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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, 2001 or
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________________ to __________________
Commission file number 1-4928
DUKE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
North Carolina 56-0205520
(State or other (I.R.S. Employer
jurisdiction of Identification No.)
incorporation or
organization)
526 South Church Street, 28202-1904
Charlotte, North Carolina
(Address of principal (Zip Code)
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 on
Title of each class which registered
------------------- -----------------------------
Common Stock, without par value New York Stock Exchange, Inc.
6.375% Preferred Stock A, 1993 Series, par value $25 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 6 5/8% Series B Due 2003 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 6 3/4% Due 2025 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 6 7/8% Series B Due 2023 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 7% Due 2033 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 7 1/2% Series B Due 2025 New York Stock Exchange, Inc.
7.20% Quarterly Income Preferred Securities issued by Duke Energy Capital
Trust I and guaranteed by Duke Energy Corporation New York Stock Exchange, Inc.
7.20% Trust Preferred Securities issued by Duke Energy Capital
Trust II and guaranteed by Duke Energy Corporation New York Stock Exchange, Inc.
Preference Stock Purchase Rights New York Stock Exchange, Inc.
Series C 6.60% Senior Notes Due 2038 New York Stock Exchange, Inc.
Corporate Units New York Stock Exchange, Inc.
Securities registered pursuant to Section 12(g) of the Act:
Title of class
Preferred Stock, par value $100
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. [_]
Estimated aggregate market value of the voting stock held by nonaffiliates of the registrant at February 28,
2002....................................................................................................... $27,435,000,000
Number of shares of Common Stock, without par value, outstanding at February 28, 2002....................... 778,199,474
Documents incorporated by reference:
The registrant is incorporating herein by reference certain sections of the
proxy statement relating to the 2002 annual meeting of shareholders to provide
information required by Part III, Items 10, 11, 12 and 13 of this annual report.
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DUKE ENERGY CORPORATION
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2001
TABLE OF CONTENTS
Item Page
- ---- ----
PART I.
1. Business............................................................................. 1
General............................................................................. 1
Franchised Electric................................................................. 4
Natural Gas Transmission............................................................ 8
Field Services...................................................................... 11
North American Wholesale Energy..................................................... 13
International Energy................................................................ 16
Other Energy Services............................................................... 17
Duke Ventures....................................................................... 17
Environmental Matters............................................................... 18
Geographic Regions.................................................................. 19
Employees........................................................................... 19
Operating Statistics................................................................ 20
Executive Officers of Duke Energy................................................... 21
2. Properties........................................................................... 22
3. Legal Proceedings.................................................................... 24
4. Submission of Matters to a Vote of Security Holders.................................. 26
PART II.
5. Market for Registrant's Common Equity and Related Stockholder Matters................ 27
6. Selected Financial Data.............................................................. 28
7. Management's Discussion and Analysis of Results of Operations and Financial Condition 29
7A. Quantitative and Qualitative Disclosures About Market Risk........................... 61
8. Financial Statements and Supplementary Data.......................................... 62
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. 111
PART III.
10. Directors and Executive Officers of the Registrant................................... 111
11. Executive Compensation............................................................... 111
12. Security Ownership of Certain Beneficial Owners and Management....................... 111
13. Certain Relationships and Related Transactions....................................... 111
PART IV.
14. Exhibits, Financial Statement Schedule, and Reports on Form 8-K...................... 112
Signatures........................................................................... 113
Exhibit Index........................................................................ 114
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Duke Energy's reports, filings and other public announcements may include
statements that reflect 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.
Generally, the words "may," "could," "project," "believe," "anticipate,"
"expect," "estimate," "plan," "forecast," "intend" and similar words identify
forward-looking statements, which generally are not historical in nature. All
such statements (other than statements of historical facts), including
statements regarding operating performance, financial position, business
strategy, budgets, projected costs, plans and objectives of management for
future operations and events or developments that we expect or anticipate will
occur in the future, are forward looking. Forward-looking statements are
subject to certain risks and uncertainties that could, and often do, cause
actual results to differ from Duke Energy's historical experience and our
present expectations or projections. Accordingly, there can be no assurance
that actual results will not differ materially from those expressed or implied
by the forward-looking statements. Caution should be taken not to place undue
reliance on any such forward-looking statements. For a discussion of some
factors that could cause results 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."
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PART I.
Item 1. Business.
GENERAL
Duke Energy Corporation (collectively with its subsidiaries, Duke Energy),
an integrated provider of energy and energy services, offers physical delivery
and management of both electricity and natural gas throughout the U.S. and
abroad. Duke Energy provides these and other services through seven business
segments.
Franchised Electric generates, transmits, distributes and sells electricity
in central and western North Carolina and western South Carolina. It conducts
operations through Duke Power and Nantahala Power and Light. These electric
operations are subject to the rules and regulations of the Federal Energy
Regulatory Commission (FERC), the North Carolina Utilities Commission (NCUC)
and the Public Service Commission of South Carolina (PSCSC).
Throughout 2001, Natural Gas Transmission provided transportation and
storage of natural gas for customers throughout North America, primarily in the
Mid-Atlantic, New England and southeastern states. It conducted operations
primarily through Duke Energy Gas Transmission Corporation. Through the
acquisition of Westcoast Energy Inc. (Westcoast) on March 14, 2002, Natural Gas
Transmission added a significant network of mostly Canadian-based natural gas
assets, including transmission pipeline, storage capacity and distribution
systems. (See "Natural Gas Transmission" in this section for additional
information.) Interstate natural gas transmission and storage operations are
subject to the FERC's rules and regulations.
Field Services gathers, processes, transports, markets and stores natural
gas and produces, transports, markets and stores natural gas liquids (NGLs). It
conducts operations primarily through Duke Energy Field Services, LLC (DEFS),
which is approximately 30% owned by Phillips Petroleum. Field Services operates
gathering systems in western Canada and 11 contiguous states in the U.S. Those
systems serve major natural gas-producing regions in the Rocky Mountain,
Permian Basin, Mid-Continent, East Texas-Austin Chalk-North Louisiana, and
onshore and offshore Gulf Coast areas.
North American Wholesale Energy (NAWE) develops, operates and manages
merchant generation facilities and engages in commodity sales and services
related to natural gas and electric power. NAWE conducts these operations
primarily through Duke Energy North America, LLC (DENA) and Duke Energy Trading
and Marketing, LLC (DETM). DETM is approximately 40% owned by Exxon Mobil
Corporation. NAWE also includes Duke Energy Merchants Holdings, LLC (DEM),
which develops new business lines in the evolving energy commodity markets
other than natural gas and power. NAWE conducts business primarily throughout
the U.S. and Canada.
International Energy develops, operates and manages natural gas
transportation and power generation facilities and engages in energy trading
and marketing of natural gas and electric power. It conducts operations
primarily through Duke Energy International, LLC (DEI) and its activities
target 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., a wholly
owned subsidiary of Fluor Corporation. (See Note 8 to the Consolidated
Financial Statements, "Investment in Affiliates and Related Party
Transactions.") On January 31, 2002, Duke Energy announced the planned sale of
DE&S to Framatome ANP, Inc. and, on March 13, 2002,
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Duke Energy announced the planned sale of DukeSolutions to Ameresco, Inc. (See
"Management's Discussion and Analysis of Results of Operations and Financial
Condition, Current Issues -- Subsequent Events.")
Duke Ventures is composed of other diverse businesses, operating primarily
through Crescent Resources, LLC (Crescent), DukeNet Communications, LLC
(DukeNet) and Duke Capital Partners, LLC (DCP). Crescent develops high-quality
commercial, residential and multi-family real estate projects and manages land
holdings primarily in the southeastern and southwestern U.S. DukeNet provides
fiber optic networks for industrial, commercial and residential customers. DCP,
a wholly owned merchant banking company, provides debt and equity capital and
financial advisory services to the energy industry.
Duke Energy is a North Carolina corporation. Its principal executive offices
are located at 526 South Church Street, Charlotte, NC 28202-1803. The telephone
number is 704-594-6200.
Certain terms used to describe Duke Energy's business are explained below.
Asset Optimization. The process of maximizing the returns on a portfolio of
assets through the use of hedging strategies involving energy contracts.
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.
Distribution. The system of lines, transformers and switches that connect
the electric transmission system to customers.
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). An entity that 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.
Liquid Market. A market in which selling and buying can be accomplished with
minimal price change; such a market has a high level of trading activity and
open interest.
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.
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Logistics & Optimization. The act of maximizing physical positions through
arbitrage, especially on contractual assets such as storage, transportation,
generation and transmission.
Mark-to-Market. The process whereby derivatives or energy trading contracts
are adjusted to market value, and the unrealized gain or loss is recognized in
current earnings and on the balance sheet.
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.
Origination. Identification and execution of physical energy related
transactions throughout the value chain.
Peak Load. The amount of electricity required during periods of highest
demand. Peak periods fluctuate by season, generally occurring in the morning
hours in winter and in late afternoon during the summer.
Throughput. The amount of natural gas or natural gas liquids transported
through a pipeline system.
Tolling. Process whereby a party moves fuel to a power generator and
receives kilowatt hours in return for a pre-established fee.
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.
Volatility. An annualized measure of the fluctuation in the price of an
energy contract. Implied volatility is a measure of what the market values
volatility to be, as reflected in the option's price.
Watt. A measure of power production or usage equal to one joule per second.
The following sections describe the business and operations of each of Duke
Energy's segments. (For more information on the operating outlook of Duke
Energy and its segments, see "Management's Discussion and Analysis of Results
of Operations and Financial Condition, Introduction -- Business Strategy." For
financial information on Duke Energy's business segments, see Note 3 to the
Consolidated Financial Statements, "Business Segments.")
3
FRANCHISED ELECTRIC
Service Area and Customers
Franchised Electric generates, transmits, distributes and sells electricity.
Its service area covers about 22,000 square miles with an estimated population
of 5.7 million in central and western North Carolina and western South
Carolina. Franchised Electric supplies electric service to approximately two
million residential, commercial and industrial customers over 92,000 miles of
distribution lines and a 12,700 mile transmission system. Electricity is sold
wholesale to incorporated municipalities and to public and private utilities.
In addition, municipal and cooperative customers who purchased portions of the
Catawba Nuclear Station buy power through contractual agreements. (For
statistics related to gigawatt-hour sales by customer type, see "Operating
Statistics" in this section. For more information on the Catawba Nuclear
Station joint ownership, see Note 5 to the Consolidated Financial Statements,
"Joint Ownership of Generating Facilities.")
Industrial and commercial development in Franchised Electric's service area
is highly diversified. The textile industry, machinery and equipment
manufacturing, and chemical industries are of major significance to the area's
economy. Other industries operating in the area include rubber and plastic
products, paper and related products, and other manufacturing and service
businesses. The textile industry, the largest industry served by Franchised
Electric, accounted for approximately $353 million of Franchised Electric's
revenues for 2001, representing 8% of total electric revenues and 32% of
industrial revenues. Franchised Electric normally experiences seasonal peak
loads in summer and winter.
[MAP OF SERVICE AREA]
4
Energy Capacity and Resources
Electric energy for Franchised Electric's customers is generated by three
nuclear generating stations with a combined net capacity of 5,409 megawatts
(MW) (including 12.5% ownership in the Catawba Nuclear Station), eight
coal-fired stations with a combined capacity of 7,572 MW, 31 hydroelectric
stations with a combined capacity of 2,791 MW and six combustion turbine
stations with a combined capacity of 2,081 MW. Energy and capacity are also
supplied through contracts with other generators and purchased on the open
market. Franchised Electric has interconnections and arrangements with its
neighboring utilities to facilitate planning, emergency assistance, exchange of
capacity and energy, and reliability of power supply. Franchised Electric
expects that additional construction, purchased power contracts and open market
purchases will meet customers' energy needs in the future. (For statistics on
sources of electric energy, see "Operating Statistics" in this section.)
Fuel Supply
Franchised Electric relies principally on coal and nuclear fuel for its
generation of electric energy. The following table lists Franchised Electric's
sources of power and fuel costs for the three years ending December 31, 2001.
Cost of Fuel per Net
Generation by Source Kilowatt-hour
(Percent) Generated (Cents)
-------------------- --------------------
2001 2000 1999 2001 2000 1999
----- ----- ----- ----- ---- ----
Coal............................. 50.9 50.9 50.4 1.48 1.29 1.33
Nuclear(a)....................... 48.6 48.1 48.0 0.42 0.42 0.43
Oil and gas(b)................... 0.2 0.5 0.8 11.48 7.32 4.51
----- ----- -----
All fuels (cost based on weighted
average)(a).................... 99.7 99.5 99.2 0.98 0.91 0.92
Hydroelectric(c)................. 0.3 0.5 0.8
----- ----- -----
100.0 100.0 100.0
===== ===== =====
- --------
(a) Statistics related to nuclear generation and all fuels reflect Franchised
Electric's 12.5% ownership interest in the Catawba Nuclear Station.
(b) Cost statistics include amounts for light-off fuel at Franchised Electric's
coal-fired stations.
(c) Generating figures are net of output required to replenish pumped storage
units during off-peak periods.
Coal. Franchised Electric meets its coal demand through purchase supply
contracts and spot agreements. Large amounts of coal are obtained under supply
contracts with mining operators who mine both underground and at the surface.
Franchised Electric has an adequate supply of coal to fuel its current
operations. Expiration dates for its supply contracts, which have price
adjustment provisions, range from 2002 to 2003. Duke Energy expects to renew
these contracts or enter into similar contracts with other suppliers for the
quantities and quality of coal required. The coal purchased under these
contracts is produced from mines in eastern Kentucky, southern West Virginia
and southwestern Virginia. Franchised Electric uses spot market purchases to
meet coal requirements not met by supply contracts.
The average sulfur content of coal purchased by Franchised Electric is
approximately 1%. This satisfies the current emission limitation for sulfur
dioxide for existing facilities. (See "Management's Discussion and Analysis of
Results of Operations and Financial Condition, Current Issues--Environmental,
Air Quality Control" for additional information regarding particulate matter.)
Nuclear. Developing nuclear generating fuel generally involves the mining
and milling of uranium ore to produce uranium concentrates, the conversion of
uranium concentrates to uranium hexafluoride gas, enrichment of that gas, and
then the fabrication of the enriched uranium hexafluoride into usable fuel
assemblies.
5
Franchised Electric has contracted for uranium materials and services
required to fuel the Oconee, McGuire and Catawba Nuclear Stations. Uranium
concentrates, conversion services and enrichment services are primarily met
through a diversified portfolio of long-term supply contracts. The contracts
are diversified by supplier, country of origin and pricing. Franchised Electric
staggers its contracting so that its portfolio of long-term contracts covers
the majority of its fuel requirements at Oconee, McGuire, and Catawba in the
near term, but so that its level of coverage decreases each year into the
future. Due to the technical complexities of changing suppliers of fuel
fabrication services, Franchised Electric generally sole sources these services
to domestic suppliers on a plant by plant basis using multi-year contracts.
Based upon current projections, Franchised Electric's existing portfolio of
contracts will meet the requirements of Oconee, McGuire, and Catawba Nuclear
Stations through the following years:
Uranium Conversion Enrichment Fabrication
Nuclear Station Material Service Service Service
--------------- -------- ---------- ---------- -----------
Oconee..... 2003 2003 2005 2006
McGuire.... 2003 2003 2005 2009
Catawba.... 2003 2003 2005 2009
After the years indicated above, a portion of the fuel requirements at
Oconee, McGuire, and Catawba are covered by long-term contracts. For
requirements not covered under long-term contracts, Duke Energy believes it
will be able to renew contracts as they expire or enter into similar
contractual arrangements with other suppliers of nuclear fuel materials and
services. Near-term requirements not met by long-term supply contracts have
been and are expected to be fulfilled with uranium spot market purchases.
Duke Energy owns and operates the McGuire and Oconee Nuclear Stations and
operates and has a partial ownership interest in the Catawba Nuclear Station.
The McGuire and Catawba Nuclear Stations have two nuclear reactors each and
Oconee has three nuclear reactors. Nuclear insurance coverage is maintained in
three program areas: liability coverage; property, decontamination and
decommissioning coverage; and business interruption and/or extra expense
coverage. The other joint owners of the Catawba Nuclear Station reimburse Duke
Energy for certain expenses associated with nuclear insurance premiums. The
Price-Anderson Act requires Duke Energy to insure against public liability
claims resulting from nuclear incidents to the full limit of liability,
approximately $9.5 billion. (See Note 15 to the Consolidated Financial
Statements, "Commitments and Contingencies--Nuclear Insurance," for more
information.)
Estimated site-specific nuclear decommissioning costs, including the cost of
decommissioning plant components not subject to radioactive contamination,
total approximately $1.9 billion stated in 1999 dollars based on
decommissioning studies completed in 1999 (studies are completed every five
years). This includes costs related to Duke Energy's 12.5% ownership in the
Catawba Nuclear Station. The other joint owners of the Catawba Nuclear Station
are responsible for decommissioning costs related to their ownership interests
in the station. (See Note 11 to the Consolidated Financial Statements, "Nuclear
Decommissioning Costs," for more information.)
Duke Energy entered into a contract with the Department of Energy (DOE) to
use mixed oxide fuel at its McGuire and Catawba Nuclear Stations. Mixed oxide
fuel is fabricated from plutonium from the government's surplus plutonium and
is similar to conventional uranium fuel. Before using the fuel, Duke Energy
must apply for and obtain amendments to the facilities' operating licenses from
the Nuclear Regulatory Commission (NRC). Mixed oxide fuel is scheduled to be
used at McGuire and Catawba Nuclear Stations no earlier than 2007.
After spent fuel is removed from a nuclear reactor, it is cooled in a spent
fuel pool at the nuclear station. Under provisions of the Nuclear Waste Policy
Act of 1982, Duke Energy contracted with the DOE for the disposal of spent
nuclear fuel. The DOE failed to begin accepting spent nuclear fuel on January
31, 1998, the date specified by the Nuclear Waste Policy Act and in Duke
Energy's contract with the DOE. In 1998, Duke Energy filed a claim with the
U.S. Court of Federal Claims against the DOE related to the DOE's failure to
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accept commercial spent nuclear fuel by the required date. Damages claimed in
the lawsuit are based upon Duke Energy's costs incurred as a result of the
DOE's partial material breach of its contract, including the cost of securing
additional spent fuel storage capacity. Duke Energy will continue to safely
manage its spent nuclear fuel until the DOE accepts it.
Competition
Electric industry restructuring is changing the industry. Duke Energy is
monitoring progress toward a more competitive environment and actively
participates in regulatory reform deliberations in North Carolina and South
Carolina. However, movement toward retail deregulation in these and other
states has slowed due to recent deregulation developments in California. (For
more information, see "Management's Discussion and Analysis of Results of
Operations and Financial Condition, Current Issues--Electric Competition and
Current Issues--California Issues.")
Franchised Electric competes in some areas with government-owned power
systems, municipally owned electric systems, rural electric cooperatives and
other private utilities. By statute, the NCUC and the PSCSC assign all service
areas outside municipalities in North Carolina and South Carolina to regulated
electric utilities and rural electric cooperatives. Substantially all of the
territory comprising Franchised Electric's service area has been assigned in
this manner. In unassigned areas, Franchised Electric's business remains
subject to competition. A decision of the North Carolina Supreme Court limits,
in some instances, the right of North Carolina municipalities to serve
customers outside their corporate limits. In South Carolina, competition
continues between municipalities and other electric suppliers outside the
municipalities' corporate limits, subject to the regulation of the PSCSC. In
addition, Franchised Electric continues to compete with natural gas providers.
Regulation
The NCUC and the PSCSC approve rates for retail electric sales within their
respective states. The FERC approves Franchised Electric's rates for some
electric sales to wholesale customers. (For more information on rate matters,
see Note 4 to the Consolidated Financial Statements, "Regulatory
Matters--Franchised Electric.") The FERC, the NCUC and the PSCSC also have
authority over the construction and operation of Franchised Electric's
facilities. Certificates of public convenience and necessity issued by the
FERC, the NCUC and the PSCSC authorize Franchised Electric to construct and
operate its electric facilities, and to sell electricity to retail and
wholesale customers. Prior approval from the NCUC and the PSCSC is required to
issue securities.
NCUC, PSCSC and FERC regulations govern access to regulated electric
customer data by non-regulated entities, and services provided between
regulated and non-regulated affiliated entities. These regulations affect
NAWE's and Other Energy Services' activities with Franchised Electric.
The Energy Policy Act of 1992 and the FERC's subsequent rulemaking
activities opened the wholesale energy market to competition. Open-access
transmission for wholesale customers, as defined by the FERC's rules, provides
energy suppliers, including Duke Energy, with opportunities to sell and deliver
capacity and energy at market-based prices. From the FERC's open-access rule,
Franchised Electric obtained the rights to sell capacity and energy at
market-based rates from its own assets, which allows Franchised Electric to
purchase, at attractive rates, a portion of its capacity and energy
requirements; resulting in lower overall costs to customers. Open access also
provides Franchised Electric's existing wholesale customers with opportunities
to seek other competitive suppliers for their capacity and energy requirements.
In 1999 and 2000, the FERC issued its Order 2000 and Order 2000-A regarding
Regional Transmission Organizations (RTOs). These orders set minimum
characteristics and functions RTOs must meet, including independent authority
to establish the terms and conditions of transmission service over the
facilities they control. The orders provide for an open and flexible RTO
structure to meet the needs of the market, and for the possibility of incentive
ratemaking and other benefits for transmission owners that participate.
7
As a result of these rulemakings, Duke Energy and two other investor-owned
utilities, Carolina Power & Light Company and South Carolina Electric & Gas
Company, planned to establish GridSouth Transco, LLC (GridSouth), as an RTO
responsible for the control of the companies' combined transmission systems. In
March 2001, GridSouth received provisional approval from the FERC. However, in
July 2001, the FERC issued orders recommending that utilities throughout the
U.S. combine their transmission systems to create four large independent
regional operators, one each in the Northeast, Southeast, Midwest and West. The
FERC ordered GridSouth and other utilities in the Southeast to join in 45 days
of mediation to negotiate terms of a Southeast RTO. The FERC has not issued an
order specifically based on those proceedings.
Duke Energy, Carolina Power & Light Company and South Carolina Electric &
Gas Company remain committed to the GridSouth RTO, but due to regulatory
uncertainties in the RTO arena, the companies have withdrawn their applications
to the PSCSC and NCUC to transfer functional control of their electric
transmission assets to GridSouth. The companies intend to file new applications
before the state commissions in the near future, including a revised GridSouth
structure designed to meet the needs of customers and regulators. Also, in
January of 2002, GridSouth signed a memorandum of understanding with the
representatives of SeTrans Grid Company (SeTrans), a group of investor-owned
utilities and public power entities in several southeastern states seeking to
form an RTO, to cooperate in discussing potential operational relationships
between GridSouth and SeTrans and the structure of wholesale electric markets
in the southeast U.S.
The actual structure of GridSouth or an alternative combined transmission
structure and the date it will become operational depend upon the resolution of
all regulatory approvals and technical issues. Management believes that the
result of this process, and the establishment and operation of GridSouth or an
alternative combined transmission system structure, will have no material
adverse effect on Duke Energy's future consolidated results of operations, cash
flows or financial position.
Franchised Electric is subject to the NRC jurisdiction for the design,
construction and operation of its nuclear generating facilities. In 2000, the
NRC renewed the operating license for Duke Energy's three Oconee nuclear units
through 2033 and 2034. Applications to renew the operating licenses for Duke
Energy's Catawba and McGuire nuclear units were filed with the NRC in June
2001. These operating licenses currently expire between 2021 and 2026.
Franchised Electric's hydroelectric generating facilities are licensed by the
FERC under Part I of the Federal Power Act, with license terms expiring from
2002 to 2036.
The FERC has authority to extend hydroelectric generating licenses. Duke
Energy expects to receive a new license for one of its hydroelectric facilities
by the end of 2002. Other hydroelectric facilities whose licenses expire
between 2005 and 2008 are in various stages of relicensing.
Franchised Electric is subject to the jurisdiction of the Environmental
Protection Agency (EPA) and state environmental agencies. (For a discussion of
environmental regulation, see "Environmental Matters" in this section.)
NATURAL GAS TRANSMISSION
During 2001, Natural Gas Transmission provided transportation and storage of
natural gas for customers primarily in the Mid-Atlantic, New England and
southeastern states of the U.S. It conducted operations primarily through Texas
Eastern Transmission, LP (Texas Eastern), Algonquin Gas Transmission Company
(Algonquin), East Tennessee Natural Gas Company (ETNG) and Market Hub Partners
(MHP). Through the acquisition of Westcoast on March 14, 2002, Natural Gas
Transmission added a significant network of mostly Canadian-based natural gas
assets, including transmission and gathering pipelines, storage capacity and
distribution systems. (For more information on the Westcoast acquisition, see
Note 2 to the Consolidated Financial Statements, "Business Acquisitions and
Dispositions.")
8
Investments in 2001 included a 37.5% ownership interest in the Maritimes &
Northeast Pipeline (Maritimes & Northeast), which has a design capacity of 530
million cubic feet per day (MMcf/d) in Canada and 422 MMcf/d in the U.S.
Maritimes & Northeast was placed in service and received the first delivery of
natural gas from the Sable Offshore Energy Project near Nova Scotia in December
1999. During 2001, Duke Energy operated the U.S. portion of Maritimes &
Northeast. Natural gas deliveries by Maritimes & Northeast were 166 trillion
British thermal units (TBtu) in 2001 and 145 TBtu in 2000. As part of the
Westcoast acquisition, Duke Energy's ownership interest in Maritimes &
Northeast increased to 75%.
On February 1, 2001, Duke Energy and The Williams Companies, Inc. (Williams)
jointly purchased Gulfstream Natural Gas System, LLC from the Coastal
Corporation. When completed, the approximately 750-mile Gulfstream gas pipeline
will originate near Mobile, Alabama, and cross the Gulf of Mexico to deliver
natural gas to the growing Florida electric generation market. Construction
began during mid-2001 and the system is expected to be in-service in two
phases, in mid-2002 and mid-2003. Duke Energy and Williams will jointly operate
the pipeline.
For 2001, Natural Gas Transmission's proportional throughput for its
pipelines totaled 1,710 TBtu, compared to 1,771 TBtu in 2000, a 3% decrease.
This includes throughput on Natural Gas Transmission's wholly-owned interstate
pipelines and its proportional share of throughput on equity investment
pipelines. (See natural gas delivery statistics under "Operating Statistics" in
this section.) 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. Demand on Natural Gas Transmission's interstate pipeline
systems is seasonal, with the highest throughput occurring during 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 OF SERVICE AREA]
9
Prior to the acquisition of Westcoast on March 14, 2002, Natural Gas
Transmission's interstate pipeline systems consisted of approximately 12,000
miles of pipe, including 830 miles related to Duke Energy's ownership interest
in Maritimes & Northeast. The pipeline systems received natural gas from major
North American producing regions for delivery to markets primarily in the
Mid-Atlantic, southeastern and New England states.
MHP owns natural gas salt cavern facilities in south Texas and Louisiana
with a total storage capacity of approximately 26 billion cubic feet (Bcf). 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. Texas Eastern and ETNG 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. Texas Eastern has two joint-venture storage facilities in
Pennsylvania and one wholly owned and operated storage field in Maryland. Texas
Eastern's certificated working capacity in these three fields is 75 Bcf. ETNG
has a liquefied natural gas storage facility in Tennessee with a certificated
working capacity of 1.2 Bcf. Algonquin owns no storage fields.
The acquisition of Westcoast on March 14, 2002, added approximately 9,800
miles of transmission pipeline, approximately 2,400 miles of gathering pipeline
and approximately 19,700 miles of distribution pipeline to Natural Gas
Transmission's systems. This includes proportional ownership interest in all
pipelines that are not wholly owned. The Westcoast acquisition also added
approximately 150 Bcf of natural gas storage capacity. The assets acquired in
the Westcoast acquisition are primarily located in western Canada, Ontario and
along Canada's Atlantic Coast. The U.S. assets acquired in the Westcoast
acquisition are primarily located around the Great Lakes and the Northeast U.S.
Competition
Duke Energy's interstate pipeline and storage subsidiaries compete with
other interstate and intrastate pipeline and storage facilities in the
transportation and storage of natural gas. Natural Gas Transmission competes
directly with other interstate pipelines serving the Mid-Atlantic, northeastern
and southeastern states, and storage facilities in south Texas and Louisiana.
With the acquisition of Westcoast, Natural Gas Transmission will also compete
directly with other Canadian based pipelines and storage facilities. The
principal elements of competition are rates, terms of service, and flexibility
and reliability of service.
Natural gas competes with other forms of energy available to Duke Energy'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, governmental regulations, the capability to convert to alternative
fuels, weather and other factors affect the demand for natural gas in the areas
served by Duke Energy.
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 via interstate commerce for resale. (For more information on 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 pipelines and related facilities used in the
transportation, storage and sale of natural gas in interstate commerce,
including the extension, enlargement or abandonment of such facilities. Texas
Eastern, Algonquin, ETNG, MHP and Maritimes & Northeast hold certificates of
public convenience and necessity issued by the FERC, authorizing them to
construct and operate pipelines, facilities and related properties, and to
transport and store natural gas via 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.
10
The FERC regulations govern access to regulated natural gas transmission
customer data by non-regulated entities and to 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 EPA and state
environmental agencies. (For a discussion of environmental regulation, see
"Environmental Matters" in this section.) Natural Gas Transmission is also
subject to the Natural Gas Pipeline Safety Act of 1968, which regulates gas
pipeline and liquefied natural gas plant safety requirements.
The Canadian assets acquired through the Westcoast acquisition are subject
to regulation by the National Energy Board and provincial agencies within
Canada, such as the Ontario Energy Board and the British Columbia Utilities
Commission.
FIELD SERVICES
Field Services gathers, processes, transports, markets and stores natural
gas and produces, transports, markets and stores NGLs. Field Services gathers
natural gas from production wellheads in western Canada and 11 contiguous
states in the U.S. Those systems serve major gas-producing regions in the Rocky
Mountain, Permian Basin, Mid-Continent, East Texas-Austin Chalk-North Louisiana
areas, as well as onshore and offshore Gulf Coast areas. Field Services owns
and operates approximately 57,000 miles of natural gas gathering systems with
approximately 40,000 active receipt points. Field Services conducts its
operations primarily through DEFS, which is approximately 30% owned by Phillips
Petroleum.
Field Services' natural gas processing operations separate raw natural gas
that has been gathered on its systems and third-party systems into NGLs and
residue gas. Field Services processes the raw natural gas at the 64 natural gas
processing facilities that it owns and operates and at 12 third-party operated
facilities in which it has an equity interest.
The NGLs separated from the raw natural gas are either sold and transported
as NGL raw mix or further separated through a process known as fractionation
into their individual components (ethane, propane, butanes and natural
gasoline) and then sold as components. Field Services fractionates NGL raw mix
at 12 processing facilities that it owns and operates and at two third-party
operated fractionators in which it has an equity interest. Field Services sells
NGLs to a variety of customers ranging from large, multi-national petrochemical
and refining companies to small regional retail propane distributors.
Substantially all of its NGL sales are made at market-based prices. At four
plants, Field Services also extracts helium from the residue gas stream.
The residue gas separated from the raw natural gas is sold at market-based
prices to marketers or end-users, including large industrial customers and
natural gas and electric utilities serving individual consumers. Field Services
markets residue gas through its wholly-owned gas marketing company. Field
Services also stores residue gas at its nine billion cubic foot natural gas
storage facility.
The following map includes Field Services' natural gas gathering systems,
intrastate pipelines, regional offices and supply areas. The map also shows
Natural Gas Transmission's interstate pipeline systems.
11
[MAP OF SERVICE AREA]
Field Services also owns Texas Eastern Products Pipeline Company (TEPPCO),
the general partner of TEPPCO Partners, L.P., a publicly traded limited
partnership which owns and operates a network of pipelines for refined products
and crude oil. TEPPCO is responsible for the management and operations of
TEPPCO Partners, L.P.
Field Services' operating results are significantly impacted by changes in
NGL prices, which decreased approximately 15% in 2001 compared to 2000. (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.)
Field Services' activities can fluctuate in response to seasonal demand for
natural gas. (See Field Services' "Operating Statistics" in this section.)
Competition
Field Services competes with major integrated oil companies, major
interstate and intrastate pipelines, national and local natural gas gatherers,
and 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 based primarily on the
reputation, efficiency and reliability of operations, the availability of
gathering and transportation to high demand markets, the pricing arrangement
offered by the gatherer/processor and the ability of the gatherer/processor to
obtain a satisfactory price for the producer's residue gas and extracted NGLs.
Competition for sales customers is based primarily upon reliability and price
of delivered natural gas and NGLs.
12
Regulation
The intrastate pipelines owned by Field Services are subject to state
regulation. To the extent they provide services under Section 311 of the
Natural Gas Policy Act of 1978, they are also subject to FERC regulation.
However, most of Field Services' natural gas gathering activities are not
subject to FERC regulation.
Field Services is subject to the jurisdiction of the EPA and state
environmental agencies. (For more information, see "Environmental Matters" in
this section.) Some Field Services' operations are subject to the jurisdiction
of the Department of Transportation and state transportation agencies. Their
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.
Field Services' Canadian assets are regulated by the Alberta Energy and
Utilities Board and the National Energy Board.
NORTH AMERICAN WHOLESALE ENERGY
NAWE develops, operates and manages merchant generation facilities and
engages in commodity sales and services related to natural gas and electric
power. NAWE conducts these operations primarily through DENA and DETM. DETM is
approximately 40% owned by Exxon Mobil Corporation. NAWE also includes DEM,
which develops new business lines in the evolving energy commodity markets
other than natural gas and power. NAWE conducts business primarily throughout
the U.S. and Canada.
DENA is an integrated energy business that develops, owns and manages a
portfolio of merchant generation facilities. Through its portfolio management
strategy, DENA invests in markets that have capacity needs and divests its
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
Duke Energy business units to build and manage 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
7,406 MW of gross operating generation and has approximately 9,070 MW of
projects under construction, which are slated for completion to meet summer
peak demand (6,620 MW in 2002 and 2,450 MW in 2003). In addition, DENA has
approximately 13,000 MW in advanced development scheduled to begin operation
between 2003 and 2005.
13
The following map shows DENA's power generation facilities.
[MAP OF SERVICE AREA]
DETM markets natural gas, electricity and other energy-related products to a
wide range of customers across North America. Duke Energy owns a 60% interest
in DETM's natural gas and electric power trading operations, with Exxon Mobil
Corporation owning a 40% minority interest. Duke Energy and Exxon Mobil
Corporation are in arbitration regarding the DETM ownership. (See "Management's
Discussion and Analysis of Results of Operations and Financial Condition,
Current Issues--Litigation and Contingencies, Exxon Mobil Corporation
Arbitration" and Note 15 to the Consolidated Financial Statements, "Commitments
and Contingencies--Litigation and Contingencies.")
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 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. On-system, DETM generally purchases natural gas from producers
connected to Field Services' facilities and delivers the gas to an intrastate
or interstate pipeline for redelivery to another customer, using Natural Gas
Transmission's pipelines when prudent. Off-system, DETM purchases natural gas
from producers, pipelines and other suppliers not connected with Duke Energy's
facilities for resale to customers. DETM is committed to market substantially
all of Exxon Mobil's U.S. and Canadian natural gas production through 2006.
DETM's electricity marketing operations involve purchasing electricity from
third-party suppliers and from DENA's domestic generation facilities for resale
to customers.
14
The vast majority of DETM's portfolio of short-term and long-term sales
agreements incorporate market-sensitive pricing terms. Long-term gas purchase
agreements with producers, principally related to 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" and Note 7 to the
Consolidated Financial Statements, "Derivative Instruments, Hedging Activities
and Credit Risk.")
DEM conducts physical and financial marketing and trading in evolving global
energy commodity markets, and provides energy, financial and asset management
services to producers, transporters and users of energy commodities and
derivative products. DEM also invests capital in limited hydrocarbon
exploration and production prospects through non-operating working interests.
DETM's and DEM's activities can fluctuate in response to seasonal demand for
electricity, natural gas and other energy-related commodities. (See "Operating
Statistics" in this section.)
Competition
DETM competes for natural gas supplies and in marketing natural gas,
electricity and other energy-related commodities. DEM competes for other
energy-related commodities. Competitors include major integrated oil companies,
major interstate pipelines and their marketing affiliates, brokers, marketers
and distributors, electric utilities and other electric power marketers. The
price of commodities and services delivered, along with the quality and
reliability of services provided, drive competition in the energy marketing
business.
DENA experiences substantial competition from utilities as well as other
merchant electric generation companies in the U.S.
Regulation
NAWE's energy marketing activities may, in some 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 to the California
Independent System Operator electricity under "reliability must run"
agreements, those sales are made at the FERC regulated rates.
As described in Note 15 to the Consolidated Financial Statements,
"Commitments and Contingencies--California Issues," the causes of higher
wholesale electric prices in California in 2000 are under investigation. During
March 2001, the FERC ordered several electricity suppliers, including DETM, to
(i) refund or offset prices bid for power in California during Stage 3
emergencies in January and February 2001, to the extent such prices exceeded a
FERC-established proxy 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. As a result, the DETM bids exceeded the FERC-established proxy
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 collected payments based on the FERC-established proxy price. In
June 2001, DETM offset approximately $20 million against amounts owed by the
California Independent System Operator and the California Power Exchange for
electricity sales during January and February 2001. It is expected that the
FERC will issue additional orders with respect to sales in California from
October 2 through December 31, 2000, and periods following February 2001. Any
such actions are subject to reconsideration or appeal. Management
15
believes this matter will not have a material effect on Duke Energy'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" in this
section.)
INTERNATIONAL ENERGY
International Energy develops, operates and manages natural gas and power
generation facilities and engages in energy trading and marketing of natural
gas and electric power. It conducts operations primarily through DEI and its
activities target the Latin American, Asia-Pacific and European regions.
Liberalization of energy markets abroad and privatization of energy
infrastructure are providing substantial growth opportunities for International
Energy. In Latin America, the Asia-Pacific region and Europe, International
Energy is building and managing integrated energy businesses by building,
through development or acquisition, regional energy portfolios that include the
control and operation of natural gas and power facilities, and energy trading
and marketing businesses. From this platform, International Energy provides
customers with energy supply at competitive prices, manages the logistics
associated with natural gas and power delivery, and offers a number of services
that allow customers to improve energy efficiency and hedge their commodity
price exposure. International Energy's customers include retail distributors,
electric utilities, independent power producers, large industrial companies,
governments, gas and oil producers and mining operations. International Energy
is committed to building integrated regional businesses that provide customers
with a full range of innovative and competitively priced energy services.
International Energy owns, operates or has substantial interests in
approximately 5,200 MW of generation facilities and 1,100 miles of pipeline
systems. The following map shows the locations of International Energy's
worldwide energy facilities, including projects under construction or under
contract.
[MAP OF SERVICE AREA]
16
Competition and Regulation
International Energy's operations are subject to country and region-specific
market and competition regulations. Commonly addressed regulatory issues
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. On January 31, 2002, Duke Energy announced the
planned sale of DE&S to Framatome ANP, Inc. (For more information, see
"Management's Discussion and Analysis of Results of Operations and Financial
Condition, Current Issues--Subsequent Events.")
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 Duke Energy and Fluor Enterprises, Inc.
each own 50% of D/FD.
DukeSolutions provides energy consulting services to large end-users of
energy by identifying and affecting points in a customer's operations where
energy-related costs are incurred, including procurement, production and
disposal. DukeSolutions provides strategic solutions to reduce costs when
customers buy energy, convert it into a usable form, use it to manufacture
products and dispose of waste. On March 13, 2002, Duke Energy announced the
planned sale of DukeSolutions to Ameresco, Inc. (For more information see
"Management's Discussion and Analysis of Results of Operations and Financial
Condition, Current Issues--Subsequent Events.")
Other Energy Services competes with utilities and independent energy
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" in this section.)
DUKE VENTURES
Duke Ventures is composed 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 in the southeastern and southwestern
U.S. On December 31, 2001, Crescent owned 3.0 million square feet of
commercial, industrial and retail space, with an additional 1.5 million square
feet under construction. This portfolio included 2.3 million square feet of
office space, 1.5 million square feet of warehouse space and .7 million square
feet of retail space. Crescent's residential developments include high-end,
country club and golf course communities with individual lots sold to custom
builders and tract developments with sales to national builders. In 2001,
Crescent had three multi-family communities in Florida. On December 31, 2001,
Crescent also had approximately 140,000 acres of land under its management.
17
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 1,230-mile fiber optic communications
network centered in the Carolinas and interconnected, through affiliate
agreements with third parties, with a 18,500-mile fiber optic communications
network, that stretches from Maine to Texas. DCP, a merchant finance company,
provides financing, investment banking and asset management services to
wholesale and commercial markets in the energy, real estate and
telecommunications industries.
ENVIRONMENTAL MATTERS
Duke Energy 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. Environmental regulations affecting
Duke Energy include:
. The Clean Air Act (CAA) and the 1990 amendments to the Act, as well as
state laws and regulations impacting air emissions, including State
Implementation Plans related to existing and new national ambient air
quality standards for ozone. Owners and/or operators of air emissions
sources are responsible for obtaining permits and for annual compliance
and reporting.
. The Federal Water Pollution Control Act which requires permits for
facilities that discharge treated wastewater into the environment.
. The Comprehensive Environmental Response, Compensation and Liability Act,
which can require any individual or entity that may have owned or operated
a disposal site, as well as transporters or generators of hazardous wastes
sent to such site, to share in remediation costs.
. The Solid Waste Disposal Act, as amended by the Resource Conservation and
Recovery Act, which requires certain solid wastes, including hazardous
wastes, to be managed pursuant to a comprehensive regulatory regime.
. The National Environmental Policy Act, which requires consideration of
potential environmental impacts by federal agencies in their decisions,
including siting approvals.
(For more information on environmental matters involving Duke Energy,
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 15 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 Duke Energy.
18
GEOGRAPHIC REGIONS
Duke Energy's significant geographic regions are as follows:
Latin Other
U.S. Canada America Foreign Consolidated
------- ------ ------- ------- ------------
In millions
2001
Consolidated revenues........ $51,723 $5,690 $ 628 $1,462 $59,503
Consolidated long-term assets 34,150 516 2,573 1,594 38,833
2000
Consolidated revenues........ $43,282 $4,964 $ 512 $ 560 $49,318
Consolidated long-term assets 30,772 900 2,823 1,222 35,717
1999
Consolidated revenues........ $19,336 $2,007 $ 171 $ 252 $21,766
Consolidated long-term assets 22,995 250 2,708 901 26,854
(For a discussion of Duke Energy'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 7 to the Consolidated
Financial Statements, "Business Segments" and "Derivative Instruments, Hedging
Activities and Credit Risk.")
EMPLOYEES
On December 31, 2001, Duke Energy had approximately 24,000 employees. A
total of 1,583 operating and maintenance employees were represented by unions.
Of these, 1,392 were represented by the International Brotherhood of Electrical
Workers at two operating units. An additional 73 employees were represented by
the United Steelworkers and Rubberworkers of America. Fifty-six employees were
represented by the Paper, Allied, Chemical and Energy Workers Union and 62
employees were represented by the International Union of Operating Engineers.
19
OPERATING STATISTICS
Years Ended December 31,
--------------------------------------------
2001 2000 1999 1998 1997
-------- -------- -------- ------- -------
Franchised Electric
Sources of Electric Energy, GWh(a)
Generated--net output:
Coal........................................... 41,796 43,526 41,306 42,164 45,234
Nuclear........................................ 39,922 41,073 39,263 38,366 29,569
Hydro.......................................... 224 394 638 1,714 1,633
Oil and gas.................................... 139 459 662 846 301
-------- -------- -------- ------- -------
Total generation............................. 82,081 85,452 81,869 83,090 76,737
Purchased power and net interchange............ 3,050 4,497 3,617 2,659 3,781
-------- -------- -------- ------- -------
Total output................................. 85,131 89,949 85,486 85,749 80,518
Plus: Purchases from other Catawba joint owners -- 150 1,233 1,656 2,316
-------- -------- -------- ------- -------
Total sources of energy...................... 85,131 90,099 86,719 87,405 82,834
Less: Line loss and company usage.............. 5,446 5,333 5,171 5,394 4,899
-------- -------- -------- ------- -------
Total GWh sales.............................. 79,685 84,766 81,548 82,011 77,935
======== ======== ======== ======= =======
Electric Energy Sales, GWh
Residential.................................... 23,272 22,884 21,897 22,002 20,483
General service................................ 23,666 22,845 21,807 21,093 19,687
Industrial
Textile...................................... 8,829 10,819 11,201 11,981 11,955
Other........................................ 18,074 18,952 18,704 18,668 18,376
Other energy and wholesale..................... 6,979 8,671 7,715 8,933 7,029
-------- -------- -------- ------- -------
Total GWh sales billed....................... 80,820 84,171 81,324 82,677 77,530
Unbilled GWh sales......................... (1,135) 595 224 (666) 405
-------- -------- -------- ------- -------
Total GWh sales.......................... 79,685 84,766 81,548 82,011 77,935
======== ======== ======== ======= =======
Natural Gas Transmission
Proportional Throughput Volumes, TBtu(b)(c)..... 1,710 1,771 1,893 1,459 1,641
Field Services
Natural Gas Gathered and
Processed/Transported, TBtu/d(d).............. 8.6 7.6 5.1 3.6 3.4
NGL Production, MBbl/d(e)....................... 397.2 358.5 192.4 110.2 108.2
Average Natural Gas Price per MMBtu(f).......... $ 4.27 $ 3.89 $ 2.27 $ 2.11 $ 2.59
Average NGL Price per Gallon.................... $ 0.45 $ 0.53 $ 0.34 $ 0.26 $ 0.35
Natural Gas Marketed,TBtu/d..................... 1.6 0.7 0.5 0.4 0.4
NAWE
Natural Gas Marketed,TBtu/d..................... 12.4 11.9 10.5 8.0 6.9
Electricity Marketed and Traded, GWh............ 335,210 275,258 109,634 98,991 64,650
- --------
(a) Gigawatt-hour
(b) Trillion British thermal units
(c) Excludes throughput of pipelines sold in March 1999: 328 TBtu (1999); 1,141
TBtu (1998); 1,279 TBtu (1997)
(d) Trillion British thermal units per day
(e) Thousand barrels per day
(f) Million British thermal units
20
EXECUTIVE OFFICERS OF DUKE ENERGY
RICHARD B. PRIORY, 55, Chairman of the Board, President and Chief Executive
Officer. Mr. Priory served as President and Chief Operating Officer from 1994
until he assumed his present position in 1997 following Duke Energy's merger
with PanEnergy Corp (PanEnergy).
RICHARD W. BLACKBURN, 59, Executive Vice President, General Counsel and
Secretary. Mr. Blackburn was named to his present position in 1997. Prior to
joining Duke Energy, he served as President and Group Executive of NYNEX
Corporation's Worldwide Communications and Media Group from 1995 to 1997.
ROBERT P. BRACE, 52, Executive Vice President and Chief Financial Officer.
Mr. Brace joined Duke Energy in 2000. Previously, he served as Group Finance
Director of British Telecommunications plc starting in 1993.
KEITH G. BUTLER, 41, Senior Vice President and Controller. Mr. Butler
assumed his present position in August 2001. Mr. Butler held various positions
at Duke Power before being named Senior Vice President and Chief Financial
Officer of Duke Energy Global and its affiliated companies in February 1998;
Senior Vice President and Chief Financial Officer of Duke Energy North America
in July 1998; and Chief Operating Officer, DukeSolutions, in September 1999.
WILLIAM A. COLEY, 58, Group President, Duke Power. Mr. Coley served as
President of Duke Energy's Associated Enterprises Group from 1994 to 1997, when
he assumed his present position following the PanEnergy merger.
FRED J. FOWLER, 56, Group President, Energy Transmission. Mr. Fowler served
as Group Vice President of PanEnergy from 1996 until the PanEnergy merger, when
he assumed his present position.
DAVID L. HAUSER, 50, Senior Vice President and Treasurer. Mr. Hauser held
various positions, including Controller, at Duke Power before being named
Senior Vice President, Global Asset Development, in 1997. He was appointed to
his current position in 1998.
RICHARD J. OSBORNE, 51, Executive Vice President and Chief Risk Officer. Mr.
Osborne assumed his present position in May 2000. He previously served as
Executive Vice President and Chief Financial Officer following the PanEnergy
merger. Prior to the merger, beginning in 1994, Mr. Osborne was Senior Vice
President and Chief Financial Officer.
HARVEY J. PADEWER, 54, Group President, Energy Services. Mr. Padewer assumed
his present position in 1999. From 1995 through 1998, he served as Senior Vice
President and General Manager of Utilicorp Energy Group.
RUTH G. SHAW, 54, Executive Vice President and Chief Administrative Officer.
Ms. Shaw served as Senior Vice President, Corporate Resources, from 1994 until
the PanEnergy merger, when she assumed her present position.
Executive officers are elected annually by the Board of Directors. They
serve until the first meeting of the Board of Directors following the annual
meeting of shareholders and until their successors are duly elected.
There are no family relationships between any of the executive officers, nor
any arrangement or understanding between any executive officer and any other
person involved in officer selection.
21
Item 2. Properties.
FRANCHISED ELECTRIC
As of December 31, 2001, Franchised Electric operated three nuclear
generating stations with a combined net capacity of 5,409 MW (including 12.5%
ownership in the Catawba Nuclear Station), eight coal-fired stations with a
combined capacity of 7,572 MW, 31 hydroelectric stations with a combined
capacity of 2,791 MW and six combustion turbine stations with a combined
capacity of 2,081 MW. All of the stations are located in North Carolina or
South Carolina.
In addition, Franchised Electric owned, as of December 31, 2001,
approximately 13,000 conductor miles of electric transmission lines, including
600 miles of 525 kilovolts, 2,600 miles of 230 kilovolts, 6,500 miles of 100 to
161 kilovolts, and 3,300 miles of 13 to 66 kilovolts. Franchised Electric also
owned approximately 93,600 conductor miles of electric distribution lines,
including 62,700 miles of rural overhead lines, 15,700 miles of urban overhead
lines, 8,300 miles of rural underground lines and 6,900 miles of urban
underground lines. As of December 31, 2001, the electric transmission and
distribution systems had approximately 1,600 substations.
Part of the electric plant is mortgaged under the indenture relating to Duke
Energy's various series of First and Refunding Mortgage Bonds.
NATURAL GAS TRANSMISSION
Texas Eastern'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
with three large-diameter parallel pipelines and the other with one to three
large-diameter pipelines. Texas Eastern's system consists of approximately
8,600 miles of pipeline and 72 compressor stations.
Texas Eastern's also owns and operates two offshore Louisiana pipeline
systems, which extend over 100 miles into the Gulf of Mexico and include 467
miles of Texas Eastern's pipelines.
Algonquin's transmission system connects with Texas Eastern'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.
ETNG's transmission system crosses Texas Eastern's system at two points in
Tennessee and consists of two mainline systems totaling 1,100 miles of pipeline
in Tennessee and Virginia, with 17 compressor stations.
(For a map showing natural gas transmission and storage properties, see
"Business, Natural Gas Transmission" earlier in this section. Also see that
section for additional information on Natural Gas Transmission's properties,
including additions due to the Westcoast acquisition.)
FIELD SERVICES
(For information and a map showing Field Services' properties, see
"Business, Field Services" earlier in this section.)
22
NORTH AMERICAN WHOLESALE ENERGY
As of December 31, 2001, DENA's generation portfolio in operation included:
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
Vermillion........ 648 Natural gas IN 100
Lee............... 640 Natural gas MS 100
Hinds............. 520 Natural gas IL 100
Maine Independence 520 Natural gas ME 100
Bridgeport........ 510 Natural gas CT 67
St. Francis....... 494 Natural gas MO 50
American Ref-Fuel. 380 Waste-to-energy CT, MA, NJ, NY 50
New Albany Energy. 349 Natural gas MS 100
Oakland........... 165 Oil CA 100
-----
Total............. 7,406
=====
DENA had approximately 9,070 gross MW under construction in various
high-growth markets slated for completion to meet summer peak demands: 6,620 MW
in 2002 and 2,450 MW in 2003. In addition to facilities in operation or under
construction, DENA had approximately 13,000 gross MW in advanced development
scheduled to begin operation between 2003 and 2005.
For additional information and a map showing NAWE's properties, see
"Business, North American Wholesale Energy" earlier in this section.
INTERNATIONAL ENERGY
As of December 31, 2001, International Energy's generation portfolio in
operation included:
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 100
Puncakjaya Power............... 383 Thermal Indonesia 43
Acajutla....................... 381 Thermal El Salvador 90
Western Australia.............. 280 Thermal Australia 100
Electroquil.................... 180 Thermal Ecuador 69
Constellation.................. 168 Oil Guatemala 100
Aquaytia....................... 160 Thermal Peru 38
Empressa Electrica Corani...... 126 Hydro Bolivia 50
New Zealand.................... 112 Thermal New Zealand 100
Bairnsdale..................... 43 Natural Gas Australia 100
-----
Total.......................... 5,216
=====
23
DEI had approximately 853 gross MW under construction in Latin America and
43 gross MW in Australia. As of December 31, 2001, DEI also owned approximately
1,346 miles of pipeline systems in Australia, including 463 miles under
development. Additionally, DEI had an 11.84% ownership interest in 855 miles of
pipeline systems in Australia and a 37.83% ownership interest in 190 miles of
pipeline systems in Peru. Also, as of December 31, 2001, 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 showing International Energy's
properties, see "Business, International Energy" earlier in this section.)
DUKE VENTURES
(For information regarding Duke Ventures' properties, see "Business, Duke
Ventures" earlier in this section.)
OTHER
None of the properties used in Duke Energy's other business activities are
considered material to Duke Energy's operations as a whole.
Item 3. Legal Proceedings.
Duke Energy, some of its subsidiaries and three current or former executives
have been named as defendants, among other corporate and individual defendants,
in one or more of a total of six lawsuits brought by or on behalf of
electricity consumers in the State of California. The plaintiffs seek damages
as a result of the defendants' alleged unlawful manipulation of the California
wholesale electricity markets. DENA and DETM are among 16 defendants in a
class-action lawsuit (the Gordon lawsuit) filed against generators and traders
of electricity in California markets. DETM was also 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, traders and other unnamed providers of electricity in California
markets. A sixth lawsuit (the Bustamante lawsuit) was brought by the Lieutenant
Governor of the State of California and a State Assemblywoman, on their own
behalf as citizens and on behalf of the general public, and includes Duke
Energy, some of its subsidiaries and three current or former executives of Duke
Energy among other corporate and individual defendants. The Gordon and
Hendricks class-action lawsuits were filed in the Superior Court of the State
of California, San Diego County, in November 2000. Three other lawsuits were
filed in January 2001, one in Superior Court, San Diego County, and the other
two in Superior Court, County of San Francisco. The Bustamante lawsuit was
filed in May 2001 in Superior Court, Los Angeles County. These lawsuits
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. The plaintiffs seek aggregate damages of
billions of dollars. The lawsuits seek the refund of alleged unlawfully
obtained revenues for electricity sales and, in four lawsuits, an award of
treble damages. These suits have been consolidated before a state court judge
in San Diego. While these matters are in their earliest stages, management
believes, based on its analysis of the facts and the asserted claims, that
their resolution will have no material adverse effect on Duke Energy's
consolidated results of operations, cash flows or financial position. (See Note
15 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 2000, the U.S. Justice Department, acting on behalf of the EPA, filed a
complaint against Duke Energy in the U.S. District Court in Greensboro, North
Carolina, for alleged violations of the New Source Review (NSR) provisions of
the CAA. The EPA claims that 29 projects performed at 25 of Duke Energy's
coal-fired units were major modifications, as defined in the CAA, and that Duke
Energy violated the CAA's NSR requirements when it undertook those projects
without obtaining permits and installing emission controls for sulfur dioxide,
nitrogen
24
oxide and particulate matter. The complaint asks the court to order Duke Energy
to stop operating the coal-fired units identified in the complaint, install
additional emission controls and pay unspecified civil penalties. This
complaint is part of the EPA's NSR enforcement initiative, in which the EPA
claims that utilities and others have committed widespread violations of the
CAA permitting requirements for the past 25 years. The EPA has sued or issued
notices of violation of investigative information requests to at least 48 other
electric utilities and cooperatives.
The EPA's allegations run counter to previous EPA guidance regarding the
applicability of the NSR permitting requirements. Duke Energy, along with other
utilities, has routinely undertaken the type of repair, replacement and
maintenance projects that the EPA now claims are illegal. Duke Energy believes
that all of its electric generation units are properly permitted and have been
properly maintained, and is defending itself vigorously against these alleged
violations. The U.S. Vice President's National Energy Policy Development Group
has ordered the EPA to review its NSR rules and has ordered the Department of
Justice to review the appropriateness of the enforcement cases. The EPA review
was scheduled to be completed by August 2001, but has not yet been concluded.
In January 2002, the Department of Justice released a report concluding that it
was not improper for the Department of Justice to initiate the enforcement
cases brought on behalf of the EPA. It specifically declined to address whether
the EPA's enforcement actions are wise as a matter of national energy policy.
Because these matters are in a preliminary stage, management cannot estimate
the effects of these matters on Duke Energy's future consolidated results of
operations, cash flows or financial position. The CAA authorizes civil
penalties of up to $27,500 per day per violation at each generating unit. Civil
penalties, if ultimately imposed by the court, and the cost of any required new
pollution control equipment, if the court accepts the EPA's contentions, could
be substantial. (See Note 15 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.")
In 2000, three Duke Energy subsidiaries initiated binding arbitration
against three Exxon Mobil Corporation subsidiaries (the Exxon Mobil entities)
concerning the parties' joint ownership of DETM and related affiliates (the
Ventures). At issue is a buy-out right provision under the joint venture
agreements for these entities. If there is a material business dispute between
the parties, which Duke Energy alleges has occurred, the buy-out provision
gives Duke Energy the right to purchase Exxon Mobil's 40% interest in DETM.
Exxon Mobil does not have a similar right under the joint venture agreements
and once Duke Energy exercises the buy-out right, each party has the right to
"unwind" the buy-out under certain specific circumstances. In December 2000,
Duke Energy exercised its right to buy the Exxon Mobil entities' interest in
the Ventures. Duke Energy 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. Duke Energy has also made additional
claims against the Exxon Mobil entities for breach of the agreements governing
the Ventures.
In January 2001, the Exxon Mobil entities made counterclaims in the
arbitration and, in a separate Texas state court action, alleged that Duke
Energy breached its obligations to the Ventures and to the Exxon Mobil
entities. In April 2001, the state court stayed its action, compelling the
Exxon Mobil entities to arbitrate their claims. The Exxon Mobil entities
proceeded with the arbitration of their claims and have not challenged this
order in an appellate court. In early October 2001, the arbitration panel
convened an evidentiary hearing regarding the buy-out right provision and Duke
Energy's and Exxon Mobil's claims against each other. The panel has not yet
ruled but Duke Energy expects a final decision from the panel in early 2002.
Management believes that the final disposition of this action will have no
material adverse effect on Duke Energy's consolidated results of operations or
financial position.
On November 15, 2001, the Illinois Pollution Control Board imposed a penalty
of $850,000 plus assessed attorney fees in an environmental enforcement
proceeding against a former subsidiary of Duke Energy relating to
25
air quality permit violations at a natural gas compressor station. Duke Energy
has resolved its indemnity obligation to the purchaser of this former
subsidiary for the penalty resulting from these violations.
In June 2001, Duke Energy's subsidiary, DEFS, received two administrative
Compliance Orders from the New Mexico Environment Department (NMED) seeking
civil penalties for primarily historic air permit matters. One order alleges
specific permit non-compliance at 11 facilities that occurred periodically
between 1996 and 1999. Allegations under this order relate primarily to
emissions from certain compressor engines in excess of what were then new
operating permit limits. The other order alleges numerous unexcused excursions
from an hourly permit limit arising from upset events at one facility's sulfur
recovery unit between 1997 and 2001. The NMED applied its civil penalty policy
to the alleged violations and calculated the penalties to be $10 million in the
aggregate. The NMED has initiated settlement discussions and offered to resolve
these matters for an amount lower than the calculated penalties. DEFS is
continuing its discussions with the NMED and anticipates that it will resolve
all issues relating to the alleged violations.
In September 2001, DEFS received a Proposed Agreed Order from the Texas
Natural Resource Conservation Commission (Commission) to settle allegations
reflected in a June 2001 notice from the Commission relating to DEFS' Port
Arthur natural gas processing plant. The Proposed Agreed Order sought penalties
of $278,000 for various items of alleged-noncompliance relating to the
facility's air permit and state air regulations, including valve monitoring and
repair requirements under 40 CFR 60, subpart KKK. DEFS has reached a settlement
with the staff of the Commission for a monetary penalty in the amount of
$39,832 and a Supplemental Environmental Project in the amount of $39,832,
subject to the approval of the Commission.
DEFS received a Consolidated Compliance Order and Notice of Potential
Penalty from the Louisiana Department of Environmental Quality (LDEQ) in the
spring of 2001 enabling DEFS to discharge certain wastewater streams from its
Minden Gas Processing Plant until a new discharge permit is issued by the LDEQ.
The Compliance Order authorized certain discharges, and otherwise addressed
various historic and recent deviations from Clean Water Act regulatory
requirements, including the lapse of the facility's discharge permit. The
Compliance Order also contemplates final resolution of these matters including
the LDEQ issuing a penalty assessment. DEFS and LDEQ are now in discussions to
resolve all issues relating to this matter.
DEFS is in discussion with the Oklahoma Department of Environmental Quality
(ODEQ) regarding apparent non-compliance issues relating to DEFS' Title V Clean
Air Act Operating permits at its Oklahoma facilities, primarily consisting of
compliance issues disclosed to the ODEQ pursuant to permit requirements or
otherwise voluntarily disclosed to the ODEQ in 2001. These non-compliance
issues relate to various specific and detailed terms of the Title V permits,
including separate filing requirements, engine testing procedural requirements,
certification requirements, and quarterly emissions testing obligations. As a
result of these discussions, DEFS anticipates that a comprehensive settlement
agreement will be entered into to resolve these various items.
Duke Energy and its subsidiaries are involved in other legal, tax and
regulatory proceedings before various courts, regulatory commissions and
governmental agencies regarding performance, contracts and other matters
arising in the ordinary course of business, some of which involve substantial
amounts. Management believes that the final disposition of these proceedings
will have no material adverse effect on Duke Energy's consolidated results of
operations, cash flows or financial position. (See Note 15 to the Consolidated
Financial Statements, "Commitments and Contingencies--Litigation and
Contingencies," and "Management's Discussion and Analysis of Results of
Operations and Financial Condition, Current Issues--Litigation and
Contingencies.")
Item 4. Submission of Matters to a Vote of Security Holders.
No matters were submitted to a vote of Duke Energy's security holders during
the fourth quarter of 2001.
26
PART II.
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
Duke Energy's common stock is listed for trading on the New York Stock
Exchange. At February 28, 2002, there were approximately 149,051 common
stockholders of record.
Common Stock Data by Quarter
2001(a) 2000(b)
--------------------------- ---------------------------
Stock Price Range Stock Price Range
Dividends ----------------- Dividends -----------------
Per Share High Low Per Share High Low
--------- ------ ------ --------- ------ ------
First Quarter. $0.275 $43.50 $32.41 $0.275 $28.94 $23.19
Second Quarter 0.55 47.74 38.40 0.55 31.25 26.16
Third Quarter. -- 42.85 34.39 -- 42.88 28.31
Fourth Quarter 0.275 41.35 32.22 0.275 44.97 40.22
- --------
(a) The 2001 stock prices represent the intra-day high and low stock price.
(b) The 2000 amounts were restated to reflect the two-for-one common stock
split effective January 26, 2001.
On December 17, 1998, Duke Energy's Board of Directors adopted a shareholder
rights plan. Under the terms of the plan, one preference stock purchase right
was distributed for each share of common stock outstanding on February 12, 1999
and for each share issued thereafter, subject to adjustment as specified
therein. The NCUC and PSCSC approved this distribution. The plan is intended to
ensure the fair treatment of all shareholders in the event of a hostile
takeover attempt, and to encourage a potential acquirer to negotiate with the
Board of Directors a fair price for all shareholders before attempting a
takeover. The adoption of the plan was not in response to any takeover offer or
threat.
27
Item 6. Selected Financial Data.
2001 2000 1999(a) 1998 1997(b)
------- ------- ------- ------- -------
In millions, except per share amounts
Income Statement
Operating revenues......................................... $59,503 $49,318 $21,766 $17,662 $16,309
Operating expenses......................................... 55,403 45,505 19,947 15,177 14,339
------- ------- ------- ------- -------
Operating income........................................... 4,100 3,813 1,819 2,485 1,970
Other income and expenses.................................. 156 201 224 162 138
Interest expense........................................... 785 911 601 514 472
Minority interest expense.................................. 327 307 142 96 23
------- ------- ------- ------- -------
Earnings before income taxes............................... 3,144 2,796 1,300 2,037 1,613
Income taxes............................................... 1,150 1,020 453 777 639
------- ------- ------- ------- -------
Income before extraordinary item and cumulative effect of
change in accounting principle........................... 1,994 1,776 847 1,260 974
Extraordinary gain (loss), net of tax...................... -- -- 660 (8) --
Cumulative effect of change in accounting principle, net of
tax...................................................... (96) -- -- -- --
------- ------- ------- ------- -------
Net income................................................. 1,898 1,776 1,507 1,252 974
Preferred and preference stock dividends................... 14 19 20 21 72
------- ------- ------- ------- -------
Earnings available for common stockholders................. $ 1,884 $ 1,757 $ 1,487 $ 1,231 $ 902
======= ======= ======= ======= =======
Common Stock Data (c)
Shares of common stock outstanding
Year-end................................................ 777 739 733 726 720
Weighted average........................................ 767 736 729 722 720
Earnings per share (before extraordinary item and
cumulative effect of change in accounting principle)
Basic................................................... $ 2.58 $ 2.39 $ 1.13 $ 1.72 $ 1.26
Diluted................................................. 2.56 2.38 1.13 1.71 1.25
Earnings per share
Basic................................................... $ 2.45 $ 2.39 $ 2.04 $ 1.70 $ 1.26
Diluted................................................. 2.44 2.38 2.03 1.70 1.25
Dividends per share........................................ 1.10 1.10 1.10 1.10 0.95
Balance Sheet
Total assets............................................... $48,375 $58,232 $33,409 $26,806 $24,029
Long-term debt, less current maturities.................... 12,321 10,717 8,683 6,272 6,530
- --------
(a) Financial information reflects a pre-tax $800 million charge for estimated
injuries and damages claims. The earnings-per-share effect of this charge
was $0.67 per share.
(b) Financial information reflects accounting for the 1997 merger with
PanEnergy as a pooling of interests. As a result, the financial information
gives effect to the merger as if it had occurred January 1, 1997.
(c) Amounts prior to 2001 were restated to reflect the two-for-one common stock
split effective January 26, 2001.
28
Item 7. Management's Discussion and Analysis of Results of Operations and
Financial Condition.
INTRODUCTION
Management's Discussion and Analysis should be read with the Consolidated
Financial Statements.
Business Segments. Duke Energy Corporation (collectively with its
subsidiaries, Duke Energy), an integrated provider of energy and energy
services, offers physical delivery and management of both electricity and
natural gas throughout the U.S. and abroad. Duke Energy provides these and
other services through seven business segments.
Franchised Electric generates, transmits, distributes and sells electricity
in central and western North Carolina and western South Carolina. It conducts
operations primarily through Duke Power and Nantahala Power and Light. These
electric operations are subject to the rules and regulations of the Federal
Energy Regulatory Commission (FERC), the North Carolina Utilities Commission
(NCUC) and the Public Service Commission of South Carolina (PSCSC).
Natural Gas Transmission provides transportation and storage of natural gas
for customers throughout North America, primarily in the Mid-Atlantic, New
England and southeastern states. It conducts operations primarily through Duke
Energy Gas Transmission Corporation. Interstate natural gas transmission and
storage operations are subject to the FERC's rules and regulations.
Field Services gathers, processes, transports, markets and stores natural
gas and produces, transports, markets and stores natural gas liquids (NGLs). It
conducts operations primarily through Duke Energy Field Services, LLC (DEFS),
which is approximately 30% owned by Phillips Petroleum. Field Services operates
gathering systems in western Canada and 11 contiguous states in the U.S. Those
systems serve major natural gas-producing regions in the Rocky Mountain,
Permian Basin, Mid-Continent, East Texas-Austin Chalk-North Louisiana, and
onshore and offshore Gulf Coast areas.
North American Wholesale Energy (NAWE) develops, operates and manages
merchant generation facilities and engages in commodity sales and services
related to natural gas and electric power. NAWE conducts these operations
primarily through Duke Energy North America, LLC (DENA) and Duke Energy Trading
and Marketing, LLC (DETM). DETM is approximately 40% owned by Exxon Mobil
Corporation. NAWE also includes Duke Energy Merchants Holdings, LLC, which
develops new business lines in the evolving energy commodity markets other than
natural gas and power. NAWE conducts business primarily throughout the U.S. and
Canada.
International Energy develops, operates and manages natural gas
transportation and power generation facilities and engages in energy trading
and marketing of natural gas and electric power. It conducts operations
primarily through Duke Energy International, LLC and its activities target 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., a wholly
owned subsidiary of Fluor Corporation. (See Note 8 to the Consolidated
Financial Statements.) On January 31, 2002, Duke Energy announced the planned
sale of DE&S to Framatome ANP, Inc. and, on March 13, 2002, Duke Energy
announced the planned sale of DukeSolutions to Ameresco, Inc. (See Current
Issues--Subsequent Events.)
29
Duke Ventures is composed of other diverse businesses, operating primarily
through Crescent Resources, LLC (Crescent), DukeNet Communications, LLC
(DukeNet) and Duke Capital Partners, LLC (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 wholly
owned merchant banking company, provides debt and equity capital and financial
advisory services to the energy industry.
Business Strategy. Duke Energy is one of the world's leading integrated
energy companies. The company's business strategy is to develop integrated
energy businesses in targeted regions where Duke Energy'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 Duke Energy's competitive business segments to
capitalize on their extensive capabilities. Domestically, Duke Energy is
investing as opportunities arise in new merchant power plants throughout the
U.S., expanding its natural gas pipeline infrastructure, advancing its leading
position in natural gas gathering and processing and NGL marketing, and
developing its trading and marketing structured origination expertise across
the energy spectrum. Planned expansion for 2002 includes the acquisition of
Westcoast Energy Inc. (Westcoast) for approximately $8 billion, including the
assumption of debt. Westcoast, headquartered in Vancouver, British Columbia, is
a North American energy company with interests in natural gas gathering,
processing, transmission, storage and distribution, as well as power generation
and international energy businesses. (See Current Issues-- Subsequent Events.)
Internationally, Duke Energy is currently focusing on electric and natural gas
opportunities in Latin America, Asia Pacific and Europe.
Franchised Electric continues to increase its customer base, maintain low
costs and deliver high-quality customer service in the Piedmont Carolinas.
Franchised Electric is expected to grow moderately. Expansion will primarily
result from continued growth in the residential and general service sectors,
partially offset by a continuing decline in the textile industry.
Natural Gas Transmission plans to continue 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 significant size and scope in natural gas
gathering and 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. DENA, through its portfolio
management strategy, seeks opportunities to invest in energy assets in U.S.
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 Duke Energy allow it to efficiently deliver natural gas
pipeline, power generation, energy marketing and other services.
30
Other Energy Services' growth opportunities will be primarily related to
D/FD. Other Energy Services plans to grow by providing an expanding customer
base with a variety of engineering, operating, procurement and construction
services in areas related to energy assets.
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.
Duke Energy's business strategy and growth expectations may 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. However, Duke
Energy's growth expectations do not rely on progress in industry restructuring
in North Carolina and South Carolina.
RESULTS OF OPERATIONS
In 2001, earnings available for common stockholders were $1,884 million, or
$2.45 per basic share, compared to $1,757 million, or $2.39 per basic share, in
2000. The increase was due primarily to a 6% increase in earnings before
interest and taxes (EBIT), as described below. Current-year EBIT increases on a
comparative basis were partially offset by the prior year's pre-tax gain of
$407 million (an after-tax gain of $0.34 per basic share) on the sale of Duke
Energy's 20% interest in BellSouth Carolina PCS, and a current-year, one-time
net-of-tax charge of $96 million (or $0.13 per basic share). This one-time
charge was the cumulative effect of a change in accounting principle for the
January 1, 2001 adoption of Statement of Financial Accounting Standards (SFAS)
No. 133, "Accounting for Derivative Instruments and Hedging Activities." (See
Note 1 to the Consolidated Financial Statements.)
Earnings available for common stockholders increased $270 million in 2000,
from 1999 earnings of $1,487 million, or $2.04 per basic share. The increase
was due primarily to a 96% increase in EBIT, as described below, including the
BellSouth Carolina PCS gain. Partially offsetting the increase in EBIT on a
comparative basis was a 1999 after-tax extraordinary gain of $660 million, or
$0.91 per basic share. This gain was from the sale of Panhandle Eastern Pipe
Line Company (PEPL), Trunkline Gas Company (Trunkline) and additional storage
related to those systems, along with Trunkline LNG Company. Higher interest and
minority interest expense in 2000 also partially offset the increase in EBIT.
Earnings per share information provided above has been restated to reflect
the two-for-one common stock split effective January 26, 2001. (See Note 16 to
the Consolidated Financial Statements.)
Operating income for 2001 was $4,100 million, compared to $3,813 million in
2000 and $1,819 million in 1999. EBIT was $4,256 million in 2001, $4,014
million in 2000 and $2,043 million in 1999. Operating income and EBIT are
affected by the same fluctuations for Duke Energy and each of its business
segments as described above. Beginning January 1, 2001, Duke Energy
discontinued allocating corporate governance costs for its business segment
analysis. Prior-year business segment EBIT amounts have been restated to
conform to the current-year presentation of corporate cost allocations. (See
Note 3 to the Consolidated Financial Statements for more information on
business segments.) The following table shows the components of EBIT and a
reconciliation from EBIT to net income.
31
Reconciliation Of Operating Income To Net Income
Years Ended December 31,
------------------------
2001 2000 1999
------ ------ ------
In millions
Operating income.............................................................. $4,100 $3,813 $1,819
Other income and expenses..................................................... 156 201 224
------ ------ ------
EBIT.......................................................................... 4,256 4,014 2,043
Interest expense.............................................................. 785 911 601
Minority interest expense..................................................... 327 307 142
------ ------ ------
Earnings before income taxes.................................................. 3,144 2,796 1,300
Income taxes.................................................................. 1,150 1,020 453
------ ------ ------
Income before extraordinary item and cumulative effect of change in accounting
principle................................................................... 1,994 1,776 847
Extraordinary gain, net of tax................................................ -- -- 660
Cumulative effect of change in accounting principle, net of tax............... (96) -- --
------ ------ ------
Net income.................................................................... $1,898 $1,776 $1,507
====== ====== ======
EBIT is the main performance measure used by management to evaluate segment
performance. As an indicator of Duke Energy's operating performance or
liquidity, EBIT should not be considered an alternative to, or more meaningful
than, net income or cash flow as determined in accordance with generally
accepted accounting principles. Duke Energy's EBIT may not be comparable to a
similarly titled measure of another company. Business segment EBIT is
summarized in the following table, and detailed discussions follow.
EBIT by Business Segment
Years Ended December 31,
-----------------------
2001 2000 1999
------ ------ ------
In millions
Franchised Electric.................... $1,631 $1,820 $ 942
Natural Gas Transmission............... 608 562 656
Field Services......................... 336 311 156
North American Wholesale Energy........ 1,351 434 219
International Energy................... 286 341 44
Other Energy Services.................. (13) (59) (86)
Duke Ventures.......................... 183 568 165
Other Operations....................... (357) (194) (145)
EBIT attributable to minority interests 231 231 92
------ ------ ------
Consolidated EBIT...................... $4,256 $4,014 $2,043
====== ====== ======
Other Operations primarily includes certain unallocated corporate costs. The
amounts discussed below include intercompany transactions that are eliminated
in the Consolidated Financial Statements.
32
Franchised Electric
Years Ended December 31,
-------------------------------
2001 2000 1999
------- ------- -------
In millions, except where noted
Operating revenues........... $ 4,746 $ 4,946 $ 4,700
Operating expenses........... 3,185 3,200 3,880
------- ------- -------
Operating income............. 1,561 1,746 820
Other income, net of expenses 70 74 122
------- ------- -------
EBIT......................... $ 1,631 $ 1,820 $ 942
======= ======= =======
Sales, GWh(a)................ 79,685 84,766 81,548
- --------
(a) Gigawatt-hours
Franchised Electric's EBIT decreased $189 million in 2001 as compared to
2000, due primarily to much milder weather in Franchised Electric's service
territory during the latter part of 2001 and decreased sales to industrial
customers, which were a result of the slowing economy. These decreased sales
were slightly offset by growth in the average number of residential and general
service customers in Franchised Electric's service territory. The 2001 results
also include a $36 million reduction in unbilled revenue receivables, resulting
from a refinement in the estimates used to calculate unbilled kilowatt-hour
sales (see Note 1 to the Consolidated Financial Statements), and $33 million in
mutual insurance distributions that were reclassified from earnings to a
deferred credit account as required by the NCUC, pending final outcome of a
regulatory audit which will likely determine the treatment of those
distributions. (See Current Issues--Regulatory Matters.) The decrease in
operating revenues, due to the decrease in GWh sales, caused an overall
decrease in operating expenses, as variable fuel costs decreased because less
fuel was needed. This decrease was partially offset by increased costs for
nuclear and fossil-fueled plant outages for repairs and maintenance.
In 2000, Franchised Electric's EBIT increased $878 million over 1999, due
primarily to an $800 million expense in 1999 for estimated injuries and damages
claims. (See Note 15 to the Consolidated Financial Statements.) Overall
favorable weather and growth in the average number of customers in Franchised
Electric's service territory resulted in an increase in GWh sales, which also
contributed to the increase in EBIT for 2000. This increase was partially
offset by increased operating costs.
The following table shows the changes in GWh sales and average number of
customers for the past two years.
Increase (decrease) over prior year 2001 2000
----------------------------------- ---- ----
Residential sales................ 1.7% 4.4%
General service sales............ 3.6% 4.7%
Industrial sales................. (9.6)% (0.5)%
Total Franchised Electric sales.. (6.0)% 3.9%
Average number of customers...... 2.0% 2.5%
33
Natural Gas Transmission
Years Ended December 31,
-------------------------------
2001 2000 1999
------ ------ ------
In millions, except where noted
Operating revenues.............. $1,105 $1,131 $1,230
Operating expenses.............. 504 581 586
------ ------ ------
Operating income................ 601 550 644
Other income, net of expenses... 7 12 12
------ ------ ------
EBIT............................ $ 608 $ 562 $ 656
====== ====== ======
Proportional throughput, TBtu(a) 1,710 1,771 1,893
- --------
(a) Trillion British thermal units
In 2001, EBIT for Natural Gas Transmission increased $46 million compared to
2000, primarily from earnings of East Tennessee Natural Gas Company (ETNG) and
Market Hub Partners (MHP) (acquired in March and September 2000, respectively;
see Note 2 to the Consolidated Financial Statements) and earnings from other
market expansion projects. The decrease in operating revenues for 2001, which
was offset by a decrease in operating expenses, resulted from $112 million in
rate reductions, which became effective in December 2000. These reduced rates
reflect lower recovery requirements for operating costs at Texas Eastern
Transmission, LP, which consists primarily of system fuel and FERC Order 636
transition costs.
Future results of Natural Gas Transmission are expected to be positively
impacted by the Westcoast acquisition. (See Current Issues--Subsequent Events.)
EBIT for Natural Gas Transmission decreased $94 million in 2000 compared to
1999, due primarily to $135 million of EBIT in 1999 that did not recur in 2000.
These earnings in 1999 resulted from $73 million of EBIT from the pipelines
sold to CMS Energy Corporation (CMS) in March 1999; a $24 million gain from the
sale of Duke Energy's interest in the Alliance Pipeline project; and benefits
totaling $38 million from the completion of certain environmental cleanup
programs below estimated costs. These items were partially offset by increased
earnings from market expansion projects, joint ventures such as the Maritimes &
Northeast Pipeline, which was placed into service in December 1999, and
earnings from ETNG and MHP.
34
Field Services
Years Ended December 31,
------------------------------
2001 2000 1999
------ ------ ------
In millions, except where noted
Operating revenues....................................... $9,651 $9,060 $3,590
Operating expenses....................................... 9,154 8,620 3,432
------ ------ ------
Operating income......................................... 497 440 158
Other income, net of expenses............................ 1 6 (2)
Minority interest expense................................ 162 135 --
------ ------ ------
EBIT..................................................... $ 336 $ 311 $ 156
====== ====== ======
Natural gas gathered and processed/transported, TBtu/d(a) 8.6 7.6 5.1
NGL production, MBbl/d(b)................................ 397.2 358.5 192.4
Natural gas marketed, TBtu/d............................. 1.6 0.7 0.5
Average natural gas price per MMBtu(c)................... $ 4.27 $ 3.89 $ 2.27
Average NGL price per gallon(d).......................... $ 0.45 $ 0.53 $ 0.34
- --------
(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 $25 million in 2001 from 2000. Operating
revenues increased due primarily to recognizing a full year of the results of
the combination of Field Services' natural gas gathering, processing and
marketing business with Phillips Petroleum's gas gathering, processing and
marketing unit's midstream natural gas business (the Phillips combination) in
March 2000. (See Note 2 to the Consolidated Financial Statements.) This
increase was partially offset by lower average NGL prices that decreased $0.08
per gallon from the prior year. (See Quantitative and Qualitative Disclosures
About Market Risk--Commodity Price Risk for information on NGL price
sensitivity.) Increased operating expenses due primarily to the Phillips
combination were partially offset by savings from cost reduction efforts and
plant consolidations, and by the interaction of Field Services' natural gas and
NGL purchase contracts with lower average NGL prices and higher average natural
gas prices. The 11% increase in NGL production, due primarily to the Phillips
combination, was offset by reduced recoveries at facilities, resulting from
tightened fractionation spreads driven by higher average natural gas prices.
In 2000, Field Services' EBIT increased $155 million compared to 1999. The
increase in EBIT and volume activity was primarily due to the Phillips
combination; the acquisition of the natural gas gathering, processing,
fractionation and NGL pipeline business from Union Pacific Resources in April
1999; and other acquisitions and plant expansions. Improved average NGL prices,
which increased 56% over 1999 prices, also contributed significantly to the
increase in EBIT.
35
North American Wholesale Energy
Years Ended December 31,
-------------------------------
2001 2000 1999
-------- -------- ---------
In millions, except where noted
Operating revenues......................... $ 43,197 $ 33,874 $ 11,801
Operating expenses......................... 41,809 33,370 11,581
-------- -------- --------
Operating income........................... 1,388 504 220
Other income, net of expenses.............. 7 3 60
Minority interest expense.................. 44 73 61
-------- -------- --------
EBIT....................................... $ 1,351 $ 434 $ 219
======== ======== ========
Natural gas marketed, TBtu/d............... 12.4 11.9 10.5
Electricity marketed and traded, GWh....... 335,210 275,258 109,634
Proportional megawatt capacity in operation 6,799 5,134 3,532
Proportional megawatt capacity owned(a).... 15,569 8,984 5,799
- --------
(a) Includes under construction or under contract at period end
Compared to 2000, NAWE's EBIT increased $917 million in 2001. The increase
in EBIT reflects a 32% increase in the proportional megawatt capacity of
generation assets in operation. Increased earnings also resulted from a 4%
increase in the marketing of natural gas volumes and a 22% increase in the
marketing and trading of electricity volumes. Additionally, EBIT increased $63
million over the prior year due to the sale of NAWE's interests in generating
facilities, consistent with its portfolio management strategy, and $110 million
due to a charge in 2000 related to receivables for energy sales in California.
These increases were partially offset by increased operating and development
costs associated with business expansion and a current-year charge of $36
million for non-collateralized accounting exposure to Enron Corporation, which
filed for bankruptcy in 2001. (See Quantitative and Qualitative Disclosures
About Market Risk--Credit Risk.) Changes in the ownership percentage of NAWE's
waste-to-energy plants and decreased earnings at DETM resulted in a $29 million
decrease in minority interest expense compared to the prior year.
In 2001, NAWE experienced strong growth rates by taking advantage of
significant volatility in the marketplace. While management is taking steps to
continue to increase earnings, 2001 results may not be indicative of NAWE's
future earnings trends.
In 2000, EBIT for NAWE increased $215 million from 1999, 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. Operating revenues and expenses
increased as the volumes of natural gas and electricity marketed increased 13%
and 151%, respectively. These increases were partially offset by the $110
million charge related to receivables for energy sales in California, and
increased operating and development costs associated with business expansion.
36
International Energy
Years Ended December 31,
-------------------------------
2001 2000 1999
------ ------ ------
In millions, except where noted
Operating revenues............................................ $2,090 $1,067 $ 357
Operating expenses............................................ 1,817 745 290
------ ------ ------
Operating income.............................................. 273 322 67
Other income, net of expenses................................. 36 42 8
Minority interest expense..................................... 23 23 31
------ ------ ------
EBIT.......................................................... $ 286 $ 341 $ 44
====== ====== ======
Proportional megawatt capacity in operation................... 4,568 4,226 2,974
Proportional megawatt capacity owned(a)....................... 5,386 4,876 2,974
Proportional maximum pipeline capacity in operation, MMcf/d(b) 255 255 83
Proportional maximum pipeline capacity owned (a), MMcf/d...... 363 363 255
- --------
(a) Includes under construction or under contract at period end
(b) Million cubic feet per day
International Energy's EBIT decreased $55 million in 2001 compared to 2000.
The decrease was due primarily to a $54 million gain recognized in 2000 from
the sale of liquefied natural gas ships, and the impact in 2001 of foreign
currency devaluation on the earnings of international operations. However,
these were offset by inflation adjustment clauses in certain contracts and
stronger Latin American operational results.
In 2000, International Energy's EBIT increased $297 million 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 liquefied
natural gas ships.
Other Energy Services
Years Ended December 31,
-----------------------
2001 2000 1999
---- ---- ------
In millions
Operating revenues $565 $695 $ 989
Operating expenses 578 754 1,075
---- ---- ------
EBIT.............. $(13) $(59) $ (86)
==== ==== ======
In 2001, EBIT for Other Energy Services improved $46 million compared to
2000. Current-year results included approximately $36 million of charges at
DE&S and DukeSolutions for goodwill impairment. These charges were offset by
the prior year's loss on a D/FD project of $62 million and a $27 million charge
at DE&S to reflect a more conservative revenue recognition approach on its
projects. D/FD uses the percentage-of-completion method to recognize income.
(See Note 1 to the Consolidated Financial Statements for a discussion of
revenue recognition.) Operating revenues and expenses also decreased compared
to 2000, due to cessation of retail commodity trading at DukeSolutions. On
January 31, 2002, Duke Energy announced the planned sale of DE&S to Framatome
ANP, Inc. and, on March 13, 2002, Duke Energy announced the planned sale of
DukeSolutions to Ameresco, Inc. (See Current Issues--Subsequent Events.)
EBIT for Other Energy Services improved $27 million in 2000 compared to
1999. New business activity and decreased operating expenses at DukeSolutions
and earnings related to new projects at D/FD were
37
responsible for improved EBIT in 2000. The results for 2000 also included the
D/FD project loss and the DE&S charge mentioned above. Partially offsetting
these amounts were 1999 charges of $38 million at DE&S and $35 million at
DukeSolutions, related to expenses for severance and office closings associated
with repositioning the companies.
Duke Ventures
Years Ended December 31,
------------------------
2001 2000 1999
---- ---- ----
In millions
Operating revenues....... $646 $797 $433
Operating expenses....... 461 229 268
---- ---- ----
Operating income......... 185 568 165
Minority interest expense 2 -- --
---- ---- ----
EBIT..................... $183 $568 $165
==== ==== ====
EBIT for Duke Ventures decreased $385 million in 2001 compared to 2000, due
mainly to DukeNet's sale of its 20% interest in BellSouth Carolina PCS to
BellSouth Corporation in 2000, for a pre-tax gain of $407 million. This
decrease was minimally offset by increased earnings at Crescent, related
primarily to increased commercial project sales, and the absence of losses
related to DukeNet's BellSouth Carolina PCS investment. Excluding the gain on
the sale in 2000, operating revenues and expenses increased due to DCP, which
began operations in late 2000.
In 2000, EBIT for Duke Ventures increased $403 million compared to 1999.
This increase, primarily attributable to the DukeNet gain on the sale mentioned
above, was slightly offset by a decrease in commercial project sales and land
sales at Crescent.
Other Operations
EBIT for Other Operations decreased $163 million in 2001 and $49 million in
2000. The decrease for 2001 was due primarily to increased contributions to the
Duke Energy Foundation (an independent, Internal Revenue Code section 501(c)(3)
entity that funds Duke Energy's charitable contributions), mark-to-market
losses on corporately managed energy risk positions used to hedge exposure to
commodity prices, increased unallocated corporate costs and a prior-year
interest refund from a Revenue Agency Ruling. The decrease in 2000 was due
primarily to increased unallocated corporate costs.
Other Impacts on Earnings Available for Common Stockholders
Interest expense decreased $126 million in 2001, due primarily to lower
interest rates. In 2000, interest expense increased $310 million due to higher
average outstanding debt balances, resulting from acquisitions and expansion.
Minority interest expense increased $20 million in 2001 and $165 million in
2000. Minority interest expense includes expense related to regular
distributions on preferred securities of Duke Energy and its subsidiaries. This
expense increased $39 million in 2001 and $14 million in 2000 related to
Catawba River Associates, LLC (Catawba), which was formed by Duke Energy in
September 2000. (See Note 13 to the Consolidated Financial Statements.) In
2000, this expense increased $21 million due to additional issuances of Duke
Energy's trust preferred securities during 1999. (See Note 12 to the
Consolidated Financial Statements.)
Minority interest expense as shown and discussed in the preceding business
segment EBIT discussions includes only minority interest expense related to
EBIT of Duke Energy's joint ventures. It does not include minority interest
expense related to interest and taxes of the joint ventures. Total minority
interest expense
38
related to the joint ventures (including the portion related to interest and
taxes) decreased $19 million in 2001 and increased $130 million in 2000. The
2001 decrease is due to changes in the ownership percentage of NAWE's
waste-to-energy plants and decreased earnings by DETM, NAWE's joint venture
with Exxon Mobil Corporation, offset slightly by increased minority interest
expense for Field Services' joint venture with Phillips Petroleum. The 2000
increase was primarily due to increased minority interest expense at Field
Services and NAWE, partially offset by decreased minority interest expense at
International Energy due to its 1999 and 2000 acquisitions. (See Notes 2 and 8
to the Consolidated Financial Statements for more information on acquisitions
and new joint venture projects.)
Duke Energy's effective tax rate was approximately 37% for 2001, 37% for
2000 and 35% for 1999.
During 2001, Duke Energy recorded a one-time net-of-tax charge of $96
million related to the cumulative effect of a change in accounting principle
for the January 1, 2001 adoption of SFAS No. 133. This charge related to
contracts that either did not meet the definition of a derivative under
previous accounting guidance or do not qualify as hedge positions under new
accounting requirements. (See Notes 1 and 7 to the Consolidated Financial
Statements.)
The sale of PEPL, Trunkline and additional storage related to those systems,
along with Trunkline LNG Company to CMS, closed in March 1999 and resulted in a
$660 million extraordinary gain, after income tax of $404 million. (See Note 1
to the Consolidated Financial Statements.)
CRITICAL ACCOUNTING POLICIES
See Quantitative and Qualitative Disclosures About Market Risk--Risk and
Accounting Policies for a discussion of Mark-to-Market Accounting, Hedge
Accounting and Normal Purchases and Normal Sales, Special Exemption. Also see
Note 1 to the Consolidated Financial Statements for a discussion of significant
accounting policies.
LIQUIDITY AND CAPITAL RESOURCES
As of December 31, 2001, Duke Energy had $290 million in Cash and Cash
Equivalents on the Consolidated Balance Sheets. This compares to $622 million
as of December 31, 2000 and $613 million as of December 31, 1999.
Operating Cash Flows
Net cash provided by operations increased $2,370 million in 2001 and
decreased $459 million in 2000. The 2001 increase is due primarily to price
movements in the energy commodities markets which have a direct impact on Duke
Energy's use and generation of cash from operations. Earnings increase as
natural gas and electricity prices move favorably with respect to contracts
that Duke Energy holds. In addition, counterparties may be required to post
collateral in cash or letters of credit if price moves benefit Duke Energy.
This mechanism gives Duke Energy use of those funds on a short-term basis.
Conversely, negative price impacts reduce earnings and may require Duke Energy
to post collateral with its counterparties. Cash collateral posted by Duke
Energy is included in Other Current Assets and cash collateral collected by
Duke Energy is included in Other Current Liabilities on the Consolidated
Balance Sheets. In 2000, Duke Energy posted more collateral with
counterparties, reducing cash from operations. In addition, Duke Energy made
tax payments in 2000 related to the sale of pipelines in 1999. These accounted
for the reduced operating cash flows for 2000 compared to 1999.
Investing Cash Flows
Cash used in investing activities increased $1,351 million in 2001 and
$1,179 million in 2000. The primary use of cash for investing activities is
capital and investment expenditures, which are detailed by business segment in
the following table.
39
Capital and Investment Expenditures by Business Segment (a)
Years Ended December 31,
------------------------
2001 2000 1999
------ ------ ------
In millions
Franchised Electric............ $1,115 $ 661 $ 759
Natural Gas Transmission....... 748 973 261
Field Services................. 587 376 1,630
North American Wholesale Energy 3,272 1,937 1,028
International Energy........... 442 980 1,779
Other Energy Services.......... 13 28 94
Duke Ventures.................. 773 643 382
Other Operations............... 90 36 3
------ ------ ------
Total consolidated............. $7,040 $5,634 $5,936
====== ====== ======
- --------
(a) Amounts are gross of cash received from acquisitions
Capital and investment expenditures increased $1,406 million in 2001
compared to 2000. The increase reflects additional expansion and development
expenditures (especially related to NAWE's generating facilities),
refurbishment and upgrades to existing assets (primarily related to Franchised
Electric) and minor acquisitions of businesses and assets. Also in 2001,
Natural Gas Transmission invested in a 50% interest in Gulfstream Natural Gas
System, LLC, a joint interstate natural gas pipeline development that will
extend from Mississippi and Alabama across the Gulf of Mexico to Florida. These
increases were partially offset by Natural Gas Transmission's acquisition of
ETNG for approximately $390 million and of MHP for approximately $250 million
in cash, and International Energy's approximately $280 million tender offer for
Companhia de Geracao de Energia Eletrica Paranapanema (Paranapanema) in 2000.
(See Note 2 to the Consolidated Financial Statements for more information about
significant acquisitions.)
Capital and investment expenditures decreased by $302 million in 2000
compared to 1999. In 2000, Natural Gas Transmission's capital expenditures
increased primarily for business expansion related to the acquisitions of ETNG
and MHP. Also in 2000, NAWE began construction of a number of power generation
plants in the U.S. and continued capital expenditures on ongoing projects.
International Energy's business expansion included completion of the
Paranapanema tender offer and 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 sale of Duke Energy's 20% interest in BellSouth Carolina PCS
in 2000 and $1,900 million from the sale of pipelines to CMS in 1999. (See Note
1 to the Consolidated Financial Statements for more information on the sale of
the pipelines.)
Projected 2002 capital and investment expenditures for Duke Energy are
approximately $8.0 billion, of which over 80% is planned for competitive
business segments not subject to state rate regulation. This projection
includes approximately $6.5 billion for acquisitions and other expansion
opportunities and $1.5 billion for existing plant upgrades. The above amounts
do not include expenditures for the Westcoast acquisition. (See Current
Issues--Subsequent Events.)
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.
Duke Energy's growth initiatives, along with dividends, debt repayments and
operating requirements are expected to be funded by cash from operations, debt
and capital market financings, project financings, common
40
stock issuances through its InvestorDirect Choice Plan and employee benefit
plans, and proceeds from the sale of assets. These financing opportunities are
dependent upon the opportunities presented and favorable market conditions.
Additionally, internal cash generation should fund approximately half of the
capital needs. Management believes Duke Energy has adequate financial resources
to meet its future needs.
Financing Cash Flows
Duke Energy's consolidated capital structure at December 31, 2001, including
short-term debt, was 46% debt, 41% common equity, 7% minority interests, 5%
trust preferred securities and 1% preferred stock. Fixed charges coverage,
calculated using Securities and Exchange Commission (SEC) guidelines, was 3.8
times for 2001, 3.6 times for 2000 and 2.7 times for 1999.
During 2001, DEFS issued $250 million of 6.875% senior unsecured notes due
in 2011 and $300 million of 5.75% senior unsecured notes due in 2006. The
proceeds were used to repay DEFS' short-term debt. Also during 2001, Duke
Capital Corporation (a wholly owned subsidiary of Duke Energy), increased its
note payable to D/FD by $427 million, to $568 million as of December 31, 2001.
The weighted-average interest rate on this note for 2001 was 4.05%. (See Notes
8 and 10 to the Consolidated Financial Statements.)
In March 2001, Duke Energy completed an offering of 25 million shares of
common stock, priced at $38.98 per share, before underwriting discount and
other offering expenses. In addition, Duke Energy completed an offering of
approximately 31 million mandatory convertible securities (Equity Units), at
$25 per unit, before underwriting discount and other offering expenses. The
Equity Units consist of senior notes of Duke Capital Corporation (which are
included in Long-term Debt on the Consolidated Balance Sheets; see Note 10 to
the Consolidated Financial Statements), and purchase contracts obligating the
investors to purchase shares of Duke Energy's common stock in 2004. The number
of shares to be issued in 2004 will be based on the price of the common stock
at conversion. Also in March 2001, the underwriters exercised options granted
to them to purchase an additional 3.75 million shares of common stock and four
million Equity Units at the original issue prices, less underwriting discounts,
to cover over-allotments made during the offerings. Total net proceeds from the
offerings, approximately $1.9 billion, were used to repay short-term debt and
for other corporate purposes.
In November 2001, Duke Energy completed an offering of 30 million Equity
Units, at $25 per unit, before underwriting discount and other offering
expenses. The Equity Units consist of senior notes of Duke Capital Corporation
(which are included in Long-term Debt on the Consolidated Balance Sheets; see
Note 10 to the Consolidated Financial Statements), and purchase contracts
obligating the investors to purchase shares of Duke Energy's common stock in
2004. The number of shares to be issued in 2004 will be based on the price of
the common stock at conversion. The net proceeds from the offering of
approximately $731 million provided a component of the permanent financing for
the Westcoast acquisition. Prior to the close of the Westcoast acquisition, the
net proceeds of the offering were used to manage working capital needs.
During 2001, Duke Energy redeemed eight issues of its first and refunding
mortgage bonds to take advantage of the general decline in interest rates. The
total face value of the redeemed bonds was $511 million, with interest rates
ranging from 5.875% to 8.3%. To fund these redemptions, Duke Energy issued
commercial paper and used cash proceeds generated from short-term investments.
In January 2002, Duke Energy issued $750 million of 6.25% senior unsecured
bonds due in 2012 and $250 million of floating rate (based on the three-month
London Interbank Offered Rate (LIBOR) plus 0.35%) senior unsecured bonds due in
2005. The proceeds from these issuances were used to manage working capital
needs.
In February 2002, Duke Capital Corporation issued $500 million of 6.25%
senior unsecured bonds due in 2013 and $250 million of 6.75% senior unsecured
bonds due in 2032. In addition, Duke Capital Corporation, through a private
placement transaction, issued $500 million of floating rate (based on the
one-month LIBOR
41
plus 0.65%) senior unsecured bonds due in 2003. The proceeds from these
issuances were used to manage working capital needs and to fund a portion of
the cash consideration for the Westcoast acquisition.
Under its commercial paper, medium-term notes and extendible commercial
notes (ECNs) programs, Duke Energy had the ability to borrow up to $5,358
million at December 31, 2001 compared with $5,720 million at December 31, 2000.
These programs do not have termination dates. The following table summarizes
the commercial paper, medium-term notes and ECNs as of December 31, 2001.
Duke Energy
Duke Duke Capital Field Duke Energy
Energy Corporation (a) Services International Total
------ --------------- ----------- ------------- ------
In millions
Commercial paper $1,250 $1,550 $675 $383(b) $3,858
ECNs............ 500 1,000 -- -- 1,500
------ ------ ---- ---- ------
Total........... $1,750 $2,550 $675 $383 $5,358
====== ====== ==== ==== ======
- --------
(a) Duke Capital Corporation provides financing and credit enhancement services
for its subsidiaries.
(b) Includes ability to issue medium-term notes
The total amount of Duke Energy's bank credit facilities was approximately
$4,606 million as of December 31, 2001 compared with $4,205 million as of
December 31, 2000. Some of the credit facilities support the issuance of
commercial paper; therefore, the issuance of commercial paper reduces the
amount available under these credit facilities. As of December 31, 2001,
approximately $2,970 million was outstanding in the form of commercial paper,
medium-term notes and ECNs, and approximately $38 million of borrowings were
outstanding under the bank credit facilities. The credit facilities expire from
2002 to 2004 and are not subject to minimum cash requirements; however,
borrowings and issuances of letters of credit under approximately $1,100
million of these facilities are subject to and dependent on the senior
unsecured debt ratings of Duke Capital Corporation (currently rated A3/A/A).
Ratings of Baa2, BBB or the equivalent by at least two of Moody's Investors
Service, Standard & Poor's and Fitch, Inc. must be maintained to obtain
additional borrowings and issuances of letters of credit. Any outstanding
borrowings would not become due and payable. (See Note 10 to the Consolidated
Financial Statements for more information on the bank credit facilities.)
As of December 31, 2001, Duke Energy and its subsidiaries had effective SEC
shelf registrations for up to $3,500 million in gross proceeds from debt and
other securities. Subsequent to December 31, 2001, these SEC shelf
registrations have been reduced by $1,750 million for the senior and unsecured
bonds issued in January and February 2002, excluding the private placement
transaction. Under the SEC shelf registrations, such securities may be issued
as senior notes, first and refunding mortgage bonds, subordinated notes, trust
preferred securities, Duke Energy common stock, stock purchase contracts or
stock purchase units.
In 2000, Duke Energy issued $250 million 7.125% senior unsecured bonds due
in 2012 with a put option that gives investors the choice to put the bond to
Duke Energy at par value in September 2002 or extend the maturity until 2012.
If extended, the bonds would be recouponed at 5.7% plus the Duke Energy 10-year
credit spread on the extension date. Also in 2000, Duke Capital Corporation
issued $150 million senior unsecured bonds due in 2003 that become due and
payable if Duke Capital Corporation's debt ratings fall below BBB.
In 2000, Catawba, a fully consolidated financing entity managed by a
subsidiary of Duke Energy, issued $1,025 million of preferred member interests
to a third-party investor. Catawba subsequently advanced the proceeds from the
sale to DE Power Generation, LLC, a wholly owned subsidiary of Duke Energy,
which indirectly owns or leases six merchant power generation facilities
located in California, Maine and Indiana. Catawba is a limited liability
company with a separate existence and identity from its preferred members, and
the assets of Catawba are separate and legally distinct from Duke Energy. The
preferred member interests receive
42
quarterly a preferred return equal to an adjusted floating reference rate
(approximately 5.20% for the full year ended December 31, 2001). (See Note 13
to the Consolidated Financial Statements for more information.)
To maintain financial flexibility and reduce the amount of financing needed
for growth opportunities, Duke Energy's Board of Directors adopted a dividend
policy in 2000 that maintains dividends at the current quarterly rate of $0.275
per share, subject to declaration by the Board of Directors. This policy is
consistent with Duke Energy's growth profile and strikes a balance between
providing a competitive dividend yield and ensuring that cash is available to
fund Duke Energy's growth. Duke Energy has paid quarterly cash dividends for 75
consecutive years. Dividends on common and preferred stocks in 2002 are
expected to be paid on March 15, June 17, September 16 and December 16, subject
to the discretion of the Board of Directors.
Duke Energy's InvestorDirect Choice Plan, a stock purchase and dividend
reinvestment plan, allows investors to reinvest dividends in new issuances of
common stock and to purchase common stock directly from Duke Energy. Issuances
under this plan were not material in 2001, 2000 or 1999.
Duke Energy used authorized but unissued shares of its common stock to meet
2001 and 2000 employee benefit plan contribution requirements. This practice is
expected to continue in 2002.
Contractual Obligations and Commercial Commitments
As part of its normal business, Duke Energy is a party to various financial
guarantees, performance guarantees and other contractual commitments to extend
guarantees of credit and other assistance to various subsidiaries, investees
and other third parties. These arrangements are largely entered into by Duke
Capital Corporation. To varying degrees, these guarantees involve elements of
performance and credit risk, which are not included on the Consolidated Balance
Sheets. The possibility of Duke Energy having to honor its contingencies is
largely dependent upon future operations of various subsidiaries, investees and
other third parties, or the occurrence of certain future events. Duke Energy
would record a reserve if events occurred that required that one be
established. (See Note 15 to the Consolidated Financial Statements for more
information on financial guarantees.)
In addition, Duke Energy enters into various fixed-price, non-cancelable
commitments to purchase or sell power (tolling arrangements or power purchase
contracts), take-or-pay arrangements, transportation or throughput agreements
and other contracts that may or may not be recognized on the Consolidated
Balance Sheets. Some of these arrangements may be recognized at market value on
the Consolidated Balance Sheets as trading contracts or qualifying hedge
positions included in Unrealized Gains or Losses on Mark-to-Market and Hedging
Transactions.
43
The following table summarizes Duke Energy's contractual cash obligations
for each of the years presented.
Contractual Cash Obligations
Payments Due
---------------------------------------------
2002 2003 2004 2005 2006 Thereafter
------ ------ ------ ------ ------ ----------
In millions
Long-term debt (Note 10).............. $ 261 $ 576 $ 883 $1,016 $2,101 $7,745
Preferred securities (Notes 12 and 14) 13 2 2 2 2 1,424
Operating leases (Note 15)............ 87 70 57 43 34 75
Firm capacity payments (a)............ 231 177 142 123 109 563
Purchase commitments (b).............. 629 262 527 586 268 --
Other(c).............................. 1,635 211 -- -- -- --
------ ------ ------ ------ ------ ------
Total contractual cash obligations.... $2,856 $1,298 $1,611 $1,770 $2,514 $9,807
====== ====== ====== ====== ====== ======
- --------
(a) Includes firm capacity payments that provide Duke Energy with uninterrupted
firm access to natural gas transportation and storage, electricity
transmission capacity, and the option to convert natural gas to electricity
at third-party owned facilities (tolling arrangements) in some natural gas
and power locations throughout North America. Based on current estimates,
the market value of underlying transportation, storage and electricity
available under such arrangements exceeds the discounted fair value of the
capacity payments.
(b) Amounts include Duke Energy's obligations as of December 31, 2001 to
purchase gas-fired turbines, steam turbines and heat recovery steam
generators (HRSG). Commitments under the turbine and HRSG purchase
agreements are payable consistent with the delivery schedule. The purchase
agreements include milestone requirements by the manufacturer and provide
Duke Energy with the ability to cancel each discrete purchase order
commitment in exchange for a termination fee, which escalates over time.
The amounts included above assume that all turbines and HRSGs will be
purchased. However, if Duke Energy had terminated the turbine and HRSG
purchase orders at December 31, 2001 as allowed by the agreements, the
termination fee would have been $569 million. Approximately 50% of this
termination fee relates to turbines that Duke Energy has allocated to power
generation facilities currently under construction.
(c) Amounts include engineering, procurement and construction costs for power
generation facilities in North America. Such amounts are payable to D/FD, a
related party in which Duke Energry has a 50% equity interest, and excluded
from the Consolidated Balance Sheets since Duke Energy accounts for D/FD
using the equity method of accounting.
Duke Energy also has substantial commitments as part of its growth strategy
and ongoing construction programs. (See Investing Cash Flows for 2002's
projected expenditures.)
The following table summarizes the commercial commitments in effect as of
December 31, 2001 by expiration date.
Commercial Commitments
Total Amount of Commitment Expiring Each Period
Amounts -----------------------------------------
(see Note 15) Committed 2002 2003 2004 2005 2006 Thereafter
- ------------- --------- ----- ---- ---- ----- ---- ----------
In millions
Guaranteed debt of affiliates $200 $ -- $ -- $ -- $ -- $ -- $200
Surety and bid bonds (a)..... 198 165 32 1 -- -- --
Letters of credit............ 181 151 10 -- 20 -- --
- --------
(a) Surety bonds are contractual agreements where Duke Energy obligates itself
to a second party to answer for the default of a third party, such as a
contractor. Bid bonds are issued to the owners of projects and are subject
to full or partial forfeiture for failure to perform obligations arising
from a successful bid. All public and some private jobs require a bid bond
or cashiers check to be submitted with a bid.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Risk and Accounting Policies
Duke Energy is exposed to market risks associated with commodity prices,
credit exposure, interest rates, equity prices and foreign currency exchange
rates. Management has established comprehensive risk management
44
policies 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 composed of senior executives who receive periodic updates from
the Chief Risk Officer (CRO) on market risk positions, corporate exposures,
credit exposures and overall risk management activities. The CRO is responsible
for the overall management of credit risk and commodity price risk, including
monitoring exposure limits.
Mark-to-Market Accounting (MTM accounting). Under the MTM accounting method,
an asset or liability is recognized at fair value and the change in the fair
value of that asset or liability is recognized in earnings during the current
period. This accounting method has been used by other industries for many
years, and in 1998 the Financial Accounting Standards Board's (FASB) Emerging
Issues Task Force (EITF) issued guidance that required MTM accounting for
energy trading contracts. MTM accounting reports contracts at their "fair
value," (the value a willing third party would pay for the particular contract
at the time a valuation is made).
When available, quoted market prices are used to record a contract's fair
value. However, market values for energy trading contracts may not be readily
determinable because the duration of the contracts exceeds the liquid activity
in a particular market. If no active trading market exists for a commodity or
for a contract's duration, holders of these contracts must calculate fair value
using pricing models or matrix pricing based on contracts with similar terms
and risks. This is validated by an internal group independent of Duke Energy's
trading area. Holders of thinly traded securities or investments (mutual funds,
for example) use similar techniques to price such holdings. Correlation and
volatility are two significant factors used in the computation of fair values.
Duke Energy validates its internally developed fair values by comparing
locations/durations that are highly correlated, using forecasted market
intelligence and mathematical extrapolation techniques. While Duke Energy uses
industry best practices to develop its pricing models, changes in Duke Energy's
pricing methodologies or the underlying assumptions could result in
significantly different fair values, income recognition and realization in
future periods.
Hedge Accounting. Hedging typically refers to the mechanism that Duke Energy
uses to mitigate the impact of volatility associated with price fluctuations.
Hedge accounting treatment is used when Duke Energy contracts to buy or sell a
commodity such as natural gas or electricity at a fixed price for future
delivery corresponding with anticipated physical sales or purchases of natural
gas and power (cash flow hedge). In addition, hedge accounting treatment is
used when Duke Energy holds firm commitments or asset positions, and enters
into transactions that "hedge" the risk that the price of natural gas or power
may change between the contract's inception and the physical delivery date of
the commodity (fair value hedge). While the majority of Duke Energy's hedging
transactions are used to protect the value of future cash flows related to its
physical assets, to the extent the hedge is effective, Duke Energy recognizes
in earnings the value of the contract when the commodity is purchased or sold,
or the hedged transaction occurs or settles.
Normal Purchases and Normal Sales, Special Exemption. A unique
characteristic of the electric power industry is that electricity cannot be
readily stored in significant quantities. As a result, some of the contracts to
buy and sell electricity allow the buyer some flexibility in determining when
to take electricity and in what quantity to match fluctuating demand. These
contracts would normally meet the definition of a derivative requiring MTM or
hedge accounting. However, because electricity cannot be readily stored in
significant quantities and an entity engaged in selling electricity is
obligated to maintain sufficient capacity to meet the electricity needs of its
customer base, an option contract for the purchase of electricity qualifies for
the normal purchases and sales exemption described in Paragraph 10 of SFAS No.
133 and Derivative Implementation Group (DIG) Issue No. C15, "Scope Exceptions:
Normal Purchases and Normal Sales Exception for Option-Type Contracts and
Forward Contracts in Electricity." Therefore, contracts that Duke Energy holds
for the sale of power in future periods that meet the criteria in DIG Issue No.
C15 have been designated as "normal purchase, normal sales" contracts, and are
exempted from recognition in the Consolidated Financial Statements until power
is delivered. Duke Energy tracks these contracts separately in its hedge
portfolio, but no value for these contracts is included in the Consolidated
Financial Statements until power is actually delivered.
45
Duke Energy's wholesale energy portfolio in North America includes the
merchant generation facilities and trading contracts held for power, natural
gas, crude oil and petroleum products. Of the total estimated value of this
portfolio, approximately 80% is attributed to the anticipated value of merchant
generation facility capacity owned or controlled by Duke Energy. This portion
of the value of the merchant generation portfolio is anticipated to be realized
in future periods as the generation facilities are dispatched. A portion of
this future value is secured by hedge contracts. Of the unhedged capacity,
dispatch performance, and in some cases price, has been further secured through
contracts designated as normal purchases and normal sales. Only the contracts
designated and effective as qualifying hedges are reflected on Duke Energy's
Consolidated Balance Sheets at fair value. Changes in the fair value of hedging
contracts do not affect current-period earnings. Normal purchase and normal
sales contracts are not subject to accounting recognition until contract
performance occurs. The remaining percentage of the total estimated value of
the merchant generation portfolio is attributed to the current value of trading
contracts. These contracts are subject to MTM accounting and changes in the
contract fair value are recorded as part of current-period earnings. The table
below represents the value by year of Duke Energy's North American merchant
generation portfolio. It does not include the value of trading positions, or
hedges of other commodity risks or exposures.
North American Merchant Generation Portfolio Value as of December 31, 2001
Maturity in 2005 and
Maturity in 2002 Maturity in 2003 Maturity in 2004 Thereafter (a) Total Portfolio Value
- ---------------- ------------------------- ------------------------- ------------------------- -------------------------
In millions
$814 $819 $835 $3,930 $6,398
- --------
(a) For purposes of calculating total portfolio value, model valuations were
calculated through 2010.
As of December 31, 2001, the portion hedged of NAWE's expected output of its
merchant generation portfolio was 91%, 62% and 62% for 2002, 2003 and 2004,
respectively, through derivative contracts such as forward natural gas
purchases and forward power sales.
Commodity Price Risk
Duke Energy, 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. Duke Energy 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 for trading purposes and for activity
other than trading activity (primarily hedge strategies). (See Notes 1 and 7 to
the Consolidated Financial Statements.)
Trading. The risk in the trading portfolio is measured and monitored on a
daily basis utilizing a Value-at-Risk model to determine the potential one-day
favorable or unfavorable Daily Earnings at Risk (DER) as described below. DER
is monitored daily in comparison to established thresholds. Other measures are
also used to limit and monitor risk in the trading portfolio (which includes
all trading contracts not designated as hedge positions) on monthly and annual
bases. These measures include limits on the nominal size of positions and
periodic loss limits.
DER computations are based on historical simulation, which uses price
movements over a specified period (generally ranging from seven to 14 days) to
simulate forward price curves in the energy markets to estimate the potential
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. DER computations utilize several key assumptions, including a 95%
confidence level for the resultant price
46
movement and the holding period specified for the calculation. Duke Energy's
DER amounts for instruments held for trading purposes are shown in the
following table.
Daily Earnings at Risk
Estimated Average One-Day Estimated Average High One-Day Low One-Day
Impact on EBIT for 2001 One-Day Impact on EBIT Impact on EBIT for Impact on EBIT for
(a) for 2000 2001 (a) 2001
------------------------- ------------------------- ------------------------- -------------------------
In millions
Calculated DER........... $21 $18 $86 $7
- --------
(a) Amounts include the impact of one origination contract that was initiated
and hedged during the current year. Duke Energy's Risk Management Committee
approved increased DER limits for this specific contract. Excluding this
contract, average and one-day high 2001 DER amounts would have been $16
million and $43 million, respectively.
DER is an estimate based on historical price volatility. Actual volatility
can exceed assumed results. DER also assumes a normal distribution of price
changes; thus, if the actual distribution is not normal, the DER may understate
or overstate actual results. DER is used to estimate the risk of the entire
portfolio, and for locations that do not have daily trading activity, it may
not accurately estimate risk due to limited price information. Stress tests are
employed in addition to DER to measure risk where market data information is
limited. In the current DER methodology, options are modeled in a manner
equivalent to forward contracts which may understate the risk.
Duke Energy's exposure to commodity price risk is influenced by a number of
factors, including contract size, length, market liquidity, location and unique
or specific contract terms. The following table illustrates the movements in
the fair value of Duke Energy's trading instruments during 2001.
Changes in Fair Value of Trading Contracts
In millions
- - -----------
Fair value of contracts outstanding at the beginning of the year............. $ 605
Contracts realized or otherwise settled during the year...................... (746)
Fair value of contracts entered into during the year......................... 622
Changes in fair value amounts attributable to changes in valuation techniques (6)
Other changes in fair values................................................. 749
------
Fair value of contracts before SFAS No. 133 transition adjustment............ 1,224
SFAS No. 133 transition adjustment........................................... (155)
------
Fair value of contracts outstanding at the end of the year................... $1,069
======
For the year ended December 31, 2001, the unrealized net margin recognized
in operating income was $619 million as compared to $139 million for 2000 and
$41 million for 1999. The fair value of these contracts is expected to be
realized in future periods, as detailed in the following table. The amount of
cash ultimately realized for these contracts will differ from the amounts shown
in the following table due to factors such as market volatility, counterparty
default and other unforeseen events that could impact the amount and/or
realization of these values. At December 31, 2001, Duke Energy held cash or
letters of credit of $1,071 million to secure such future performance, and had
deposited with counterparties $178 million of such collateral to secure its
obligations to provide such future services. Collateral amounts held or posted
vary depending on the value of the underlying contracts and cover trading,
normal purchases and normal sales, and hedging contracts outstanding. Duke
Energy may be required to return held collateral and post additional collateral
should price movements adversely impact the value of open contracts or
positions.
47
When available, Duke Energy uses observable market prices for valuing its
trading instruments. When quoted market prices are not available, management
uses established guidelines for the valuation of these contracts. Management
may use a variety of reasonable methods to assist in determining the valuation
of a trading instrument, including analogy to reliable quotations of similar
trading instruments, pricing models, matrix pricing and other formula-based
pricing methods. These methodologies incorporate factors for which published
market data may be available. All valuation methods employed by Duke Energy are
approved by an independent internal corporate risk management organization.
The following table shows the fair value of Duke Energy's trading portfolio
as of December 31, 2001.
Fair Value of Trading Contracts as of December 31, 2001
-------------------------------------------------------
Maturity
in 2005 Total
Maturity Maturity Maturity and Fair
Sources of Fair Value in 2002 in 2003 in 2004 Thereafter Value
- --------------------- -------- -------- -------- ---------- ------
In millions
Prices supported by quoted market prices and other external
sources.................................................. $ 457 $153 $ 9 $ 26 $ 645
Prices based on models and other Valuation methods......... (104) 11 128 389 424
----- ---- ---- ---- ------
Total...................................................... $ 353 $164 $137 $415 $1,069
===== ==== ==== ==== ======
The "prices supported by quoted market prices and other external sources"
category includes Duke Energy's New York Mercantile Exchange (NYMEX) futures
positions in natural gas and crude oil. The NYMEX has currently quoted prices
for the next 32 months. In addition, this category includes Duke Energy's
forward positions and options in natural gas and power and natural gas basis
swaps at points for which over-the-counter (OTC) broker quotes are available.
On average, OTC quotes for natural gas and power forwards and swaps extend 22
and 32 months into the future, respectively. OTC quotes for natural gas and
power options extend 12 months into the future, on average. Duke Energy values
these positions against internally developed forward market price curves that
are constantly validated and recalibrated against OTC broker quotes. This
category also includes "strip" transactions whose prices are obtained from
external sources and then modeled to daily or monthly prices as appropriate.
The "prices based on models and other valuation methods" category includes
(i) the value of options not quoted by an exchange or OTC broker, (ii) the
value of transactions for which an internally developed price curve was
constructed as a result of the long dated nature of the transaction or the
illiquidity of the market point, and (iii) the value of structured
transactions. It is important to understand that in certain instances
structured transactions can be decomposed and modeled by Duke Energy as simple
forwards and options based on prices actively quoted. Although the valuation of
the simple structures might not be different from the valuation of contracts in
other categories, the effective model price for any given period is a
combination of prices from two or more different instruments and therefore have
been included in this category due to the complex nature of these transactions.
The value of Duke Energy's trading portfolio valuation adjustments for
liquidity, credit and cost of service is reflected in the above amounts.
Hedging Strategies. Some Duke Energy subsidiaries are exposed to market
fluctuations in the prices of energy commodities related to their power
generating and natural gas gathering, processing and marketing activities. Duke
Energy closely monitors the risks associated with these commodity price changes
on its future operations and, where appropriate, uses various commodity
instruments such as electricity, natural gas, crude oil and NGL contracts to
hedge the value of its assets and operations from such price risks. In
accordance with SFAS No. 133, Duke Energy's primary use of energy commodity
derivatives is to hedge the output and
48
production of assets it physically owns. Contract terms are up to 13 years;
however, since these contracts are designated and qualify as effective hedge
positions of future cash flows, or fair values of assets owned by Duke Energy,
to the extent that the hedge relationships are effective, their market value
change impacts are not recognized in current earnings. The unrealized gains or
losses on these contracts are deferred in Other Comprehensive Income (OCI) or
included in Other Current or Noncurrent Assets or Liabilities on the
Consolidated Balance Sheets, in accordance with SFAS No. 133. Amounts deferred
in OCI are realized in earnings concurrently with the transaction being hedged.
(See Notes 1 and 7 to the Consolidated Financial Statements.) However, in
instances where the hedging contract no longer qualifies for hedge accounting,
amounts included in OCI through the date of de-designation remain in OCI until
the underlying transaction actually occurs. The derivative contract (if
continued as an open position) will be marked to market currently through
earnings. Several factors influence the effectiveness of a hedge contract,
including counterparty credit risk.
The following table shows when gains and losses deferred on the Consolidated
Balance Sheets for derivative instruments qualifying as effective hedges of
firm commitments or anticipated future transactions will be recognized into
earnings. Contracts with terms extending several years are generally valued
using models and assumptions developed internally or by industry standards.
However, as mentioned previously, the gains and losses for these contracts are
not recognized in earnings until settlement at their then market price.
Therefore, assumptions and valuation techniques for these contracts have no
impact on reported earnings prior to settlement.
The fair value of Duke Energy's qualifying hedge positions at a point in
time is not necessarily indicative of the value realized when such contracts
settle.
Fair Value of Hedge Position Contracts as of December 31, 2001
Maturity in 2005 and
Maturity in 2002 Maturity in 2003 Maturity in 2004 Thereafter Total Contract Value
- ---------------- ------------------------- ------------------------- ------------------------- -------------------------
In millions
$454 $156 $71 $(38) $643
In addition to the hedge contracts described above and recorded on the
Consolidated Balance Sheets, Duke Energy enters into other contracts that
qualify for the normal purchases and sales exemption described in Paragraph 10
of SFAS No. 133 and DIG Issue No. C15. These contracts, generally forward
agreements to sell power, bear the same counterparty credit risk as the hedge
contracts described above. Under the same risk reduction guidelines used for
other contracts, normal purchases and sales contracts are also subject to
collateral requirements. Income recognition and realization related to these
contracts coincide with the physical delivery of power.
Based on a sensitivity analysis as of December 31, 2001, it was estimated
that a difference of one cent per gallon in the average price of NGLs in 2002
would have a corresponding effect on EBIT of approximately $6 million, after
considering the effect of Duke Energy's commodity hedge positions.
Comparatively, the same sensitivity analysis as of December 31, 2000 estimated
that EBIT would have changed by approximately $8 million in 2001. Based on the
sensitivity analyses associated with other commodities' price changes, net of
Duke Energy's commodity hedge positions, the effect on EBIT was not material as
of December 31, 2001 or 2000. Duke Energy's qualifying hedge positions protect
it from immediate earnings impact for adverse price movements. The resulting
gains and losses are deferred on the Consolidated Balance Sheets until cash
settlement occurs, provided that the hedge positions remain effective.
These hypothetical adverse impacts do not consider the likely positive
impact that price movements would have on Duke Energy's physical purchases and
sales of natural gas and electricity which these contracts hedge. The hedge
contracts are intended to mitigate the impact that price changes have on Duke
Energy's physical positions. Therefore, although the fair value of these
positions may decline with adverse price changes, the impact on results would
be minimal as Duke Energy's physical positions are inversely affected by such
changes.
49
Credit Risk
Duke Energy's principal customers for power and natural gas marketing
services are industrial end-users and utilities located throughout the U.S.,
Canada, Asia Pacific, Europe and Latin America. Duke Energy 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 Duke Energy's overall credit risk in that certain
customers may be similarly affected by changes in economic, regulatory or other
factors. Where exposed to credit risk, Duke Energy analyzes the counterparties'
financial condition prior to entering into an agreement, establishes credit
limits and monitors the appropriateness of those limits on an ongoing basis.
Duke Energy frequently uses master collateral agreements to mitigate credit
exposure. The collateral agreement provides for a counterparty to post cash or
letters of credit for exposure in excess of the established threshold. The
threshold amount represents an open credit limit, determined in accordance with
the corporate credit policy. The collateral agreement also provides that the
inability to post collateral is sufficient cause to terminate a contract and
liquidate all positions.
The change in market value of NYMEX-traded futures and options contracts
requires daily cash settlement in margin accounts with brokers. Financial
derivatives are generally cash settled periodically throughout the contract
term. However, these transactions are also generally subject to margin
agreements with many of Duke Energy's counterparties.
As of December 31, 2001, Duke Energy had a pre-tax bad debt provision of $90
million related to receivables for energy sales in California. (See Current
Issues--California Issues.) Following the bankruptcy of Enron Corporation, Duke
Energy terminated substantially all contracts with Enron Corporation and its
affiliated companies (collectively, Enron). As a result, Duke Energy recorded,
as a charge, a non-collateralized accounting exposure of $43 million. The $43
million non-collateralized accounting exposure is comprised of charges of $36
million at NAWE, $3 million at International Energy, $3 million at Field
Services and $1 million at Natural Gas Transmission. These amounts are stated
on a pre-tax basis as charges against the reporting segment's earnings.
The transactions between Enron and Duke Energy consisted of the following:
. NAWE--forward contracts, swaps, options and physical contracts used to
trade natural gas, power, crude oil, liquefied petroleum gas and coal
. International Energy--forward contracts and options used to trade and
hedge natural gas, power and oil
. Field Services--physical purchase/sale contracts for natural gas and NGLs;
forward contracts, swaps and options used to trade natural gas and NGLs;
transportation and storage
. Natural Gas Transmission--forward financial sales of NGLs
The $43 million charge was a direct reduction to earnings before income
taxes and was a result of charging the full amount of unsettled mark-to-market
earnings previously recognized, and all derivative assets and accounts
receivable that became impaired due to Enron's financial deteriation. All
assets written off or reserved for were net of the margin (cash collateral)
posted by Enron of $330 million and applied by Duke Energy in connection with
transactions between the companies.
Duke Energy's determination of its bankruptcy claims against Enron is still
under review, and its claims made in the bankruptcy case are likely to exceed
$43 million. Any bankruptcy claims that exceed this amount would primarily
relate to termination and settlement rights under contracts and transactions
with Enron that would have been recognized in future periods, and not in the
historical periods covered by the financial statements to which the $43 million
charge relates.
50
Substantially all contracts with Enron were completed or terminated prior to
December 31, 2001. Duke Energy has continuing contractual relationships with
certain Enron affiliates, which are not in bankruptcy. In Brazil, a power
purchase agreement between a Duke Energy affiliate, Paranapanema, and Elektro
Eletricidade e Servicos S/A (Elektro), a distribution company 40% owned by
Enron, will expire December 31, 2005. The contract was executed by Duke
Energy's predecessor in interest in Paranapanema, and obligates Paranapanema to
provide energy to Elektro on an irrevocable basis for the contract period. In
addition, a purchase/sale agreement expiring September 1, 2005 between a Duke
Energy affiliate and Citrus Trading Corporation (Citrus), a 50/50 joint venture
between Enron and El Paso Corporation, continues to be in effect. The contract
requires the Duke Energy affiliate to provide liquefied natural gas to Citrus.
Citrus has provided a letter of credit in favor of Duke Energy to cover its
exposure.
Interest Rate Risk
Duke Energy is exposed to risk resulting from changes in interest rates as a
result of its issuance of variable-rate debt, fixed-to-floating interest rate
swaps, commercial paper and auction market preferred stock. Duke Energy 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. Duke Energy also
enters into financial derivative instruments, including, but not limited to,
interest rate swaps, options, swaptions and lock agreements to manage and
mitigate interest rate risk exposure. (See Notes 1, 7, 10, 12 and 14 to the
Consolidated Financial Statements.)
Based on a sensitivity analysis as of December 31, 2001, it was estimated
that if market interest rates average 1% higher (lower) in 2002 than in 2001,
earnings before income taxes would decrease (increase) by approximately $57
million. Comparatively, based on a sensitivity analysis as of December 31,
2000, had interest rates averaged 1% higher (lower) in 2001 than in 2000, it
was estimated that earnings before income taxes would have decreased
(increased) by approximately $53 million. These amounts include the effects of
interest rate hedges and were determined by considering the impact of the
hypothetical interest rates on the variable-rate securities outstanding as of
December 31, 2001 and 2000. The increase in interest rate sensitivity is
primarily due to the increase in outstanding variable-rate commercial paper. If
interest rates changed significantly, 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 Duke Energy's financial structure.
Equity Price Risk
Duke Energy maintains trust funds, as required by the Nuclear Regulatory
Commission (NRC), to fund certain costs of nuclear decommissioning. (See Note
11 to the Consolidated Financial Statements.) As of December 31, 2001 and 2000,
these funds were invested primarily in domestic and international equity
securities, fixed-rate, fixed-income securities and cash and cash equivalents.
Duke Energy has an agreement with the NRC that these funds will only be used
for activities relating to nuclear decommissioning. Because the accounting for
nuclear decommissioning recognizes that costs are recovered through Franchised
Electric's rates, fluctuations in equity prices or interest rates do not affect
consolidated results of operations, cash flows or financial position. (See
Current Issues--Nuclear Decommissioning Costs.)
Foreign Currency Risk
Duke Energy is exposed to foreign currency risk from investments in
international affiliates and businesses owned and operated in foreign
countries. To mitigate risks associated with foreign currency fluctuations,
when possible, transactions are denominated in or indexed to the U.S. dollar
and/or local inflation rates, or investments may be hedged through debt
denominated or issued in the foreign currency. Duke Energy also uses foreign
currency derivatives, where possible, to manage its risk related to foreign
currency fluctuations. To monitor its
51
currency exchange rate risks, Duke Energy uses sensitivity analysis, which
measures the impact of devaluation of the foreign currencies to which it has
exposure.
As of December 31, 2001, Duke Energy's primary foreign currency 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, 2001, a 10%
devaluation in the currency exchange rate in any or all of these foreign
currencies would be insignificant to Duke Energy's Consolidated Statements of
Income. Significant devaluations may impact Duke Energy's Consolidated Balance
Sheets by decreasing the value of Duke Energy's net investments through a
reduction in the cumulative translation adjustment in OCI.
Since 1991, the Argentine peso has been pegged to the U.S. dollar at a fixed
1:1 exchange ratio. In December 2001, the Argentine government imposed a
restriction that limited cash withdrawals above a certain amount and foreign
money transfers. Financial institutions were allowed to conduct limited
activity as a bank and exchange holiday was announced, and currency exchange
activity was essentially halted. In January 2002, the Argentine government
announced the creation of a dual-currency system. Subsequently, however, the
Argentine government has decided to use a free-floating currency.
Duke Energy's investment in Argentina was U.S. dollar functional as of
December 31, 2001. Once a functional currency determination has been made, that
determination must be adhered to consistently, unless significant changes in
economic factors indicate that the entity's functional currency has changed.
The recent events in Argentina require a change. In January 2002, the
functional currency of Duke Energy's investment in Argentina changed from the
U.S. dollar to the Argentine peso. In compliance with SFAS No. 52, "Foreign
Currency Translation," the change in functional currency will be made
prospectively. Management believes that the events in Argentina will have no
material adverse effect on Duke Energy's future consolidated results of
operations, cash flows or financial position.
CURRENT ISSUES
Electric Competition. Wholesale Competition. The Energy Policy Act of 1992
and the FERC's subsequent rulemaking activities opened the wholesale energy
market to competition. Open-access transmission for wholesale customers, as
defined by the FERC's rules, provides energy suppliers, including Duke Energy,
with opportunities to sell and deliver capacity and energy at market-based
prices. From the FERC's open-access rule, Franchised Electric obtained the
rights to sell capacity and energy at market-based rates from its own assets,
which allows Franchised Electric to purchase, at attractive rates, a portion of
its capacity and energy requirements resulting in lower overall costs to
customers. Open access also provides Franchised Electric's existing wholesale
customers with competitive opportunities to seek other suppliers for their
capacity and energy requirements.
In 1999 and 2000, the FERC issued its Order 2000 and Order 2000-A regarding
Regional Transmission Organizations (RTOs). These orders set minimum
characteristics and functions RTOs must meet, including independent authority
to establish the terms and conditions of transmission service over the
facilities they control. The orders provide for an open and flexible RTO
structure to meet the needs of the market, and for the possibility of incentive
ratemaking and other benefits for transmission owners that participate.
As a result of these rulemakings, Duke Energy and two other investor-owned
utilities, Carolina Power & Light Company and South Carolina Electric & Gas
Company, planned to establish GridSouth Transco, LLC (GridSouth), as an RTO
responsible for the control of the companies' combined transmission systems. In
March 2001, GridSouth received provisional approval from the FERC. However, in
July 2001, the FERC issued orders recommending that utilities throughout the
U.S. combine their transmission systems to create four large independent
regional operators, one each in the Northeast, Southeast, Midwest and West. The
FERC ordered
52
GridSouth and other utilities in the Southeast to join in 45 days of mediation
to negotiate terms of a Southeast RTO. The FERC has not issued an order
specifically based on those proceedings.
Duke Energy, Carolina Power & Light Company and South Carolina Electric &
Gas Company remain committed to the GridSouth RTO, but due to regulatory
uncertainties in the RTO arena, the companies have withdrawn their applications
to the PSCSC and NCUC to transfer functional control of their electric
transmission assets to GridSouth. The companies intend to file new applications
before the state commissions in the near future, including a revised GridSouth
structure designed to meet the needs of customers and regulators. Also, in
January of 2002, GridSouth signed a memorandum of understanding with the
representatives of SeTrans Grid Company (SeTrans), a group of investor-owned
utilities and public power entities in several southeastern states seeking to
form an RTO, to cooperate in discussing potential operational relationships
between GridSouth and SeTrans and the structure of wholesale electric markets
in the southeast U.S.
The actual structure of GridSouth or an alternative combined transmission
structure and the date it will become operational depend upon the resolution of
all regulatory approvals and technical issues. Management believes that the
result of this process, and the establishment and operation of GridSouth or an
alternative combined transmission system structure, will have no material
adverse effect on Duke Energy's future consolidated results of operations, cash
flows or financial position.
Retail Competition. Currently, Franchised Electric operates as a vertically
integrated, investor-owned utility with exclusive rights to supply electricity
in a franchised service territory--a 22,000-square-mile service territory in
the Carolinas. In its retail business, the NCUC and the PSCSC regulate
Franchised Electric's service and rates.
Electric industry restructuring is being addressed throughout the U.S. and
will likely impact all entities owning electric generating assets. The NCUC and
the PSCSC are studying the merits of restructuring the electric utility
industry in the Carolinas. In 1997, North Carolina passed a bill that
established a study commission, including legislators, customers, utilities and
a member of an environmental group, to examine whether competition should be
implemented in the state. In 2000, the study commission unanimously approved a
set of recommendations on electric restructuring and submitted a report
containing these recommendations to the General Assembly. The report
recommended retail deregulation beginning partially in 2005 and fully in 2006.
However, events in California's power market have led the study commission to
evaluate whether, and to what extent, proposed legislation should be
introduced. In general, the commission has expressed interest in ensuring that
a viable wholesale electric market is in place prior to opening the state's
retail electric market.
Currently, the electric utility industry is predominantly regulated on a
basis designed to recover the cost of providing electric power to customers. If
cost-based regulation were to be discontinued in the industry for any reason,
including competitive pressure on the cost-based prices of electricity, profits
could be reduced and electric utilities might be required to reduce their asset
balances to reflect a market basis less than cost. Discontinuance of cost-based
regulation would also require affected utilities to write off their associated
regulatory assets. Duke Energy's regulatory assets are included in the
Consolidated Balance Sheets. The portion of these regulatory assets related to
Franchised Electric is approximately $1.0 billion, including primarily
purchased capacity costs, deferred debt expense and deferred taxes related to
regulatory assets. Duke Energy is recovering substantially all of these
regulatory assets through its current wholesale and retail electric rates and
may attempt to continue to recover these assets during a transition to
competition. In addition, Duke Energy would seek to recover the costs of its
electric generating facilities in excess of the market price of power at the
time of transition.
Duke Energy supports a properly managed and orderly transition to
competitive generation and retail services in the electric industry. However,
transforming the current regulated industry into efficient, competitive
generation and retail electric markets is a complex undertaking, which will
require a carefully considered transition to a restructured electric industry.
The key to effective retail competition is fairness among customers,
53
service providers and investors. Duke Energy intends to continue to work with
customers, legislators and regulators to address all the important issues.
Management currently cannot predict the impact, if any, of these competitive
forces on future consolidated results of operations, cash flows or financial
position.
Natural Gas Competition. Wholesale Competition. In 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
interstate pipelines to 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 Duke
Energy during 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 2000, the
FERC generally denied requests for rehearing and several parties, including
Duke Energy, 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 2001, Duke Energy's interstate pipelines submitted revised pro forma tariff
sheets to update the filings originally submitted in 2000. These filings are
currently subject to review and approval by the FERC.
Management believes that the effects of these matters will have no material
adverse effect on Duke Energy's future consolidated results of operations, cash
flows or financial position.
Retail Competition. Changes in regulation to allow retail competition could
affect Duke Energy's natural gas transportation contracts with local natural
gas distribution companies. While natural gas retail deregulation is in the
very early stages of development, management believes the effects of this
matter will have no material adverse effect on Duke Energy's future
consolidated results of operations, cash flows or financial position.
Nuclear Decommissioning Costs. Estimated site-specific nuclear
decommissioning costs, including the cost of decommissioning plant components
not subject to radioactive contamination, total approximately $1.9 billion
stated in 1999 dollars based on decommissioning studies completed in 1999
(studies are completed every five years). Duke Energy contributes to an
external decommissioning trust fund and maintains an internal reserve to fund
these costs.
The balance of the external funds was $716 million as of December 31, 2001
and $717 million as of December 31, 2000, and is reflected in the Consolidated
Balance Sheets as Nuclear Decommissioning Trust Funds (asset) and Nuclear
Decommissioning Costs Externally Funded (liability). The balance of the
internal reserve was $239 million as of December 31, 2001 and $231 million as
of December 31, 2000, and is reflected in the Consolidated Balance Sheets as
Accumulated Depreciation and Amortization.
Both the NCUC and the PSCSC have granted Duke Energy recovery of estimated
decommissioning costs through retail rates over the expected remaining service
periods of its nuclear plants. Management believes that the decommissioning
costs being recovered through rates, when coupled with expected fund earnings,
are sufficient to provide for the cost of decommissioning. Additionally,
management believes that funding of the decommissioning costs will not have a
material adverse effect on consolidated results of operations, cash flows or
financial position. (See Note 11 to the Consolidated Financial Statements.)
The external decommissioning trust fund is invested primarily in domestic
and international equity securities, fixed-rate, fixed-income securities and
cash and cash equivalents. Duke Energy has an agreement with the NRC that these
funds will only be used for activities relating to nuclear decommissioning.
These investments
54
are exposed to price fluctuations in equity markets and changes in interest
rates. Because the accounting for nuclear decommissioning recognizes that costs
are recovered through Franchised Electric's rates, fluctuations in equity
prices or interest rates do not affect consolidated results of operations, cash
flows or financial position.
Nuclear Relicensing. In 2000, the NRC renewed the operating license for Duke
Energy's three Oconee nuclear units through 2033 to 2034. Applications to renew
the operating licenses for Duke Energy's Catawba and McGuire nuclear units were
filed with the NRC in June 2001. These operating licenses currently expire
between 2021 and 2026.
Environmental. Duke Energy is subject to international, federal, state and
local regulations regarding air and water quality, hazardous and solid waste
disposal and other environmental matters.
Manufactured Gas Plants and Superfund Sites. Duke Energy operated
manufactured gas plants until the early 1950s and has entered into a
cooperative effort with the State of North Carolina and other owners of former
manufactured gas plant sites to investigate and, where necessary, remediate
those contaminated sites. Regulators consider Duke Energy to be a potentially
responsible party, possibly subject to future liability at six federal and two
state Superfund sites. While remediation costs may be substantial, Duke Energy
will share in any liability associated with contamination at these sites with
other potentially responsible parties. Management believes that resolution of
these matters will have no material adverse effect on consolidated results of
operations, cash flows or financial position.
PCB (Polychlorinated Biphenyl) Assessment and Cleanup Programs. In 2001,
Texas Eastern Transmission, LP, a wholly owned subsidiary of Duke Energy,
completed the remaining requirements of a 1989 U.S. Consent Decree regarding
the cleanup of PCB-contaminated sites. The Environmental Protection Agency
(EPA) certified the completion of all work under the Consent Decree in January
2002. Monitoring of groundwater and remediation at certain sites may continue
as required by various state authorities.
In March 1999, Duke Energy sold PEPL and Trunkline to CMS. (See Note 1 to
the Consolidated Financial Statements for more information on the sale of the
pipelines.) Under the terms of the sales agreement with CMS, Duke Energy 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 Duke Energy's experience to date and costs incurred for cleanup,
management believes the resolution of matters relating to the environmental
issues discussed above will have no material adverse effect on consolidated
results of operations, cash flows or financial position.
Air Quality Control. In 1998, the EPA issued a final rule on regional ozone
control that required 22 eastern states and the District of Columbia to revise
their State Implementation Plans (SIPs) to significantly reduce emissions of
nitrogen oxide by May 1, 2003. The EPA rule was challenged in court by various
states, industry and other interests, including Duke Energy and the states of
North Carolina and South Carolina. In 2000, the court upheld most aspects of
the EPA rule. The same court subsequently extended the compliance deadline for
implementation of emission reductions to May 31, 2004.
In 2000, the EPA finalized another ozone-related rule under Section 126 of
the Clean Air Act (CAA). Section 126 of the CAA has virtually identical
emission control requirements as the 1998 action, and specified a May 1, 2003
compliance date. While the emission reduction requirements of the rule have
been upheld in court, the implementation date for the rule has been revised to
May 2004 as a result of a legal challenge and the resulting court order.
Management estimates that Duke Energy will spend from $500 million to $900
million in capital costs for additional emission controls through 2007 to
comply with the new EPA rules.
55
Both North Carolina and South Carolina have revised their SIPs in response
to the EPA's 1998 rule, and are awaiting EPA approval. Legislation was
introduced in the North Carolina General Assembly in 2001 and passed by the
state Senate that would require North Carolina electric utilities, including
Duke Energy, to make significant reductions in emissions of sulfur dioxide and
nitrogen oxides from coal-fired power plants over the next seven to 11 years.
Management estimates Duke Energy's cost of achieving the proposed emission
reductions to be approximately $1.5 billion. A provision in the proposed North
Carolina legislation allows Duke Energy to recover those costs from customers
through an environmental compliance expenditure-recovery factor that is
separate from the electric utility's base rates. If passed into law, the final
provisions could be significantly different from the proposal.
Emission control retrofits needed to comply with the new rules are large
technical, design and construction projects. These projects will be managed
closely to ensure the continuation of reliable electric service to Duke
Energy's customers throughout the projects and upon their completion.
In 2000, the U.S. Justice Department, acting on behalf of the EPA, filed a
complaint against Duke Energy in the U.S. District Court in Greensboro, North
Carolina, for alleged violations of the New Source Review (NSR) provisions of
the CAA. The EPA claims that 29 projects performed at 25 of Duke Energy's
coal-fired units were major modifications, as defined in the CAA, and that Duke
Energy violated the CAA's NSR requirements when it undertook those projects
without obtaining permits and installing emission controls for sulfur dioxide,
nitrogen oxide and particulate matter. The complaint asks the court to order
Duke Energy to stop operating the coal-fired units identified in the complaint,
install additional emission controls and pay unspecified civil penalties. This
complaint is part of the EPA's NSR enforcement initiative, in which the EPA
claims that utilities and others have committed widespread violations of the
CAA permitting requirements for the past 25 years. The EPA has sued or issued
notices of violation of investigative information requests to at least 48 other
electric utilities and cooperatives.
The EPA's allegations run counter to previous EPA guidance regarding the
applicability of the NSR permitting requirements. Duke Energy, along with other
utilities, has routinely undertaken the type of repair, replacement and
maintenance projects that the EPA now claims are illegal. Duke Energy believes
that all of its electric generation units are properly permitted and have been
properly maintained, and is defending itself vigorously against these alleged
violations. The U.S. Vice President's National Energy Policy Development Group
has ordered the EPA to review its NSR rules and has ordered the Department of
Justice to review the appropriateness of the enforcement cases. The EPA review
was scheduled to be completed by August 2001, but has not yet been concluded.
In January 2002, the Department of Justice released a report concluding that it
was not improper for the Department of Justice to initiate the enforcement
cases brought on behalf of the EPA. It specifically declined to address whether
the EPA's enforcement actions are wise as a matter of national energy policy.
Because these matters are in a preliminary stage, management cannot estimate
the effects of these matters on Duke Energy's future consolidated results of
operations, cash flows or financial position. The CAA authorizes civil
penalties of up to $27,500 per day per violation at each generating unit. Civil
penalties, if ultimately imposed by the court, and the cost of any required new
pollution control equipment, if the court accepts the EPA's contentions, could
be substantial.
Global Climate Change. 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 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. The high-level operational framework
for implementing the Kyoto Protocol was agreed to in November 2001. If the
Kyoto Protocol were to be implemented in developed countries where Duke Energy
operates, it could have far-reaching implications for Duke Energy and the
entire energy industry. However, the outcome and timing of these implications
are highly uncertain, and Duke Energy cannot estimate the effects on future
consolidated results of operations, cash flows or financial position. Duke
Energy remains engaged in discussions with those developing public policy
initiatives and continuously assesses the commercial implications for its
markets around the world.
56
Notice of Proposed Rulemaking (NOPR). On September 27, 2001, the FERC issued
a NOPR announcing that it is considering new regulations regarding standards of
conduct that would apply uniformly to natural gas pipelines and electric
transmitting public utilities that are currently subject to different gas or
electric standards. The proposed standards would change how companies and their
affiliates interact and share information by broadening the definition of
"affiliate" covered by the standards of conduct, from the more narrow
definition in the existing regulations. The NOPR also seeks comment on whether
the standards of conduct should be broadened to include the separation of those
involved in the bundled retail electric sales function from those in the
transmission function, as the current standards apply only to those involved in
wholesale activities. Various entities filed comments on the NOPR with the
FERC, including Duke Energy which filed on December 20, 2001. The FERC has
indicated that they appreciate the complexity of the issues and that they would
prefer having a technical conference before entering directly into a final
rulemaking. No notice of a technical conference has been given at this time.
Regulatory Matters. In 2001, the NCUC and PSCSC began a joint investigation,
along with the Public Staff of the NCUC, regarding certain Duke Power
regulatory accounting entries for 1998. In its internal review of the 14
entries in question, Duke Energy concluded that nine items were correctly
classified for regulatory accounting. Four items were incorrectly classified
for regulatory purposes for 1998 only, and did not recur. The classification of
the remaining item, distributions from a mutual insurance company, is subject
to differing regulatory interpretations. Duke Energy believes this item was
appropriately classified, but is evaluating its classification for future
years. As part of their investigation, the NCUC and PSCSC have jointly engaged
an independent firm to conduct an audit of Duke Power's accounting records for
reporting periods from 1998 through June 30, 2001. Duke Energy continues to
fully cooperate with the commissions in their investigation. As requested by
the NCUC, Duke Energy has recorded the 2001 mutual insurance distribution,
approximately $33 million, in a deferred credit account on the Consolidated
Balance Sheets, pending final outcome of the independent audit.
California Issues. Duke Energy, some of its subsidiaries and three current
or former executives have been named as defendants, among other corporate and
individual defendants, in one or more of a total of six lawsuits brought by or
on behalf of electricity consumers in the State of California. The plaintiffs
seek damages as a result of the defendants' alleged unlawful manipulation of
the California wholesale electricity markets. DENA and DETM are among 16
defendants in a class-action lawsuit (the Gordon lawsuit) filed against
generators and traders of electricity in California markets. DETM was also
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, traders and other unnamed providers of electricity in
California markets. A sixth lawsuit (the Bustamante lawsuit) was brought by the
Lieutenant Governor of the State of California and a State Assemblywoman, on
their own behalf as citizens and on behalf of the general public, and includes
Duke Energy, some of its subsidiaries and three current or former executives of
Duke Energy among other corporate and individual defendants. The Gordon and
Hendricks class-action lawsuits were filed in the Superior Court of the State
of California, San Diego County, in November 2000. Three other lawsuits were
filed in January 2001, one in Superior Court, San Diego County, and the other
two in Superior Court, County of San Francisco. The Bustamante lawsuit was
filed in May 2001 in Superior Court, Los Angeles County. These lawsuits
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. The plaintiffs seek aggregate damages of
billions of dollars. The lawsuits seek the refund of alleged unlawfully
obtained revenues for electricity sales and, in four lawsuits, an award of
treble damages. These suits have been consolidated before a state court judge
in San Diego. While these matters are in their earliest stages, management
believes, based on its analysis of the facts and the asserted claims, that
their resolution will have no material adverse effect on Duke Energy's
consolidated results of operations, cash flows or financial position.
In addition to the lawsuits, several investigations and regulatory
proceedings at the state and federal levels are looking into the causes of high
wholesale electricity prices in the western U.S. At the federal level, numerous
proceedings are before the FERC. Some parties to those proceedings have made
claims for billions of dollars of
57
refunds from sellers of wholesale electricity, including DETM. Some parties
have also sought to revoke the authority of DETM and other DENA-affiliated
electricity marketers to sell electricity at market-based rates. The FERC is
also conducting its own wholesale pricing investigation. As a result, the FERC
has ordered some sellers, including DETM, to refund, or to offset against
outstanding accounts receivable, amounts billed for electricity sales in excess
of a FERC-established proxy price. The proxy price represents what the FERC
believes would have been the market-clearing price in a perfectly competitive
market. In June 2001, DETM offset approximately $20 million against amounts
owed by the California Independent System Operator and the California Power
Exchange for electricity sales during January and February 2001. This offset
reduced the $110 million reserve established in 2000 to $90 million.
Proceedings are ongoing to determine, among other issues, the amount of any
refunds or offsets for periods prior to January 2001, and the method to be used
to determine the proxy price in future months.
At the state level, the California Public Utilities Commission is conducting
formal and informal investigations to determine if power plant operators in
California, including some Duke Energy entities, have improperly "withheld,"
either economically or physically, generation output from the market to
manipulate market prices. In addition, the California State Senate formed a
Select Committee to Investigate Price Manipulation of the Wholesale Energy
Market (Select Committee). The Select Committee has served a subpoena on Duke
Energy and some of its subsidiaries seeking data concerning their California
market activities. The Select Committee has heard testimony from several
witnesses but no one from Duke Energy has yet been subpoenaed to testify.
The California Attorney General is also conducting an investigation to
determine if any market participants engaged in illegal activity, including
antitrust violation, in the course of their electricity sales into wholesale
markets in the western U.S. The Attorneys General of Washington and Oregon are
participating in the California Attorney General's investigation. The San Diego
District Attorney is conducting a separate investigation into market activities
and has issued subpoenas to DETM and a DENA subsidiary.
The California Attorney General has also convened a grand jury to determine
whether criminal charges should be brought against any market participants. To
date, no Duke Energy employee has been called to testify before the grand jury
nor have any criminal charges been filed against Duke Energy or any of its
officers, directors or employees in connection with the wholesale electricity
markets in the states of the western U.S.
Throughout 2001, Duke Energy conducted its business in California to supply
the maximum possible electricity to meet the needs of the state, limit its
exposure to non-creditworthy counterparties and manage the output limitations
on its power plants imposed by applicable permits and laws. Since December 31,
2000, Duke Energy has closely managed the balance of doubtful receivables, and
believes that the current pre-tax bad debt provision of $90 million is
appropriate. No additional provisions for California receivables were recorded
in 2001. Management believes, based on its analysis of the facts and the
asserted claims, that the resolution of these matters will have no material
adverse effect on Duke Energy's consolidated results of operations, cash flows
or financial position.
Litigation and Contingencies. Exxon Mobil Corporation Arbitration. In 2000,
three Duke Energy subsidiaries initiated binding arbitration against three
Exxon Mobil Corporation subsidiaries (the Exxon Mobil entities) concerning the
parties' joint ownership of DETM and related affiliates (the Ventures). At
issue is a buy-out right provision under the joint venture agreements for these
entities. If there is a material business dispute between the parties, which
Duke Energy alleges has occurred, the buy-out provision gives Duke Energy the
right to purchase Exxon Mobil's 40% interest in DETM. Exxon Mobil does not have
a similar right under the joint venture agreements and once Duke Energy
exercises the buy-out right, each party has the right to "unwind" the buy-out
under certain specific circumstances. In December 2000, Duke Energy exercised
its right to buy the Exxon Mobil entities' interest in the Ventures. Duke
Energy claims that refusal by the Exxon Mobil entities to
58
honor the exercise is a breach of the buy-out right provision, and seeks
specific performance of the provision. Duke Energy has also made additional
claims against the Exxon Mobil entities for breach of the agreements governing
the Ventures.
In January 2001, the Exxon Mobil entities made counterclaims in the
arbitration and, in a separate Texas state court action, alleged that Duke
Energy breached its obligations to the Ventures and to the Exxon Mobil
entities. In April 2001, the state court stayed its action, compelling the
Exxon Mobil entities to arbitrate their claims. The Exxon Mobil entities
proceeded with the arbitration of their claims and have not challenged this
order in an appellate court. In early October 2001, the arbitration panel
convened an evidentiary hearing regarding the buy-out right provision and Duke
Energy's and Exxon Mobil's claims against each other. The panel has not yet
ruled but Duke Energy expects a final decision from the panel in early 2002.
Management believes that the final disposition of this action will have no
material adverse effect on Duke Energy's consolidated results of operations or
financial position.
Duke Energy and its subsidiaries are involved in other legal, tax and
regulatory proceedings before various courts, regulatory commissions and
governmental agencies regarding performance, contracts and other matters
arising in the ordinary course of business, some of which involve substantial
amounts. Management believes that the final disposition of these proceedings
will have no material adverse effect on consolidated results of operations,
cash flows or financial position. (See Note 15 to the Consolidated Financial
Statements for information concerning litigation and other commitments and
contingencies.)
New Accounting Standards. In June 2001, the FASB issued SFAS No. 141,
"Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible
Assets."
SFAS No. 141 requires that all business combinations initiated (as defined
by the standard) after June 30, 2001 be accounted for using the purchase
method. Companies may no longer use the pooling method of accounting for future
combinations.
SFAS No. 142 is effective for fiscal years beginning after December 15,
2001, and was adopted by Duke Energy as of January 1, 2002. SFAS No. 142
requires that goodwill no longer be amortized over an estimated useful life, as
previously required. Instead, goodwill amounts will be subject to a
fair-value-based annual impairment assessment. The standard also requires
certain identifiable intangible assets to be recognized separately and
amortized as appropriate. No such intangibles have been identified at Duke
Energy. Duke Energy expects the adoption of SFAS No. 142 to have an impact on
future financial statements, due to the discontinuation of goodwill
amortization expense. For 2001, pre-tax goodwill amortization expense was $101
million. The FASB and the EITF continue to respond to questions to clarify key
aspects of SFAS No. 142. Duke Energy has determined the effect of implementing
SFAS No. 142 and does not expect to record any impairment in 2002.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 provides the accounting requirements for retirement
obligations associated with tangible long-lived assets. It is effective for
fiscal years beginning after June 15, 2002, and early adoption is permitted.
Duke Energy is currently assessing the new standard and has not yet determined
the impact on its consolidated results of operations or financial position.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." The new rules supersede SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of." The new rules retain many of the fundamental recognition
and measurement provisions, but significantly change the criteria for
classifying an asset as held-for-sale. SFAS No. 144 is effective for fiscal
years beginning after December 15, 2001. Duke Energy has evaluated the new
standard, and management believes that it will have no material adverse effect
on Duke Energy's consolidated results of operations or financial position.
59
Energy Industry and Accounting Practices. The energy industry landscape
changed during 2001. The bankruptcy of Enron (See Quantitative and Qualitative
Disclosures About Market Risk--Credit Risk), the tragic events of September 11,
2001 and the global economic downturn will likely have continued impacts on the
industry.
Near-term economic growth is likely to be lower and more cyclical than in
the recent past. As a result, industrial or commercial customers and trading
counterparties could reduce their business volume with Duke Energy. However,
overall demand for power is still on the rise. Current estimates place demand
growth for power between 1% and 2% annually over the next decade. Duke Energy
will continue to seek opportunities to reduce the risks associated with
economic impacts on its customers, and help markets achieve desired
supply/demand equilibrium and infrastructure reliability.
The situation surrounding Enron's bankruptcy has forced regulators and
legislators to take a renewed look at accounting practices, financial
disclosures, companies' relationships with their independent auditors and
retirement plan practices. Duke Energy cannot predict the ultimate impact of
any future changes in laws or regulations. However, Duke Energy is committed to
complying with all laws and regulations and will continue to play an active
role in helping to shape future laws and regulations as they evolve.
Subsequent Events. On January 31, 2002, Duke Energy announced the planned
sale of its DE&S business unit to Framatome ANP, Inc. (a nuclear supplier) for
approximately $84 million. Two components of DE&S are not part of the sale.
Duke Energy will establish Duke Energy--Energy Delivery Services, formed by the
power delivery services component of DE&S, which will continue to supply power
delivery solutions to customers. Leadership of the U.S. Department of Energy
Mixed Oxide Fuel project will also remain with Duke Energy. The transaction
will require a Hart Scott Rodino filing and is expected to close in the second
quarter of 2002.
On March 13, 2002, Duke Energy announced the planned sale of DukeSolutions
to Ameresco, Inc. Duke Energy expects to close the transaction during the
second quarter of 2002, and record a loss of approximately $20 million.
On March 14, 2002, Duke Energy acquired Westcoast for approximately $8
billion, including the assumption of debt. Westcoast, headquartered in
Vancouver, British Columbia, is a North American energy company with interests
in natural gas gathering, processing, transmission, storage and distribution,
as well as power generation and international energy businesses. In the
transaction, a Duke Energy subsidiary acquired all of the outstanding common
shares of Westcoast in exchange for approximately 49.9 million shares of Duke
Energy common stock (including exchangeable shares of a Duke Energy Canadian
subsidiary that are substantially equivalent to and exchangeable on a
one-for-one basis for Duke Energy common stock), and approximately $1.8 billion
in cash. Under proration provisions that ensure that approximately 50% of the
total consideration is paid in cash and 50% in stock, each common share of
Westcoast entitled the holder to elect to receive $43.80 in cash (Canadian),
.7711 of a share of Duke Energy common stock or of an exchangeable share of a
Duke Energy Canadian subsidiary, or a combination thereof. The cash portion of
the consideration was funded with the proceeds from the issuance of $750
million in Equity Units in November 2001 (See Financing Cash Flows) along with
incremental commercial paper. Duke Energy plans to retire the commercial paper
later in 2002 and replace it with permanent capital in the form of mandatory
convertible equity. The timing for the mandatory convertible equity will be
dependent on the opportunities presented and favorable market conditions. The
Westcoast acquisition was accounted for using the purchase method of accounting.
Forward-Looking Statements. Duke Energy's reports, filings and other public
announcements may include statements that reflect 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. Generally, the words "may," "could," "project,"
"believe," "anticipate," "expect," "estimate," "plan," "forecast," "intend" and
similar words identify forward-looking statements, which generally are not
historical in nature. All such statements (other than statements of historical
facts), including statements regarding
60
operating performance, financial position, business strategy, budgets,
projected costs, plans and objectives of management for future operations and
events or developments that we expect or anticipate will occur in the future,
are forward looking. Forward-looking statements are subject to certain risks
and uncertainties that could, and often do, cause actual results to differ from
Duke Energy's historical experience and our present expectations or
projections. Accordingly, there can be no assurance that actual results will
not differ materially from those expressed or implied by the forward-looking
statements. Caution should be taken not to place undue reliance on any such
forward-looking statements.
Factors that could cause actual results to differ materially from the
expectations expressed or implied in such forward-looking statements include,
but are not limited to: state, federal and foreign legislative and regulatory
initiatives that affect cost and investment recovery, have an impact on rate
structures and affect the speed and degree at which competition enters the
electric and natural gas industries; industrial, commercial and residential
growth in the service territories of Duke Energy and its subsidiaries; the
weather and other natural phenomena; the timing and extent of changes in
commodity prices, interest rates and foreign currency exchange rates; changes
in environmental and other laws and regulations to which Duke Energy and its
subsidiaries are subject or other external factors over which Duke Energy has
no control; the results of financing efforts, including Duke Energy's ability
to obtain financing on favorable terms, which can be affected by Duke Energy's
credit rating and general economic conditions; level of creditworthiness of
counterparties to transactions; growth opportunities for Duke Energy's business
units; and the effect of accounting policies issued periodically by accounting
standard-setting bodies.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
See "Management's Discussion and Analysis of Results of Operations and
Financial Condition, Quantitative and Qualitative Disclosures About Market
Risk."
61
Item 8. Financial Statements and Supplementary Data.
DUKE ENERGY CORPORATION
Consolidated Statements Of Income
Years Ended December 31,
------------------------
2001 2000 1999
------- ------- -------
In millions, except
per-share amounts
Operating Revenues
Sales, trading and marketing of natural gas and petroleum products (Notes 1 and 7).... $33,364 $28,284 $10,922
Trading and marketing of electricity (Notes 1 and 7).................................. 18,010 13,086 3,745
Generation, transmission and distribution of electricity (Notes 1 and 4).............. 5,410 5,315 4,799
Transportation and storage of natural gas (Notes 1 and 4)............................. 996 1,045 1,139
Gain on sale of equity investment (Note 2)............................................ -- 407 --
Other (Note 8)........................................................................ 1,723 1,181 1,161
------- ------- -------
Total operating revenues............................................................. 59,503 49,318 21,766
------- ------- -------
Operating Expenses
Natural gas and petroleum products purchased (Note 1)................................. 32,021 27,670 10,636
Net interchange and purchased power (Notes 1, 4 and 5)................................ 16,515 12,000 3,507
Fuel used in electric generation (Notes 1 and 11)..................................... 965 781 764
Other operation and maintenance (Notes 4 and 11)...................................... 4,135 3,469 3,701
Depreciation and amortization (Notes 1 and 5)......................................... 1,336 1,167 968
Property and other taxes.............................................................. 431 418 371
------- ------- -------
Total operating expenses............................................................. 55,403 45,505 19,947
------- ------- -------
Operating Income........................................................................ 4,100 3,813 1,819
Other Income and Expenses............................................................... 156 201 224
Interest Expense (Notes 7 and 10)....................................................... 785 911 601
Minority Interest Expense (Notes 2, 12 and 13).......................................... 327 307 142
------- ------- -------
Earnings Before Income Taxes............................................................ 3,144 2,796 1,300
Income Taxes (Notes 1 and 6)............................................................ 1,150 1,020 453
------- ------- -------
Income Before Extraordinary Item and Cumulative Effect of Change in Accounting Principle 1,994 1,776 847
Extraordinary Gain, net of tax (Note 1)................................................. -- -- 660
Cumulative Effect of Change in Accounting Principle, net of tax (Note 1)................ (96) -- --
------- ------- -------
Net Income.............................................................................. 1,898 1,776 1,507
Preferred and Preference Stock Dividends (Note 14)...................................... 14 19 20
------- ------- -------
Earnings Available For Common Stockholders.............................................. $ 1,884 $ 1,757 $ 1,487
======= ======= =======
Common Stock Data (Note 1)
Weighted-average shares outstanding................................................... 767 736 729
Earnings per share (before extraordinary item and cumulative effect of change in
accounting principle)
Basic................................................................................ $ 2.58 $ 2.39 $ 1.13
Diluted.............................................................................. $ 2.56 $ 2.38 $ 1.13
Earnings per share
Basic................................................................................ $ 2.45 $ 2.39 $ 2.04
Diluted.............................................................................. $ 2.44 $ 2.38 $ 2.03
Dividends per share................................................................... $ 1.10 $ 1.10 $ 1.10
See Notes to Consolidated Financial Statements.
62
DUKE ENERGY CORPORATION
Consolidated Statements Of Cash Flows
Years Ended December 31,
-------------------------
2001 2000 1999
------- ------- -------
In millions
Cash Flows From Operating Activities
Net income...................................................................................... $ 1,898 $ 1,776 $ 1,507
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization.................................................................. 1,450 1,348 1,151
Cumulative effect of change in accounting principle............................................ 96 -- --
Extraordinary gain, net of tax................................................................. -- -- (660)
Gain on sale of equity investment.............................................................. -- (407) --
Provision on NAWE's California receivables..................................................... -- 110 --
Impairment charges............................................................................. 36 -- --
Injuries and damages accrual................................................................... -- -- 800
Deferred income taxes.......................................................................... 129 152 (210)
Purchased capacity levelization................................................................ 156 138 104
Transition cost recoveries, net................................................................ -- 82 95
(Increase) decrease in
Net unrealized mark-to-market and hedging transactions........................................ 91 (464) (24)
Receivables................................................................................... 3,166 (5,167) (659)
Inventory..................................................................................... (192) (100) (89)
Other current assets.......................................................................... 694 (796) (138)
Increase (decrease) in
Accounts payable.............................................................................. (3,545) 4,867 477
Taxes accrued................................................................................. 183 (439) (57)
Interest accrued.............................................................................. 28 64 32
Other current liabilities..................................................................... 297 1,116 73
Other, assets.................................................................................. 351 175 221
Other, liabilities............................................................................. (243) (230) 61
------- ------- -------
Net cash provided by operating activities................................................... 4,595 2,225 2,684
------- ------- -------
Cash Flows From Investing Activities
Capital expenditures, net of cash acquired...................................................... (5,930) (4,568) (5,291)
Investment expenditures......................................................................... (1,093) (966) (596)
Proceeds from sale of subsidiaries and equity investment........................................ -- 400 1,900
Notes Receivable................................................................................ 201 (158) 83
Other........................................................................................... 541 362 153
------- ------- -------
Net cash used in investing activities....................................................... (6,281) (4,930) (3,751)
------- ------- -------
Cash Flows From Financing Activities
Proceeds from the issuance of
Long-term debt................................................................................. 2,673 3,206 3,221
Guaranteed preferred beneficial interests in subordinated notes of Duke Energy Corporation or
subsidiaries.................................................................................. -- -- 484
Common stock and stock options................................................................. 1,432 230 162
Payments for the redemption of
Long-term debt................................................................................. (1,298) (1,191) (1,505)
Preferred and preference stock................................................................. (33) (33) (20)
Net change in notes payable and commercial paper................................................ (246) 1,484 58
Distributions to minority interests............................................................. (329) (1,216) --
Contributions from minority interests........................................................... -- 1,116 --
Dividends paid.................................................................................. (871) (828) (822)
Other........................................................................................... 26 (54) 22
------- ------- -------
Net cash provided by financing activities................................................... 1,354 2,714 1,600
------- ------- -------
Net (decrease) increase in cash and cash equivalents............................................ (332) 9 533
Cash and cash equivalents at beginning of period................................................ 622 613 80
------- ------- -------
Cash and cash equivalents at end of period...................................................... $ 290 $ 622 $ 613
======= ======= =======
Supplemental Disclosures
Cash paid for interest, net of amount capitalized............................................... $ 733 $ 817 $ 541
Cash paid for income taxes...................................................................... $ 770 $ 1,177 $ 732
See Notes to Consolidated Financial Statements.
63
DUKE ENERGY CORPORATION
Consolidated Balance Sheets
December 31,
---------------
2001 2000
------- -------
In millions
ASSETS
Current Assets (Note 1)
Cash and cash equivalents (Note 7)......................................... $ 290 $ 622
Receivables (Notes 1 and 7)................................................ 5,301 8,648
Inventory (Note 1)......................................................... 1,017 739
Current portion of purchased capacity costs (Note 5)....................... 160 149
Unrealized gains on mark-to-market and hedging transactions (Notes 1 and 7) 2,326 11,038
Other...................................................................... 451 1,317
------- -------
Total current assets................................................... 9,545 22,513
------- -------
Investments and Other Assets
Investments in affiliates (Note 8)......................................... 1,480 1,387
Nuclear decommissioning trust funds (Note 11).............................. 716 717
Pre-funded pension costs (Note 18)......................................... 313 304
Goodwill, net of accumulated amortization (Notes 1 and 2).................. 1,730 1,566
Notes receivable........................................................... 576 462
Unrealized gains on mark-to-market and hedging transactions (Notes 1 and 7) 3,117 4,218
Other...................................................................... 1,299 1,143
------- -------
Total investments and other assets..................................... 9,231 9,797
------- -------
Property, Plant and Equipment (Notes 1, 5, 9, 10 and 11)
Cost....................................................................... 39,464 34,598
Less accumulated depreciation and amortization............................. 11,049 10,146
------- -------
Net property, plant and equipment...................................... 28,415 24,452
------- -------
Regulatory Assets and Deferred Debits (Notes 1 and 4)
Purchased capacity costs (Note 5).......................................... 189 356
Deferred debt expense...................................................... 203 208
Regulatory asset related to income taxes................................... 510 506
Other (Notes 4 and 15)..................................................... 282 400
------- -------
Total regulatory assets and deferred debits............................ 1,184 1,470
------- -------
Total Assets................................................................ $48,375 $58,232
======= =======
See Notes to Consolidated Financial Statements.
64
DUKE ENERGY CORPORATION
Consolidated Balance Sheets--(Continued)
December 31,
---------------
2001 2000
------- -------
In millions
LIABILITIES AND COMMON STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable..................................................................... $ 4,231 $ 7,733
Notes payable and commercial paper (Notes 7 and 10).................................. 1,603 1,826
Taxes accrued (Note 1)............................................................... 443 261
Interest accrued..................................................................... 239 208
Current maturities of long-term debt and preferred stock (Notes 10 and 14)........... 274 470
Unrealized losses on mark-to-market and hedging transactions (Notes 1 and 7)......... 1,519 11,070
Other (Notes 1 and 15)............................................................... 2,118 1,769
------- -------
Total current liabilities........................................................ 10,427 23,337
------- -------
Long-term Debt (Notes 7 and 10)....................................................... 12,321 10,717
------- -------
Deferred Credits and Other Liabilities (Note 1)
Deferred income taxes (Note 6)....................................................... 4,307 3,851
Investment tax credit (Note 6)....................................................... 189 211
Nuclear decommissioning costs externally funded (Note 11)............................ 716 717
Environmental cleanup liabilities (Note 15).......................................... 85 100
Unrealized losses on mark-to-market and hedging transactions (Notes 1 and 7)......... 2,212 3,581
Other (Notes 4 and 15)............................................................... 1,542 1,574
------- -------
Total deferred credits and other liabilities..................................... 9,051 10,034
------- -------
Commitments and Contingencies (Notes 5, 11 and 15)
Guaranteed Preferred Beneficial Interests in Subordinated
Notes of Duke Energy Corporation or Subsidiaries (Notes 7 and 12)................... 1,407 1,406
------- -------
Minority Interest in Financing Subsidiary (Note 13)................................... 1,025 1,025
------- -------
Minority Interests (Note 2)........................................................... 1,221 1,410
------- -------
Preferred and Preference Stock (Notes 7 and 14)
Preferred and preference stock with sinking fund requirements........................ 25 38
Preferred and preference stock without sinking fund requirements..................... 209 209
------- -------
Total preferred and preference stock............................................. 234 247
------- -------
Common Stockholders' Equity (Notes 1, 16 and 17)
Common stock, no par, 2 billion shares authorized; 777 million and 739 million shares
outstanding at December 31, 2001 and 2000, respectively............................ 6,217 4,797
Retained earnings.................................................................... 6,292 5,379
Accumulated other comprehensive income (loss)........................................ 180 (120)
------- -------
Total common stockholders' equity................................................ 12,689 10,056
------- -------
Total Liabilities and Common Stockholders' Equity..................................... $48,375 $58,232
======= =======
See Notes to Consolidated Financial Statements.
65
DUKE ENERGY CORPORATION
Consolidated Statements Of Common Stockholders' Equity And Comprehensive Income
Accumulated
Other Total
Common Retained Comprehensive Comprehensive
Stock Earnings Income (Loss) Total Income
------ -------- ------------- ------- -------------
In millions
Balance December 31, 1998............................ $4,449 $3,701 $ -- $ 8,150
------ ------ ------ -------
Net income........................................... -- 1,507 -- 1,507 $1,507
Other comprehensive income...........................
Foreign currency translation adjustments
(Note 1)........................................ -- -- (2) (2) (2)
------
Total comprehensive income..................... $1,505
======
Dividend reinvestment and employee benefits
(Note 17).......................................... 154 -- -- 154
Common stock dividends............................... -- (802) -- (802)
Preferred and preference stock dividends (Note 14)... -- (20) -- (20)
Other capital stock transactions, net................ -- 11 -- 11
------ ------ ------ -------
Balance December 31, 1999............................ $4,603 $4,397 $ (2) $ 8,998
------ ------ ------ -------
Net income........................................... -- 1,776 -- 1,776 $1,776
Other comprehensive income...........................
Foreign currency translation adjustments
(Note 1)........................................ -- -- (118) (118) (118)
------
Total comprehensive income..................... $1,658
======
Dividend reinvestment and employee benefits
(Note 17).......................................... 194 -- -- 194
Common stock dividends............................... -- (809) -- (809)
Preferred and preference stock dividends (Note 14)... -- (19) -- (19)
Other capital stock transactions, net................ -- 34 -- 34
------ ------ ------ -------
Balance December 31, 2000............................ $4,797 $5,379 $ (120) $10,056
------ ------ ------ -------
Net income........................................... -- 1,898 -- 1,898 $1,898
Other Comprehensive Income(a)........................
Cumulative effect of change in accounting
principle (Note 1).............................. -- -- (921) (921) (921)
Foreign currency translation adjustments
(Note 1)........................................ -- -- (187) (187) (187)
Net unrealized gains on cash flow hedges (Notes 1
and 7).......................................... -- -- 1,324 1,324 1,324
Reclassification into earnings (Notes 1 and 7).... -- -- 84 84 84
------
Total comprehensive income..................... $2,198
======
Dividend reinvestment and employee benefits
(Note 17).......................................... 329 -- -- 329
Equity offering (Note 16)............................ 1,091 -- -- 1,091
Common stock dividends, including equity units
contract adjustment (Note 16)...................... -- (973) -- (973)
Preferred and preference stock dividends (Note 14)... -- (14) -- (14)
Other capital stock transactions, net................ -- 2 -- 2
------ ------ ------ -------
Balance December 31, 2001............................ $6,217 $6,292 $ 180 $12,689
====== ====== ====== =======
- --------
(a) Other Comprehensive Income amounts are net of tax, except for foreign
currency translation.
See Notes to Consolidated Financial Statements.
66
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements
For the Years Ended December 31, 2001, 2000 and 1999
1. Summary of Significant Accounting Policies
Consolidation. The Consolidated Financial Statements include the accounts of
Duke Energy Corporation and all majority-owned subsidiaries, after eliminating
significant intercompany transactions and balances. Investments in businesses
not controlled by Duke Energy Corporation, but over which it has significant
influence, are accounted for using the equity method.
Conformity with generally accepted accounting principles (GAAP) requires
management to make estimates and assumptions that affect the amounts reported
in the financial statements and notes. Although these estimates are based on
management's best available knowledge of current and expected future events,
actual results could be different from those estimates.
In these Notes, "Duke Energy" refers to Duke Energy Corporation and its
subsidiaries.
Cash and Cash Equivalents. All liquid investments with maturities of three
months or less at the date of purchase are considered cash equivalents.
Inventory. Inventory, excluding inventory held for trading, consists
primarily of materials and supplies, natural gas and natural gas liquid (NGL)
products held in storage for transmission, processing and sales commitments,
and coal held for electric generation. This inventory is recorded at the lower
of cost or market value, primarily using the average cost method. Inventory
held for trading is marked to market.
Accounting for Hedges and Trading Activities. All derivatives not qualifying
for the normal purchases and sales exemption under Statement of Financial
Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and
Hedging Activities," are recorded on the Consolidated Balance Sheets at their
fair value as Unrealized Gains or Unrealized Losses on Mark-to-Market and
Hedging Transactions. On the date that swaps, futures, forwards or option
contracts are entered into, Duke Energy designates the derivative as either
held for trading (trading instrument); as a hedge of a forecasted transaction
or future cash flows (cash flow hedge); as a hedge of a recognized asset,
liability or firm commitment (fair value hedge); as a normal purchase or sale
contract; or leaves the derivative undesignated and marks it to market.
For hedge contracts, Duke Energy formally assesses, both at the hedge
contract's inception and on an ongoing basis, whether the hedge contract is
highly effective in offsetting changes in fair values or cash flows of hedged
items. The time value of options of $1 million was excluded in the assessment
and measurement of hedge effectiveness for the year ended December 31, 2001.
When available, quoted market prices or prices obtained through external
sources are used to verify a contract's fair value. For contracts with a
delivery location or duration for which quoted market prices are not available,
fair value is determined based on pricing models developed primarily from
historical and expected correlations with quoted market prices.
Values are adjusted to reflect the potential impact of liquidating the
positions held in an orderly manner over a reasonable time period under current
conditions. Changes in market price and management estimates directly affect
the estimated fair value of these contracts. Accordingly, it is reasonably
possible that such estimates may change in the near term.
67
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Trading. Prior to settlement of any energy contract held for trading
purposes, a favorable or unfavorable price movement is reported as Natural Gas
and Petroleum Products Purchased, or Net Interchange and Purchased Power, in
the Consolidated Statements of Income. An offsetting amount is recorded on the
Consolidated Balance Sheets as Unrealized Gains or Unrealized Losses on
Mark-to-Market and Hedging Transactions. When a contract to sell is physically
settled, the fair value entries are reversed and the gross amount invoiced to
the customer is included as Sales, Trading and Marketing of Natural Gas and
Petroleum Products, or Trading and Marketing of Electricity, in the
Consolidated Statements of Income. Similarly, when a contract to purchase is
physically settled, the purchase price is included as Natural Gas and Petroleum
Products Purchased, or Net Interchange and Purchased Power, in the Consolidated
Statements of Income. If a contract is not financially settled, the unrealized
gain or loss on the Consolidated Balance Sheets is reversed and reclassified to
a receivable or payable account. For income statement purposes, financial
settlement has no revenue presentation effect on the Consolidated Statements of
Income.
Cash Flow Hedges. Changes in the fair value of a derivative designated and
qualified as a cash flow hedge are included in the Consolidated Statements of
Common Stockholders' Equity and Comprehensive Income as Other Comprehensive
Income (OCI) until earnings are affected by the hedged item. Settlement amounts
and ineffective portions of cash flow hedges are removed from OCI and recorded
in the Consolidated Statements of Income in the same accounts as the item being
hedged. Duke Energy discontinues hedge accounting prospectively when it is
determined that the derivative no longer qualifies as an effective hedge, or
when it is no longer probable that the hedged transaction will occur. When
hedge accounting is discontinued because the derivative no longer qualifies as
an effective hedge, the derivative continues to be carried on the Consolidated
Balance Sheets at its fair value, with subsequent changes in its fair value
recognized in current-period earnings. Gains and losses related to discontinued
hedges that were previously accumulated in OCI will remain in OCI until
earnings are affected by the hedged item, unless it is no longer probable that
the hedged transaction will occur. Gains and losses that were accumulated in
OCI will be immediately recognized in current-period earnings.
Fair Value Hedges. Duke Energy enters into interest rate swaps to convert
some of its fixed-rate long-term debt to floating-rate long-term debt and
designates such interest rate swaps as fair value hedges. Duke Energy also
enters into electricity derivative instruments such as swaps, futures and
forwards to manage the fair value risk associated with some of its unrecognized
firm commitments to sell generated power due to changes in the market price of
power. Upon designation of such derivatives as fair value hedges, prospective
changes in the fair value of the derivative and the hedged item are recognized
in current earnings in a manner consistent with the earnings effect of the
hedged risk. All components of each derivative gain or loss are included in the
assessment of hedge effectiveness, unless otherwise noted.
Goodwill. Goodwill is the cost of an acquisition less the fair value of the
net assets of the acquired business. Prior to January 1, 2002, Duke Energy
amortized goodwill on a straight-line basis over the useful lives of the
acquired assets, ranging from 10 to 40 years. The amount of goodwill reported
on the Consolidated Balance Sheets as of December 31, 2001 was $1,730 million,
net of accumulated amortization of $388 million. The amount of goodwill as of
December 31, 2000 was $1,566 million, net of accumulated amortization of $291
million. Duke Energy has implemented SFAS No. 142, "Goodwill and Other
Intangible Assets" as of January 1, 2002. For information on the impact of SFAS
No. 142 on goodwill and goodwill amortization, see the New Accounting Standards
section of this footnote. (See Note 2 for information on significant goodwill
additions.)
Property, Plant and Equipment. Property, plant and equipment are stated at
historical cost less accumulated depreciation. Duke Energy capitalizes all
construction-related direct labor and material costs, as well as indirect
construction costs. Indirect costs include general engineering, taxes and the
cost of funds used
68
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
during construction. The cost of renewals and betterments that extend the
useful life of property, plant and equipment is also capitalized. The cost of
repairs, replacements and major maintenance projects is expensed as it is
incurred. Depreciation is generally computed using the straight-line method.
The composite weighted-average depreciation rates, excluding nuclear fuel, were
4.01% for 2001, 3.97% for 2000 and 3.73% for 1999.
When Duke Energy retires its regulated property, plant and equipment, it
charges the original cost plus the cost of retirement, less salvage, to
accumulated depreciation and amortization. When it sells entire regulated
operating units, or retires or sells non-regulated properties, the property and
related accumulated depreciation and amortization accounts are reduced. Any
gain or loss is recorded as income, unless otherwise required by the Federal
Energy Regulatory Commission (FERC).
Impairment of Long-Lived Assets. Duke Energy reviews the recoverability of
long-lived and intangible assets when circumstances indicate that the carrying
amount of the asset may not be recoverable. This evaluation is based on various
analyses, including undiscounted cash flow projections.
Unamortized Debt Premium, Discount and Expense. Premiums, discounts and
expenses incurred with the issuance of outstanding long-term debt are amortized
over the terms of the debt issues. Any call premiums or unamortized expenses
associated with refinancing higher-cost debt obligations used to finance
regulated assets and operations are amortized consistent with regulatory
treatment of those items, where appropriate.
Environmental Expenditures. Duke Energy expenses environmental expenditures
that relate to conditions caused by past operations that do not generate
current or future revenues. Environmental expenditures related to operations
that generate current or future revenues are expensed or capitalized, as
appropriate. Liabilities are recorded when environmental assessments and/or
cleanups are probable and the costs can be reasonably estimated.
Cost-Based Regulation. Duke Energy's regulated operations are subject to
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." The
economic effects of regulation can result in a regulated company recording
costs that have been or are expected to be allowed in the rate-setting process
in a period different from the period in which the costs would be charged to
expense by an unregulated enterprise. Accordingly, Duke Energy records assets
and liabilities that result from the regulated ratemaking process that would
not be recorded under GAAP for non-regulated entities. These regulatory assets
and liabilities are classified in the Consolidated Balance Sheets as Regulatory
Assets and Deferred Debits, and Deferred Credits and Other Liabilities. (See
Note 4.) Duke Energy periodically evaluates the applicability of SFAS No. 71,
and considers factors such as regulatory changes and the impact of competition.
If cost-based regulation ends or competition increases, companies may have to
reduce their asset balances to reflect a market basis less than cost, and write
off their associated regulatory assets.
Stock-Based Compensation. Duke Energy accounts for stock-based compensation
under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued
to Employees," by which compensation cost is the quoted market price of Duke
Energy stock on the date of the grant minus the amount an employee must pay to
acquire the stock. Restricted stock grants and company performance awards are
recorded over the required vesting period as compensation cost, based on the
market value on the date of the grant. (See Note 17 for pro forma disclosures
using the fair value accounting method.) All outstanding common stock amounts
and compensation awards have been adjusted to reflect the two-for-one common
stock split effective January 26, 2001. (See Note 16 for more information on
the stock split.)
69
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Revenues. Revenues on sales of electricity and on natural gas transportation
and storage are recognized when the service is provided. Revenues on sales of
natural gas and petroleum products, as well as electricity, natural gas and
other energy products marketed, are recognized in the delivery period. The
allowance for doubtful accounts was $265 million as of December 31, 2001 and
$200 million as of December 31, 2000. Receivables on the Consolidated Balance
Sheets included $177 million as of December 31, 2001 and $244 million as of
December 31, 2000 for electric service provided but not yet billed. The amount
for 2001 includes a $36 million reduction in unbilled revenue receivables,
resulting from a refinement in the estimates used to calculate unbilled
kilowatt-hour sales. Pending final approval of rate cases, a portion of
revenues is subject to possible refund, and reserves are established where
required.
Long-term contracts, primarily in the Other Energy Services segment, are
accounted for using the percentage-of-completion method. Under the
percentage-of-completion method, sales and gross profit are recognized as the
work is performed based on the relationship between costs incurred and total
estimated costs at completion. Sales and gross profit are adjusted
prospectively for revisions in estimated total contract costs and contract
values. When the current estimates of total contract revenue and contract cost
indicate a loss, a provision for the entire loss on the contract is recorded in
that period. The provision for the loss arises because estimated cost for the
contract exceeds estimated revenue.
Nuclear Fuel. Amortization of nuclear fuel is included in the Consolidated
Statements of Income as Fuel Used in Electric Generation. The amortization is
recorded using the units-of-production method.
Deferred Returns and Allowance for Funds Used During Construction (AFUDC).
Deferred returns, recorded in accordance with SFAS No. 71, represent the
estimated financing costs associated with funding regulatory assets that
primarily arise from the funding of purchased capacity costs above levels
collected in rates. Deferred returns are non-cash items and are primarily
recognized as an addition to Purchased Capacity Costs, with an offsetting
credit to Other Income and Expenses. The amount of deferred returns included in
Other Income and Expenses was $43 million in 2001, $50 million in 2000 and $67
million in 1999.
AFUDC represents the estimated debt and equity costs of capital funds
necessary to finance the construction of new regulated facilities. AFUDC is a
non-cash item and is recognized as a Property, Plant and Equipment cost, with
offsetting credits to Other Income and Expenses and to Interest Expense. After
construction is completed, Duke Energy is permitted to recover these costs,
including a fair return, by including them in the rate base and in the
depreciation provision. The total amount of AFUDC included in Other Income and
Expenses and Interest Expense was $39 million in 2001, $20 million in 2000 and
$23 million in 1999.
Rates used for capitalization of deferred returns and AFUDC by Duke Energy's
regulated operations are calculated in compliance with GAAP rules.
Foreign Currency Translation. Duke Energy translates assets and liabilities
for its international operations, where the local currency is the functional
currency, at year-end exchange rates. Revenues and expenses are translated
using average exchange rates during the year. Foreign Currency Translation
Adjustments are included in the Consolidated Statements of Common Stockholders'
Equity and Comprehensive Income. In the financial statements for international
operations, where the U.S. dollar is the functional currency, transactions
denominated in the local currency have been remeasured in U.S. dollars.
Remeasurement resulting from foreign currency gains and losses is included in
consolidated net income.
70
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Income Taxes. Duke Energy and its subsidiaries file a consolidated federal
income tax return. Deferred income taxes have been provided for temporary
differences. These occur when there are differences between the GAAP and tax
carrying amounts of assets and liabilities. These differences create taxable or
tax-deductible amounts for future periods. Investment tax credits have been
deferred and are being amortized over the estimated useful lives of the related
properties.
Excise and Other Pass-Through Taxes. Duke Energy generally presents revenues
net of pass-through taxes on the Consolidated Statements of Income.
Earnings Per Common Share. Basic earnings per share is based on a simple
weighted average of common shares outstanding. Diluted earnings per share
reflects the potential dilution that could occur if securities or other
agreements to issue common stock, such as stock options and equity units, were
exercised or converted into common stock. The numerator for the calculation of
both basic and diluted earnings per share is earnings available for common
stockholders. The following table shows the denominator for basic and diluted
earnings per share.
Denominator for Earnings per Share
2001 2000 1999
----- ----- -----
In millions
Denominator for basic earnings per share (weighted-average shares
outstanding)................................................... 767.5 735.7 729.3
Assumed exercise of diluted stock equivalents.................... 5.4 3.7 1.6
----- ----- -----
Denominator for diluted earnings per share....................... 772.9 739.4 730.9
===== ===== =====
Prior years' common stock amounts have been adjusted to reflect the
two-for-one common stock split effective January 26, 2001. (See Note 16.)
Options to purchase approximately 6.0 million shares of common stock as of
December 31, 2001, 3.3 million shares as of December 31, 2000 and 4.7 million
shares as of December 31, 1999 were not included in the computation of diluted
earnings per share because the option exercise prices were greater than the
average market price of the common shares during the periods.
Cumulative Effect of Change in Accounting Principle. Duke Energy adopted
SFAS No. 133 as amended and interpreted on January 1, 2001. In accordance with
the transition provisions of SFAS No. 133, Duke Energy recorded a net-of-tax
cumulative effect adjustment of $96 million, or $0.13 per basic share, as a
reduction in earnings. The net-of-tax cumulative effect adjustment reducing OCI
and Common Stockholders' Equity was $921 million. For the 12 months ended
December 31, 2001, Duke Energy reclassified as earnings $222 million of losses
from OCI for derivatives included in the transition adjustment related to hedge
transactions that settled. The amount reclassified out of OCI will be different
from the amount included in the transition adjustment due to market price
changes since January 1, 2001.
The Financial Accounting Standards Board's (FASB) Derivative Implementation
Group (DIG), while no longer an active group, was active during 2001. In
December 2001, the DIG issued a final revision to Issue C15, "Scope Exceptions:
Normal Purchases and Normal Sales Exception for Option-Type Contracts and
Forwards Contracts in Electricity." Under the guidance of Issue C15, if certain
electricity contracts meet the criteria, they could qualify as a normal
purchase or sale under SFAS No. 133. This new guidance will be effective April
1, 2002. The original wording of Issue C15, which was effective beginning July
1, 2001, will apply through the first
71
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
quarter of 2002. For contracts previously designated as hedges, Duke Energy
treated the change as a de-designation under SFAS No. 133, and the fair value
for each qualifying contract on July 1, 2001 became the contract's net carrying
amount. Duke Energy is continuing to determine the impact of the revision on
its future consolidated results of operations, cash flows and financial
position.
Extraordinary Items. In 1999, Duke Energy realized an extraordinary
after-tax gain of $660 million, or $0.91 per share, from the sale of Panhandle
Eastern Pipe Line Company (PEPL), Trunkline Gas Company (Trunkline) and
additional storage related to those systems, along with Trunkline LNG Company,
to CMS Energy Corporation (CMS).
New Accounting Standards. In June 2001, the FASB issued SFAS No. 141,
"Business Combinations," and SFAS No. 142.
SFAS No. 141 requires that all business combinations initiated (as defined
by the standard) after June 30, 2001 be accounted for using the purchase
method. Companies may no longer use the pooling method of accounting for future
combinations.
SFAS No. 142 is effective for fiscal years beginning after December 15,
2001, and was adopted by Duke Energy as of January 1, 2002. SFAS No. 142
requires that goodwill no longer be amortized over an estimated useful life, as
previously required. Instead, goodwill amounts will be subject to a
fair-value-based annual impairment assessment. The standard also requires
certain identifiable intangible assets to be recognized separately and
amortized as appropriate. No such intangibles have been identified at Duke
Energy. Duke Energy expects the adoption of SFAS No. 142 to have an impact on
future financial statements, due to the discontinuation of goodwill
amortization expense. For 2001, pre-tax goodwill amortization expense was $101
million. The FASB and the Emerging Issues Task Force (EITF) continue to respond
to questions to clarify key aspects of SFAS No. 142. Duke Energy has determined
the effect of implementing SFAS No. 142 and does not expect to record any
impairment in 2002.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 provides the accounting requirements for retirement
obligations associated with tangible long-lived assets. It is effective for
fiscal years beginning after June 15, 2002, and early adoption is permitted.
Duke Energy is currently assessing the new standard and has not yet determined
the impact on its consolidated results of operations or financial position.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." The new rules supersede SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of." The new rules retain many of the fundamental recognition
and measurement provisions, but significantly change the criteria for
classifying an asset as held-for-sale. SFAS No. 144 is effective for fiscal
years beginning after December 15, 2001. Duke Energy has evaluated the new
standard, and management believes that it will have no material adverse effect
on Duke Energy's consolidated results of operations or financial position.
Reclassifications. Certain amounts reported in prior periods have been
reclassified in the Consolidated Financial Statements to conform to current
classifications.
72
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
2. Business Acquisitions and Dispositions
Business Acquisitions. Using the purchase method for acquisitions, Duke
Energy consolidates assets and liabilities as of the purchase date, and
includes earnings from acquisitions in consolidated earnings after the purchase
date. Assets acquired and liabilities assumed are recorded at estimated fair
values on the date of acquisition. The purchase price minus the estimated fair
value of the acquired assets and liabilities is recorded as goodwill. In
accordance with SFAS No. 142, goodwill is subject to a fair-value-based annual
impairment assessment beginning January 1, 2002. The allocation of the purchase
price may be adjusted if additional information on asset and liability
valuations becomes available within one year after the acquisition.
Market Hub Partners (MHP). In September 2000, Duke Energy, through a wholly
owned subsidiary, completed the acquisition of MHP from subsidiaries of
NiSource Inc. for approximately $250 million in cash and the assumption of $150
million in debt. MHP provides natural gas storage services in Louisiana and
Texas. Approximately $228 million of goodwill was recorded in the transaction.
MHP debt agreements required a tender offer for $115 million of the assumed
debt. As of December 31, 2001, approximately $88 million of this debt was
retired.
Phillips Petroleum's Gas Gathering, Processing and Marketing Unit. In March
2000, Duke Energy, through a wholly owned subsidiary, completed the
approximately $1.7 billion transaction that combined Field Services' and
Phillips Petroleum's gas gathering, processing and marketing business to form a
new midstream company, Duke Energy Field Services, LLC (DEFS). In connection
with the combination, DEFS issued approximately $2.75 billion of commercial
paper in April 2000 and used the proceeds to make one-time cash distributions
of approximately $1.53 billion to Duke Energy and $1.22 billion to Phillips
Petroleum. Duke Energy owns approximately 70% of DEFS and Phillips Petroleum
owns approximately 30%. Goodwill of approximately $432 million was recorded in
the transaction.
East Tennessee Natural Gas Company (ETNG). In March 2000, Duke Energy,
through a wholly owned subsidiary, completed the approximately $390 million
acquisition of ETNG from El Paso Energy. ETNG owns a 1,100-mile interstate
natural gas pipeline system that crosses Duke Energy's Texas Eastern
Transmission, LP's pipeline and serves the southeastern region of the U.S.
Goodwill of approximately $125 million was recorded in the transaction.
Dominion Resources' Hydroelectric, Natural Gas and Diesel Power Generation
Businesses. In April 2000, Duke Energy, through its wholly owned subsidiary
Duke Energy International, LLC (DEI), completed the acquisition (which began,
and parts of which had already closed, in 1999) of Dominion Resources Inc.'s
1,200-megawatt portfolio of hydroelectric, natural gas and diesel power
generation businesses in Latin America. The total purchase price was
approximately $405 million. Goodwill totaling $109 million was recorded in the
transaction.
Companhia de Geracao de Energia Eletrica Paranapanema (Paranapanema). In
January 2000, Duke Energy, through its wholly owned subsidiary DEI, completed a
series of transactions to purchase for approximately $1.03 billion an
approximate 95% interest in Paranapanema, an electric generating company in
Brazil. Goodwill of approximately $134 million was recorded in the transaction.
Acquisition of Westcoast Energy Inc. (Westcoast). On March 14, 2002, Duke
Energy acquired Westcoast for approximately $8 billion, including the
assumption of debt. Westcoast, headquartered in Vancouver, British Columbia, is
a North American energy company with interests in natural gas gathering,
processing, transmission, storage and distribution, as well as power generation
and international energy businesses. In the
73
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
transaction, a Duke Energy subsidiary acquired all of the outstanding common
shares of Westcoast in exchange for approximately 49.9 million shares of Duke
Energy common stock (including exchangeable shares of a Duke Energy Canadian
subsidiary that are substantially equivalent to and exchangeable on a
one-for-one basis for Duke Energy common stock), and approximately $1.8 billion
in cash. Under proration provisions that ensure that approximately 50% of the
total consideration is paid in cash and 50% in stock, each common share of
Westcoast entitled the holder to elect to receive $43.80 in cash (Canadian),
.7711 of a share of Duke Energy common stock or of an exchangeable share of a
Duke Energy Canadian subsidiary, or a combination thereof. The cash portion of
the consideration was funded with the proceeds from the issuance of $750
million in mandatory convertible securities (Equity Units) in November 2001
(See Note 16) along with incremental commercial paper. Duke Energy plans to
retire the commercial paper later in 2002 and replace it with permanent capital
in the form of mandatory convertible equity. The timing for the mandatory
convertible equity will be dependent on the opportunities presented and
favorable market conditions. The Westcoast acquisition was accounted for using
the purchase method of accounting.
Dispositions. BellSouth Carolina PCS. In September 2000, Duke Energy,
through its wholly owned subsidiary DukeNet Communications, LLC (DukeNet), sold
its 20% interest in BellSouth Carolina PCS for approximately $400 million to
BellSouth Corporation. Operating revenues in 2000 include the resulting pre-tax
gain of $407 million, or an after-tax gain of $0.34 per basic share.
The pro forma results of operations for acquisitions and dispositions do not
materially differ from reported results.
3. Business Segments
Duke Energy, an integrated provider of energy and energy services, offers
physical delivery and management of both electricity and natural gas throughout
the U.S. and abroad. Duke Energy provides these and other services through
seven business segments.
Franchised Electric generates, transmits, distributes and sells electricity
in central and western North Carolina and western South Carolina. It conducts
operations primarily through Duke Power and Nantahala Power and Light. These
electric operations are subject to the rules and regulations of the FERC, the
North Carolina Utilities Commission (NCUC) and the Public Service Commission of
South Carolina (PSCSC).
Natural Gas Transmission provides transportation and storage of natural gas
for customers throughout North America, primarily in the Mid-Atlantic, New
England and southeastern states. It conducts operations primarily through Duke
Energy Gas Transmission Corporation. Interstate natural gas transmission and
storage operations are subject to the FERC's rules and regulations.
Field Services gathers, processes, transports, markets and stores natural
gas and produces, transports, markets and stores NGLs. It conducts operations
primarily through DEFS, which is approximately 30% owned by Phillips Petroleum.
Field Services operates gathering systems in western Canada and 11 contiguous
states in the U.S. Those systems serve major natural gas-producing regions in
the Rocky Mountain, Permian Basin, Mid-Continent, East Texas-Austin Chalk-North
Louisiana, and onshore and offshore Gulf Coast areas.
North American Wholesale Energy (NAWE) develops, operates and manages
merchant generation facilities and engages in commodity sales and services
related to natural gas and electric power. NAWE conducts these operations
primarily through Duke Energy North America, LLC (DENA) and Duke Energy Trading
and
74
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Marketing, LLC (DETM). DETM is approximately 40% owned by Exxon Mobil
Corporation. NAWE also includes Duke Energy Merchants Holdings, LLC, which
develops new business lines in the evolving energy commodity markets other than
natural gas and power. NAWE conducts business primarily throughout the U.S. and
Canada.
International Energy develops, operates and manages natural gas
transportation and power generation facilities and engages in energy trading
and marketing of natural gas and electric power. It conducts operations
primarily through DEI and its activities target 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. (Duke Solutions). D/FD is a
50/50 partnership between Duke Energy and Fluor Enterprises, Inc., a wholly
owned subsidiary of Fluor Corporation. (See Note 8.) On January 31, 2002, Duke
Energy announced the planned sale of DE&S to Framatome ANP, Inc. and, on March
13, 2002, Duke Energy announced the planned sale of DukeSolutions to Ameresco,
Inc. (See Note 20.)
Duke Ventures is composed of other diverse businesses, operating primarily
through Crescent Resources, LLC (Crescent), DukeNet and Duke Capital Partners,
LLC (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 wholly owned merchant banking
company, provides debt and equity capital and financial advisory services to
the energy industry.
Duke Energy's reportable segments offer different products and services and
are managed separately as strategic business units. Their accounting policies
are the same as those described in Note 1. Management evaluates segment
performance based on earnings before interest and taxes (EBIT) after deducting
minority interests. EBIT is calculated as follows:
Reconciliation of Operating Income to EBIT
Years Ended December 31,
------------------------
2001 2000 1999
------ ------ ------
In millions
Operating income......... $4,100 $3,813 $1,819
Other income and expenses 156 201 224
------ ------ ------
EBIT..................... $4,256 $4,014 $2,043
====== ====== ======
EBIT is the main performance measure used by management to evaluate segment
performance. As an indicator of Duke Energy's operating performance or
liquidity, EBIT should not be considered an alternative to, or more meaningful
than, net income or cash flow as determined in accordance with GAAP. Duke
Energy's EBIT may not be comparable to a similarly titled measure of another
company.
Beginning January 1, 2001, Duke Energy discontinued allocating corporate
governance costs for its business segment analysis. Information for the 2000
and 1999 periods has been reclassified to conform to the current-year
presentation. Other Operations primarily includes certain unallocated corporate
costs.
75
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
In the accompanying table, EBIT includes intersegment sales at prices
representative of unaffiliated party transactions. Capital and investment
expenditures are gross of cash received from acquisitions. The table also
provides information on segment assets, net of intercompany advances,
intercompany notes receivable, intercompany current assets, intercompany
derivative assets and investments in subsidiaries.
Business Segment Data
Depreciation Capital and
Unaffiliated Intersegment Total and Investment Segment
Revenues Revenues Revenues EBIT Amortization Expenditures Assets
------------ ------------ -------- ------ ------------ ------------ -------
In millions
Year Ended December 31, 2001
Franchised Electric................ $ 4,737 $ 9 $ 4,746 $1,631 $ 588 $1,115 $12,964
Natural Gas Transmission........... 967 138 1,105 608 141 748 5,027
Field Services..................... 7,997 1,654 9,651 336 285 587 7,113
North American Wholesale Energy.... 42,815 382 43,197 1,351 132 3,272 14,562
International Energy............... 2,074 16 2,090 286 97 442 5,115
Other Energy Services.............. 267 298 565 (13) 42 13 145
Duke Ventures...................... 646 -- 646 183 20 773 1,926
Other Operations................... -- 62 62 (357) 31 90 2,369
Eliminations and minority interests -- (2,559) (2,559) 231 -- -- (846)
------- ------- ------- ------ ------ ------ -------
Total consolidated.............. $59,503 $ -- $59,503 $4,256 $1,336 $7,040 $48,375
======= ======= ======= ====== ====== ====== =======
Year Ended December 31, 2000
Franchised Electric................ $ 4,946 $ -- $ 4,946 $1,820 $ 565 $ 661 $12,819
Natural Gas Transmission........... 998 133 1,131 562 131 973 4,995
Field Services..................... 7,601 1,459 9,060 311 240 376 6,624
North American Wholesale Energy.... 33,590 284 33,874 434 75 1,937 28,213
International Energy............... 1,060 7 1,067 341 97 980 4,551
Other Energy Services.............. 326 369 695 (59) 13 28 543
Duke Ventures...................... 797 -- 797 568 17 643 1,967
Other Operations................... -- (134) (134) (194) 29 36 2,749
Eliminations and minority interests -- (2,118) (2,118) 231 -- -- (4,229)
------- ------- ------- ------ ------ ------ -------
Total consolidated.............. $49,318 $ -- $49,318 $4,014 $1,167 $5,634 $58,232
======= ======= ======= ====== ====== ====== =======
Year Ended December 31, 1999
Franchised Electric................ $ 4,700 $ -- $ 4,700 $ 942 $ 542 $ 759 $13,133
Natural Gas Transmission........... 1,124 106 1,230 656 126 261 3,897
Field Services..................... 2,883 707 3,590 156 131 1,630 3,565
North American Wholesale Energy.... 11,623 178 11,801 219 57 1,028 6,268
International Energy............... 323 34 357 44 58 1,779 4,459
Other Energy Services.............. 680 309 989 (86) 14 94 612
Duke Ventures...................... 433 -- 433 165 13 382 1,031
Other Operations................... -- (162) (162) (145) 27 3 1,250
Eliminations and minority interests -- (1,172) (1,172) 92 -- -- (806)
------- ------- ------- ------ ------ ------ -------
Total consolidated.............. $21,766 $ -- $21,766 $2,043 $ 968 $5,936 $33,409
======= ======= ======= ====== ====== ====== =======
76
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Geographic Data
Latin Other
U.S. Canada America Foreign Consolidated
------- ------ ------- ------- ------------
In millions
2001
Consolidated revenues........ $51,723 $5,690 $ 628 $1,462 $59,503
Consolidated long-term assets 34,150 516 2,573 1,594 38,833
2000
Consolidated revenues........ $43,282 $4,964 $ 512 $ 560 $49,318
Consolidated long-term assets 30,772 900 2,823 1,222 35,717
1999
Consolidated revenues........ $19,336 $2,007 $ 171 $ 252 $21,766
Consolidated long-term assets 22,995 250 2,708 901 26,854
4. Regulatory Matters
Regulatory Assets and Liabilities
Duke Energy's regulated operations are subject to SFAS No. 71. Accordingly,
Duke Energy records assets and liabilities that result from the regulated
ratemaking process that would not be recorded under GAAP for non-regulated
entities. (See Note 1.) The following table details Duke Energy's regulatory
assets and liabilities.
Regulatory Assets and Liabilities
December 31,
------------
Assets (Liabilities) 2001 2000
-------------------- ----- -----
In millions
Purchased capacity costs (see Note 5)........ $ 349 $ 505
Deferred debt expense........................ 203 208
Regulatory asset related to income taxes..... 510 506
Department of Energy (DOE) assessment fee (a) 53 62
Emission allowance control (a)............... 10 14
Demand-side management costs (a)............. 57 71
Environmental cleanup costs (a).............. 29 28
Nuclear property and liability reserves (b).. (100) (100)
Fuel cost liabilities (b).................... (17) (45)
-----
(a) Included in Other Regulatory Assets and Deferred Debits on the
Consolidated Balance Sheets
(b) Included in Other Deferred Credits and Other Liabilities on the
Consolidated Balance Sheets
Franchised Electric. The NCUC and the PSCSC approve rates for retail
electric sales within their states. The FERC approves Franchised Electric's
rates for electric sales to wholesale customers, excluding the other joint
owners of the Catawba Nuclear Station. Electric sales to the other joint owners
of the Catawba Nuclear Station are set through contractual agreements. (See
Note 5 for ownership interests in Catawba Nuclear Station.)
77
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Fuel costs are reviewed semiannually by the FERC and annually by the PSCSC,
with provisions for reviewing those costs in base rates. The NCUC reviews fuel
costs in rates annually and during general rate case proceedings. All
jurisdictions allow Duke Energy to adjust electric rates for past over- or
under-recovery of fuel costs. The difference between actual fuel costs incurred
for electric operations and fuel costs recovered through rates is reflected in
revenues.
In 1999 and 2000, the FERC issued its Order 2000 and Order 2000-A regarding
Regional Transmission Organizations (RTOs). These orders set minimum
characteristics and functions RTOs must meet, including independent authority
to establish the terms and conditions of transmission service over the
facilities they control. The orders provide for an open and flexible RTO
structure to meet the needs of the market, and for the possibility of incentive
ratemaking and other benefits for transmission owners that participate.
As a result of these rulemakings, Duke Energy and two other investor-owned
utilities, Carolina Power & Light Company and South Carolina Electric & Gas
Company, planned to establish GridSouth Transco, LLC (GridSouth), as an RTO
responsible for the control of the companies' combined transmission systems. In
March 2001, GridSouth received provisional approval from the FERC. However, in
July 2001, the FERC issued orders recommending that utilities throughout the
U.S. combine their transmission systems to create four large independent
regional operators, one each in the Northeast, Southeast, Midwest and West. The
FERC ordered GridSouth and other utilities in the Southeast to join in 45 days
of mediation to negotiate terms of a Southeast RTO. The FERC has not issued an
order specifically based on those proceedings.
Duke Energy, Carolina Power & Light Company and South Carolina Electric &
Gas Company remain committed to the GridSouth RTO, but due to regulatory
uncertainties in the RTO arena, the companies have withdrawn their applications
to the PSCSC and NCUC to transfer functional control of their electric
transmission assets to GridSouth. The companies intend to file new applications
before the state commissions in the near future, including a revised GridSouth
structure designed to meet the needs of customers and regulators. Also, in
January of 2002, GridSouth signed a memorandum of understanding with the
representatives of SeTrans Grid Company (SeTrans), a group of investor-owned
utilities and public power entities in several southeastern states seeking to
form an RTO, to cooperate in discussing potential operational relationships
between GridSouth and SeTrans and the structure of wholesale electric markets
in the southeast U.S.
The actual structure of GridSouth or an alternative combined transmission
structure and the date it will become operational depend upon the resolution of
all regulatory approvals and technical issues. Management believes that the
result of this process, and the establishment and operation of GridSouth or an
alternative combined transmission system structure, will have no material
adverse effect on Duke Energy's future consolidated results of operations, cash
flows or financial position.
In 2001, the NCUC and PSCSC began a joint investigation, along with the
Public Staff of the NCUC, regarding certain Duke Power regulatory accounting
entries for 1998. In its internal review of the 14 entries in question, Duke
Energy concluded that nine items were correctly classified for regulatory
accounting. Four items were incorrectly classified for regulatory purposes for
1998 only, and did not recur. The classification of the remaining item,
distributions from a mutual insurance company, is subject to differing
regulatory interpretations. Duke Energy believes this item was appropriately
classified, but is evaluating its classification for future years. As part of
their investigation, the NCUC and PSCSC have jointly engaged an independent
firm to conduct an audit of Duke Power's accounting records for reporting
periods from 1998 through June 30, 2001. Duke Energy continues to fully
cooperate with the commissions in their investigation. As requested by the
NCUC, Duke Energy has recorded the 2001 mutual insurance distribution,
approximately $33 million, in a deferred credit account on the Consolidated
Balance Sheets, pending final outcome of the independent audit.
78
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Natural Gas Transmission. In 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
interstate pipelines to 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 Duke
Energy during 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 2000, the
FERC generally denied requests for rehearing and several parties, including
Duke Energy, 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 2001, Duke Energy's interstate pipelines submitted revised pro forma tariff
sheets to update the filings originally submitted in 2000. These filings are
currently subject to review and approval by the FERC.
Management believes that the effects of these matters will have no material
adverse effect on Duke Energy's future consolidated results of operations, cash
flows or financial position.
Notice of Proposed Rulemaking (NOPR). On September 27, 2001, the FERC issued
a NOPR announcing that it is considering new regulations regarding standards of
conduct that would apply uniformly to natural gas pipelines and electric
transmitting public utilities that are currently subject to different gas or
electric standards. The proposed standards would change how companies and their
affiliates interact and share information by broadening the definition of
"affiliate" covered by the standards of conduct, from the more narrow
definition in the existing regulations. The NOPR also seeks comment on whether
the standards of conduct should be broadened to include the separation of those
involved in the bundled retail electric sales function from those in the
transmission function, as the current standards apply only to those involved in
wholesale activities. Various entities filed comments on the NOPR with the
FERC, including Duke Energy which filed on December 20, 2001. The FERC has
indicated that they appreciate the complexity of the issues and that they would
prefer having a technical conference before entering directly into a final
rulemaking. No notice of a technical conference has been given at this time.
5. Joint Ownership of Generating Facilities
Joint Ownership of Catawba Nuclear Station (a)
Ownership
Owner Interest
----- ---------
North Carolina Municipal Power Agency Number 1 (NCMPA) 37.5%
North Carolina Electric Membership Corporation (NCEMC) 28.1%
Duke Energy Corporation............................... 12.5%
Piedmont Municipal Power Agency (PMPA)................ 12.5%
Saluda River Electric Cooperative, Inc. (Saluda River) 9.4%
-----
100.0%
=====
-----
(a) Facility operated by Duke Energy
79
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
As of December 31, 2001, $536 million of property, plant and equipment and
$296 million of accumulated depreciation and amortization represented Duke
Energy's undivided interest in Catawba Nuclear Station Units 1 and 2. Duke
Energy's share of operating costs is included in the Consolidated Statements of
Income.
Contractual agreements to purchase declining percentages of the generating
capacity and energy from the station through the year 2000 resulted in
purchased capacity costs subject to rate levelization and deferral. The cost of
capacity purchased but not reflected in current rates is reported in the
Consolidated Balance Sheets as Current Portion of Purchased Capacity Costs and
Purchased Capacity Costs. Those costs were $349 million as of December 31, 2001
and $505 million as of December 31, 2000. Duke Energy expects to recover the
accumulated balance, including returns on the deferred balance, through 2004.
The amounts levelized in rates are intended to recover total costs, including
deferred returns, and are subject to adjustments, including final true-ups.
Purchased capacity and energy costs from the other joint owners were not
material for 2001, but were approximately $7 million for 2000 and $62 million
for 1999. After adjustments for current rates, these amounts are included in
the Consolidated Statements of Income as Net Interchange and Purchased Power.
The interconnection agreements also provide for supplemental power sales by
Duke Energy to the other joint owners of Catawba Nuclear Station, to satisfy
their capacity and energy needs beyond what they retain from the station or
acquire elsewhere. NCEMC, Saluda River and NCMPA have elected to buy power
outside of these contractual agreements effective January 1, 2001. Management
believes this will have no material adverse effect on Duke Energy's
consolidated results of operations, cash flows or financial position. PMPA will
continue to receive supplemental power sales from Duke Energy through December
31, 2005.
6. Income Taxes
Income Tax Expense
For the Years Ended December 31,
-----------------------------
2001 2000 1999
------ ------ -----
In millions
Current income taxes
Federal.................................. $ 826 $ 679 $ 525
State.................................... 106 109 138
Foreign.................................. 24 18 1
------ ------ -----
Total current income taxes........... 956 806 664
------ ------ -----
Deferred income taxes, net
Federal.................................. 165 187 (126)
State.................................... 9 13 (65)
Foreign.................................. 33 29 (1)
------ ------ -----
Total deferred income taxes, net..... 207 229 (192)
------ ------ -----
Investment tax credit amortization (c)...... (13) (15) (19)
------ ------ -----
Total income tax expense.................... $1,150(a) $1,020 $ 453(b)
====== ====== =====
- --------
(a) Excludes $59 million of deferred federal and state tax benefits related to
the cumulative effect of change in accounting principle recorded net of
tax. (See Note 1.)
(b) Excludes $404 million of current federal and state tax expense related to
the extraordinary item recorded net of tax. (See Note 1.)
(c) Unamortized investment tax credit was $189 million at December 31, 2001.
80
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Income Tax Expense Reconciliation to Statutory Rate
For the Years Ended December 31,
-------------------------------
2001 2000 1999
------ ------ -----
In millions
Income tax, computed at the statutory rate of 35%..... $1,100 $ 979 $ 455
Adjustments resulting from
State income tax, net of federal income tax effect. 74 75 47
Favorable resolution of federal tax issues......... (11) (18) (30)
Other items, net................................... (13) (16) (19)
------ ------ -----
Total income tax expense....................... $1,150 $1,020 $ 453
------ ------ -----
Effective tax rate.................................... 36.6% 36.5% 34.9%
====== ====== =====
Net Deferred Income Tax Liability Components
December 31,
----------------
2001 2000
------- -------
In millions
Deferred credits and other liabilities................ $ 507 $ 429
International property, plant and equipment........... 109 153
Other................................................. 58 10
------- -------
Total deferred income tax assets............... 674 592
Valuation allowance................................... (17) (9)
------- -------
Net deferred income tax assets................. 657 583
------- -------
Investments and other assets.......................... (711) (320)
Accelerated depreciation rates........................ (2,885) (2,707)
Regulatory assets and deferred debits................. (290) (326)
Regulatory asset related to restating to pre-tax basis (465) (429)
------- -------
Total deferred income tax liability............ (4,351) (3,782)
------- -------
State deferred income tax, net of federal tax effect.. (333) (320)
------- -------
Total net deferred income tax liability........ $(4,027) $(3,519)
======= =======
81
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
7. Derivative Instruments, Hedging Activities and Credit Risk
Duke Energy, 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. Duke Energy 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 for trading purposes and for activity
other than trading activity (primarily hedge strategies). The following table
shows the fair value of Duke Energy's derivative portfolio as of December 31,
2001.
Fair Value of Contracts as of December 31, 2001
Maturity
in 2005 Total
Maturity Maturity Maturity and Fair
Type of Contract in 2002 in 2003 in 2004 Thereafter Value
- ---------------- -------- -------- -------- ---------- ------
In millions
Trading contracts.............................. $353 $164 $137 $415 $1,069
Hedge contracts................................ 454 156 71 (38) 643
---- ---- ---- ---- ------
Total.......................................... $807 $320 $208 $377 $1,712
==== ==== ==== ==== ======
Commodity Cash Flow Hedges. Some Duke Energy subsidiaries are exposed to
market fluctuations in the prices of various commodities related to their
ongoing power generating and natural gas gathering, processing and marketing
activities. Duke Energy closely monitors the potential impacts of commodity
price changes and, where appropriate, enters into contracts to protect margins
for a portion of future sales and generation revenues. Duke Energy uses
commodity instruments, consisting of swaps, futures, forwards and collared
options, as cash flow hedges for natural gas, electricity and NGL transactions.
Duke Energy is hedging exposures to the price variability of these commodities
for a maximum of nine years.
The ineffective portion of commodity cash flow hedges and the amount
recognized for transactions that no longer qualified as cash flow hedges were
not material in 2001. As of December 31, 2001, $323 million of after-tax
deferred net gains on derivative instruments accumulated in OCI are expected to
be recognized in earnings during the next 12 months as the hedged transactions
occur. However, due to the volatility of the commodities markets, the
corresponding value in OCI is subject to change prior to its reclassification
into earnings.
Commodity Fair Value Hedges. Some Duke Energy subsidiaries are exposed to
changes in the fair value of unrecognized firm commitments to sell generated
power or natural gas due to market fluctuations in the underlying commodity
prices. Duke Energy actively evaluates changes in the fair value of such
unrecognized firm commitments due to commodity price changes and, where
appropriate, uses various instruments to hedge its market risk. These commodity
instruments, consisting of swaps, futures and forwards, serve as fair value
hedges for the firm commitments associated with generated power and natural gas
sales. Duke Energy is hedging exposures to the market risk of such items for a
maximum of 13 years. For 2001, the ineffective portion of commodity fair value
hedges was not material.
Trading Contracts. Duke Energy provides energy supply, structured
origination, trading and marketing, risk management and commercial optimization
services to large energy customers, energy aggregators and other wholesale
companies. These services require Duke Energy to use natural gas, electricity,
NGL and transportation derivatives and contracts that expose it to a variety of
market risks. Duke Energy manages its trading exposure
82
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
with strict policies that limit its market risk and require daily reporting of
potential financial exposure to management. These policies include statistical
risk tolerance limits using historical price movements to calculate a daily
earnings at risk measurement.
Interest Rate (Fair Value or Cash Flow) Hedges. Changes in interest rates
expose Duke Energy to risk as a result of its issuance of variable-rate debt,
fixed-to-floating interest rate swaps, commercial paper and auction market
preferred stock. Duke Energy 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. Duke Energy also enters into financial derivative
instruments, including, but not limited to, interest rate swaps, options,
swaptions and lock agreements to manage and mitigate interest rate risk
exposure. Duke Energy's existing interest rate derivative instruments and
related ineffectiveness were not material to its consolidated results of
operations, cash flows or financial position in 2001.
Interest Rate Derivatives
December 31,
-------------------------------------------------
2001 2000
------------------------ ------------------------
Notional Fair Contracts Notional Fair Contracts
Amounts Value Expire Amounts Value Expire
-------- ----- --------- -------- ----- ---------
Dollars in millions
Fixed-to-floating rate swaps........... $875 $20 2003-2019 $275 $27 2009
Cancelable fixed-to-floating rate swaps 455 7 2014-2025 630 20 2004-2022
CP(a) floating-to-fixed rate swaps..... -- -- -- 100 (1) 2001
Interest rate locks.................... -- -- -- 275 (9) 2011
-----
(a) Commercial paper
Gains and losses deferred in anticipation of planned financing transactions
on interest rate swap derivatives are included in OCI and amortized over the
life of the underlying debt once issued. These deferred gains and losses were
not material in 2001 or 2000. As a result of the interest rate swap contracts,
interest expense for the relative notional amount is recognized at the
weighted-average rates as depicted in the following table.
Weighted-Average Rates for Interest Rate Swaps
For the Years Ended
December 31,
------------------
2001 2000 1999
---- ---- ----
Fixed-to-floating rate swaps.................. 3.92% 6.50% 5.71%
Cancelable fixed-to-floating rate swaps....... 3.23% 5.09% --
Commercial paper swaps........................ -- 6.11% 4.95%
Foreign Currency (Fair Value or Cash Flow) Hedges. Duke Energy is exposed to
foreign currency risk from investments in international affiliates and
businesses owned and operated in foreign countries. To mitigate risks
associated with foreign currency fluctuations, when possible, transactions are
denominated in or indexed to the U.S. dollar and/or local inflation rates, or
investments may be hedged through debt denominated or issued in the foreign
currency. Duke Energy also uses foreign currency derivatives, where possible,
to manage its risk related to foreign currency fluctuations. In 2001, the
impact of Duke Energy's foreign currency derivative instruments was not
material to its consolidated results of operations, cash flows or financial
position.
83
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Financial Instruments. The fair value of financial instruments not currently
carried at market value is summarized in the following table. Judgment is
required in interpreting market data to develop the estimates of fair value.
Accordingly, the estimates determined as of December 31, 2001 and 2000, are not
necessarily indicative of the amounts Duke Energy could have realized in
current markets.
Financial Instruments
2001 2000
------------------- -------------------
Book Approximate Book Approximate
Value Fair Value Value Fair Value
------- ----------- ------- -----------
In millions
Long-term debt (a)....................................... $12,582 $13,239 $11,154 $11,896
Guaranteed preferred beneficial interests in subordinated
notes of Duke Energy or subsidiaries................... 1,407 1,440 1,406 1,389
Preferred stock (a)...................................... 247 242 280 275
-----
(a) Includes current maturities
The fair value of cash and cash equivalents, notes receivable, notes payable
and commercial paper are not materially different from their carrying amounts
because of the short-term nature of these instruments or because the stated
rates approximate market rates.
Credit Risk. Duke Energy's principal customers for power and natural gas
marketing services are industrial end-users and utilities located throughout
the U.S., Canada, Asia Pacific, Europe and Latin America. Duke Energy 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 Duke Energy's overall credit risk in
that certain customers may be similarly affected by changes in economic,
regulatory or other factors. Where exposed to credit risk, Duke Energy analyzes
the counterparties' financial condition prior to entering into an agreement,
establishes credit limits and monitors the appropriateness of those limits on
an ongoing basis. Duke Energy frequently uses master collateral agreements to
mitigate credit exposure. The collateral agreement provides for a counterparty
to post cash or letters of credit for exposure in excess of the established
threshold. The threshold amount represents an open credit limit, determined in
accordance with the corporate credit policy. The collateral agreement also
provides that the inability to post collateral is sufficient cause to terminate
a contract and liquidate all positions.
The change in market value of New York Mercantile Exchange-traded futures
and options contracts requires daily cash settlement in margin accounts with
brokers. Financial derivatives are generally cash settled periodically
throughout the contract term. However, these transactions are also generally
subject to margin agreements with many of Duke Energy's counterparties.
As of December 31, 2001, Duke Energy had a pre-tax bad debt provision of $90
million related to receivables for energy sales in California. (See Note 15 for
further information regarding market and credit exposure.) Following the
bankruptcy of Enron Corporation, Duke Energy terminated substantially all
contracts with Enron Corporation and its affiliated companies (collectively,
Enron). As a result, Duke Energy recorded, as a charge, a non-collateralized
accounting exposure of $43 million. The $43 million non-collateralized
accounting exposure is comprised of charges of $36 million at NAWE, $3 million
at International Energy, $3 million at Field Services and $1 million at Natural
Gas Transmission. These amounts are stated on a pre-tax basis as charges
against the reporting segment's earnings.
84
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
The transactions between Enron and Duke Energy consisted of the following:
. NAWE--forward contracts, swaps, options and physical contracts used to
trade natural gas, power, crude oil, liquefied petroleum gas and coal
. International Energy--forward contracts and options used to trade and
hedge natural gas, power and oil
. Field Services--physical purchase/sale contracts for natural gas and NGLs;
forward contracts, swaps and options used to trade natural gas and NGLs;
transportation and storage
. Natural Gas Transmission--forward financial sales of NGLs
The $43 million charge was a direct reduction to earnings before income
taxes and was a result of charging the full amount of unsettled mark-to-market
earnings previously recognized, and all derivative assets and accounts
receivable that became impaired due to Enron's financial deterioration. All
assets written off or reserved for were net of the margin (cash collateral)
posted by Enron of $330 million and applied by Duke Energy in connection with
transactions between the companies.
Duke Energy's determination of its bankruptcy claims against Enron is still
under review, and its claims made in the bankruptcy case are likely to exceed
$43 million. Any bankruptcy claims that exceed this amount would primarily
relate to termination and settlement rights under contracts and transactions
with Enron that would have been recognized in future periods, and not in the
historical periods covered by the financial statements to which the $43 million
charge relates.
Substantially all contracts with Enron were completed or terminated prior to
December 31, 2001. Duke Energy has continuing contractual relationships with
certain Enron affiliates, which are not in bankruptcy. In Brazil, a power
purchase agreement between a Duke Energy affiliate, Paranapanema, and Elektro
Eletricidade e Servicos S/A (Elektro), a distribution company 40% owned by
Enron, will expire December 31, 2005. The contract was executed by Duke
Energy's predecessor in interest in Paranapanema, and obligates Paranapanema to
provide energy to Elektro on an irrevocable basis for the contract period. In
addition, a purchase/sale agreement expiring September 1, 2005 between a Duke
Energy affiliate and Citrus Trading Corporation (Citrus), a 50/50 joint venture
between Enron and El Paso Corporation, continues to be in effect. The contract
requires the Duke Energy affiliate to provide liquefied natural gas to Citrus.
Citrus has provided a letter of credit in favor of Duke Energy to cover its
exposure.
8. Investment in Affiliates and Related Party Transactions
Investments in domestic and international affiliates that are not controlled
by Duke Energy, but over which it has significant influence, are accounted for
by the equity method. These investments include undistributed earnings of $166
million in 2001 and $70 million in 2000. Duke Energy received distributions of
$158 million in 2001, $138 million in 2000 and $111 million in 1999 from these
investments. Duke Energy's share of net income from these affiliates is
reflected in the Consolidated Statements of Income as Other Operating Revenues.
Natural Gas Transmission. Investments primarily include a 37.5% interest in
the Maritimes & Northeast Pipeline and a 50% interest in Gulfstream Natural Gas
System, LLC. The Maritimes & Northeast Pipeline is composed of Canadian and
U.S. natural gas pipeline joint ventures that together transport natural gas
into the U.S. from Canada. Gulfstream Natural Gas System, LLC is a joint
interstate natural gas pipeline development that will extend from Mississippi
and Alabama across the Gulf of Mexico to Florida.
85
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Field Services. Investments primarily include a 21.1% ownership interest in
TEPPCO Partners, LP, a publicly traded limited partnership which owns and
operates a network of pipelines for refined products and crude oil.
North American Wholesale Energy. Significant investments include a 50%
interest in American Ref-Fuel Company, LLC and a 50% interest in Southwest
Power Partners, LLC. American Ref-Fuel Company, LLC owns and operates
facilities that convert waste to energy. Southwest Power Partners, LLC is a
gas-fired combined-cycle facility under construction in Arizona. Once
completed, this facility will serve markets in Arizona, Nevada and California.
International Energy. Significant investments include 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.
Other Energy Services. Investments include participation in various
construction and support activities for fossil-fueled generating plants.
Duke Ventures. Significant investments include various real estate
development projects.
Investment in Affiliates
December 31, 2001 December 31, 2000 December 31, 1999
----------------------------- ----------------------------- -----------------------------
Domestic International Total Domestic International Total Domestic International Total
-------- ------------- ------ -------- ------------- ------ -------- ------------- ------
In millions
Natural Gas Transmission $ 565 $ 88 $ 653 $ 82 $ 88 $ 170 $ 67 $ 83 $ 150
Field Services.......... 252 -- 252 373 -- 373 439 -- 439
North American Wholesale
Energy................. 315 -- 315 635 9 644 425 -- 425
International Energy.... -- 165 165 -- 154 154 -- 224 224
Other Energy Services... 53 7 60 11 7 18 51 6 57
Duke Ventures........... 30 -- 30 23 -- 23 10 -- 10
Other Operations........ 5 -- 5 5 -- 5 -- -- --
------ ---- ------ ------ ---- ------ ---- ---- ------
Total................ $1,220 $260 $1,480 $1,129 $258 $1,387 $992 $313 $1,305
====== ==== ====== ====== ==== ====== ==== ==== ======
Equity in Earnings of Investment
For the years ended
-------------------------------------------------------------------------------------
December 31, 2001 December 31, 2000 December 31, 1999
--------------------------- --------------------------- ---------------------------
Domestic International Total Domestic International Total Domestic International Total
-------- ------------- ----- -------- ------------- ----- -------- ------------- -----
In millions
Natural Gas Transmission....... $ 38 $ 7 $ 45 $ 13 $ 4 $ 17 $ 16 $ 9 $ 25
Field Services................. 45 -- 45 39 -- 39 44 -- 44
North American Wholesale Energy 35 -- 35 36 -- 36 47 -- 47
International Energy........... -- 39 39 -- 43 43 -- 10 10
Other Energy Services.......... 49 -- 49 (13) -- (13) 10 3 13
Duke Ventures.................. 2 -- 2 (9) -- (9) (22) -- (22)
Other Operations............... (47) -- (47) (10) -- (10) (5) -- (5)
---- --- ---- ---- --- ---- ---- --- ----
Total....................... $122 $46 $168 $ 56 $47 $103 $ 90 $22 $112
==== === ==== ==== === ==== ==== === ====
86
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Summarized Combined Financial Information of Unconsolidated Affiliates
December 31,
--------------------
2001 2000 1999
------ ------ ------
In millions
Balance Sheet
Current assets......... $1,239 $1,242 $1,544
Noncurrent assets...... 8,199 6,588 7,826
Current liabilities.... 1,202 888 1,155
Noncurrent liabilities. 4,400 4,404 4,727
------ ------ ------
Net assets............. $3,836 $2,538 $3,488
====== ====== ======
Income Statement
Operating revenues..... $5,202 $4,617 $3,510
Operating expenses..... 4,525 4,039 3,104
Net income............. 499 440 193
Related Party Transactions. Outstanding notes receivable from affiliates
were $25 million as of December 31, 2001 and $70 million as of December 31,
2000.
Duke Energy and Fluor Enterprises, Inc. formed the D/FD 50/50 partnership in
1989. The partnership provides full-service siting, permitting, licensing,
engineering, procurement, construction, start-up, operating and maintenance
services for fossil-fired plants in the U.S. and internationally. D/FD is the
primary builder for NAWE's merchant generation plants currently under
construction. Fifty percent of the profit earned by D/FD for the construction
of NAWE's merchant generation plants, which is associated with Duke Energy's
ownership, is deferred in consolidation until the plant is sold as part of
NAWE's portfolio management strategy, or once the plant becomes operational it
is amortized over the plant's useful life. Fifty percent of the profit earned
by D/FD for operating and maintenance services, which is associated with Duke
Energy's ownership, is eliminated in consolidation. For the year ended December
31, 2001, Duke Energy deferred profit of $54 million for D/FD construction
contracts, and eliminated profit of $9 million for operating and maintenance
services. For the year ended December 31, 2000, Duke Energy deferred profit of
$16 million for construction contracts. There was no profit from operating and
maintenance services to be eliminated in 2000. For the year ended December 31,
1999, Duke Energy deferred profit of $6 million for construction contracts.
There was no profit from operating and maintenance services to be eliminated in
1999. In addition, as part of the D/FD partnership agreement, excess cash is
loaned at current market rates to Duke Energy and Fluor Enterprises, Inc. (See
Note 10.)
In the normal course of business, Duke Energy's consolidated subsidiaries
enter into energy trading contracts with one another. On a stand-alone basis,
the accounting for such contracts may differ by counterparty. For example,
DETM, an energy-trading subsidiary within the scope of EITF Issue No. 98-10,
"Accounting for Energy Trading and Risk Management Activities," may enter into
a contract to purchase natural gas storage from DEFS. DEFS may treat this
contract as a hedge position, and DETM may mark to market the contract through
its current earnings. In the consolidation process, the effects of this
contract are eliminated, and not reflected in Duke Energy's Consolidated
Financial Statements. In all cases, energy trading contracts (and any resulting
mark-to-market gains or losses) between consolidated subsidiaries are
eliminated in the consolidation process.
Also see Note 13, Minority Interest Financing, for additional related party
information.
87
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
9. Property, Plant and Equipment
Net Property, Plant and Equipment
December 31,
----------------
2001 2000
- ------- -------
In millions
Land.................................................. $ 49 $ 36
Plant
Electric generation, distribution and transmission. 19,792 18,669
Natural gas transmission........................... 6,200 5,449
Gathering and processing facilities................ 4,106 4,470
Other buildings and improvements................... 1,346 1,339
Leasehold improvements............................. 4 14
Nuclear fuel.......................................... 788 761
Equipment............................................. 251 108
Vehicles.............................................. 69 36
Construction in process............................... 5,068 2,192
Other................................................. 1,791 1,524
------- -------
Total property, plant and equipment............ 39,464 34,598
Total accumulated depreciation (a)............. (11,049) (10,146)
------- -------
Total net property, plant and equipment........ $28,415 $24,452
======= =======
- --------
(a) Includes accumulated amortization of nuclear fuel: 2001--$546 million;
2000--$503 million
Capitalized interest of $167 million for 2001, $67 million for 2000 and $52
million for 1999 is included in the Consolidated Statements of Income.
10. Debt and Credit Facilities
Debt
December 31,
--------------
Year Due 2001 2000
---------- ------ ------
In millions
Duke Energy
First and refunding mortgage bonds
6.125%--6.625%......................................... 2003 $ 175 $ 175
6.75%--7.5%............................................ 2023--2025 450 450
7.0%--8.95%............................................ 2027--2033 165 165
Pollution control debt, 3.85%--5.8%....................... 2012--2017 172 172
Notes
5.375%--9.21%.......................................... 2009--2016 809 811
6.0%--6.6%............................................. 2028--2038 500 500
Commercial paper, 1.93% and 6.52% weighted-average rate at
December 31, 2001 and 2000, respectively (a)............ 1,087 1,256
Other debt................................................ 19 18
Fair value hedge carrying value adjustment................ 2010--2014 (10) --
Notes matured during 2001................................. -- 661
(Table continued on next page)
88
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Debt (continued)
December 31,
--------------
Year Due 2001 2000
---------- ------ ------
In millions
Duke Capital Corporation(b)
Senior notes
4.73%--7.5%................................................. 2003--2009 $1,400 $1,400
6.75%--8.5%................................................. 2018--2019 650 650
4.32%(c).................................................... 2006 750 --
5.87%(c).................................................... 2006 875 --
Commercial paper, 2.16% and 6.71% weighted-average rate at
December 31, 2001 and 2000, respectively (a)................. 1,456 1,378
Note payable to D/FD, 4.05% and 6.14% weighted-average rate at
December 31, 2001 and 2000, respectively..................... 568 141
Fair value hedge carrying value adjustment..................... 2009--2025 30 --
Subsidiary Debt Guaranteed by Duke Capital Corporation
Duke Energy Australia Pty Ltd.
Medium-term note, 7.25% (d)................................. 2004 128 139
Credit facilities, 6.41% and 6.13% weighted-average rate at
December 31, 2001 and 2000, respectively.................. 38 44
Commercial paper, 5.96% and 6.4% weighted-average rate at
December 31, 2001 and 2000, respectively (d).............. 231 223
Hidroelectrica Cerros Colorados S.A.
Notes, 3.8%................................................. 2002 68 95
Duke Energy South Bay, LLC
Capital leases.............................................. 2009 94 272
PanEnergy Corp
Bonds
7.75%....................................................... 2022 328 328
8.625% debentures........................................... 2025 100 100
Notes, 7.0%--9.9%, maturing serially........................... 2003--2006 372 384
Fair value hedge carrying value adjustment..................... 7 --
Texas Eastern Transmission, LP
Notes
7.3%--8.25%................................................. 2002--2010 500 500
Medium-term, Series A, 7.92%--9.07%......................... 2004--2012 35 51
Notes matured during 2001...................................... -- 100
Algonquin Gas Transmission Company
Notes, 9.13%................................................... 2002--2003 67 100
Duke Energy Field Services, LLC
Notes
7.5%--8.125%................................................ 2005--2030 1,700 1,700
5.75%--6.875%............................................... 2006--2011 550 --
Commercial paper, 2.53% and 7.39% weighted-average rate at
December 31, 2001 and 2000, respectively..................... 213 346
Capital leases................................................. 3 --
Fair value hedge carrying value adjustment..................... 2009--2025 (5) --
Crescent, LLC (e)
Construction and mortgage loans, 2.73%--10.0%.................. 2002--2005 73 67
(Table continued on next page)
89
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Debt (continued)
December 31,
----------------
Year Due 2001 2000
---------- ------- -------
In millions
Other Debt of Subsidiaries
Duke Energy Western Australia Holdings
Notes, 5.35% (d).......................... 2004--2013 $ 124 $ 138
Paranapanema
Notes, 6.0%--10.0% (f).................... 2002--2017 427 477
Duke Energy Vermillion
Notes, 6.8%............................... 2002 5 --
Other international debt of subsidiaries..... 76 127
Other domestic debt of subsidiaries.......... 61 103
Unamortized debt discount and premium, net... (106) (91)
------- -------
Total debt................................... 14,185 12,980
Current maturities of long-term debt......... (261) (437)
Short-term notes payable and commercial paper (1,603) (1,826)
------- -------
Total long-term debt......................... $12,321 $10,717
======= =======
- --------
(a) Amounts include extendible commercial notes.
(b) Duke Capital Corporation is a wholly owned subsidiary of Duke Energy that
provides financing and credit enhancement services for its subsidiaries.
(c) Component of Equity Units (See Note 16.)
(d) Debt denominated in Australian dollars
(e) A portion of Crescent's real estate development projects, land and
buildings are pledged as collateral.
(f) Debt denominated in Brazilian reais and principal is indexed annually to
inflation
In January 2002, Duke Energy issued $750 million of 6.25% senior unsecured
bonds due in 2012 and $250 million of floating rate (based on the three-month
London Interbank Offered Rate (LIBOR) plus 0.35%) senior unsecured bonds due in
2005. The proceeds from these issuances were used to manage working capital
needs.
In February 2002, Duke Capital Corporation issued $500 million of 6.25%
senior unsecured bonds due in 2013 and $250 million of 6.75% senior unsecured
bonds due in 2032. In addition, Duke Capital Corporation, through a private
placement transaction, issued $500 million of floating rate (based on the
one-month LIBOR plus 0.65%) senior unsecured bonds due in 2003.
The weighted-average interest rate on outstanding short-term notes payable
and commercial paper was 3.13% as of December 31, 2001 and 6.8% as of December
31, 2000.
In millions
Annual Maturities -----------
2002................ $ 261
2003................ 576
2004................ 883
2005................ 1,016
2006................ 2,101
Thereafter.......... 7,745
-------
Total long-term debt $12,582
=======
90
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Annual maturities after 2006 include $1,360 million of long-term debt with
call options, meaning Duke Energy has the option to repay the debt early. Based
on the years in which Duke Energy may first exercise its redemption options, it
could potentially repay $1,033 million in 2002, $227 million in 2003 and $100
million in 2005.
In 2000, Duke Energy issued $250 million 7.125% senior unsecured bonds due
in 2012 with a put option that gives investors the choice to put the bond to
Duke Energy at par value in September 2002 or extend the maturity until 2012.
If extended, the bonds would be recouponed at 5.7% plus the Duke Energy 10-year
credit spread on the extension date. Also in 2000, Duke Capital Corporation
issued $150 million senior unsecured bonds due in 2003 that become due and
payable if Duke Capital Corporation's debt ratings fall below BBB.
Credit Facilities
December 31, 2001 December 31, 2000
---------------------- ----------------------
Credit Credit
Facilities Outstanding Facilities Outstanding
---------- ----------- ---------- -----------
In millions
Bridge facility.................... $ 250 $ -- $ -- $ --
364-day facilities (a)............. 2,716 -- 1,796 --
Three-year revolving facilities (a) 1,640 38 84 44
Four-year revolving facilities..... -- -- 125 --
Five-year revolving facilities (a). -- -- 2,200 --
------ ---- ------ -----
Total consolidated.............. $4,606 $ 38 $4,205 $ 44
====== ==== ====== =====
-----
(a) Majority of facilities support commercial paper facilities
The credit facilities expire from 2002 to 2004 and are not subject to
minimum cash requirements; however, borrowings and issuances of letters of
credit under approximately $1,100 million of these facilities are subject to
and dependent on the senior unsecured debt ratings of Duke Capital Corporation
(currently rated A3/A/A). Ratings of Baa2, BBB or the equivalent by at least
two of Moody's Investors Service, Standard & Poor's and Fitch, Inc. must be
maintained to obtain additional borrowings and issuances of letters of credit.
Any outstanding borrowings would not become due and payable.
11. Nuclear Decommissioning Costs
Nuclear Decommissioning Costs. Estimated site-specific nuclear
decommissioning costs, including the cost of decommissioning plant components
not subject to radioactive contamination, total approximately $1.9 billion
stated in 1999 dollars based on decommissioning studies completed in 1999
(studies are completed every five years). This includes costs related to Duke
Energy's 12.5% ownership in the Catawba Nuclear Station. The other joint owners
of the Catawba Nuclear Station are responsible for decommissioning costs
related to their ownership interests in the station. Both the NCUC and the
PSCSC have allowed Duke Energy to recover estimated decommissioning costs
through retail rates over the expected remaining service periods of Duke
Energy's nuclear stations. The operating licenses for Duke Energy's nuclear
units are subject to extension. In 2000, Duke Energy was granted a license
renewal for the Oconee Nuclear Station. Applications to renew the operating
licenses for Duke Energy's other nuclear units were filed with the Nuclear
Regulatory Commission (NRC) in June 2001. Duke Energy's nuclear units are
currently licensed as shown in the following table.
91
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Operating Licenses for Nuclear Units
Unit Year
---- ----
McGuire 1..... 2021
McGuire 2..... 2023
Catawba 1..... 2024
Catawba 2..... 2026
Oconee 1 and 2 2033
Oconee 3...... 2034
During 2001 and 2000, Duke Energy expensed approximately $57 million, and a
corresponding amount of cash was contributed to external funds for
decommissioning costs, and accrued an additional $8 million to the internal
reserve. Nuclear units are depreciated at an annual rate of 4.7%, of which
1.61% is for decommissioning. The balance of the external funds was $716
million as of December 31, 2001 and $717 million as of December 31, 2000, and
is reflected in the Consolidated Balance Sheets as Nuclear Decommissioning
Trust Funds (asset) and Nuclear Decommissioning Costs Externally Funded
(liability). The balance of the internal reserve was $239 million as of
December 31, 2001 and $231 million as of December 31, 2000, and is reflected in
the Consolidated Balance Sheets as Accumulated Depreciation and Amortization.
The external decommissioning trust fund is invested primarily in domestic and
international equity securities, fixed-rate, fixed-income securities and cash
and cash equivalents. Duke Energy has an agreement with the NRC that these
funds will only be used for activities relating to nuclear decommissioning.
These investments are exposed to price fluctuations in equity markets and
changes in interest rates. Because the accounting for nuclear decommissioning
recognizes that costs are recovered through Franchised Electric's rates,
fluctuations in equity prices or interest rates do not affect consolidated
results of operations, cash flows or financial position. Management believes
that the decommissioning costs being recovered through rates, when coupled with
expected fund earnings, are sufficient to provide for the cost of
decommissioning.
A provision in the Energy Policy Act of 1992 established a fund for the
decontamination and decommissioning of the DOE's uranium enrichment plants (the
D&D Fund). Licensees are subject to an annual assessment for 15 years based on
their pro rata share of past enrichment services. In 1998, Duke Energy and 21
other utilities filed a lawsuit challenging the constitutionality of the D&D
Fund and seeking an injunction that prohibits the government from collecting
the assessment and refunds all assessments paid. The annual assessment is
recorded in the Consolidated Statements of Income as Fuel Used in Electric
Generation. Duke Energy has paid $96 million into the fund, including $11
million during 2001. The remaining liability and regulatory assets of $53
million as of December 31, 2001 and $62 million as of December 31, 2000 are
reflected in the Consolidated Balance Sheets as Deferred Credits and Other
Liabilities, and Regulatory Assets and Deferred Debits.
Spent Nuclear Fuel. Under provisions of the Nuclear Waste Policy Act of
1982, Duke Energy has entered into contracts with the DOE for the disposal of
spent nuclear fuel. The DOE failed to begin accepting spent nuclear fuel on
January 31, 1998, the date specified by the Nuclear Waste Policy Act and in
Duke Energy's contract with the DOE. In 1998, Duke Energy filed a claim with
the U.S. Court of Federal Claims against the DOE related to the DOE's failure
to accept commercial spent nuclear fuel by the required date. Damages claimed
in the lawsuit are based upon Duke Energy's costs incurred as a result of the
DOE's partial material breach of its contract, including the cost of securing
additional spent fuel storage capacity. Duke Energy will continue to safely
manage its spent nuclear fuel until the DOE accepts it. Payments made to the
DOE for disposal costs are based on nuclear output and are included in the
Consolidated Statements of Income as Fuel Used in Electric Generation.
92
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
12. Guaranteed Preferred Beneficial Interests in Subordinated Notes of Duke
Energy or Subsidiaries
Duke Energy and one of its subsidiaries have formed business trusts for
which they own all the common securities. The trusts issue and sell preferred
securities and invest the gross proceeds in junior subordinated notes issued by
the respective parent companies.
Trust Preferred Securities
December 31,
--------------
Issued Rate Due 2001 2000
------ ----- ---- ------ ------
In millions
1997..................... 7.20% 2037 $ 350 $ 350
1998..................... 7.375% 2038 350 350
1998..................... 7.375% 2038 250 250
1999..................... 8.375% 2029 250 250
1999..................... 7.20% 2039 250 250
Unamortized debt discount (43) (44)
------ ------
$1,407 $1,406
====== ======
These trust preferred securities represent preferred undivided beneficial
interests in the assets of the respective trusts. Distribution payments on
these preferred securities are guaranteed by the respective parent companies,
but only to the extent that the trusts have funds legally and immediately
available to make distributions. Dividends related to the trust preferred
securities were $108 million for 2001, $108 million for 2000 and $87 million
for 1999, and have been included in the Consolidated Statements of Income as
Minority Interest Expense.
13. Minority Interest Financing
In 2000, Catawba River Associates, LLC (Catawba), a fully consolidated
financing entity managed by a subsidiary of Duke Energy, issued $1,025 million
of preferred member interests to a third-party investor. Catawba subsequently
advanced the proceeds from the sale to DE Power Generation, LLC (DEPG), a
wholly owned subsidiary of Duke Energy, which indirectly owns or leases six
merchant power generation facilities located in California, Maine and Indiana.
Catawba is a limited liability company with a separate existence and identity
from its preferred members, and the assets of Catawba are separate and legally
distinct from Duke Energy. The preferred member interests receive quarterly a
preferred return equal to an adjusted floating reference rate (approximately
5.20% for the full year ended December 31, 2001).
The purpose of the transaction was to reimburse Duke Energy for a portion of
its prior investment in the DEPG assets in a separate venture financing with
third-party investors not requiring direct recourse to the credit of Duke
Energy. The results of operations, cash flows and financial position of Catawba
are consolidated with Duke Energy for financial reporting purposes. The
preferred member interests are included in Minority Interest in Financing
Subsidiary on the Consolidated Balance Sheets, and the payments made with
respect to the preferred return are included in Minority Interest Expense on
the Consolidated Statements of Income of Duke Energy.
The initial term of the financing ends in September 2005, at which time
Catawba must either (a) reset the preferred rate as agreed by the existing
preferred investors, (b) re-market the preferred member interests to other
preferred investors, (c) redeem the outstanding preferred member interests, in
whole or in part, plus any accrued and unpaid return, or (d) commence an
orderly liquidation of DEPG and Catawba. This could impact Duke
93
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Energy's liquidity at the time if it were to elect to redeem the preferred
member interests or, alternatively, result in the loss of the future associated
earnings contribution to Duke Energy of the assets of DEPG in the event of an
orderly liquidation.
Duke Energy and Catawba have the right to redeem the preferred member
interests at any time, and the holder of the preferred member interests may
require an early liquidation of the assets of DEPG and Catawba and a redemption
of the preferred member interests from the available liquidation proceeds upon
the occurrence of specified events (such as failure to make required payments
or to perform other obligations).
Duke Capital Corporation has the right to borrow certain amounts from DEPG
and Catawba as demand loans. If Duke Capital Corporation's credit rating
(currently A3/A) declines below investment grade (Baa3/BBB-), the preferred
members may and will likely require that these loans be repaid. In addition, if
there were such a downgrade, the preferred investor could cause an increase in
the quarterly payments and a recharacterization of the preferred member
interests as a debt obligation on the Consolidated Financial Statements of Duke
Energy.
14. Preferred and Preference Stock
Authorized Shares of Stock as of December 31, 2001 and 2000
Par Value Shares
--------- -----------
In millions
Preferred Stock.. $100 12.5
Preferred Stock A $ 25 10.0
Preference Stock. $100 1.5
As of December 31, 2001 and 2000, there were no shares of preference stock
outstanding.
Preferred Stock with Sinking Fund Requirements
December 31,
Share Outstanding -------------------
Rate/Series Year Issued at December 31, 2001 2001 2000
- ----------- ----------- -------------------- ---- ----
Dollars in millions
6.20% D (Preferred Stock A) 1992 -- $ -- $20
6.30% U.................... 1992 -- -- 13
6.40% V.................... 1992 130,000 13 13
6.75% X.................... 1993 250,000 25 25
---- ---
Total...................... $ 38 $71
==== ===
The annual sinking fund requirements are $13 million for 2002 and $2 million
each year for 2003 through 2006. Additional redemptions are permitted at Duke
Energy's option.
94
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Preferred Stock without Sinking Fund Requirements
December 31,
Shares Outstanding -------------------
Rate/Series Year Issued at December 31, 2001 2001 2000
- ----------- ----------- -------------------- ---- ----
Dollars in millions
4.50% C................... 1964 175,000 $ 18 $ 18
7.85% S................... 1992 300,000 30 30
7.00% W................... 1993 249,989 25 25
7.04% Y................... 1993 299,995 30 30
6.375% (Preferred Stock A) 1993 1,257,185 31 31
Auction Series A.......... 1990 750,000 75 75
---- ----
Total..................... $209 $209
==== ====
The call provisions for outstanding preferred stock specify redemption
prices not exceeding 104% of par value, plus accumulated dividends to the
redemption date.
15. Commitments and Contingencies
Nuclear Insurance. Duke Energy owns and operates the McGuire and Oconee
Nuclear Stations and operates and has a partial ownership interest in the
Catawba Nuclear Station. The McGuire and Catawba Nuclear Stations have two
nuclear reactors each and Oconee has three. Nuclear insurance includes:
liability coverage; property, decontamination and decommissioning coverage; and
business interruption and/or extra expense coverage. The other joint owners of
the Catawba Nuclear Station reimburse Duke Energy for certain expenses
associated with nuclear insurance premiums.
The Price-Anderson Act requires Duke Energy to insure against public
liability claims resulting from nuclear incidents to the full limit of
liability, approximately $9.5 billion.
Primary Liability Insurance. Duke Energy has purchased the maximum required
private primary liability insurance, $200 million, along with a like amount to
cover certain worker tort claims.
Excess Liability Insurance. This policy currently provides approximately
$9.3 billion of coverage through the Price-Anderson Act's mandatory
industry-wide excess secondary insurance program of risk pooling. The $9.3
billion is the sum of the current potential cumulative retrospective premium
assessments of $88 million per licensed commercial nuclear reactor. This would
be increased by $88 million for each additional commercial nuclear reactor
licensed, or reduced by $88 million for nuclear reactors no longer operational
and may be exempted from the risk pooling insurance program. Under this
program, licensees could be assessed retrospective premiums to compensate for
damages in the event of a nuclear incident at any licensed facility in the U.S.
If such an incident should occur and public liability damages exceed primary
insurances, licensees may be assessed up to $88 million for each of their
licensed reactors, payable at a rate not to exceed $10 million a year per
licensed reactor for each incident. The $88 million is subject to indexing for
inflation and may be subject to state premium taxes.
Duke Energy is a member of Nuclear Electric Insurance Limited (NEIL), which
provides property and business interruption insurance coverage for Duke
Energy's nuclear facilities under three policy programs:
Primary Property Insurance. This policy provides $500 million of primary
property damage coverage for each of Duke Energy's nuclear facilities.
95
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Excess Property Insurance. This policy provides excess property,
decontamination and decommissioning liability insurance: $2.25 billion for the
Catawba Nuclear Station and $1.5 billion each for the Oconee and McGuire
Nuclear Stations.
Business Interruption Insurance. This policy provides business interruption
and/or extra expense coverage resulting from an accidental outage of a nuclear
unit. Each McGuire and Catawba unit is insured for up to approximately $4
million per week, and the Oconee units are insured for up to approximately $3
million per week. Coverage amounts decline if more than one unit is involved in
an accidental outage. Initial coverage begins after a 12-week deductible period
and continues at 100% for 52 weeks and 80% for the next 110 weeks.
If NEIL's losses exceed its reserves for any of the above three programs,
Duke Energy is liable for assessments of up to 10 times its annual premiums.
The current potential maximum assessments are: Primary Property Insurance--$31
million, Excess Property Insurance--$36 million and Business Interruption
Insurance--$29 million.
The other joint owners of the Catawba Nuclear Station are obligated to
assume their pro rata share of liability for retrospective premiums and other
premium assessments resulting from the Price-Anderson Act's excess secondary
insurance program of risk pooling, or the NEIL policies.
Environmental. Duke Energy is subject to international, federal, state and
local regulations regarding air and water quality, hazardous and solid waste
disposal and other environmental matters.
Manufactured Gas Plants and Superfund Sites. Duke Energy operated
manufactured gas plants until the early 1950s and has entered into a
cooperative effort with the State of North Carolina and other owners of former
manufactured gas plant sites to investigate and, where necessary, remediate
those contaminated sites. Regulators consider Duke Energy to be a potentially
responsible party, possibly subject to future liability at six federal and two
state Superfund sites. While remediation costs may be substantial, Duke Energy
will share in any liability associated with contamination at these sites with
other potentially responsible parties. Management believes that resolution of
these matters will have no material adverse effect on consolidated results of
operations, cash flows or financial position.
PCB (Polychlorinated Biphenyl) Assessment and Cleanup Programs. In 2001,
Texas Eastern Transmission, LP, a wholly owned subsidiary of Duke Energy,
completed the remaining requirements of a 1989 U.S. Consent Decree regarding
the cleanup of PCB-contaminated sites. The Environmental Protection Agency
(EPA) certified the completion of all work under the Consent Decree in January
2002. Monitoring of groundwater and remediation at certain sites may continue
as required by various state authorities.
In March 1999, Duke Energy sold PEPL and Trunkline to CMS. (See Note 1 for
more information on the sale of the pipelines.) Under the terms of the sales
agreement with CMS, Duke Energy 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 Duke Energy's experience to date and costs incurred for cleanup,
management believes the resolution of matters relating to the environmental
issues discussed above will have no material adverse effect on consolidated
results of operations, cash flows or financial position.
Air Quality Control. In 1998, the EPA issued a final rule on regional ozone
control that required 22 eastern states and the District of Columbia to revise
their State Implementation Plans (SIPs) to significantly reduce
96
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
emissions of nitrogen oxide by May 1, 2003. The EPA rule was challenged in
court by various states, industry and other interests, including Duke Energy
and the states of North Carolina and South Carolina. In 2000, the court upheld
most aspects of the EPA rule. The same court subsequently extended the
compliance deadline for implementation of emission reductions to May 31, 2004.
In 2000, the EPA finalized another ozone-related rule under Section 126 of
the Clean Air Act (CAA). Section 126 of the CAA has virtually identical
emission control requirements as the 1998 action, and specified a May 1, 2003
compliance date. While the emission reduction requirements of the rule have
been upheld in court, the implementation date for the rule has been revised to
May 2004 as a result of a legal challenge and the resulting court order.
Both North Carolina and South Carolina have revised their SIPs in response
to the EPA's 1998 rule, and are awaiting EPA approval. Legislation was
introduced in the North Carolina General Assembly in 2001 and passed by the
state Senate that would require North Carolina electric utilities, including
Duke Energy, to make significant reductions in emissions of sulfur dioxide and
nitrogen oxides from coal-fired power plants over the next seven to 11 years. A
provision in the proposed North Carolina legislation allows Duke Energy to
recover costs of achieving the proposed emission reductions from customers
through an environmental compliance expenditure-recovery factor that is
separate from the electric utility's base rates. If passed into law, the final
provisions could be significantly different from the proposal.
Emission control retrofits needed to comply with the new rules are large
technical, design and construction projects. These projects will be managed
closely to ensure the continuation of reliable electric service to Duke
Energy's customers throughout the projects and upon their completion.
In 2000, the U.S. Justice Department, acting on behalf of the EPA, filed a
complaint against Duke Energy in the U.S. District Court in Greensboro, North
Carolina, for alleged violations of the New Source Review (NSR) provisions of
the CAA. The EPA claims that 29 projects performed at 25 of Duke Energy's
coal-fired units were major modifications, as defined in the CAA, and that Duke
Energy violated the CAA's NSR requirements when it undertook those projects
without obtaining permits and installing emission controls for sulfur dioxide,
nitrogen oxide and particulate matter. The complaint asks the court to order
Duke Energy to stop operating the coal-fired units identified in the complaint,
install additional emission controls and pay unspecified civil penalties. This
complaint is part of the EPA's NSR enforcement initiative, in which the EPA
claims that utilities and others have committed widespread violations of the
CAA permitting requirements for the past 25 years. The EPA has sued or issued
notices of violation of investigative information requests to at least 48 other
electric utilities and cooperatives.
The EPA's allegations run counter to previous EPA guidance regarding the
applicability of the NSR permitting requirements. Duke Energy, along with other
utilities, has routinely undertaken the type of repair, replacement and
maintenance projects that the EPA now claims are illegal. Duke Energy believes
that all of its electric generation units are properly permitted and have been
properly maintained, and is defending itself vigorously against these alleged
violations. The U.S. Vice President's National Energy Policy Development Group
has ordered the EPA to review its NSR rules and has ordered the Department of
Justice to review the appropriateness of the enforcement cases. The EPA review
was scheduled to be completed by August 2001, but has not yet been concluded.
In January 2002, the Department of Justice released a report concluding that it
was not improper for the Department of Justice to initiate the enforcement
cases brought on behalf of the EPA. It specifically declined to address whether
the EPA's enforcement actions are wise as a matter of national energy policy.
Because these matters are in a preliminary stage, management cannot estimate
the effects of these matters on Duke Energy's future consolidated results of
operations, cash flows or financial position. The CAA authorizes
97
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
civil penalties of up to $27,500 per day per violation at each generating unit.
Civil penalties, if ultimately imposed by the court, and the cost of any
required new pollution control equipment, if the court accepts the EPA's
contentions, could be substantial.
California Issues. Duke Energy, some of its subsidiaries and three current
or former executives have been named as defendants, among other corporate and
individual defendants, in one or more of a total of six lawsuits brought by or
on behalf of electricity consumers in the State of California. The plaintiffs
seek damages as a result of the defendants' alleged unlawful manipulation of
the California wholesale electricity markets. DENA and DETM are among 16
defendants in a class-action lawsuit (the Gordon lawsuit) filed against
generators and traders of electricity in California markets. DETM was also
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, traders and other unnamed providers of electricity in
California markets. A sixth lawsuit (the Bustamante lawsuit) was brought by the
Lieutenant Governor of the State of California and a State Assemblywoman, on
their own behalf as citizens and on behalf of the general public, and includes
Duke Energy, some of its subsidiaries and three current or former executives of
Duke Energy among other corporate and individual defendants. The Gordon and
Hendricks class-action lawsuits were filed in the Superior Court of the State
of California, San Diego County, in November 2000. Three other lawsuits were
filed in January 2001, one in Superior Court, San Diego County, and the other
two in Superior Court, County of San Francisco. The Bustamante lawsuit was
filed in May 2001 in Superior Court, Los Angeles County. These lawsuits
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. The plaintiffs seek aggregate damages of
billions of dollars. The lawsuits seek the refund of alleged unlawfully
obtained revenues for electricity sales and, in four lawsuits, an award of
treble damages. These suits have been consolidated before a state court judge
in San Diego. While these matters are in their earliest stages, management
believes, based on its analysis of the facts and the asserted claims, that
their resolution will have no material adverse effect on Duke Energy's
consolidated results of operations, cash flows or financial position.
In addition to the lawsuits, several investigations and regulatory
proceedings at the state and federal levels are looking into the causes of high
wholesale electricity prices in the western U.S. At the federal level, numerous
proceedings are before the FERC. Some parties to those proceedings have made
claims for billions of dollars of refunds from sellers of wholesale
electricity, including DETM. Some parties have also sought to revoke the
authority of DETM and other DENA-affiliated electricity marketers to sell
electricity at market-based rates. The FERC is also conducting its own
wholesale pricing investigation. As a result, the FERC has ordered some
sellers, including DETM, to refund, or to offset against outstanding accounts
receivable, amounts billed for electricity sales in excess of a
FERC-established proxy price. The proxy price represents what the FERC believes
would have been the market-clearing price in a perfectly competitive market. In
June 2001, DETM offset approximately $20 million against amounts owed by the
California Independent System Operator and the California Power Exchange for
electricity sales during January and February 2001. This offset reduced the
$110 million reserve established in 2000 to $90 million. Proceedings are
ongoing to determine, among other issues, the amount of any refunds or offsets
for periods prior to January 2001, and the method to be used to determine the
proxy price in future months.
At the state level, the California Public Utilities Commission is conducting
formal and informal investigations to determine if power plant operators in
California, including some Duke Energy entities, have improperly "withheld,"
either economically or physically, generation output from the market to
manipulate market prices. In addition, the California State Senate formed a
Select Committee to Investigate Price Manipulation of the Wholesale Energy
Market (Select Committee). The Select Committee has served a subpoena
98
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
on Duke Energy and some of its subsidiaries seeking data concerning their
California market activities. The Select Committee has heard testimony from
several witnesses but no one from Duke Energy has yet been subpoenaed to
testify.
The California Attorney General is also conducting an investigation to
determine if any market participants engaged in illegal activity, including
antitrust violations, in the course of their electricity sales into wholesale
markets in the western U.S. The Attorneys General of Washington and Oregon are
participating in the California Attorney General's investigation. The San Diego
District Attorney is conducting a separate investigation into market activities
and has issued subpoenas to DETM and a DENA subsidiary. The California Attorney
General has also convened a grand jury to determine whether criminal charges
should be brought against any market participants. To date, no Duke Energy
employee has been called to testify before the grand jury nor have any criminal
charges been filed against Duke Energy or any of its officers, directors or
employees in connection with the wholesale electricity markets in the states of
the western U.S.
Throughout 2001, Duke Energy conducted its business in California to supply
the maximum possible electricity to meet the needs of the state, limit its
exposure to non-creditworthy counterparties and manage the output limitations
on its power plants imposed by applicable permits and laws. Since December 31,
2000, Duke Energy has closely managed the balance of doubtful receivables, and
believes that the current pre-tax bad debt provision of $90 million is
appropriate. No additional provisions for California receivables were recorded
in 2001. Management believes, based on its analysis of the facts and the
asserted claims, that the resolution of these matters will have no material
adverse effect on Duke Energy's consolidated results of operations, cash flows
or financial position.
Litigation and Contingencies. Exxon Mobil Corporation Arbitration. In 2000,
three Duke Energy subsidiaries initiated binding arbitration against three
Exxon Mobil Corporation subsidiaries (the Exxon Mobil entities) concerning the
parties' joint ownership of DETM and related affiliates (the Ventures). At
issue is a buy-out right provision under the joint venture agreements for these
entities. If there is a material business dispute between the parties, which
Duke Energy alleges has occurred, the buy-out provision gives Duke Energy the
right to purchase Exxon Mobil's 40% interest in DETM. Exxon Mobil does not have
a similar right under the joint venture agreements and once Duke Energy
exercises the buy-out right, each party has the right to "unwind" the buy-out
under certain specific circumstances. In December 2000, Duke Energy exercised
its right to buy the Exxon Mobil entities' interest in the Ventures. Duke
Energy 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. Duke Energy has also made additional claims against the Exxon Mobil
entities for breach of the agreements governing the Ventures.
In January 2001, the Exxon Mobil entities made counterclaims in the
arbitration and, in a separate Texas state court action, alleged that Duke
Energy breached its obligations to the Ventures and to the Exxon Mobil
entities. In April 2001, the state court stayed its action, compelling the
Exxon Mobil entities to arbitrate their claims. The Exxon Mobil entities
proceeded with the arbitration of their claims and have not challenged this
order in an appellate court. In early October 2001, the arbitration panel
convened an evidentiary hearing regarding the buy-out right provision and Duke
Energy's and Exxon Mobil's claims against each other. The panel has not yet
ruled but Duke Energy expects a final decision from the panel in early 2002.
Management believes that the final disposition of this action will have no
material adverse effect on Duke Energy's consolidated results of operations or
financial position.
99
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Duke Energy and its subsidiaries are involved in other legal, tax and
regulatory proceedings before various courts, regulatory commissions and
governmental agencies regarding performance, contracts and other matters
arising in the ordinary course of business, some of which involve substantial
amounts. Management believes that the final disposition of these proceedings
will have no material adverse effect on consolidated results of operations,
cash flows or financial position.
Injuries and Damages Claims. Duke Energy has experienced numerous claims
relating to damages for personal injuries alleged to have arisen from the
exposure to or use of asbestos in connection with construction and maintenance
activities conducted by Duke Energy on its electric generation plants during
the 1960s and 1970s. During 1999, Duke Energy experienced a significant
increase in the number of these claims. This increase, coupled with its
cumulative experience in claims received, prompted Duke Energy to conduct a
comprehensive review which was completed in late 1999 and to record an $800
million accrual, to reflect the purchase of a third-party insurance policy as
well as estimated amounts for future claims not recoverable under such policy.
The insurance policy, combined with amounts covered by self-insurance reserves,
provides for claims paid up to an aggregate of $1.6 billion. Duke Energy
currently believes the estimated claims relating to this exposure will not
exceed such amount. While Duke Energy is uncertain as to the timing of when
claims will be received, portions of the estimated claims may not be received
and paid for 30 or more years.
While Duke Energy has recorded an accrual related to this estimated
liability, such estimates cannot be made with certainty. Factors, such as the
frequency and magnitude of claims, could result in changes in the estimates of
the injuries and damages liability and insurance recoveries. Such changes could
result in, over time, a difference from the amount currently reflected in the
financial statements. However, due to Duke Energy's insurance program relating
to this liability, management believes that any changes in the estimates would
not have a material adverse effect on consolidated results of operations, cash
flows or financial position.
Other Commitments and Contingencies. As part of its normal business, Duke
Energy is a party to various financial guarantees, performance guarantees and
other contractual commitments to extend guarantees of credit and other
assistance to various subsidiaries, investees and other third parties. These
arrangements are largely entered into by Duke Capital Corporation. To varying
degrees, these guarantees involve elements of performance and credit risk,
which are not included on the Consolidated Balance Sheets. The possibility of
Duke Energy having to honor its contingencies is largely dependent upon future
operations of various subsidiaries, investees and other third parties, or the
occurrence of certain future events. Duke Energy would record a reserve if
events occurred that required that one be established.
In addition, Duke Energy enters into various fixed-price, non-cancelable
commitments to purchase or sell power (tolling arrangements or power purchase
contracts), take-or-pay arrangements, transportation or throughput agreements
and other contracts that may or may not be recognized on the Consolidated
Balance Sheets. Some of these arrangements may be recognized at market value on
the Consolidated Balance Sheets as trading contracts or qualifying hedge
positions included in Unrealized Gains or Losses on Mark-to-Market and Hedging
Transactions.
Financial Guarantees. Some Duke Energy subsidiaries have guaranteed
affiliates' debt agreements and have provided surety bonds and letters of
credit, totaling approximately $579 million as of December 31, 2001 and $1.9
billion as of December 31, 2000. The decrease in these obligations is due
primarily to decreasing support for margin deposits and power exchange
participation.
Leases. Duke Energy leases assets in several areas of its operations.
Consolidated rental expense for operating leases was $114 million in 2001, $90
million in 2000 and $87 million in 1999. Future minimum rental
100
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
payments under operating leases for the years 2002 through 2006 are $87
million, $70 million, $57 million, $43 million and $34 million, respectively.
16. Common Stock and Equity Offerings
In March 2001, Duke Energy completed an offering of 25 million shares of
common stock, priced at $38.98 per share, before underwriting discount and
other offering expenses. In addition, Duke Energy completed an offering of
approximately 31 million units of Equity Units, at $25 per unit, before
underwriting discount and other offering expenses. The Equity Units consist of
senior notes of Duke Capital Corporation, and purchase contracts obligating the
investors to purchase shares of Duke Energy's common stock in 2004. The number
of shares to be issued in 2004 will be based on the price of the common stock
at conversion. Also in March 2001, the underwriters exercised options granted
to them to purchase an additional 3.75 million shares of common stock and four
million Equity Units at the original issue prices, less underwriting discounts,
to cover over-allotments made during the offerings. Total net proceeds from the
offerings, approximately $1.9 billion, were used to repay short-term debt and
for other corporate purposes.
In November 2001, Duke Energy completed an offering of 30 million Equity
Units, at $25 per unit, before underwriting discount and other offering
expenses. The Equity Units consist of senior notes of Duke Capital Corporation,
and purchase contracts obligating the investors to purchase shares of Duke
Energy's common stock in 2004. The number of shares to be issued in 2004 will
be based on the price of the common stock at conversion. The net proceeds from
the offering were approximately $731 million.
The Duke Capital Corporation senior notes that are part of the Equity Units
are included in Long-term Debt on the Consolidated Balance Sheets. (See Note
10.) The value of the forward purchase contracts associated with the Equity
Units were assumed to be zero at inception as the offerings were done at market
prices. The return on the Equity Units consists of interest on the debt
component and a contract adjustment payment. The contract adjustment was
recorded as a declared dividend and its present value was recorded in Other
Current and Noncurrent Liabilities on the Consolidated Balance Sheets.
At Duke Energy's Annual Meeting of Shareholders held on April 26, 2001,
shareholders approved an amendment to the Articles of Incorporation to increase
the authorized common stock from one billion to two billion shares.
On December 20, 2000, Duke Energy announced a two-for-one common stock split
effective January 26, 2001, to shareholders of record on January 3, 2001. All
2000 and 1999 outstanding share and per share amounts have been restated to
reflect the stock split. Appropriate adjustments have been made in the exercise
price and number of shares subject to stock options, as well as in stock
amounts and other employee benefit programs. Effective with the stock split,
the quarterly cash dividend rate on common stock is $0.275 per share.
17. Stock-Based Compensation
The following information regarding outstanding common stock shares and
options reflects the two-for-one common stock split discussed in Note 16.
Duke Energy's 1998 Long-term Incentive Plan, as amended (the 1998 Plan),
reserved 60 million shares of common stock for company performance awards to
employees and outside directors. Incentive stock options may only be granted to
key employees. Under the 1998 Plan, the exercise price of each option granted
cannot be less than the market price of Duke Energy's common stock on the date
of grant. Vesting periods range from one to five years with a maximum term of
10 years.
101
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Stock Option Activity
Weighted-
Average
Exercise
Options Price
------------ ---------
In thousands
Outstanding at December 31, 1998 8,923 $23
Granted..................... 10,308 27
Exercised................... (856) 12
Forfeited................... (750) 29
------
Outstanding at December 31, 1999 17,625 25
Granted..................... 7,594 41
Exercised................... (2,047) 21
Forfeited................... (666) 27
------
Outstanding at December 31, 2000 22,506 31
Granted..................... 7,090 37
Exercised................... (2,285) 25
Forfeited................... (905) 33
------
Outstanding at December 31, 2001 26,406 33
======
Stock Options at December 31, 2001
Outstanding Exercisable
-------------------------------- ----------------------
Weighted- Weighted- Weighted-
Range of Average Average Average
Exercise Remaining Exercise Exercise
Prices Number Life Price Number Price
-------- --- --------- --------- -------- ---------
In thousands In years In thousands
$5 to $8 21 2.2 $ 8 21 $ 8
$9 to $12 784 2.4 10 784 10
$13 to $16 168 4.1 14 168 14
$17 to $22 186 5.1 22 186 22
$23 to $27 5,278 8.0 25 2,317 25
$28 to $33 6,565 6.7 29 3,049 29
$34 to $39 7,236 9.9 38 -- --
(greater than) $39 6,168 9.0 43 1,412 43
------ -----
Total 26,406 7,937 $28
====== =====
On December 31, 2000, Duke Energy had 5.2 million exercisable options with a
$23 weighted-average exercise price. On December 31, 1999, Duke Energy had 3.6
million exercisable options with a $17 weighted-average exercise price.
The weighted-average fair value per option granted was $10 during 2001, $10
during 2000 and $5 during 1999. The fair value of each option grant was
estimated on the date of grant using the Black-Scholes option-pricing model.
102
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Weighted-Average Assumptions for Option-Pricing
2001 2000 1999
------- ------- -------
Stock dividend yield........... 3.4% 3.7% 4.1%
Expected stock price volatility 29.5% 25.1% 18.8%
Risk-free interest rates....... 5.0% 5.3% 5.9%
Expected option lives.......... 7 years 7 years 7 years
Duke Energy's net income for 2001 would have been $1,876 million, or $2.42
per basic share, had compensation expense for stock-based compensation been
based on the fair value at the grant dates. Net income for 2000 would have been
$1,764 million, or $2.37 per basic share, and 1999 net income would have been
$1,498 million, or $2.03 per basic share.
The 1998 Plan allows for a maximum of six million shares of common stock to
be issued under restricted stock awards, performance awards and phantom stock
awards. Performance awards granted under the 1998 Plan vest over periods from
one to seven years. Duke Energy awarded 24,000 shares (fair value of
approximately $1 million at grant dates) in 2001, 225,000 shares (fair value of
approximately $7 million at grant dates) in 2000 and 986,400 shares (fair value
of approximately $26 million at grant dates) in 1999. Compensation expense for
the stock grants is charged to earnings over the vesting period, and totaled $6
million in 2001, $7 million in 2000 and $3 million in 1999.
Phantom stock awards granted under the 1998 Plan vest over periods from one
to four years. Duke Energy awarded 457,700 shares (fair value of approximately
$17 million at grant dates) in 2001 and 168,500 shares (fair value of
approximately $7 million at grant dates) in 2000. No phantom stock awards were
granted in 1999. Compensation expense for the stock grants is charged to
earnings over the vesting period, and totaled $4 million in 2001, and was less
than $1 million in 2000. There was no compensation expense for stock grants in
1999.
Duke Energy's 1996 Stock Incentive Plan (the 1996 Plan) reserved four
million shares of common stock for awards to employees. Restricted stock grants
under the 1996 Plan vest over periods ranging from one to five years. Duke
Energy awarded 124,005 restricted shares (fair value of approximately $5
million at grant dates) in 2001, 294,526 restricted shares (fair value of
approximately $8 million at grant dates) in 2000 and 131,700 restricted shares
(fair value of approximately $4 million at grant dates) in 1999. Compensation
expense for the grants is charged to earnings over the restriction period and
totaled $4 million in 2001, $4 million in 2000, and $1 million in 1999.
18. Employee Benefit Plans
Retirement Plans. Duke Energy and its subsidiaries maintain a
non-contributory defined benefit retirement plan. It covers most employees with
minimum service requirements using a cash balance formula. Under a cash balance
formula, a plan participant accumulates a retirement benefit based upon a
percentage (which may vary with age and years of service) of current eligible
earnings and current interest credits.
Duke Energy's policy is to fund amounts on an actuarial basis to provide
assets sufficient to meet benefits to be paid to plan participants. No
contributions to the Duke Energy plan were necessary in 2001 or 2000. The net
unrecognized transition asset, resulting from the implementation of accrual
accounting, is amortized over approximately 20 years. Investment gains or
losses are amortized over five years.
103
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Components of Net Periodic Pension Costs
For the Years Ended
December 31,
-------------------
2001 2000 1999
----- ----- -----
In millions
Service cost benefit earned during the year.. $ 74 $ 70 $ 72
Interest cost on projected benefit obligation 188 184 165
Expected return on plan assets............... (264) (244) (224)
Amortization of prior service cost........... (3) (3) (3)
Amortization of net transition asset......... (4) (4) (4)
Recognized net actuarial loss................ -- -- 12
----- ----- -----
Net periodic pension costs................... $ (9) $ 3 $ 18
===== ===== =====
Reconciliation of Funded Status to Pre-funded Pension Costs
December 31,
--------------
2001 2000
------ ------
In millions
Change in Benefit Obligation
Benefit obligation at beginning of year........... $2,586 $2,446
Service cost...................................... 74 70
Interest cost..................................... 188 184
Actuarial (gain) loss............................. (147) 16
Plan amendments................................... 1 --
Benefits paid..................................... (174) (130)
------ ------
Benefit obligation at end of year................. $2,528 $2,586
------ ------
Change in Plan Assets
Fair value of plan assets at beginning of year (a) $3,038 $3,121
Actual return on plan assets...................... (394) 47
Benefits paid..................................... (174) (130)
------ ------
Fair value of plan assets at end of year (a)...... $2,470 $3,038
------ ------
Funded status..................................... $ (58) $ 452
Unrecognized net experience loss (gain)........... 400 (110)
Unrecognized prior service cost reduction......... (17) (22)
Unrecognized net transition asset................. (12) (16)
------ ------
Pre-funded pension costs.......................... $ 313 $ 304
====== ======
-----
(a) Principally equity and fixed-income securities. For measurement
purposes, plans assets were valued as of September 30.
Assumptions Used for Pension Benefits Accounting (a)
2001 2000 1999
---- ---- ----
Percent
Discount rate................................... 7.25 7.50 7.50
Salary increase................................. 4.94 4.53 4.50
Expected long-term rate of return on plan assets 9.25 9.25 9.25
-----
(a) Reflects weighted averages across all plans
104
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Duke Energy also sponsors employee savings plans that cover substantially
all employees. Duke Energy expensed employer matching contributions of $69
million in 2001, $66 million in 2000 and $68 million in 1999.
Other Post-Retirement Benefits. Duke Energy and most of its subsidiaries
provide some health care and life insurance benefits for retired employees on a
contributory and non-contributory basis. Employees are eligible for these
benefits if they have met age and service requirements at retirement, as
defined in the plans. Under plan amendments effective late 1998 and early 1999,
health care benefits for future retirees were changed to limit employer
contributions and medical coverage.
These benefit costs are accrued over an employee's active service period to
the date of full benefits eligibility. The net unrecognized transition
obligation, resulting from accrual accounting, is amortized over approximately
20 years.
Components of Net Periodic Post-Retirement Benefit Costs
For the Years Ended
December 31,
------------------
2001 2000 1999
---- ---- ----
In millions
Service cost benefit earned during the year.................... $ 5 $ 5 $ 7
Interest cost on accumulated post-retirement benefit obligation 44 43 40
Expected return on plan assets................................. (24) (23) (21)
Amortization of prior service cost............................. 1 1 1
Amortization of net transition obligation...................... 18 18 18
Recognized net actuarial gain.................................. -- -- (1)
Plan curtailments.............................................. (3) -- --
---- ---- ----
Net periodic post-retirement benefit costs..................... $ 41 $ 44 $ 44
==== ==== ====
105
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Reconciliation of Funded Status to Accrued Post-Retirement Benefit Costs
December 31,
------------
2001 2000
----- -----
In millions
Change in Benefit Obligation
Accumulated post-retirement benefit obligation at beginning of year $ 614 $ 562
Service cost....................................................... 5 5
Interest cost...................................................... 44 43
Plan participants' contributions................................... 9 7
Actuarial loss..................................................... 104 39
Benefits paid...................................................... (61) (42)
Plan curtailments.................................................. (3) --
----- -----
Accumulated post-retirement benefit obligation at end of year...... $ 712 $ 614
----- -----
Change in Plan Assets
Fair value of plan assets at beginning of year (a)................. $ 325 $ 327
Actual return on plan assets....................................... (40) 8
Employer contributions............................................. 32 25
Plan participants' contributions................................... 9 7
Benefits paid...................................................... (61) (42)
----- -----
Fair market value of plan assets at end of year (a)................ $ 265 $ 325
----- -----
Funded status...................................................... $(447) $(289)
Employer contributions............................................. 11 9
Unrecognized net experience loss (gain)............................ 111 (56)
Unrecognized prior service cost.................................... 4 5
Unrecognized transition obligation................................. 196 214
----- -----
Accrued post-retirement benefit costs.............................. $(125) $(117)
===== =====
- --------
(a) Principally equity and fixed-income securities. For measurement purposes,
plan assets were valued as of September 30.
Assumptions Used for Post-Retirement Benefits Accounting (a)
2001 2000 1999
----- ----- -----
Percent
Discount rate.............................. 7.25 7.50 7.50
Salary increase............................ 4.94 4.53 4.50
Expected long-term rate of return on assets 9.25 9.25 9.25
Assumed tax rate (b)....................... 39.60 39.60 39.60
- --------
(a) Reflects weighted averages across all plans/ /
(b) Applicable to the health care portion of funded post-retirement benefits
For measurement purposes, the net per capita cost of covered health care
benefits for employees who have not retired are assumed to have an initial
annual rate of increase of 11.5% in 2002 that will gradually decrease to 6% in
2008. For employees that have retired, an initial annual rate of increase of
14.5% in 2002 will gradually decrease to 6% in 2011. Assumed health care cost
trend rates have a significant effect on the amounts reported for the health
care plans.
106
DUKE ENERGY CORPORATION
Notes To Consolidated Financial Statements -- Continued
Sensitivity to Changes in Assumed Health Care Cost Trend Rates
1-Percentage- 1-Percentage-Point
Point Increase Decrease
-------------- ------------------
In millions
Effect on total service and interest costs........... $ 2 $ (2)
Effect on post-retirement benefit obligation......... 47 (40)
19. Quarterly Financial Data (Unaudited)
First Second Third Fourth
Quarter Quarter Quarter Quarter Total
------- ------- ------- ------- -------
In millions, except per share data
2001
Operating revenues....................................... $16,491 $15,580 $16,718 $10,714 $59,503
Operating income......................................... 1,182 880 1,492 546 4,100
EBIT..................................................... 1,254 902 1,529 571 4,256
Income before cumulative effect of change in accounting
principle.............................................. 554 419 796 225 1,994
Net income............................................... 458 419 796 225 1,898
Earnings per share (before cumulative effect of change in
accounting principle)
Basic................................................. $ 0.74 $ 0.54 $ 1.02 $ 0.29 $ 2.58
Diluted............................................... $ 0.73 $ 0.53 $ 1.01 $ 0.28 $ 2.56
Earnings per share
Basic................................................. $ 0.61 $ 0.54 $ 1.02 $ 0.29 $ 2.45
Diluted............................................... $ 0.60 $ 0.53 $ 1.01 $ 0.28 $ 2.44
2000
Operating revenues....................................... $ 7,290 $10,926 $15,691 $15,411 $49,318
Operating income......................................... 812 794 1,501 706 3,813
EBIT..................................................... 859 837 1,556 762 4,014
Net income............................................... 393 329 770 284 1,776
Earnings per share (a)
Basic................................................. $ 0.53 $ 0.44 $ 1.04 $ 0.38 $ 2.39
Diluted............................................... $ 0.53 $ 0.44 $ 1.03 $ 0.38 $ 2.38
- --------
(a) Restated to reflect the two-for-one common stock split effective January
26, 2001
During the fourth quarter of 2001, Duke Energy recorded a $43 million
provision for non-collateralized accounting exposure to Enron, as well as a $36
million reduction in unbilled revenue receivables, resulting from a refinement
in the estimates used to calculate unbilled kilowatt-hour sales.
20. Subsequent Events
On January 31, 2002, Duke Energy announced the planned sale of its DE&S
business unit to Framatome ANP, Inc. (a nuclear supplier) for approximately $84
million. Two components of DE&S are not part of the sale. Duke Energy will
establish Duke Energy--Energy Delivery Services, formed by the power delivery
services component of DE&S, which will continue to supply power delivery
solutions to customers. Leadership of the U.S. Department of Energy Mixed Oxide
Fuel project will also remain with Duke Energy. The transaction will require a
Hart Scott Rodino filing and is expected to close in the second quarter of 2002.
On March 13, 2002, Duke Energy announced the planned sale of DukeSolutions
to Ameresco, Inc. Duke Energy expects to close the transaction during the
second quarter of 2002, and record a loss of approximately $20 million.
107
DUKE ENERGY CORPORATION
SCHEDULE II--VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Additions
------------------
Balance at Charged to Balance at
Beginning Charged to Other End
of Period Expense Accounts Deductions(a) of Period
---------- ---------- ---------- ------------- ----------
In millions
December 31, 2001:
Injuries and damages............ $ 531 $ 31 $ 11 $114 $ 459
Allowance for doubtful accounts. 200 160 4 99 265
Other (b)....................... 377 201 84 256 406
------ ------ ---- ---- ------
$1,108 $ 392 $ 99(c) $469 $1,130
December 31, 2000:
Injuries and damages............ $ 902 $ 18 $ 2 $391 $ 531
Allowance for doubtful accounts. 43 165 8 16 200
Other (b)....................... 317 40 97 77 377
------ ------ ---- ---- ------
$1,262 $ 223 $107(d) $484 $1,108
December 31, 1999:
Injuries and damages............ $ 113 $ 900 $ -- $111 $ 902
Allowance for doubtful accounts. 29 16 6 8 43
Other (b)....................... 225 134 54 96 317
------ ------ ---- ---- ------
$ 367 $1,050 $ 60(d) $215 $1,262
- --------
(a) Principally cash payments and reserve reversals.
(b) Principally property insurance reserves and litigation and other reserves,
included in "Other Current Liabilities" or "Deferred Credits and Other
Liabilities" in the Consolidated Balance Sheets.
(c) Principally reserves for construction costs, and litigation and other
reserves assumed in business acquisitions.
(d) Principally litigation and other reserves assumed in business acquisitions.
108
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of Duke Energy Corporation:
We have audited the accompanying consolidated balance sheets of Duke Energy
Corporation and subsidiaries (Duke Energy) as of December 31, 2001 and 2000,
and the related consolidated statements of income, common stockholders' equity
and comprehensive income, and cash flows for each of the three years in the
period ended December 31, 2001. Our audits also included the financial
statement schedule listed in the Index at Item 14. These financial statements
and financial statement schedule are the responsibility of Duke Energy's
management. Our responsibility is to express an opinion on the financial
statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Duke Energy as of December 31,
2001 and 2000, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2001, in conformity with
accounting principles generally accepted in the United States of America. Also,
in our opinion, such financial statement schedule, when considered in relation
to the basic consolidated financial statements taken as a whole, presents
fairly in all material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Deloitte & Touche LLP
Charlotte, North Carolina
February 19, 2002 (March 14, 2002 as to the acquisition of Westcoast Energy,
Inc. described in Note 2 and as to the planned sale of DukeSolutions, Inc.
described in Notes 3 and 20)
109
RESPONSIBILITY FOR FINANCIAL STATEMENTS
The financial statements of Duke Energy Corporation (Duke Energy) are
prepared by management, who are responsible for their integrity and
objectivity. The statements are prepared in conformity with generally accepted
accounting principles in all material respects and necessarily include
judgments and estimates of the expected effects of events and transactions that
are currently being reported.
Duke Energy's system of internal accounting control is designed to provide
reasonable assurance that assets are safeguarded and transactions are executed
according to management's authorization. Internal accounting controls also
provide reasonable assurance that transactions are recorded properly, so that
financial statements can be prepared according to generally accepted accounting
principles. In addition, accounting controls provide reasonable assurance that
errors or irregularities which could be material to the financial statements
are prevented or are detected by employees within a timely period as they
perform their assigned functions. Duke Energy's accounting controls are
continually reviewed for effectiveness. In addition, written policies,
standards and procedures, and an internal audit program augment Duke Energy's
accounting controls.
The Board of Directors pursues its oversight role for the financial
statements through the audit committee, which is composed entirely of
independent directors who are not employees of Duke Energy. The audit committee
meets with management and internal auditors periodically to review accounting
control issues and to monitor each group's discharge of its responsibilities.
The audit committee also meets periodically with Duke Energy's independent
auditors, Deloitte & Touche LLP. The independent auditors have free access to
the audit committee and the Board of Directors to discuss internal accounting
control, auditing and financial reporting matters without the presence of
management.
/s/ Keith G. Butler
Keith G. Butler
Senior Vice President and Controller
110
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
PART III.
Item 10. Directors and Executive Officers of the Registrant.
Reference is made to "Executive Officers of Duke Energy" included in "Item
1. Business" of this report. See "The Board of Directors," "Information on the
Board of Directors" and "Other Information" in the Proxy Statement relating to
Duke Energy's 2002 annual meeting of shareholders, incorporated herein by
reference.
Item 11. Executive Compensation.
See "Compensation" and "Information on the Board of Directors--Compensation
of Directors" in the Proxy Statement relating to Duke Energy's 2002 annual
meeting of shareholders, incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
See "Beneficial Ownership" in the Proxy Statement relating to Duke Energy's
2002 annual meeting of shareholders, incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions.
None.
111
PART IV.
Item 14. Exhibits, Financial Statement Schedule, and Reports on Form 8-K.
(a) Consolidated Financial Statements, Supplemental Financial Data and
Supplemental Schedule included in Part II of this annual report are as follows:
Consolidated Financial Statements
Consolidated Statements of Income for the Years Ended December 31,
2001, 2000 and 1999
Consolidated Statements of Cash Flows for the Years Ended December
31, 2001, 2000 and 1999
Consolidated Balance Sheets as of December 31, 2001 and 2000
Consolidated Statements of Common Stockholders' Equity and
Comprehensive Income for the Years Ended December 31, 2001, 2000
and 1999
Notes to Consolidated Financial Statements
Quarterly Financial Data (unaudited, included in Note 19 to the Consolidated
Financial Statements)
Consolidated Financial Statement Schedule II--Valuation and Qualifying Accounts
and Reserves for the Years Ended December 31, 2001, 2000 and 1999
Independent Auditors' Report
All other schedules are omitted because they are not required, or
because the required information included in the Financial Statements
or Notes.
(b) Reports on Form 8-K
A Current Report on Form 8-K filed on November 20, 2001 contained
disclosures under Item 5, Other Events and Item 7, Exhibits.
(c) Exhibits--See Exhibit Index immediately following the signature page.
112
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
Date: March 28, 2002 DUKE ENERGY CORPORATION
(Registrant)
By: RICHARD B. PRIORY
----------------------------------
Richard B. Priory
Chairman of the Board, President
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
(i) Principal executive officer:
Richard B. Priory
Chairman of the Board, President and Chief Executive Officer
(ii) Principal financial officer:
Robert P. Brace
Executive Vice President and Chief Financial Officer
(iii) Principal accounting officer:
Keith G. Butler
Senior Vice President and Controller
(iv) All of the Directors:
Richard B. Priory
G. Alex Bernhardt, Sr.
Robert J. Brown
William A. Coley
William T. Esrey
Ann Maynard Gray
Dennis R. Hendrix
Harold S. Hook
George Dean Johnson, Jr.
Max Lennon
Leo E. Linbeck, Jr.
James G. Martin
James T. Rhodes
Date: March 28, 2002
Robert P. Brace, by signing his name hereto, does hereby sign this document
on behalf of the registrant and on behalf of each of the above-named persons
pursuant to a power of attorney duly executed by the registrant and such
persons, filed with the Securities and Exchange Commission as an exhibit hereto.
By: /s/ ROBERT P. BRACE
-----------------------------
Attorney-In-Fact
113
EXHIBIT INDEX
Exhibits filed herewith are designated by an asterisk (*). All exhibits not
so designated are incorporated by reference to a prior filing, as indicated.
Items constituting management contracts or compensatory plans or arrangements
are designated by a double asterisk (**).
Exhibit
Number
- ------
2-1 Agreement and Plan of Merger, dated as of November 24, 1996, as amended and restated as of March
10, 1997, among registrant, Duke Transaction Corporation and PanEnergy Corp (filed with Form 8-K
dated March 20, 1997, File No. 1-4928, as Exhibit 2(a)).
2-2 Amended and Restated Combination Agreement dated as of September 20, 2001, among Duke Energy
Corporation, 3058368 Nova Scotia Company, 3946509 Canada Inc. and Westcoast Energy Inc. (filed
with Form 10-Q of Duke Energy Corporation for the quarter ended September 30, 2001, File No.
1-4928, as Exhibit 10.7).
3-1 Restated Articles of Incorporation of registrant, dated June 18, 1997 (filed with Form S-8, No. 333-
29563, effective June 19, 1997, as Exhibit 4(G)).
3-2 Articles of Amendment to Restated Articles of Incorporation of registrant (filed with Form 10-K of the
registrant for the year ended December 31, 1999, as Exhibit 3-A).
3-3 By-Laws of registrant, as amended (filed with Form S-3, File No. 333-52204, Exhibit 4(B)).
3-4 Articles of Amendment to Restated Articles of Incorporation of registrant (filed with Post Effective
Amentment No. 2 to Form S-3 of the registrant, file number 333-81573, filed December 12, 2001 as
Exhibit 4(B)-1).
4 Rights Agreement, dated as of December 17, 1998, between the registrant and The Bank of New York,
as Rights Agent (filed with Form 8-K dated February 11, 1999).
10-1 Agreement, dated March 6, 1978, between the registrant and the North Carolina Municipal Power
Agency No. 1 (filed with Form 8-K for the month of March 1978, File No. 1-4928).
10-2 Agreement, dated August 1, 1980, between the registrant and Piedmont Municipal Power Agency
(filed with Form 8-K for the month of August 1980, File No. 1-4928).
10-3 Agreement, dated October 14, 1980, between the registrant and North Carolina Electric Membership
Corporation (filed with Form 10-Q for the quarter ended September 30, 1980, File No. 1-4928).
10-4 Agreement, dated October 14, 1980, between the registrant and Saluda River Electric Cooperative, Inc.
(filed with Form 10-Q for the quarter ended September 30, 1980, File No. 1-4928).
10-5** Directors' Charitable Giving Program (filed with Form 10-K for the year ended December 31, 1992,
File No. 1-4928, as Exhibit 10-P).
10-6** Estate Conservation Plan (filed with Form 10-K for the year ended December 31, 1992, File
No. 1-4928, as Exhibit 10-R).
10-7** Duke Power Company Stock Incentive Plan (filed as Appendix A to Schedule 14A of registrant, March
18, 1996, File No. 1-4928).
10-8 Formation Agreement between PanEnergy Trading and Market Services, Inc. and Mobil Natural Gas,
Inc. dated May 29, 1996 (filed with Form 10-Q of PanEnergy Corp for the quarter ended June 30,
1996, File No. 1-8157, as Exhibit 2).
10-9** Duke Energy Corporation Long-Term Incentive Plan, as amended (filed as Exhibit A to Schedule 14A
of the registrant, March 16, 1998).
114
Exhibit
Number
- ------
10-10** Duke Energy Corporation Policy Committee Short-Term Incentive Plan (filed as Appendix B to
Schedule 14A of the registrant, March 16, 1998).
10-11 Stock Purchase Agreement between PanEnergy Corp, Texas Eastern Corporation and CMS Energy
Corporation, dated as of October 31, 1998 (filed as Exhibit 10 to Form 8-K of the registrant, File No.
1-4928, filed November 5, 1998).
10-12 Merger and Purchase Agreement among Union Pacific Resources Company, Union Pacific Fuels, Inc.,
Duke Energy Field Services, Inc. and DEFS Merger Sub Corp., dated as of November 20, 1998 (filed
as Exhibit 10 to Form 8-K of the registrant, File No. 1-4928, filed December 1, 1998).
10-13** Duke Energy Corporation Executive Savings Plan (filed with Form 10-K Report of TEPPCO Partners,
LP, File No. 1-10403, for the year ended December 31, 1999, as Exhibit 10.7).
10-14** Duke Energy Corporation Executive Cash Balance Plan (filed with Form 10-K Report of TEPPCO
Partners, LP, File No. 1-10403, for the year ended December 31, 1999, as Exhibit 10.8).
10-15** Duke Energy Corporation Retirement Benefit Equalization Plan (filed with Form 10-K Report of
TEPPCO Partners, LP, File No. 1-10403, for the year ended December 31, 1999, as Exhibit 10.9).
10-16** Form of Key Employee Severance Agreement and Release between the registrant and certain key
executives (filed with Form 10-K of the registrant for the year ended December 31, 1999, as Exhibit
10-BB).
10-17** Form of Change in Control Agreement between the registrant and certain key executives (filed with
Form 10-K of the registrant for the year ended December 31, 1999, as Exhibit 10-CC).
10-18 Contribution Agreement by and among Phillips Petroleum Company, Duke Energy Corporation and
Duke Energy Field Services L.L.C., dated as of December 16, 1999 (filed as Exhibit 2.1 to Form 8-K
of the registrant, filed December 30, 1999).
10-19 Governance Agreement by and among Phillips Petroleum Company, Duke Energy Corporation and
Duke Energy Field Services L.L.C., dated as of December 16, 1999 (filed as Exhibit 2.2 to Form 8-K
of the registrant, filed December 30, 1999).
10-20 First Amendment to Contribution and Governance Agreement dated as of March 23, 2000 among
Phillips Petroleum Company, Duke Energy Corporation and Duke Energy Field Services, LLC
(incorporated by reference to Exhibit 10.7 (b) to Registration Statement on Form S-1/A (Registration
No. 333-32502) of Duke Energy Field Services Corporation, filed on March 27, 2000).
10-21 Parent Company Agreement dated as of March 31, 2000 among Phillips Petroleum Company, Duke
Energy Corporation, Duke Energy Field Services, LLC and Duke Energy Field Services Corporation
(incorporated by reference to Exhibit 10.10 to Registration Statement on Form S-1/A (Registration
No. 333-32502) of Duke Energy Field Services Corporation, filed on May 4, 2000).
10-22 Amended and Restated Limited Liability Company Agreement of Duke Energy Field Services, LLC
by and between Phillips Gas Company and Duke Energy Field Services Corporation, dated as of
March 31, 2000 (filed as Exhibit 3.1 to Form 10 of Duke Energy Field Services LLC, File No. 000-
31095, filed July 20, 2000).
10-23 First Amendment to the Parent Company Agreement dated as of May 25, 2000 among Phillips
Petroleum Company, Duke Energy Corporation, Duke Energy Field Services, LLC and Duke Energy
Field Services Corporation (filed as Exhibit 10.8 (b) to Form 10 of Duke Energy Field Services LLC,
File No. 000-31095, filed July 20, 2000).
115
Exhibit
Number
- ------
10.24 $537,500,000 364-Day Credit Agreement dated as of April 19, 2001,among Duke Capital Corporation,
the Banks listed therein and Bank One, NA, as Administrative Agent (filed with Form 10-Q of Duke
Energy Corporation for the quarter ended September 30, 2001, File No. 1-4928, as Exhibit 10.1).
10.25 $537,500,000 Three-Year Credit Agreement dated as of April 19, 2001, among Duke Capital
Corporation, the Banks listed therein and Bank One, NA, as Administrative Agent (filed with Form 10-
Q of Duke Energy Corporation for the quarter ended September 30, 2001, File No. 1-4928, as Exhibit
10.2).
10.26 $550,000,000 364-Day Credit Agreement dated as of August 20, 2001, among Duke Capital
Corporation, the Banks listed therein and The Chase Manhattan Bank, as Administrative Agent (filed
with Form 10-Q of Duke Energy Corporation for the quarter ended September 30, 2001, File
No. 1-4928, as Exhibit 10.3).
10.27 $550,000,000 Three-Year Credit Agreement dated as of August 20, 2001, among Duke Capital
Corporation, the Banks listed therein and The Chase Manhattan Bank, as Administrative Agent (filed
with Form 10-Q of Duke Energy Corporation for the quarter ended September 30, 2001, File
No. 1-4928, as Exhibit 10.4).
10.28 $475,000,000 364-Day Credit Agreement dated as of August 29, 2001, among Duke Energy
Corporation, the Banks listed therein and The Chase Manhattan Bank, as Administrative Agent (filed
with Form 10-Q of Duke Energy Corporation for the quarter ended September 30, 2001, File
No. 1-4928, as Exhibit 10.5).
10.29 $475,000,000 Three-Year Credit Agreement dated as of August 29, 2001, among Duke Energy
Corporation, the Banks listed therein and The Chase Manhattan Bank, as Administrative Agent (filed
with Form 10-Q of Duke Energy Corporation for the quarter ended September 30, 2001, File
No. 1-4928, as Exhibit 10.6).
*12 Computation of Ratio of Earnings to Fixed Charges.
*21 List of Subsidiaries.
*23(a) Independent Auditors' Consent.
*24(a) Power of attorney authorizing Robert P. Brace and others to sign the annual report on behalf of the
registrant and certain of its directors and officers.
*24(b) Certified copy of resolution of the Board of Directors of the registrant authorizing power of attorney.
The total amount of securities of the registrant or its subsidiaries
authorized under any instrument with respect to long-term debt not filed as an
exhibit does not exceed 10% of the total assets of the registrant and its
subsidiaries on a consolidated basis. The registrant agrees, upon request of
the Securities and Exchange Commission, to furnish copies of any or all of such
instruments.
116