENTAL MATTERS
The Company is subject to international, federal, state and local
regulations with regard to air and water quality, hazardous and solid waste
disposal and other environmental matters. Certain environmental regulations
affecting the Company include:
. The Clean Air Act and the 1990 amendments to the Act, as well as state
laws and regulations impacting air emissions that impose
responsibilities on owners, operators or both of air emissions sources
including obtaining permits and annual compliance and reporting
obligations;
. State Implementation Plans, which were issued by the EPA to 22 states
and the District of Columbia related to existing and new national
ambient air quality standards for ozone;
. The Federal Water Pollution Control Act Amendments of 1987, which
require permits for facilities that discharge treated wastewater into
the environment; and
. The Comprehensive Environmental Response, Compensation and Liability
Act, which can require any individual or entity which may have owned or
operated a disposal site, as well as transporters or generators of
hazardous wastes which were sent to such site, to share in remediation
costs for the site.
For further discussion of environmental matters involving the Company,
including possible liability and capital costs, see Item 3--"Legal
Proceedings," "Management's Discussion and Analysis of Results of Operations
and Financial Condition, Current Issues--Environmental" and Note 11 to the
Consolidated Financial Statements, "Commitments and Contingencies--
Environmental." Compliance with international, federal, state and local
provisions' regulating the discharge of materials into the environment, or
otherwise protecting the environment, is not expected to have a material
adverse effect on the competitive position, consolidated results of
operations, cash flows or financial position of the Company.
11
GEOGRAPHIC REGIONS
The Company's significant geographic regions are as follows:
Latin Other
U.S. Canada America Foreign Consolidated
------- ------ ------- ------- ------------
(In millions)
2000
Consolidated revenues.............. $33,895 $4,964 $ 512 $ 560 $39,931
Consolidated long-term assets...... 17,972 900 2,823 1,222 22,917
1999
Consolidated revenues.............. $14,466 $2,007 $ 171 $ 252 $16,896
Consolidated long-term assets...... 11,005 250 2,708 901 14,864
1998
Consolidated revenues.............. $12,038 $ 996 $ 31 $ 46 $13,111
Consolidated long-term assets...... 9,032 140 207 632 10,011
For a discussion of the Company's foreign operations and the risks
associated with them, see "Management's Discussion and Analysis of Results of
Operations and Financial Condition, Quantitative and Qualitative Disclosures
About Market Risk--Foreign Currency Risk" and Notes 3 and 6 to the
Consolidated Financial Statements, "Business Segments" and "Risk Management
and Financial Instruments," respectively.
EMPLOYEES AND MANAGEMENT
At December 31, 2000, the Company had approximately 12,000 employees.
Approximately 175 operating and maintenance employees are represented by
unions. Of these, approximately 60 are represented by the International
Brotherhood of Electrical Workers (IBEW). During 2000, a new agreement was
reached with the IBEW for these employees. Approximately 37 employees are
represented by the Paper, Allied, Chemical and Energy Workers Union (PACE) and
13 employees are represented by the PACE International Unit. A new labor
agreement was reached with the PACE International Unit in 2000. Approximately
64 employees are represented by the International Union of Operating
Engineers.
The officers and directors of the Company consist of certain executive
officers of Duke Energy. Duke Energy has entered into employment agreements
with certain key executives. Additionally, the Company's business units
maintain their own management structure.
RECENT FINANCING
In late March 2001, Duke energy completed an offering of 31 million units of
mandatorily convertible securities (Equity Units) at a price of $25 per unit
before underwriting discount and other offering expenses. The Equity Units
consist of senior notes of the Company and Duke Energy purchase contracts
obligating the investors to purchase shares of Duke Energy's common stock in
2004. Also in March 2001, the underwriters exercised options granted to them
to purchase an additional 4 million Equity Units at the original issue prices,
less underwriting discounts, to cover over-allotment made during the
offerings. Total net proceeds from the offering were approximately $850
million and were used to repay short-term debt and for other corporate
purposes.
12
OPERATING STATISTICS
Years Ended December 31,
-----------------------------------
2000 1999 1998 1997 1996
------- ------- ------ ------ -----
Natural Gas Transmission
Throughput Volumes(a), TBtu(b):........... 1,717 1,565 1,459 1,641 1,676
Field Services
Natural Gas Gathered and
Processed/Transported, TBtu/d(c)......... 7.6 5.1 3.6 3.4 2.9
NGL Production, MBbl/d(d)................. 358.5 192.4 110.2 108.2 78.5
Average Natural Gas Price per MMBtu(e).... $3.89 $2.27 $2.11 $2.59 $2.59
Average NGL Price per Gallon.............. $0.53 $0.34 $0.26 $0.35 $0.39
Natural Gas Marketed, TBtu/d.............. 0.7 0.5 0.4 0.4 0.5
NAWE
Natural Gas Marketed, TBtu/d.............. 11.9 10.5 8.0 6.9 5.5
Electricity Marketed, GWh(f).............. 275,258 109,634 98,991 64,650 4,229
- --------
(a) Excludes throughput of pipelines sold in March 1999 to CMS Energy: 328
TBtu (1999); 1,141 Tbtu (1998); 1,279 TBtu (1997); 1,319 TBtu (1996).
(b) Trillion British thermal units.
(c) Trillion British thermal units per day.
(d) Thousand barrels per day.
(e) Million British thermal units.
(f) Gigawatt-hour
Item 2. Properties.
NATURAL GAS TRANSMISSION
TETCO's gas transmission system extends approximately 1,700 miles from
producing fields in the Gulf Coast region of Texas and Louisiana to Ohio,
Pennsylvania, New Jersey and New York. It consists of two parallel systems,
one consisting of three large-diameter parallel pipelines and the other
consisting of from one to three large-diameter pipelines over its length.
TETCO's system consists of approximately 9,000 miles of pipeline and has 70
compressor stations.
TETCO also owns and operates two offshore Louisiana pipeline systems, which
extend over 100 miles into the Gulf of Mexico and include 469 miles of TETCO's
pipeline system.
Algonquin's transmission system connects with TETCO's facilities in New
Jersey, and extends approximately 250 miles through New Jersey, New York,
Connecticut, Rhode Island and Massachusetts. The system consists of 1,066
miles of pipeline with six compressor stations.
East Tennessee's transmission system crosses TETCO's system at two points in
Tennessee and consists of two mainline systems totaling 1,100 miles of
pipeline in Tennessee and Virginia with 18 compressor stations.
For additional information and a map concerning natural gas transmission and
storage properties, see "Business, Natural Gas Transmission."
FIELD SERVICES
For information and a map regarding the properties of Field Services, see
"Business, Field Services."
13
NAWE
The DENA generation portfolio includes:
Ownership
Gross Interest
Name MW Fuel Location (percentage)
- ---- ----- --------------- -------------- ------------
Moss Landing.................. 1,478 Natural gas CA 100%
Morro Bay..................... 1,002 Natural gas CA 100
South Bay..................... 700 Natural gas CA 100
Madison....................... 640 Natural gas OH 50
Vermillion.................... 640 Natural gas IN 50
Maine Independence............ 520 Natural gas ME 100
Bridgeport.................... 480 Natural gas CT 67
American Ref-Fuel............. 286 Waste-to-energy CT, MA, NJ, NY 37
St. Francis................... 247 Natural gas MO 50
Oakland....................... 165 Oil CA 100
Fort Drum..................... 50 Coal NY 10
-----
Total....................... 6,208
=====
DENA has approximately 7,300 MW under construction in various high-growth
markets, which are slated for completion to meet summer peak demands: 3,200 MW
in 2001 and 4,100 MW in 2002. In addition to the facilities in operation or
under construction, DENA has approximately 13,500 MW in advanced development
scheduled to begin operation between 2002 and 2004.
For additional information and a map regarding the properties of NAWE, see
"Business, NAWE."
INTERNATIONAL ENERGY
The International Energy generation portfolio in operation includes:
Approximate
Ownership
Gross Interest
Name MW Fuel Location (percentage)
- ---- ----- ------------- ----------- ------------
Paranapanema...................... 2,307 Hydro Brazil 95
Hidroelectrica Cerros Colorados... 547 Thermal/Hydro Argentina 91
Egenor............................ 529 Hydro/Thermal Peru 90
Acajutla.......................... 400 Thermal El Salvador 88
Puncakjaya Power.................. 389 Thermal Indonesia 43
Western Australia................. 280 Thermal Australia 100
Electroquil....................... 169 Thermal Ecuador 52
Aquaytia.......................... 160 Hydro Peru 22
Empressa Electrica Corani......... 126 Hydro Bolivia 50
New Zealand....................... 112 Thermal New Zealand 100
Mollejon.......................... 25 Hydro Belize 95
-----
Total........................... 5,044
=====
DEI has approximately 562 and 43 gross MWs under construction in Latin
America and Australia, respectively. DEI owns approximately 1,320 miles of
pipeline systems in Australia, including 434 miles under development.
Additionally, DEI has an 11.84% ownership interest in 855 miles of pipeline
systems in Australia and a 21.9% ownership interest in 190 miles of pipeline
systems in Peru. Also as of December 31, 2000, DEI had a 25% indirect interest
in National Methanol Company, which owns and operates a methanol and MTBE
(methyl tertiary butyl ether) business in Jubail, Saudi Arabia.
For additional information and a map regarding the properties of
International Energy, see "Business, International Energy."
14
DUKE VENTURES
For information regarding the properties of Duke Ventures, see "Business,
Duke Ventures."
OTHER
None of the properties used in connection with the Company's other business
activities are considered material to the Company's operations as a whole.
Item 3. Legal Proceedings.
The Company's subsidiaries, DENA and DETM, have been named among 16
defendants in a class action lawsuit (the Gordon lawsuit) filed against
companies identified as "generators and traders" of electricity in California
markets. DETM also was named as one of numerous defendants in four additional
lawsuits, including two class actions (the Hendricks and Pier 23 Restaurant
lawsuits), filed against generators, marketers and traders and other unnamed
providers of electricity in California markets. These suits were brought
either by or on behalf of electricity consumers in the State of California.
The Gordon and Hendricks class action suits were filed in the Superior Court
of the State of California, San Diego County, in November 2000. The other
three suits were filed in January 2001, one in the Superior Court of the State
of California, San Diego County, and the other two in the Superior Court of
the State of California, County of San Francisco. These suits generally allege
that the defendants manipulated the wholesale electricity markets in violation
of state laws against unfair and unlawful business practices and state
antitrust laws. Plaintiffs in the Gordon suit seek aggregate damages of over
$4 billion, and the plaintiffs in the other suits, to the extent damages are
specified, allege damages in excess of $1 billion. The lawsuits each seek the
disgorgement of alleged unlawfully obtained revenues for sales of electricity
and, in three suits, an award of treble damages. For further information
related to this lawsuit, see Note 11 to the Consolidated Financial Statements,
"Commitments and Contingencies--California Issues," and "Management's
Discussion and Analysis of Results of Operations and Financial Condition,
Current Issues--California Issues."
In December 2000, three subsidiaries of the Company initiated binding
arbitration against three subsidiaries of the Exxon Mobil Corporation
(collectively, the "Exxon Mobil entities") concerning the parties' joint
ownership of DETM and certain related affiliates (collectively, the
"Ventures"). At issue is a buy-out right provision in the parties' agreement.
The agreements governing the ownership of the Ventures contain provisions
giving the Company the right to purchase the Exxon Mobil entities' 40%
interest in the Ventures in the event material business disputes arise between
the Ventures' owners. Such disputes have arisen, and consequently, the Company
exercised its right to buy the Exxon Mobil entities' interest. The Company
claims that refusal by the Exxon Mobil entities to honor the exercise is a
breach of the buy-out right provision, and seeks specific performance of the
provision. The Company also complains of the Exxon Mobil entities' lack of use
of, and contributions to, the Ventures.
In January 2001, the Exxon Mobil entities asserted counterclaims in the
arbitration and claims in a separate Texas state court action alleging that
the Company breached its obligations to the Ventures and to the Exxon Mobil
entities. The Exxon Mobil entities also claim that the Company violated a
Guaranty Agreement. While this matter is in its early stages, management
believes that the final disposition of this action will not have a material
adverse effect on the Company's consolidated results of operations, cash flows
or financial position.
The Illinois Environmental Protection Agency has initiated an environmental
enforcement proceeding against a former subsidiary of the Company relating to
alleged air quality permit violations at a natural gas compressor station. The
Company has agreed to indemnify the purchaser of this former subsidiary
against liability for any penalty or fines resulting from these alleged
violations. This proceeding could result in a penalty in excess of $100,000.
Management believes that the resolution of this matter will not have a
material adverse effect on consolidated results of operations, cash flows or
financial position.
The Company's subsidiary, DEFS, is presently resolving non-compliance issues
with the Texas Natural Resources Conservation Commission associated with the
timing of air permit annual compliance certifications submitted to the agency
in 1998 and 1999. This matter, the bulk of which was voluntarily self-
disclosed to the agency, involves approximately 115 of DEFS' facilities that
did not meet specific administrative filing deadlines for required air permit
paperwork. Additionally, DEFS is actively resolving, with the New Mexico
Environment Department, alleged non-compliance of various air permit
requirements at four facilities in New Mexico. These matters, the majority of
which were also voluntarily self-disclosed to the agency, generally involve
document
15
preparation and submittal as required by permits, compliance testing
requirements at two facilities and compliance with permit emissions limits at
one facility. DEFS believes that these apparent non-compliance issues being
addressed with Texas and New Mexico agencies, under relevant air programs,
will result in total penalty assessments of less than $500,000. Management
believes that the resolution of this matter will not have a material adverse
effect on consolidated results of operations, cash flows or financial
position.
DEFS has also been in discussions with the Colorado Air Pollution Control
Division regarding various asserted non-compliance issues arising from agency
inspections of DEFS' Colorado facilities in 1999 and 2000, and arising from
compliance issues disclosed to the agency pursuant to permit requirements or
voluntarily disclosed to the agency in 2000. These items relate to various
specific and detailed terms of the Title V Operation Permits at seven gas
plants and two compressor stations in Colorado, including record keeping
requirements, parametric monitoring requirements, delayed filings, and
operation inconsistent with throughput limits on particular pieces of
equipment. As a result of these discussions, DEFS received from the agency in
March 2001, a comprehensive proposed settlement agreement to resolve all of
these various items related to air permit compliance at the nine facilities.
Although DEFS is still discussing the appropriate resolution of these non-
compliance instances with the Colorado Air Pollution Control Division,
management believes that the comprehensive resolution for all nine facilities
will result in a total penalty assessment of less than $575,000.
For additional information concerning litigation and other contingencies,
see Note 11 to the Consolidated Financial Statements, "Commitments and
Contingencies--Environmental," and "Management's Discussion and Analysis of
Results of Operations and Financial Condition, Current Issues--Environmental;
Current Issues--California Issues, and Current Issues--Litigation and
Contingencies."
PART II.
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
All of the outstanding common stock of the Company is, as of the date
hereof, owned by Duke Energy. There is no market for the Company's common
stock. Dividends on the Company's common stock will be paid when declared by
the Board of Directors. The Company did not pay dividends on its common stock
in 2000 or 1999 and, in present, has no plans to pay such dividends in the
foreseeable future.
Item 6. Selected Financial Data.
Selected Financial Data
2000 1999 1998 1997(a) 1996(a)
------- ------- ------- ------- -------
(In millions, except per share amounts)
Income Statement
Operating revenues................... $39,931 $16,896 $13,111 $11,915 $7,816
Operating expenses................... 37,683 15,830 12,023 11,079 6,947
------- ------- ------- ------- ------
Operating income..................... 2,248 1,066 1,088 836 869
Other income and expenses............ 83 94 49 37 20
------- ------- ------- ------- ------
Earnings before interest and taxes... 2,331 1,160 1,137 873 889
Interest expense..................... 621 326 237 214 232
Minority interest expense............ 263 107 71 22 6
------- ------- ------- ------- ------
Earnings before income taxes......... 1,447 727 829 637 651
Income taxes......................... 521 237 310 257 252
------- ------- ------- ------- ------
Income before extraordinary item..... 926 490 519 380 399
Extraordinary gain (loss), net of
tax................................. -- 660 (8) -- (17)
------- ------- ------- ------- ------
Net income......................... $ 926 $ 1,150 $ 511 $ 380 $ 382
Balance Sheet
Total assets......................... $43,522 $20,600 $13,856 $11,097 $9,752
Long-term debt, less current
maturities.......................... $ 7,254 $ 5,319 $ 2,884 $ 2,919 $2,028
- --------
(a) Financial information reflects accounting for the 1997 merger with
PanEnergy Corp as a pooling of interests. As a result, the financial
information gives effect to the merger as if it had occurred January 1,
1996.
16
Item 7. Management's Discussion and Analysis of Results of Operations and
Financial Condition.
INTRODUCTION
Management's Discussion and Analysis should be read in conjunction with the
Consolidated Financial Statements.
Business Segments. Duke Capital Corporation (collectively with its
subsidiaries, "the Company") is a wholly owned subsidiary of Duke Energy
Corporation (Duke Energy) and serves as the parent for certain of Duke
Energy's non-utility and other operations. The Company provides financing and
credit enhancement services for its subsidiaries and conducts its operations
through six business segments.
Natural Gas Transmission provides interstate transportation and storage of
natural gas for customers primarily in the Mid-Atlantic, New England and
southeastern states. Its operations are conducted primarily through Duke
Energy Gas Transmission Corporation. The interstate natural gas transmission
and storage operations are subject to the rules and regulations of the Federal
Energy Regulatory Commission (FERC).
Field Services gathers, processes, transports, markets and stores natural
gas and produces, transports, markets and stores natural gas liquids (NGLs).
Its operations are conducted primarily through Duke Energy Field Services, LLC
(DEFS), a limited liability company that is approximately 30% owned by
Phillips Petroleum. Field Services operates gathering systems in western
Canada and 11 contiguous states that serve major natural gas-producing regions
in the Rocky Mountain, Permian Basin, Mid-Continent, East Texas-Austin Chalk-
North Louisiana, as well as onshore and offshore Gulf Coast areas.
North American Wholesale Energy's (NAWE's) activities include asset
development, operation and management, primarily through Duke Energy North
America, LLC (DENA), and commodity sales and services related to natural gas
and power, primarily through Duke Energy Trading and Marketing, LLC (DETM).
DETM is a limited liability company that is approximately 40% owned by Exxon
Mobil Corporation. NAWE conducts its business throughout the U.S. and Canada.
The operations of the previously segregated Trading and Marketing segment were
combined by management into NAWE during 2000. Previous periods have been
restated to conform to current period presentation.
International Energy conducts its operations through Duke Energy
International, LLC. International Energy's activities include asset
development, operation and management of natural gas and power facilities and
energy trading and marketing of natural gas and electric power. This activity
is targeted in the Latin American, Asia Pacific and European regions.
Other Energy Services is a combination of businesses that provide
engineering, consulting, construction and integrated energy solutions
worldwide, primarily through Duke Engineering & Services, Inc. (DE&S),
Duke/Fluor Daniel (D/FD) and DukeSolutions, Inc. (DukeSolutions). D/FD is a
50/50 partnership between the Company and Fluor Enterprises, Inc.
Duke Ventures is comprised of other diverse businesses, primarily operating
through Crescent Resources, Inc. (Crescent), DukeNet Communications, LLC.
(DukeNet) and Duke Capital Partners (DCP). Crescent develops high-quality
commercial, residential and multi-family real estate projects and manages land
holdings primarily in the southeastern U.S. DukeNet provides fiber optic
networks for industrial, commercial and residential customers. DCP, a newly
formed, wholly owned merchant finance company, provides financing, investment
banking and asset management services to wholesale and commercial energy
markets.
Business Strategy. The company's business strategy is to develop integrated
energy businesses in targeted regions where the Company's extensive
capabilities in developing energy assets, operating electricity, natural gas
and NGL plants, optimizing commercial operations and managing risk can provide
comprehensive energy solutions for customers and create superior value for
shareholders. The growth in and restructuring of global energy markets are
providing opportunities for the Company's competitive business segments to
capitalize on their comprehensive capabilities. Domestically, the Company is
aggressively investing in new merchant power plants throughout the U.S.,
expanding its natural gas pipeline infrastructure in the eastern U.S., rapidly
increasing
17
its leading position in natural gas gathering, processing and NGL marketing,
and developing its trading and marketing structured origination expertise
across the energy spectrum. Internationally, the Company is currently focusing
on integrated electric and natural gas opportunities in Latin America, Asia
Pacific and Europe.
Natural Gas Transmission has increased its earnings growth rate by executing
a comprehensive strategy of selected acquisitions and expansions and by
developing expanded services and incremental projects that meet changing
customer needs.
Field Services has developed market-leading size, scope and reliability of
supply in natural gas gathering, processing and NGL marketing. Field Services
plans to make additional investments in gathering, processing and NGL
infrastructure. Field Services' interconnected natural gas processing
operations provide an opportunity to capture fee-based investment
opportunities in certain NGL assets, including pipelines, fractionators and
terminals.
NAWE plans to continue increasing earnings through acquisitions,
divestitures, construction of greenfield projects and expansion of existing
facilities as regional opportunities are identified, evaluated and realized
throughout the North American marketplace. To capture the greatest value in
the U.S., DENA, through its portfolio management strategy, seeks opportunities
to invest in energy assets in markets that have capacity needs and to divest
other assets, in whole or in part, when significant value can be realized.
Commodity sales and services related to natural gas and power continue to
expand as NAWE provides energy supply, structured origination, trading and
marketing, risk management and commercial optimization services to large
energy customers, energy aggregators and other wholesale companies.
International Energy plans to continue expanding through acquisitions,
divestitures, construction of greenfield projects and expansion of existing
facilities in selected international regions. International Energy's
combination of assets and capabilities and close working relationships with
other subsidiaries of the Company allow it to efficiently deliver natural gas
pipeline, power generation, energy marketing and other services.
Other Energy Services plans to grow by providing an expanding customer base
with a variety of engineering and energy efficiency services that allow
customers to more effectively deal with rapidly changing conditions in the
energy marketplace.
Duke Ventures plans to expand earnings capabilities in its real estate,
telecommunications and capital financing business units by developing regional
opportunities and by applying extensive experience to new project development.
The Company's business strategy and growth expectations can vary
significantly depending on many factors, including, but not limited to, the
pace and direction of industry restructuring, regulatory constraints,
acquisition opportunities, market volatility and economic trends.
Results of Operations
In 2000, net income was $926 million, including a pre-tax gain of $407
million on the sale of the Company's 20% interest in BellSouth Carolina PCS
(BellSouth PCS). In 1999, net income was $1,150 million, including an after-
tax extraordinary gain of $660 million resulting from the sale of the
Panhandle Eastern Pipe Line Company (PEPL), Trunkline Gas Company (Trunkline)
and additional storage related to those systems, which substantially comprised
the Midwest Pipelines along with Trunkline LNG Company. The increase in income
before extraordinary items in 2000 was primarily due to a 101% increase in
segment earnings as described below, including the BellSouth PCS gain.
Partially offsetting this increase was the 1999 extraordinary gain and higher
interest and minority interest expense in the current year.
Net income increased $639 million in 1999 from 1998 net income of $511
million. The increase in net income was primarily due to the 1999
extraordinary gain resulting from the sale of the Midwest Pipelines. This
gain, along with the factors described below that affect segment earnings, was
partially offset by higher interest and minority interest expense.
18
Operating income for 2000 was $2,248 million compared to $1,066 million in
1999 and $1,088 million in 1998. Earnings before interest and taxes (EBIT)
were $2,331 million, $1,160 million and $1,137 million for 2000, 1999 and
1998, respectively. Management evaluates each business segment based on an
internal measure of EBIT, after deducting minority interests. Operating income
and EBIT are affected by the same fluctuations for the Company and each of its
business segments. The only notable difference between operating income and
EBIT is the inclusion in EBIT of certain non-operating activities. See Note 3
to the Consolidated Financial Statements for additional information on
business segments. EBIT is summarized in the following table and is discussed
by business segment thereafter.
EBIT by Business Segment
Years Ended December 31,
----------------------------
2000 1999 1998
-------- -------- --------
(In millions)
Natural Gas Transmission.......................... $ 534 $ 627 $ 702
Field Services.................................... 296 144 76
North American Wholesale Energy................... 330 214 133
International Energy.............................. 331 42 12
Other Energy Services............................. (61) (94) 10
Duke Ventures..................................... 563 162 122
Other Operations.................................. 107 (27) 25
EBIT attributable to minority interests........... 231 92 57
-------- -------- --------
Consolidated EBIT................................. $ 2,331 $ 1,160 $ 1,137
======== ======== ========
Other Operations primarily include certain unallocated corporate costs.
Included in the amounts discussed hereafter are intercompany transactions that
are eliminated in the Consolidated Financial Statements.
Natural Gas Transmission
Years Ended December 31,
--------------------------
2000 1999 1998
-------- -------- --------
(In millions, except
where noted)
Operating revenues.................................. $ 1,131 $ 1,230 $ 1,542
Operating expenses.................................. 609 615 864
-------- -------- --------
Operating income.................................... 522 615 678
Other income, net of expenses....................... 12 12 24
-------- -------- --------
EBIT................................................ $ 534 $ 627 $ 702
======== ======== ========
Throughput--TBtu(a)................................. 1,717 1,893 2,593
- --------
(a) Trillion British thermal units.
In 2000, EBIT for Natural Gas Transmission decreased $93 million compared to
1999, primarily due to $132 million of EBIT in 1999 that did not reoccur in
2000. These items consisted of $70 million of EBIT related to the Midwest
Pipelines, which were sold to CMS Energy Corporation (CMS) in March 1999; a
$24 million gain resulting from the sale of the Company's interest in the
Alliance Pipeline project; and benefits totaling $38 million related to the
completion of certain environmental cleanup programs below estimates. These
items were partially offset by increased earnings from market-expansion
projects and joint ventures such as the Maritimes & Northeast Pipeline, which
was placed into service in December 1999, and earnings from East Tennessee
Natural Gas Company and Market Hub Partners (MHP), which were acquired in
March and September 2000, respectively. See Note 2 to the Consolidated
Financial Statements for additional information on the sale of the Midwest
Pipelines and the acquisitions of East Tennessee Natural Gas Company and MHP.
19
EBIT for Natural Gas Transmission decreased $75 million in 1999 compared to
1998. As a result of the sale of the Midwest Pipelines in March 1999, EBIT for
the Midwest Pipelines decreased $156 million compared to 1998's full year of
operation. For the remainder of Natural Gas Transmission, EBIT increased $81
million compared to 1998, primarily as a result of increased earnings from
market-expansion projects and joint ventures, higher throughput and lower
operating expenses. A $24 million gain resulting from the sale of the
Company's interest in the Alliance Pipeline project and benefits totaling $38
million related to the completion of certain environmental cleanup programs
below estimates also increased EBIT in 1999. Partially offsetting these
contributions to EBIT were the favorable impacts in 1998 in connection with
the resolution of regulatory issues related to natural gas supply realignment
cost issues and a refund from a state property tax ruling.
Field Services
Years Ended December 31,
---------------------------
2000 1999 1998
-------- -------- --------
(In millions, except where
noted)
Operating revenues............................... $ 9,060 $ 3,590 $ 2,677
Operating expenses............................... 8,635 3,444 2,598
-------- -------- --------
Operating income................................. 425 146 79
Other income, net of expenses.................... 6 (2) (3)
Minority interest expense........................ 135 -- --
-------- -------- --------
EBIT............................................. $ 296 $ 144 $ 76
======== ======== ========
Natural gas gathered and processed/transported,
TBtu/d(a)....................................... 7.6 5.1 3.6
NGL production, MBbl/d(b)........................ 358.5 192.4 110.2
Natural gas marketed, TBtu/d..................... 0.7 0.5 0.4
Average natural gas price per MMBtu(c)........... $ 3.89 $ 2.27 $ 2.11
Average NGL price per gallon(d).................. $ 0.53 $ 0.34 $ 0.26
- --------
(a) Trillion British thermal units per day.
(b) Thousand barrels per day.
(c) Million British thermal units.
(d) Does not reflect results of commodity hedges.
Field Services' EBIT increased $152 million in 2000 from 1999. The increase
in EBIT and volume activity was primarily due to the combination of Field
Services' natural gas gathering, processing and marketing business with
Phillips Petroleum's Gas Gathering, Processing and Marketing unit (Phillips)
in March 2000; the acquisition of the natural gas gathering, processing,
fractionation and NGL pipeline business from Union Pacific Resources (UPR)
(collectively, the "UPR acquisition") in April 1999; and other recent
acquisitions and plant expansions. For additional information on the Phillips
combination and the UPR acquisition, see Note 2 to the Consolidated Financial
Statements. Improved average NGL prices, which increased 56% over 1999 prices,
also contributed significantly to the increase in EBIT.
In 1999, Field Services' EBIT increased $68 million compared to 1998. A
significant portion of the increase resulted from earnings from the UPR
acquisition. Improved average NGL prices, which were up 31% from the prior
year also contributed to the increase in EBIT. Partially offsetting these
increases were $34 million of asset sale gains in 1998.
20
North American Wholesale Energy
Years Ended December 31,
--------------------------
2000 1999 1998
-------- -------- --------
(In millions, except
where noted)
Operating revenues................................... $ 29,303 $ 11,541 $ 8,783
Operating expenses................................... 28,900 11,326 8,619
-------- -------- -------
Operating income..................................... 403 215 164
Other income, net of expenses........................ -- 60 20
Minority interest expense............................ 73 61 51
-------- -------- -------
EBIT................................................. $ 330 $ 214 $ 133
======== ======== =======
Natural gas marketed, TBtu/d......................... 11.9 10.5 8.0
Electricity marketed, GWh(a)......................... 275,258 109,634 98,991
Proportional megawatt capacity owned(b).............. 8,984 5,799 5,098
- --------
(a)Gigawatt-hours.
(b)Includes under construction or under contract.
NAWE's EBIT increased $116 million in 2000 compared to 1999. The increase
was the result of increased earnings from asset positions, increased trading
margins due to price volatility in natural gas and power and a $47 million
increase in income from the sale of interests in generating facilities as a
result of NAWE executing its portfolio management strategy. Operating revenues
and expenses increased as the volumes of natural gas and power marketed
increased 13% and 151%, respectively. These increases were partially offset by
a $110 million charge related to receivables for energy sales in California,
and increased operating and development costs associated with business
expansion. See the Current Issues, California Issues section of Management's
Discussion and Analysis, and Note 11 to the Consolidated Financial Statements
for further information.
In 1999, EBIT for NAWE increased $81 million from 1998. The increase
included $99 million in income from the sale of partial interests in four
generating facilities as a result of NAWE executing its portfolio management
strategy, as well as, higher power trading margins. Partially offsetting these
increases were lower natural gas trading margins. Higher operating expenses
and increased development costs associated with business expansion also
partially offset the earnings increases.
International Energy
Years Ended
December 31,
-----------------
2000 1999 1998
------ ----- ----
(In millions,
except where
noted)
Operating revenues........................................... $1,067 $ 357 $159
Operating expenses........................................... 755 292 145
------ ----- ----
Operating income............................................. 312 65 14
Other income, net of expenses................................ 42 8 4
Minority interest expense.................................... 23 31 6
------ ----- ----
EBIT......................................................... $ 331 $ 42 $ 12
====== ===== ====
Proportional megawatt capacity owned(a)...................... 4,876 2,974 943
Proportional maximum pipeline capacity(a), MMcf/d(b)......... 416 321 124
- --------
(a) Includes under construction or under contract.
(b) Million cubic feet per day.
21
International Energy's EBIT increased $289 million in 2000 when compared to
1999. The increase was primarily attributable to increased earnings in Latin
America, mainly resulting from new investments (see Note 2 to the Consolidated
Financial Statements for a discussion of significant acquisitions). The
increase also included $54 million from the February 2000 sale of certain
assets relating to the transportation of liquefied natural gas.
In 1999, International Energy's EBIT increased $30 million compared to 1998.
Earnings from new investments in Latin America and Australia contributed $63
million to the increase. Partially offsetting these increases were higher
operating expenses and increased development costs associated with business
expansion.
Other Energy Services
Years Ended
December 31,
------------------
2000 1999 1998
---- ------ ----
(In millions)
Operating revenues........................................... $695 $ 989 $521
Operating expenses........................................... 756 1,083 511
---- ------ ----
EBIT......................................................... $(61) $ (94) $ 10
==== ====== ====
In 2000, EBIT for Other Energy Services improved $33 million compared to
1999. New business activity and decreased operating expenses at DukeSolutions,
and earnings related to new projects at D/FD were responsible for current year
improved EBIT. The results for 2000 also include the Company's portion of an
estimated project loss recorded by D/FD of approximately $62 million,
partially offset by 1999 charges of $38 million and $35 million at DE&S and
DukeSolutions, respectively. The 1999 charges primarily related to expenses
for severance and office closings associated with repositioning the companies
for growth.
EBIT for Other Energy Services decreased $104 million in 1999 compared to
1998. The decrease was primarily due to the above-mentioned charges of $38
million and $35 million at DE&S and DukeSolutions, respectively. Increased
development costs at DukeSolutions and decreased earnings from projects of
DE&S also contributed to lower EBIT.
Duke Ventures
Years Ended
December 31,
--------------
2000 1999 1998
---- ---- ----
(In millions)
Operating revenues............................................... $642 $232 $171
Operating expenses............................................... 79 70 49
---- ---- ----
EBIT............................................................. $563 $162 $122
==== ==== ====
EBIT for Duke Ventures increased $401 million in 2000 when compared to 1999.
This increase is primarily attributable to the sale by DukeNet of its 20%
interest in BellSouth PCS to BellSouth Corporation for a pre-tax gain of $407
million. Slightly offsetting this increase in EBIT was a decrease in
commercial project sales and land sales at Crescent.
In 1999, EBIT for Duke Ventures increased $40 million compared to 1998. The
increase was primarily due to Crescent's increased residential developed lot
sales, land sales and commercial project sales, partially offset by decreased
lake lot sales. Increased fiber optic revenues at DukeNet and decreased losses
related to its interest in BellSouth PCS also contributed to increased EBIT.
22
Other Impacts on Earnings Available for Common Stockholders
Interest expense increased $295 million in 2000 compared to 1999, and $89
million in 1999 compared to 1998 due to higher average debt balances
outstanding, resulting from acquisitions and expansion.
Minority interest expense increased $156 million in 2000 compared to 1999
and $36 million in 1999 compared to 1998. Included in minority interest
expense is expense related to regular distributions on issuances of the
Company's trust preferred securities (see Note 10 to the Consolidated
Financial Statements). This expense increased $13 million for 2000 and $34
million for 1999 due to additional issuances of the Company's trust preferred
securities during 1999 and 1998.
In addition, the increase for 2000 includes minority interest expense
related to Field Services' combination with Phillips Petroleum, and increased
minority interest expense at NAWE related to its joint venture with Exxon
Mobil Corporation, partially offset by decreased minority interest expense at
International Energy related to its 1999 and 2000 acquisitions. The 1999
increase in minority interest expense over 1998 related primarily to
International Energy's 1999 investments and NAWE's joint venture with Exxon
Mobil Corporation. For additional information regarding acquisitions and new
joint venture projects, see Notes 2 and 7 to the Consolidated Financial
Statements.
The Company's effective income tax rate was approximately 36%, 33% and 37%
for 2000, 1999 and 1998, respectively. The decrease in 1999 was primarily due
to the favorable resolution of several income tax issues and the utilization
of certain capital loss carryforwards due to the sale of the Midwest
Pipelines.
The sale of the Midwest Pipelines to CMS closed in March 1999 and resulted
in a $660 million extraordinary gain, net of income tax of $404 million (see
Note 2 to the Consolidated Financial Statements).
In January 1998, TEPPCO Partners, LP, in which the Company has a 21.1%
ownership interest, redeemed certain First Mortgage Notes. This resulted in a
non-cash extraordinary loss of $8 million, net of income tax of $5 million,
related to the Company's share of costs of the early retirement of debt.
LIQUIDITY AND CAPITAL RESOURCES
Operating Cash Flows
Net cash provided by operations was $1,272 million in 2000, $1,128 million
in 1999 and $930 million in 1998. Cash flows from operations decreased in 2000
compared to 1999 primarily due to tax payments made in 2000 related to the
sale of the Midwest Pipelines. The increase in cash flows from operations in
1999 from 1998 was primarily due to net income resulting from business
expansion.
Investing Cash Flows
Capital and investment expenditures were approximately $4.8 billion in 2000
compared to $5.2 billion in 1999. The primary use of cash in investing
activities for capital and investment expenditures reflects development and
expansion expenditures, upgrades to existing assets and the acquisitions of
various businesses and assets. The change in Natural Gas Transmission's
capital expenditures is primarily due to business expansion related to the
approximately $390 million acquisition of East Tennessee Natural Gas Company
and the approximately $250 million of cash for the acquisition of MHP. In
2000, NAWE began construction of a number of power generation plants in the
U.S. and continued capital expenditures on projects initiated prior to 2000.
International Energy's business expansion included the completion of a tender
offer to the minority shareholders of Companhia de Geracao de Energia Eletrica
Paranapanema (Paranapanema) for approximately $280 million and the completion
of the approximately $405 million acquisition of Dominion Resources, Inc.'s
portfolio of hydroelectric, natural gas and diesel power generation businesses
in Latin America. Offsetting the capital and investing expenditures were cash
proceeds of $400 million from the 2000 sale of The Company's 20% interest in
BellSouth PCS to
23
BellSouth Corporation. For additional information concerning significant
acquisitions and dispositions, see Note 2 to the Consolidated Financial
Statements.
Capital and Investment Expenditures by Business Segment
Years Ended December 31,
--------------------------
2000 1999 1998
-------- -------- --------
(In millions)
Natural Gas Transmission............................ $ 973 $ 261 $ 290
Field Services...................................... 376 1,630 304
North American Wholesale Energy..................... 1,737 1,028 796
International Energy................................ 980 1,779 239
Other Energy Services............................... 28 94 41
Duke Ventures....................................... 643 382 232
Other Operations.................................... 35 3 12
-------- -------- --------
Total consolidated................................ $ 4,772 $ 5,177 $ 1,914
======== ======== ========
Capital and investment expenditures in 1999 increased approximately $3.3
billion from 1998 capital and investment expenditures of approximately $1.9
billion. The increase primarily resulted from business expansion for the Field
Services, NAWE and International Energy business segments. Business expansion
for Field Services included the $1.35 billion UPR acquisition. In 1999, NAWE
began construction of multiple power generation plants in the U.S. and
continued capital expenditures on projects initiated prior to 1999.
International Energy's business expansion included $1.7 billion for multiple
acquisitions in Latin America, western Australia and New Zealand. Expenditures
related to these activities were partially funded by $1.9 billion in cash
proceeds from the sale of the Midwest Pipelines. For additional information
concerning significant acquisitions and dispositions, see Note 2 to the
Consolidated Financial Statements.
Projected 2001 capital and investment expenditures for the Company are
approximately $6.4 billion, including approximately $5.8 billion for
acquisitions and other expansion opportunities and approximately $600 million
for existing plant upgrades. The Company's projected capital expenditures also
include $800 million in expenditures over the next three years for its
Gulfstream pipeline project.
All projected capital and investment expenditures are subject to periodic
review and revision and may vary significantly depending on a number of
factors including, but not limited to, industry restructuring, regulatory
constraints, acquisition opportunities, market volatility and economic trends.
Financing Cash Flows
The Company's consolidated capital structure at December 31, 2000, including
short-term debt, was 49% debt, 47% common equity and minority interests and 4%
trust preferred securities. Fixed charges coverage, calculated using the
Securities and Exchange Commission (SEC) method, was 3.1 times, 2.9 times and
4.2 times for 2000, 1999 and 1998, respectively.
The Company's business expansion opportunities, along with debt repayments
and operating requirements, are expected to be funded by cash from operations,
external financing, capital contributions from parent and the proceeds from
certain asset sales. Funding requirements met by external financing, capital
contributions from parent and proceeds from the sale of assets are dependent
upon the opportunities presented and favorable market conditions. Management
believes the Company has adequate financial resources to meet its future
needs.
In April 2000, DEFS issued approximately $2.75 billion of commercial paper
associated with the Phillips combination of which $1.22 billion was
distributed to Phillips Petroleum. In August 2000, DEFS issued $1.7 billion of
notes at rates from 7.50% to 8.125% and reduced the outstanding balance of its
commercial paper. In
24
December 2000, Texas Eastern Transmission Corporation (TETCO) issued $300
million of 7.30% notes due 2010. For additional information regarding debt,
see Note 9 to the Consolidated Financial Statements.
During 2000, the Company formed Catawba River Associates, LLC, and third-
party, non-controlling, preferred interest holders invested approximately
$1,025 million. The preferred interest receives a preferred return equal to an
adjusted floating reference rate (approximately 7.847% at December 31, 2000).
See Note 2 to the Consolidated Financial Statements for further discussion.
During 2000, the Company repaid $380 million of 8.0% notes, $200 million of
10.375% notes and made $320 million in scheduled debt repayments. In addition,
the Company made a tender offer for $115 million of the notes assumed with the
acquisition of MHP. As of December 31, 2000, approximately $88 million of
these notes had been retired.
Also during 2000, the Company received a $200 million capital contribution
from its parent, Duke Energy.
Under its commercial paper facilities and extendible commercial note
programs (ECNs), The Company had the ability to borrow up to $4.0 billion and
$2.1 billion at December 31, 2000 and 1999, respectively. A summary of the
available commercial paper and ECNs as of December 31, 2000, is as follows:
Duke Capital Duke Energy Duke Energy
Corporation Field Services International Total
------------ -------------- ------------- -----
(In billions)
Commercial paper................ $1.55 $1.00(a) $0.41(b) $2.96
ECNs............................ 1.00 -- -- 1.00
----- ----- ----- -----
Total......................... $2.55 $1.00 $0.41 $3.96
===== ===== ===== =====
- --------
(a) Original availability of $2.8 billion was reduced to $1.0 billion upon
DEFS' issuance of $1.7 billion in notes in August 2000.
(b) Includes ability to issue medium-term notes.
The amount of the Company's bank credit and construction facilities
available at December 31, 2000 and 1999, was approximately $3.0 billion and
$2.5 billion, respectively. Certain of the bank credit facilities support the
issuance of commercial paper; therefore, the issuance of commercial paper
reduces the amount available under these credit facilities. At December 31,
2000, approximately $1.9 billion was outstanding under the commercial paper
facilities and ECNs, and approximately $44 million was outstanding under bank
credit and construction facilities.
As of December 31, 2000, the Company and its subsidiaries had the ability to
issue up to $2.4 billion aggregate public offering price of debt and other
securities under shelf registrations filed with the SEC. Such securities may
be issued as Senior Notes, Subordinated Notes and Trust Preferred Securities.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Risk Policies
The Company is exposed to market risks associated with interest rates,
commodity prices, equity prices and foreign currency exchange rates.
Comprehensive risk management policies have been established by management to
monitor and manage these market risks. Duke Energy's Policy Committee is
responsible for the overall approval of market risk management policies and
the delegation of approval and authorization levels. The Policy Committee is
comprised of senior executives who receive periodic updates from the Chief
Risk Officer (CRO) on market risk positions, corporate exposures, credit
exposures and overall results of the Company's risk management activities. The
CRO has responsibility for the overall management of interest rate risk,
foreign currency risk, credit risk and energy risk, including monitoring of
exposure limits.
25
Interest Rate Risk
The Company is exposed to risk resulting from changes in interest rates as a
result of its issuance of variable-rate debt, fixed-rate securities and trust
preferred securities and commercial paper, as well as interest rate swaps and
interest rate lock agreements. The Company manages its interest rate exposure
by limiting its variable-rate and fixed-rate exposures to certain percentages
of total capitalization, as set by policy, and by monitoring the effects of
market changes in interest rates. The Company may also enter into financial
derivative instruments, including, but not limited to, swaps, options and
treasury lock agreements to manage and mitigate interest rate risk exposure.
See Notes 1, 6, 9, and 10 to the Consolidated Financial Statements for
additional information.
Based on a sensitivity analysis as of December 31, 2000, it was estimated
that if market interest rates average 1% higher (lower) in 2001 than in 2000,
earnings before income taxes would decrease (increase) by approximately $35
million. Comparatively, based on a sensitivity analysis as of December 31,
1999, had interest rates averaged 1% higher (lower) in 2000 than in 1999, it
was estimated that earnings before income taxes would have decreased
(increased) by approximately $10 million. These amounts were determined by
considering the impact of the hypothetical interest rates on the variable-rate
securities outstanding as of December 31, 2000 and 1999. The increase in
interest rate sensitivity is primarily the result of the increase in
outstanding variable-rate commercial paper. In the event of a significant
change in interest rates, management would likely take actions to manage its
exposure to the change. However, due to the uncertainty of the specific
actions that would be taken and their possible effects, the sensitivity
analysis assumes no changes in the Company's financial structure.
Commodity Price Risk
The Company, substantially through its subsidiaries, is exposed to the
impact of market fluctuations in the price of natural gas, electricity and
other energy-related products marketed and purchased. The Company employs
established policies and procedures to manage its risks associated with these
market fluctuations using various commodity derivatives, including forward
contracts, futures, swaps and options. See Notes 1 and 6 to the Consolidated
Financial Statements for additional information.
The risk in the commodity trading portfolio is measured and monitored on a
daily basis utilizing a Value-at-Risk model to determine the maximum potential
one-day favorable or unfavorable Daily Earnings at Risk (DER). The DER is
monitored daily in comparison to established thresholds. Other measures are
also utilized to limit and monitor the risk in the commodity trading portfolio
on monthly and annual bases.
The DER computations are based on a historical simulation, which utilizes
price movements over a specified period to simulate forward price curves in
the energy markets to estimate the favorable or unfavorable impact of one
day's price movement on the existing portfolio. The historical simulation
emphasizes the most recent market activity, which is considered the most
relevant predictor of immediate future market movements for natural gas,
electricity and other energy-related products. The DER computations utilize
several key assumptions, including a 95% confidence level for the resultant
price movement and the holding period specified for the calculation. The
Company's DER calculation includes commodity derivative instruments held for
trading purposes. The Company's DER amounts are depicted in the table below.
The increase in DER amounts as compared to 1999 is a result of the Company's
expanding portfolio of energy-related products both domestically and
internationally.
Daily Earnings at Risk
Estimated One-Day Estimated One-Day Estimated Average Estimated Average
Impact on EBIT at Impact on EBIT at One-Day Impact on One-Day Impact on
Operational Locations December 31, 2000 December 31, 1999 EBIT for 2000 EBIT for 1999
- --------------------- ----------------- ----------------- ----------------- -----------------
(In millions)(a)
North American.......... $18 $ 7 $16 $ 8
Other international..... 11 -- 2 --
- --------
(a) Changes in markets inconsistent with historical trends could cause actual
results to exceed predicted limits.
26
Certain subsidiaries of the Company are also exposed to market fluctuations
in the prices of various commodities related to their ongoing power
generating, natural gas gathering, processing and marketing activities. The
Company closely monitors the risks associated with these commodities' price
changes on its future operations, and where appropriate, uses various
commodity instruments, such as electricity, natural gas, crude oil and NGLs to
hedge these price risks. Based on a sensitivity analysis as of December 31,
2000, it was estimated that if NGL prices average one cent per gallon less in
2001, EBIT would decrease by approximately $8 million, after considering the
effect of the Company's commodity hedge positions. Comparatively, the same
sensitivity analysis as of December 31, 1999, estimated that EBIT would have
decreased by approximately $6 million. Based on the sensitivity analyses
associated with other commodities' price changes, net of the Company's
commodity hedge positions, the effect on EBIT was not material as of December
31, 2000 or 1999.
Credit Risk
The Company's principal markets for power and natural gas marketing services
are industrial end-users and utilities located throughout the U.S., Canada,
Asia Pacific and Latin America. The Company has concentrations of receivables
from natural gas and electric utilities and their affiliates, as well as
industrial customers throughout these regions. These concentrations of
customers may affect the Company's overall credit risk in that certain
customers may be similarly affected by changes in economic, regulatory or
other factors. On all transactions where the Company is exposed to credit
risk, the Company analyzes the counterparties' financial condition prior to
entering into an agreement, establishes credit limits and monitors the
appropriateness of these limits on an ongoing basis. As of December 31, 2000,
the Company had approximately $400 million in receivables related to energy
sales in California. The Company quantified its exposures with regard to those
receivables and recorded a provision of $110 million. See the Current Issues,
California Issues section of Management's Discussion and Analysis, and Note 11
to the Consolidated Financial Statements for further information regarding
credit exposure.
The change in market value of New York Mercantile Exchange-traded futures
and options contracts requires daily cash settlement in margin accounts with
brokers. Physical forward contracts and financial derivatives are generally
settled at the expiration of the contract term or each delivery period;
however, these transactions are also generally subject to margin agreements
with the majority of the Company's counterparties.
Foreign Currency Risk
The Company is exposed to foreign currency risk that arises from investments
in international affiliates and businesses owned and operated in foreign
countries. To mitigate risks associated with foreign currency fluctuations,
when possible, contracts are denominated in or indexed to the U.S. dollar, or
investments may be hedged through debt denominated in the foreign currency.
The Company also uses foreign currency derivatives, where possible, to manage
its risk related to foreign currency fluctuations. To monitor its currency
exchange rate risks, the Company uses sensitivity analysis, which measures the
impact of a devaluation of the foreign currencies to which it has exposure.
At December 31, 2000, the Company's primary foreign currency exchange rate
exposures were the Brazilian real, the Peruvian nuevo sol, the Australian
dollar, the El Salvadoran colon, the Argentine peso, the European euro and the
Canadian dollar. Based on a sensitivity analysis as of December 31, 2000, a
10% devaluation in the currency exchange rates in Brazil would reduce the
Company's financial position by approximately $91 million and would not
significantly affect the Company's consolidated results of operations, cash
flows or financial position over the next 12 months. Based on a sensitivity
analysis as of December 31, 1999, a 10% devaluation in the Brazilian currency
exchange rates would have reduced the Company's financial position by
approximately $65 million. The increase in sensitivity to the Brazilian real
is primarily due to the increased investment in Paranapanema as a result of
the Company's tender offer in 2000. See Note 2 to the Consolidated Financial
Statements for further information. Based on these sensitivity analyses, a 10%
devaluation in other foreign currencies was insignificant to the Company's
consolidated results of operations, cash flows or financial position.
27
CURRENT ISSUES
Natural Gas Competition. Wholesale Competition. On February 9, 2000, the
FERC issued Order 637, which sets forth revisions to its regulations governing
short-term natural gas transportation services and policies governing the
regulation of interstate natural gas pipelines. "Short-term" has been defined
as all transactions of less than one year. Among the significant actions taken
are the lifting of the price cap for short-term capacity release by pipeline
customers for an experimental 2 1/2-year period ending September 1, 2002, and
requiring that interstate pipelines file pro forma tariff sheets to (i)
provide for nomination equality between capacity release and primary pipeline
capacity; (ii) implement imbalance management services (for which interstate
pipelines may charge fees) while at the same time reducing the use of
operational flow orders and penalties; and (iii) provide segmentation rights
if operationally feasible. Order 637 also narrows the right of first refusal
to remove economic biases perceived in the current rule. Order 637 imposes
significant new reporting requirements for interstate pipelines that were
implemented by the Company during the third quarter of 2000. Additionally,
Order 637 permits pipelines to propose peak/off-peak rates and term-
differentiated rates, and encourages pipelines to propose experimental
capacity auctions. By Order 637-A, issued in February 2000, the FERC generally
denied requests for rehearing and several parties, including the Company, have
filed appeals in the District of Columbia Court of Appeals seeking court
review of various aspects of the Order. During the third quarter of 2000, the
Company's interstate pipelines made the required pro forma tariff sheet
filings. These filings are currently subject to review and approval by the
FERC.
Management does not believe the effects of these matters will have a
material effect on the Company's future consolidated results of operations,
cash flows or financial position.
Retail Competition. Changes in regulation to allow retail competition could
affect the Company's natural gas transportation contracts with local natural
gas distribution companies. Natural gas retail deregulation is in the very
early stages of development and management cannot estimate the effects of this
matter on future consolidated results of operations, cash flows or financial
position.
Environmental. The Company is subject to international, federal, state and
local regulations regarding air and water quality, hazardous and solid waste
disposal and other environmental matters.
Superfund Sites. The Company is considered by regulators to be a potentially
responsible party and may be subject to future liability at four federal
Superfund sites and one state Superfund site. While the cost of remediation of
these sites may be substantial, the Company will share in any liability
associated with remediation of contamination at such sites with other
potentially responsible parties. Management believes that resolution of these
matters will not have a material adverse effect on consolidated results of
operations, cash flows or financial position.
PCB (Polychlorinated Biphenyl) Assessment and Cleanup Programs. In June
1999, the Environmental Protection Agency (EPA) certified that TETCO, a wholly
owned subsidiary of the Company, had completed cleanup of PCB-contaminated
sites under conditions stipulated by a U.S. Consent Decree in 1989. TETCO was
required to continue groundwater monitoring on a number of sites for two
years. This required monitoring was completed as of the end of 2000, pending
EPA concurrence. TETCO will be evaluating and discussing with the EPA,
appropriate state authorities or both the need for additional remediation or
monitoring.
Under terms of the sales agreement with CMS discussed in Note 2 to the
Consolidated Financial Statements, the Company is obligated to complete
cleanup of previously identified contamination resulting from the past use of
PCB-containing lubricants and other discontinued practices at certain sites on
the PEPL and Trunkline systems. Based on the Company's experience to date and
costs incurred for cleanup operations, management believes the resolution of
matters relating to the environmental issues discussed above will not have a
material adverse effect on consolidated results of operations, cash flows or
financial position.
Air Quality Control. In 1997, the United Nations held negotiations in Kyoto,
Japan to determine how to minimize global warming. The resulting Kyoto
Protocol prescribed, among other greenhouse gas emission
28
reduction tactics, carbon dioxide emission reductions from fossil-fueled
electric generating facilities in the U.S. and other developed nations, as
well as methane emission reductions from natural gas operations. Several
subsequent meetings have been held attempting to resolve operational details
to clear the way for multinational ratification and implementation without
resolution. If the Kyoto Protocol were to be adopted in its current form, it
could have far-reaching implications for the Company and the entire energy
industry. However, the outcome and timing of these implications are highly
uncertain, and the Company cannot estimate the effects on future consolidated
results of operations, cash flows or financial position. The Company remains
engaged with those developing public policy initiatives and continuously
assesses the commercial implications for its markets around the world.
California Issues. California Litigation. The Company's subsidiaries, DENA
and DETM, have been named among 16 defendants in a class action lawsuit (the
Gordon lawsuit) filed against companies identified as "generators and traders"
of electricity in California markets. DETM also was named as one of numerous
defendants in four additional lawsuits, including two class actions (the
Hendricks and Pier 23 Restaurant lawsuits), filed against generators,
marketers and traders and other unnamed providers of electricity in California
markets. These suits were brought either by or on behalf of electricity
consumers in the State of California. The Gordon and Hendricks class action
suits were filed in the Superior Court of the State of California, San Diego
County, in November 2000. The other three suits were filed in January 2001,
one in the Superior Court of the State of California, San Diego County, and
the other two in the Superior Court of the State of California, County of San
Francisco. These suits generally allege that the defendants manipulated the
wholesale electricity markets in violation of state laws against unfair and
unlawful business practices and state antitrust laws. Plaintiffs in the Gordon
suit seek aggregate damages of over $4 billion, and the plaintiffs in the
other suits, to the extent damages are specified, allege damages in excess of
$1 billion. The lawsuits each seek the disgorgement of alleged unlawfully
obtained revenues for sales of elect