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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
(Mark One)
[X] Annual report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the fiscal year ended December 31, 1997 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 jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
422 South Church Street, Charlotte, North Carolina 28202-1904
(Address of principal executive offices) (Zip Code)
704-594-6200
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
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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, 5 7/8% Due 2001 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 5 7/8% Series C Due 2003 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 6 1/4% Series B Due 2004 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 6 3/8% Due 2008 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 2000 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 7% Series B Due 2000 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 7% Due 2005 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 7% Due 2033 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 7 3/8% Due 2023 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 7 1/2% Series B Due 2025 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 7 7/8% Due 2024 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 8% Series B Due 1999 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.
Securities registered pursuant to Section 12(g) of the Act:
Title of class
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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
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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 27, 1998 .................... $20,010,800,000
Number of shares of Common Stock, without par value, outstanding at February
27, 1998 .................................................... 360,149,391
Documents incorporated by reference:
The registrant is incorporating herein by reference certain sections of
the proxy statement relating to the 1998 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, 1997
TABLE OF CONTENTS
Item Page
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PART I.
1. Business ........................................................................ 1
General ......................................................................... 1
Electric Operations ............................................................. 1
Natural Gas Transmission ........................................................ 4
Energy Services ................................................................. 6
Other Operations ................................................................ 9
Environmental Matters ........................................................... 9
Other Matters ................................................................... 10
Safe Harbor Statement under the Private Securities Litigation Reform Act of 1995 10
Operating Statistics ............................................................ 11
Executive Officers of the Corporation ........................................... 12
2. Properties ...................................................................... 12
3. Legal Proceedings ............................................................... 14
4. Submission of Matters to a Vote of Security Holders ............................. 14
PART II.
5. Market for Registrant's Common Equity and Related Stockholder Matters ........... 15
6. Selected Financial Data ......................................................... 15
7. Management's Discussion and Analysis of Results of Operations and Financial 16
Condition
7A. Quantitative and Qualitative Disclosures About Market Risk ...................... 26
8. Financial Statements and Supplementary Data ..................................... 27
9. Changes in and Disagreements with Accountants on Accounting and Financial 61
Disclosure
PART III.
10. Directors and Executive Officers of the Registrant .............................. 61
11. Executive Compensation .......................................................... 61
12. Security Ownership of Certain Beneficial Owners and Management .................. 61
13. Certain Relationships and Related Transactions .................................. 61
PART IV.
14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K ................ 62
Signatures ....................................................................... 63
Exhibit Index .................................................................... 64
PART I.
Item 1. Business.
GENERAL
On June 18, 1997, Duke Power Company (Duke Power) changed its name to Duke
Energy Corporation (the Corporation) in accordance with the terms of a merger
agreement with PanEnergy Corp (PanEnergy), pursuant to which the Corporation
issued 158.3 million shares of its common stock in exchange for all of the
outstanding common stock of PanEnergy (the merger). PanEnergy was involved in
the gathering, processing, transportation and storage of natural gas, the
production of natural gas liquids and the marketing of natural gas,
electricity, liquefied petroleum gases and related energy services. Pursuant to
the merger, each share of PanEnergy common stock outstanding was converted into
the right to receive 1.0444 shares of the Corporation's common stock. In
addition, each outstanding option to purchase PanEnergy common stock became an
option to purchase common stock of the Corporation, adjusted accordingly. The
merger was accounted for as a pooling of interests.
As a result of the merger, the Corporation is an integrated energy and
energy services provider with the ability to offer physical delivery and
management of both electricity and natural gas throughout the United States and
abroad. The Corporation provides these services through four business segments:
Electric Operations, Natural Gas Transmission, Energy Services, and Other
Operations.
The Electric Operations segment is engaged in the generation,
transmission, distribution and sale of electric energy in central and western
North Carolina and the western portion of South Carolina. 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).
The Natural Gas Transmission segment is involved in interstate
transportation and storage of natural gas for customers primarily in the
Mid-Atlantic, New England and Midwest states. The interstate natural gas
transmission and storage operations are also subject to the rules and
regulations of the FERC.
The Energy Services segment is comprised of several separate business
units: Field Services gathers and processes natural gas, produces and markets
natural gas liquids (NGLs) and transports and trades crude oil; Trading and
Marketing markets natural gas, electricity and other energy-related products;
Global Asset Development develops, owns and operates energy-related facilities
worldwide; and Other Energy Services provides engineering consulting,
construction and integrated energy solutions.
Other Operations include the real estate operations of Crescent Resources,
Inc. (Crescent Resources) and communications services. Corporate costs and
intersegment eliminations are also reflected in the financial results of this
segment.
A discussion of the current business and operations of each of the
Corporation's segments follows. The Corporation expects moderate growth in its
Electric Operations segment, consistent with historical trends. In the Natural
Gas Transmission segment, relatively slow growth is expected due to increased
competition. The Corporation is seeking to significantly grow its Energy
Services segment through acquisition, construction and expansion opportunities.
For further discussion of the operating outlook of the Corporation and its
segments, see "Management's Discussion and Analysis of Results of Operations
and Financial Condition, Current Issues -- Operations Outlook." For financial
information concerning the Corporation's business segments, see Note 4 to the
Consolidated Financial Statements, "Business Segments."
The Corporation is a North Carolina corporation with its principal
executive offices located at 422 South Church Street, Charlotte, NC 28202-1904.
The telephone number is 704-594-6200.
ELECTRIC OPERATIONS
Service Area and Customers
The Electric Operations service area, approximately two-thirds of which
lies in North Carolina, covers about 20,000 square miles with an estimated
population of 5.1 million and includes a number of cities, of which the largest
are Charlotte, Greensboro, Winston-Salem and Durham in North Carolina and
Greenville and Spartanburg in South Carolina. Electric Operations supplies
electric service directly to approximately two million residential, commercial
and industrial customers in more than 200 cities, towns and unincorporated
communities. Electricity is sold at wholesale to incorporated municipalities
and to several public and private utilities. In addition, sales are made
through contractual agreements to municipal or cooperative customers who
purchased portions of the Catawba Nuclear Station. For statistics related to
gigawatt-hour sales
1
by customer type, see "Business, Operating Statistics." For further discussion
of the Catawba Nuclear Station joint ownership, see Note 6 to the Consolidated
Financial Statements, "Joint Ownership of Generating Facilities."
The Electric Operations service area is undergoing increasingly
diversified industrial development. The textile industry, machinery and
equipment manufacturing, and chemical and chemical-related industries are of
major significance to the economy of the area. Other industrial activities
include rubber and plastic products, paper and allied products, and various
other light and heavy manufacturing and service businesses. The largest
industry served is the textile industry, which accounted for approximately $457
million of the revenues of the Electric Operations segment for 1997,
representing 10% of electric revenues and 38% of industrial revenues. Electric
Operations normally experiences seasonal peak loads in summer and winter which
are relatively in balance.
Shown below is the Electric Operations service area, in which business is
conducted under the name "Duke Power" and by Nantahala Power and Light
Company, a subsidiary of the Corporation.
[Map of North and South Carolina depicting
Electric Operations Service Area appears here]
Capability and Resources of Energy
Electric energy required to supply the needs of the customers of Electric
Operations is primarily generated through three nuclear generating stations
with a combined net capability of 5,078 MW (Oconee Nuclear Station -- 2,538 MW,
McGuire Nuclear Station -- 2,258 MW and Catawba Nuclear Station -- 282 MW,
which represents Electric Operations' 12.5% ownership share in the Catawba
Nuclear Station), eight coal-fired stations with a combined capability of 7,699
MW, twenty hydroelectric stations with a combined capability of 2,685 MW and
six combustion turbine stations with a combined capability of 1,784 MW. Energy
and capacity are also supplied through contracts with other generators of
electricity and purchased on the open market. Electric Operations has
interconnections and arrangements with its neighboring utilities, which are
considered adequate for planning, emergency assistance, exchange of capacity
and energy and reliability of power supply. Future increased energy
requirements of Electric Operations' customers are expected to be supplied
through open market purchases. For statistics regarding sources of electric
energy see "Business, Operating Statistics."
Fuel Supply
Electric Operations presently relies principally on coal and nuclear fuel
for the generation of electric energy. Electric Operations reliance on oil and
gas is minimal. Information regarding the utilization of sources of power and
cost of fuels for each of the three years in the period ended December 31, 1997
is set forth in the following table:
2
Cost of Fuel per Net
Generation by Source Kilowatt-hour Generated
(Percent) (Cents)
----------------------------- -----------------------------
1997 1996 1995 1997 1996 1995
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Coal .......................................... 59.3 54.0 43.7 1.30 1.40 1.56
Nuclear (a) ................................... 38.8 44.0 53.7 0.48 0.53 0.57
Oil and gas (b) ............................... .4 .3 .3 5.58 6.74 5.06
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All fuels (cost based on weighted average) (a) 98.5 98.3 97.7 0.99 1.02 1.03
Hydroelectric (c) ............................. 1.5 1.7 2.3
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100.0 100.0 100.0
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(a) Statistics related to nuclear generation and all fuels reflect the
Electric Operations' 12.5% ownership interest in the Catawba Nuclear
Station.
(b) Cost statistics include amounts for light-off fuel at the Electric
Operations' coal-fired stations.
(c) Generating figures are net of output required to replenish pumped storage
units during off-peak periods.
Coal. Electric Operations obtains a large amount of its coal under supply
contracts with mining operators utilizing both underground and surface mining.
Electric Operations currently has an adequate supply of coal. Electric
Operations' supply contracts, all of which have price adjustment provisions,
have expiration dates ranging from 1998 to 2003. The Corporation believes that
it will be able to renew such contracts as they expire or to enter into similar
contractual arrangements with other coal suppliers for the quantities and
qualities of coal required. The coal purchased under these supply contracts is
produced from mines located in eastern Kentucky, southern West Virginia and
southwestern Virginia. Coal requirements not met by supply contracts have been
and are expected to be fulfilled with spot market purchases.
The average sulfur content of coal being purchased by Electric Operations
is approximately 1%. Such coal satisfies the current emission limitation for
sulfur dioxide for existing facilities. See also "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. Generally, the supply of fuel for nuclear generating units
involves the mining and milling of uranium ore to produce uranium concentrates,
the conversion of uranium concentrates to uranium hexafluoride, enrichment of
that gas and fabrication of the enriched uranium hexafluoride into usable fuel
assemblies. After a region (approximately one-third of the nuclear fuel
assemblies in the reactor at any time) of spent fuel is removed from a nuclear
reactor, it is placed in temporary storage for cooling in a spent fuel pool at
the nuclear station site. Electric Operations has contracted for uranium
materials and services required to fuel the Oconee, McGuire and Catawba Nuclear
Stations. Based upon current projections, these contracts will meet Electric
Operations' requirements through the following years:
Uranium Conversion Enrichment Fabrication
Nuclear Station Material Service Service Service
- ----------------------- ---------- ------------ ------------ ------------
Oconee .......... 1998 1998 2000 2006
McGuire ......... 1998 1998 2000 2009
Catawba ......... 1998 1998 2000 2009
Uranium material requirements will be met through various supplier
contracts, with uranium material produced primarily in the United States and
Canada. The Corporation believes that it will be able to renew contracts as
they expire or to enter into similar contractual arrangements with other
suppliers of nuclear fuel materials and services. Requirements not met by
long-term supply contracts have been and are expected to be fulfilled with
uranium spot market purchases.
Under provisions of the Nuclear Waste Policy Act of 1982, the Corporation
entered into contracts with the Department of Energy (DOE) for the disposal of
spent nuclear fuel. The DOE delayed in accepting the waste materials on the
contract date of January 31, 1998. The Corporation has joined with 35 other
utilities in a lawsuit attempting to force the DOE to meet its obligations as
called for in the contract. The Corporation has satisfactory plans in place to
provide storage of spent nuclear fuel if the DOE cannot accept it.
3
Competition
Competition for retail electric customers is not generally allowed in the
Electric Operations' service territory. However, there are discussions and
events at the national level and within certain states regarding retail
competition which are resulting in changes in the industry. For further
discussion, see "Management's Discussion and Analysis of Results of Operations
and Financial Condition, Current Issues -- Electric Competition."
Electric Operations is subject to competition in some areas from
government-owned power systems, municipally-owned electric systems, rural
electric cooperatives and, in certain instances, from other private utilities.
Currently, statutes in North Carolina and South Carolina provide for the
assignment by the NCUC and the PSCSC, respectively, of all areas outside
municipalities in such states to regulated electric utilities and rural
electric cooperatives. Substantially all of the territory comprising the
Electric Operations' service area has been so assigned. The remaining areas
have been designated as unassigned and in such areas Electric Operations
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 there continues to
be competition between municipalities and other electric suppliers outside the
corporate limits of the municipalities, subject, however, to the regulation of
the PSCSC. In addition, Electric Operations is engaged in continuing
competition with various natural gas providers.
Regulation
The NCUC and the PSCSC approve rates for retail electric sales within
their respective states. The FERC approves the Electric Operations' rates for
electric sales to wholesale customers. For further discussion of rate matters
and fuel and purchased power cost adjustment procedures, see Note 5 to the
Consolidated Financial Statements, "Regulatory Matters -- Electric Operations."
The FERC, the NCUC and the PSCSC also have authority over the construction and
operation of the Electric Operations' facilities. Electric Operations holds
certificates of public convenience and necessity issued by the FERC, the NCUC
and the PSCSC, authorizing it to construct and operate the electric facilities
now in operation for which certificates are required, and to sell electricity
to retail and wholesale customers.
The Energy Policy Act of 1992 (EPACT) and the FERC's subsequent rulemaking
activities permit the FERC to order transmission access for third parties to
transmission facilities owned by another entity. EPACT does not, however,
permit the FERC to issue orders requiring transmission access to retail
customers. The FERC has issued orders for third-party transmission service and
a number of rules of general applicability, including Orders 888 and 889.
Pursuant to the FERC's final rules, Electric Operations obtained from the FERC
open-access rights to sell at market-based rates up to 2,500 megawatts (MW) of
capacity and energy from its own assets. For further discussion, see
"Management's Discussion and Analysis of Results of Operations and Financial
Condition, Current Issues -- Electric Competition."
The Electric Operations segment is subject to the jurisdiction of the
Nuclear Regulatory Commission (NRC) as to the design, construction and
operation of its nuclear stations. For discussions of nuclear decommissioning
costs and nuclear insurance regulatory requirements and coverages, see Note 12
to the Consolidated Financial Statements, "Nuclear Decommissioning Costs &
Spent Nuclear Fuel" and Note 15 to the Consolidated Financial Statements,
"Commitments and Contingencies -- Nuclear Insurance," respectively.
The hydroelectric generating facilities of Electric Operations are
licensed by the FERC under Part I of the Federal Power Act, with license terms
expiring from 2008 to 2036. The nuclear generating facilities of the Electric
Operations are licensed by the NRC with license terms expiring from 2013 to
2026. The FERC has authority to grant extensions of hydroelectric generating
licenses, and the NRC has authority to grant extensions of nuclear generating
licenses.
The Electric Operations segment is subject to the jurisdiction of the
Environmental Protection Agency (EPA) and state environmental agencies. For a
discussion of environmental regulation, see "Business, Environmental Matters."
NATURAL GAS TRANSMISSION
During 1997, the Natural Gas Transmission segment completed the
organization of its operations into the Northeast Pipelines, which includes
Texas Eastern Transmission Corporation (TETCO) and Algonquin Gas Transmission
Company (Algonquin), and the Midwest Pipelines, which includes Panhandle
Eastern Pipe Line Company (PEPL) and Trunkline Gas Company (Trunkline).
4
In 1997, consolidated natural gas deliveries by the Natural Gas
Transmission segment's interstate pipelines totaled 2,862 TBtu (Trillion
British thermal units), compared to 2,939 TBtu in 1996, which represented
approximately 12% of the natural gas consumed in the United States. A
substantial majority of the delivered volumes of the Natural Gas Transmission
segment's interstate pipelines represents gas transported under long-term firm
service agreements with local distribution company (LDC) customers in the
pipelines' market areas. Firm transportation services are also provided under
contract to gas marketers, producers, other pipelines, electric power
generators and a variety of end-users. In addition, the pipelines offer
interruptible transportation to customers on a short-term or seasonal basis.
See natural gas deliveries statistics under "Business, Operating Statistics."
Demand for gas transmission of the Natural Gas Transmission segment's
interstate pipeline systems is seasonal, with the highest throughput occurring
during the colder periods in the first and fourth quarters.
The Natural Gas Transmission segment's 37,500 mile interstate pipeline
system is fully interconnected and can receive natural gas from most major
North American producing regions for delivery to markets throughout the
Northeast and Midwest states, as shown in the map below.
[Map of United States depicting the Natural Gas Transmission segment Interstate
Pipelines and Storage Fields appears here]
Northeast Pipelines
TETCO's major customers are located in Pennsylvania, New Jersey and New
York, and include LDCs serving the Pittsburgh, Philadelphia, Newark and New
York City metropolitan areas. Algonquin's major customers include LDCs and
electric power generators located in the Boston, Hartford, New Haven,
Providence and Cape Cod areas.
TETCO also provides firm and interruptible open-access storage services.
Since the implementation of the FERC Order 636 restructuring, storage is
offered as a stand-alone unbundled service or as part of a no-notice bundled
service. TETCO's storage services utilize two joint venture storage facilities
in Pennsylvania and one wholly owned and operated storage field in Maryland.
TETCO also leases storage capacity. TETCO's certificated working capacity in
these three fields is 70 Billion cubic feet (Bcf), and the combined working gas
in storage was 55 Bcf on December 31, 1997. Algonquin owns no storage fields.
For further discussion of Order 636, see "Business, Natural Gas Transmission --
Regulation."
Midwest Pipelines
PEPL's market volumes are concentrated among approximately 20 utilities
located in the Midwest market area that encompasses large portions of Michigan,
Ohio, Indiana, Illinois and Missouri. Trunkline's major customers include eight
utilities located in portions of Tennessee, Missouri, Illinois, Indiana and
Michigan.
PEPL also owns and operates three underground storage fields located in
Illinois, Michigan and Oklahoma. Trunkline owns and operates one storage field
in Louisiana. The combined maximum working gas capacity of the four fields is
44
5
Bcf. Additionally, PEPL, through a subsidiary, Pan Gas Storage Company (Pan
Gas), is the owner of a storage field in Kansas with an estimated maximum
capacity of 26 Bcf. PEPL is the operator of the field. Since the implementation
of Order 636, each of PEPL, Trunkline and Pan Gas offer firm and interruptible
storage on an open-access basis. In addition to owning and operating storage
fields, PEPL also leases storage capacity. PEPL and Trunkline have retained the
right to use up to 15 Bcf and 10 Bcf, respectively, of their storage capacity
for system needs. See further discussion of Order 636 in "Business, Natural Gas
Transmission -- Regulation."
Competition
The Corporation's interstate pipeline subsidiaries compete with other
interstate and intrastate pipeline companies in the transportation and storage
of natural gas. The principal elements of competition among pipelines are
rates, terms of service and flexibility and reliability of service. The
Corporation's pipelines continue to offer selective discounting to maximize
revenues from existing capacity and to advance projects that provide expanded
services to meet the specific needs of customers.
In the Mid-Atlantic and New England markets, TETCO competes directly with
Transcontinental Gas Pipe Line Corporation, Tennessee Gas Pipeline Company
(TGPC), Iroquois Gas Transmission System (Iroquois), CNG Transmission
Corporation and Columbia Gas Transmission Corporation. Algonquin competes
directly in certain market areas with TGPC and Iroquois. PEPL and Trunkline
compete directly with ANR Pipeline Company, Natural Gas Pipeline Company of
America and Texas Gas Transmission Corporation in the Midwest market area.
Natural gas competes with other forms of energy available to the
Corporation's customers and end-users, including electricity, coal and fuel
oils. The primary competitive factor is price. Changes in the availability or
price of natural gas and other forms of energy, the level of business activity,
conservation, legislation and governmental regulations, the capability to
convert to alternative fuels, and other factors, including weather, affect the
demand for natural gas in the areas served by the Corporation.
Regulation
The FERC has authority to regulate rates and charges for natural gas
transported in or stored for interstate commerce or sold by a natural gas
company in interstate commerce for resale. For further discussion of rate
matters, see Note 5 to the Consolidated Financial Statements, "Regulatory
Matters -- Natural Gas Operations." The FERC also has authority over the
construction and operation of pipeline and related facilities utilized in the
transportation and sale of natural gas in interstate commerce, including the
extension, enlargement or abandonment of such facilities. TETCO, Algonquin,
PEPL, Trunkline and Pan Gas hold certificates of public convenience and
necessity issued by the FERC, authorizing them to construct and operate the
pipelines, facilities and properties now in operation for which such
certificates are required, and to transport and store natural gas in interstate
commerce.
The Natural Gas Transmission segment's pipelines operate as open-access
transporters of natural gas. In 1992, the FERC issued Order 636, which requires
open-access pipelines to provide firm and interruptible transportation services
on an equal basis for all gas supplies, whether purchased from the pipeline or
from another gas supplier. To implement this requirement, Order 636 provided,
among other things, for mandatory unbundling of services that have historically
been provided by pipelines into separate open-access transportation, sales and
storage services. Order 636 allows pipelines to recover eligible costs, known
as "transition costs," resulting from the implementation of Order 636. For
further discussion of Order 636, see Note 5 to the Consolidated Financial
Statements, "Regulatory Matters -- Natural Gas Operations."
The Natural Gas Transmission segment is subject to the jurisdiction of the
EPA and state environmental agencies. For a discussion of environmental
regulation, see "Business, Environmental Matters." The Natural Gas Transmission
segment is also subject to the Natural Gas Pipeline Safety Act of 1968, which
regulates gas pipeline safety requirements, and to the Hazardous Liquid
Pipeline Safety Act of 1979, which regulates oil and petroleum pipelines.
ENERGY SERVICES
The Energy Services segment is comprised of several separate business
units: Field Services, Trading and Marketing, Global Asset Development and
Other Energy Services. See certain operating statistics of the Energy Services
segment under "Operating Statistics." Activities of the Energy Services segment
can fluctuate in response to the seasonality affecting both electricity and
natural gas.
6
Field Services
Field Services owns and operates approximately 17,000 miles of natural gas
gathering systems, including intrastate pipelines, and 27 natural gas
processing plants in the United States. Field Services also has ownership
interests in 11 other natural gas processing plants in the United States.
Field Services' gathering systems are located in 10 states, which serve
major gas-producing regions in the Rocky Mountain, Permian Basin, Mid-Continent
and Gulf Coast (offshore and onshore) areas. Field Services' gathering
operations also include several intrastate pipeline systems and two natural gas
storage facilities.
Field Services' NGL processing operations involve the extraction of NGLs
from natural gas and, at certain facilities, the fractionation of the NGLs into
their individual components (ethane, propane, butane and natural gasoline). The
natural gas used in Field Services' processing operations is generally gathered
on its own gathering system or from the natural gas stream on the Corporation's
transmission system. Field Services also operates approximately 450 miles of
NGL pipelines in the Texas Gulf Coast area which transport NGLs received from
12 processing plants in South Texas. NGLs are sold by Field Services to a
variety of customers ranging from large multi-national petrochemical and
refining companies to small family-owned retail propane distributors. NGL sales
are based upon current market-related prices. Field Services also provides, on
a more limited basis, processing services to producers and others for a
stipulated fee and produces helium at the National Helium facility.
Field Services also operates approximately 1,500 miles of intrastate crude
oil pipelines in the Mid-Continent and South Texas areas. The crude oil
pipeline system provides gathering and mainline transportation service, for a
volumetric fee, based on published tariffs. Crude oil is also purchased from
producers and sold to end users.
Trading and Marketing
The Corporation's energy marketing operations are conducted through Duke
Energy Trading and Marketing L.L.C. in the United States, Duke Energy Marketing
Limited Partnership in Canada (collectively, DETM) and Duke/Louis Dreyfus
L.L.C. (D/LD).
DETM was formed in August 1996 as a natural gas and power marketing joint
venture with Mobil Corporation (Mobil). All of Mobil's United States and
Canadian natural gas production is committed to be marketed through DETM for at
least a 10-year period. The Corporation, through its affiliates, operates the
joint venture and owns a 60% interest, with Mobil owning a 40% minority
interest.
In June 1997, a wholly owned subsidiary of the Corporation acquired the
remaining 50% ownership interest in D/LD not already owned from affiliates of
Louis Dreyfus Corp. A substantial portion of the Corporation's trading and
marketing of electricity is conducted through D/LD.
Trading and Marketing markets natural gas primarily to LDCs, electric
power generators, municipalities, industrial end-users and energy marketing
companies and markets electricity to investor owned utilities, municipal power
generators and other power marketers. Operations are primarily in the United
States and, to a lesser extent, in Canada, and are serviced through 13 offices
or operating centers.
Natural gas marketing operations encompass both on-system and off-system
sales. With respect to on-system sales, Trading and Marketing generally
purchases natural gas from the Corporation's Field Services facilities and
delivers the gas to an intrastate or interstate pipeline for redelivery to
another customer. The Corporation's Natural Gas Transmission pipelines are
utilized for deliveries when prudent. With respect to off-system sales, Trading
and Marketing purchases natural gas from producers, pipelines and other
suppliers not connected with the Corporation's facilities for resale to
customers.
Trading and Marketing has a portfolio of short-term and long-term sales
agreements with customers, the vast majority of which incorporate
market-sensitive pricing terms. Long-term gas purchase agreements with
producers, principally entered into in connection with on-system sales, also
generally include market-sensitive pricing provisions. Purchases and sales of
off-system gas and electricity supply are normally made under short-term
contracts. Purchase and sales commitments involving significant price and
location risk are generally hedged with commodity futures, swaps and options.
For information concerning the Corporation's risk-management activities, see
"Management's Discussion and Analysis of Results of Operations and Financial
Condition, Quantitative and Qualitative Information About Market Risk --
Commodity Price Risk" and Note 8 to the Consolidated Financial Statements,
"Financial Instruments and Risk Management -- Commodity Derivative
Instruments."
7
Trading and Marketing 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.
Global Asset Development
Global Asset Development is an active participant in competitive power
markets worldwide and has ownership interests in more than 6,500 megawatts of
generation worldwide, including projects under construction and under contract.
Global Asset Development is comprised of three units: Duke Energy Power
Services (DEPS), Duke Energy Industrial Asset Development, and Duke Energy
International.
DEPS develops, owns and operates electric generation projects for
customers in the United States and Canada. DEPS focuses on acquisitions of
existing energy production facilities, greenfield opportunities and operating
energy assets. Domestic investments include a 32.5% indirect ownership interest
in American Ref-Fuel Company, which owns five waste to energy facilities in New
York, New Jersey, Massachusetts and Connecticut. Such facilities process about
4 million tons of municipal solid waste per year and have an aggregate
generating capacity of 286 megawatts. DEPS projects under construction include
an ownership interest in the Bridgeport Energy Project, a 520 megawatt combined
cycle natural gas fired merchant generation plant which will be Connecticut's
largest non-nuclear power plant.
On November 18, 1997, DEPS entered into an agreement with Pacific Gas &
Electric Company (PG&E) for the purchase of three electric generating plants in
California for approximately $500 million. The plants have a combined net
operating capacity of 2,645 megawatts. The sale is expected to close during
1998. Pursuant to California's electric restructuring law, DEPS must contract
with PG&E to operate and maintain the facilities for two years following the
sale. Energy and capacity from the plants will be sold into the California
power exchange and under separate contracts.
Duke Energy Industrial Asset Development was formed in July 1997 to
develop, own, manage and operate on-site, inside-the-fence electric generation
and energy conversion facilities for industrial customers. Its market focus is
the United States and Canada. This unit is currently working with prospective
customers from the textile, pulp and paper, petrochemical, agricultural, food
and automotive industries and the federal privatization sector.
Duke Energy International develops, owns and operates energy projects
worldwide. This unit focuses on projects involving natural gas exploration,
production, processing, transportation and supply. Additionally, projects
include generation, delivery and marketing of electric power and thermal
energy. Its ownership interests include investments in Argentina, Chile, Peru,
Indonesia and Saudi Arabia.
Other Energy Services
Other Energy Services provides engineering consulting, construction and
integrated energy solutions, primarily through Duke Engineering & Services,
Inc. (DE&S), Duke/Flour Daniel and DukeSolutions, Inc. (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 projects worldwide.
Duke/Flour Daniel, 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.
DukeSolutions provides integrated energy solutions to industrial,
commercial, institutional, governmental and wholesale customers and focuses on
increasing customers' efficiency, productivity and profitability through energy
cost savings.
Competition
Field Services and Trading and Marketing compete with major integrated oil
companies, major interstate pipelines and their marketing affiliates, national
and local natural gas gatherers, brokers, marketers and distributors and
electric utilities and other electric power marketers for natural gas supplies,
in gathering and processing natural gas and in marketing and transporting
natural gas, electricity, NGLs and crude oil. Competition for natural gas
supplies is primarily based on efficiency, reliability, availability of
transportation and the ability to obtain a satisfactory price for the
producer's natural gas. Competition for customers is based primarily upon
reliability and price of delivered natural gas, NGLs and crude oil. Competition
in the energy marketing business is driven by the price of commodities and
services delivered, along with the quality and reliability of services
provided.
8
The Global Asset Development and Other Energy Services business units
experience substantial competition in their fields from utility companies in
the United States or abroad and from independent companies.
Regulation
The intrastate pipelines owned by the Field Services group are subject to
state regulation and, to the extent they provide services under Section 311 of
the Natural Gas Policy Act of 1978 (NGPA), are also subject to FERC regulation.
The natural gas gathering activities of the Field Services group are generally
not subject to regulation by the FERC, but are subject to state regulation.
The energy marketing activities of the Trading and Marketing group may, in
certain circumstances, be subject to the jurisdiction of the FERC. Current FERC
policies permit the Trading and Marketing entities subject to the FERC
jurisdiction to market natural gas and electricity at market-based rates.
The NCUC, PSCSC and FERC have implemented regulations governing access to
regulated electric customer data by non-regulated entities and services
provided between regulated and non-regulated affiliated entities. These
regulations affect Energy Services' activities with the Corporation's Electric
Operations segment.
The Energy Services segment is subject to the jurisdiction of the EPA and
state environmental agencies. For a discussion of environmental regulation, see
"Business, Environmental Matters." The Energy Services segment is also subject
to the Natural Gas Pipeline Safety Act of 1968, which regulates gas pipeline
and LNG plant safety requirements, and to the Hazardous Liquid Pipeline Safety
Act of 1979, which regulates oil and petroleum pipelines.
OTHER OPERATIONS
The Other Operations segment includes the Corporation's non-energy related
subsidiaries, including Crescent Resources and DukeNet Communications, Inc.
(DukeNet).
Crescent Resources develops high quality commercial and residential real
estate projects and manages substantial forest holdings. At December 31, 1997,
Crescent Resources owned 3.5 million square feet of commercial space, of which
75% of the operating space was leased. Crescent Resources' portfolio included
2.1 million square feet of warehouse space, 1.1 million square feet of office
space and .3 million square feet of retail space. In 1997, Crescent Resources
sold 884 residential developed lots compared to 869 lots in 1996. At December
31, 1997, Crescent Resources also had approximately .2 million acres of land
under its management.
DukeNet develops and manages communications systems, including fiber optic
and wireless digital network services. DukeNet provides a network for
communications and other services to commercial, industrial and residential
markets.
ENVIRONMENTAL MATTERS
The Corporation is subject to federal, state and local regulations with
regard to air and water quality, hazardous and solid waste disposal and other
environmental matters. Certain environmental regulations affecting the
Corporation include:
o The Clean Air Act Amendments of 1990, which require a two-phase reduction by
electric utilities in aggregate annual emissions of sulfur dioxide and
nitrogen oxide by 2000;
o State Implementation Plans (SIP), which were issued by the EPA to 22 states
related to existing and new national ambient air quality standards for
ozone;
o The Federal Water Pollution Control Act Amendments of 1987, which require
permits for facilities that discharge treated wastewater into the
environment; and
o The Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA), which can require any individual or entity which may have owned
or operated a disposal site, as well as transporters or generators of
hazardous wastes which were sent to such site, to share in remediation
costs for the site.
For further discussion of environmental matters involving the Corporation,
including possible liability and capital costs, see "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." Except as set
9
forth therein, compliance with federal, state and local provisions which have
been enacted or adopted regulating the discharge of materials into the
environment, or otherwise protecting the environment, is not expected to have a
material adverse effect on the consolidated results of operations or financial
position of the Corporation.
OTHER MATTERS
The Corporation is exempt from regulation as a holding company under the
Public Utility Holding Company Act of 1935 (PUHCA), except with respect to the
acquisition of the securities of other public utilities. The issuance of debt
or equity securities by the Corporation is subject to the regulation of the
NCUC and the PSCSC.
Foreign operations and export sales are not material to the Corporation's
business as a whole. For a discussion of risks associated with the
Corporation's foreign operations, see "Management's Discussion and Analysis of
Results of Operations and Financial Condition, Quantitative and Qualitative
Disclosures About Market Risk -- Foreign Operations Risk."
At December 31, 1997, the Corporation had approximately 23,000 employees.
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF
1995
From time to time, the Corporation may make statements regarding its
expectations, intent or beliefs about future events. These statements are
intended as "forward-looking statements" under the Private Securities
Litigation Reform Act of 1995. The Corporation cautions that assumptions,
projections and expectations about future events may and often do vary from
actual results, the differences between assumptions, projections and
expectations and actual results can be material, and there can be no assurance
that the forward-looking statements will be realized. For a discussion of some
factors that could cause actual achievements and events to differ materially
from those expressed or implied in such forward-looking statements, see
"Management's Discussion and Analysis of Results of Operations and Financial
Condition, Current Issues -- Forward-Looking Statements."
10
OPERATING STATISTICS
Years Ended December 31
----------------------------------------------------
1997 1996 1995 1994 1993
----------------------------------------------------
Electric Operations
Sources of Electric Energy, GWh (a)
Generated -- net output:
Coal .............................................................. 45,234 40,649 32,389 32,714 34,097
Nuclear ........................................................... 29,569 33,177 39,836 35,587 34,390
Hydro ............................................................. 1,129 1,319 1,685 1,460 1,582
Oil and gas ....................................................... 301 199 255 35 43
------ ------ ------ ------ ------
Total generation ............................................... 76,233 75,344 74,165 69,796 70,112
Purchased power and net interchange ............................... 3,776 3,587 1,175 1,276 1,750
------ ------ ------ ------ ------
Total output ................................................... 80,009 78,931 75,340 71,072 71,862
Plus: Purchases from other Catawba joint owners ................... 2,316 2,662 6,070 9,046 8,810
------ ------ ------ ------ ------
Total sources of energy ........................................ 82,325 81,593 81,410 80,118 80,672
Less: Line loss and company usage ................................. 4,784 4,741 4,673 4,555 4,614
------ ------ ------ ------ ------
Total GWh sales ................................................ 77,541 76,852 76,737 75,563 76,058
====== ====== ====== ====== ======
Electric Energy Sales, GWh
Residential ....................................................... 20,005 20,992 19,669 18,870 19,465
General service ................................................... 19,368 19,269 18,160 17,289 16,904
Industrial
Textile ......................................................... 11,950 11,599 12,151 12,285 11,954
Other ........................................................... 18,253 18,021 17,631 17,005 16,244
Other energy and wholesale ........................................ 7,555 7,028 8,330 10,274 11,337
------ ------ ------ ------ ------
Total GWh sales billed ......................................... 77,131 76,909 75,941 75,723 75,904
Unbilled GWh sales ............................................ 410 (57) 796 (160) 154
------ ------ ------ ------ ------
Total GWh sales ............................................. 77,541 76,852 76,737 75,563 76,058
====== ====== ====== ====== ======
Natural Gas Transmission
Throughput Volumes, TBtu (b):
Northeast Pipelines
TETCO ........................................................... 1,300 1,349 1,234 1,194 1,115
Algonquin ....................................................... 341 327 331 288 245
----- ----- ----- ----- ------
Total Northeast Pipelines ...................................... 1,641 1,676 1,565 1,482 1,360
Midwest Pipelines
PEPL ............................................................ 659 687 663 626 607
Trunkline ....................................................... 620 632 519 560 633
----- ----- ----- ----- ------
Total Midwest Pipelines ........................................ 1,279 1,319 1,182 1,186 1,240
Intercompany eliminations ........................................ (58) (56) (44) (91) (125)
----- ----- ----- ----- ------
Total Natural Gas Transmission .................................... 2,862 2,939 2,703 2,577 2,475
===== ===== ===== ===== ======
Energy Services
Field Services Natural Gas Gathered/Processed, TBtu/d (c) ......... 3.4 2.9 1.9 1.6 1.4
Field Services NGL Production, MBbl/d (d) ......................... 103.9 76.5 54.8 49.4 42.0
Trading and Marketing Natural Gas Marketed, TBtu/d ................ 6.9 5.5 3.6 2.7 2.1
Trading and Marketing Electricity Marketed, GWh ................... 64,650 4,229 513 -- --
- ---------
(a) Gigawatt-hour
(b) Trillion British thermal units
(c) Trillion British thermal units per day
(d) Thousand barrels per day
11
Executive Officers of the Corporation
RICHARD B. PRIORY, 51, Chairman of the Board and Chief Executive Officer.
Mr. Priory served as President and Chief Operating Officer from 1994 until he
assumed his present position in 1997. He was Executive Vice President, Power
Generation Group, from 1991 to 1994.
PAUL M. ANDERSON, 52, President and Chief Operating Officer. Mr. Anderson
served as Chairman of the Board, President and Chief Executive Officer of
PanEnergy prior to the merger, when he assumed his present position. Mr.
Anderson was elected Chairman of the Board of PanEnergy in 1997, Chief
Executive Officer in 1995 and President in 1993. He was Executive Vice
President of PanEnergy from 1991 to 1993.
WILLIAM A. COLEY, 54, Group President, Duke Power. Mr. Coley served as
President, Associated Enterprises Group, from 1994 to 1997 when he assumed his
present position following the merger. Mr. Coley served as Executive Vice
President, Customer Group, from 1991 to 1994.
FRED J. FOWLER, 52, Group President, Energy Transmission. Mr. Fowler
served as Group Vice President of PanEnergy from 1996 until the merger, when he
assumed his present position. He was President of TETCO from 1994 to 1996,
President of 1Source Corporation from 1993 to 1994 and President of Trunkline
Gas Company from 1991 to 1993.
JAMES T. HACKETT, 44, Group President, Energy Services. Mr. Hackett served
as Executive Vice President of PanEnergy from 1996 until the merger, when he
assumed his present position. Prior to joining PanEnergy, Mr. Hackett served as
Senior Vice President of NGC Corporation (formerly Natural Gas Clearinghouse)
from 1990 to 1995.
RICHARD W. BLACKBURN, 55, Executive Vice President and General Counsel.
Mr. Blackburn was named to his present position in October 1997. Prior to
joining the Corporation, he served as President and Group Executive of NYNEX
Corporation's Worldwide Communications and Media Group from 1995 to 1997. He
was Chief Operating Officer, Worldwide Communications and Media Group, of NYNEX
from 1993 to 1995 and Senior Vice President for Business Development and
General Counsel of NYNEX from 1991 to 1993.
RICHARD J. OSBORNE, 46, Executive Vice President and Chief Financial
Officer. Mr. Osborne served as Senior Vice President and Chief Financial
Officer from 1994 until he assumed his present position in 1997 following the
merger. Mr. Osborne served as Vice President and Chief Financial Officer from
1991 to 1994.
RUTH G. SHAW, 50, Executive Vice President and Chief Administrative
Officer. Ms. Shaw served as Senior Vice President, Corporate Resources, from
1994 until she assumed her present position following the merger. Ms. Shaw was
Vice President, Corporate Communications, from 1992 to 1994, and prior to
joining the Corporation, she served as President of Central Piedmont Community
College from 1986 to 1992.
JEFFREY L. BOYER, 41, Vice President and Corporate Controller. Mr. Boyer
served as Controller from 1994 to 1997, when he assumed his present position
following the merger. He was Director of Corporate Accounting from 1992 to
1994.
Executive officers are elected annually by the Board of Directors and
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 pursuant to which the officer was selected.
Item 2. Properties.
ELECTRIC OPERATIONS
At December 31, 1997, the Corporation's Electric Operations segment
operated three nuclear generating stations with a combined net capability of
5,078 MW (which includes Electric Operations' 12.5% ownership share in the
Catawba Nuclear Station), eight coal-fired stations with a combined capability
of 7,699 MW, twenty hydroelectric stations with a combined capability of 2,685
MW and six combustion turbine stations with a combined capability of 1,784 MW,
all of which are located in North Carolina or South Carolina.
In addition, the Corporation owned, as of December 31, 1997, approximately
12,800 conductor miles of electric transmission lines, including 600 conductor
miles of 500 kilovolts, 2,600 conductor miles of 220 kilovolts, 6,400 conductor
miles of 100 kilovolts, and 3,200 conductor miles of 13 to 66 kilovolts. The
Corporation also owned approximately 75,000 conductor miles of electric
distribution lines, including 47,300 conductor miles of rural overhead lines,
15,000 conductor miles of urban overhead lines, 7,000 conductor miles of rural
underground lines and 5,700 conductor miles of urban underground
12
lines. At December 31, 1997, the Corporation's electric transmission and
distribution systems comprised approximately 1,600 substations with an
installed transformer capacity of approximately 84,100,000 kVA
(kilovolt-ampere).
Substantially all electric plant is mortgaged under the Indenture relating
to the First and Refunding Mortgage Bonds of the Corporation.
NATURAL GAS TRANSMISSION
TETCO's gas transmission system extends approximately 1,700 miles from
producing fields in the Gulf Coast region of Texas and Louisiana to Ohio,
Pennsylvania, New Jersey and New York. It consists of two parallel systems, one
consisting of three large-diameter parallel pipelines and the other consisting
of from one to three large-diameter pipelines over its length. TETCO's system,
including its gathering systems, has 73 compressor stations. The TETCO system
connects with the PEPL and Trunkline systems in Lebanon, Ohio.
TETCO also owns and operates two offshore Louisiana gas supply systems,
which extend over 100 miles into the Gulf of Mexico and consist of 490 miles of
pipeline.
Algonquin's transmission system connects with TETCO's facilities in New
Jersey, and extends through New Jersey, New York, Connecticut, Rhode Island and
Massachusetts. The system consists of approximately 250 miles of pipeline with
6 compressor stations.
PEPL's transmission system, which consists of four large-diameter parallel
pipelines and 13 mainline compressor stations, extends a distance of
approximately 1,300 miles from producing areas in the Anadarko Basin of Texas,
Oklahoma and Kansas through the states of Missouri, Illinois, Indiana and Ohio
into Michigan.
Trunkline's transmission system extends approximately 1,400 miles from the
Gulf Coast areas of Texas and Louisiana through the states of Arkansas,
Mississippi, Tennessee, Kentucky, Illinois and Indiana to a point on the
Indiana-Michigan border. The system consists principally of three
large-diameter parallel pipelines and 18 mainline compressor stations.
Trunkline also owns and operates two offshore Louisiana gas supply systems
consisting of 337 miles of pipeline extending approximately 81 miles into the
Gulf of Mexico.
For information concerning natural gas storage properties, see "Business,
Natural Gas Transmission."
ENERGY SERVICES
For information regarding the properties of Field Services, see "Business,
Energy Services -- Field Services."
Global Asset Development owns two liquid natural gas (LNG) ships, each
with a transportation capacity of 125,000 cubic meters of LNG. Both vessels
have been chartered to Nigeria LNG Limited (Nigeria LNG) for 22 years starting
in 1999. Under the terms of the charter, Nigeria LNG will have the right to
purchase the vessels.
Global Asset Development also owns a marine terminal, storage and
regasification facility for LNG located in Louisiana. This LNG facility has a
design output capacity of approximately 700 million cubic feet per day (MMcf/d)
and a storage capacity of approximately 1.8 million barrels, which approximates
6 Bcf.
Other generation, transmission and distribution properties of Global Asset
Development are owned primarily through joint ventures in which the
Corporation's ownership interest is 50% or less.
Properties of Trading and Marketing and Other Energy Services are not
considered material to the Corporation's operations as a whole.
OTHER OPERATIONS
None of the other properties used in connection with the Corporation's
other business activities are considered material to the Corporation's
operations as a whole.
13
Item 3. Legal Proceedings.
See Note 15 to the Consolidated Financial Statements, "Commitments and
Contingencies" and "Management's Discussion and Analysis of Results of
Operations and Financial Condition, Current Issues -- Environmental" for a
discussion of legal proceedings.
Item 4. Submission of Matters to a Vote of Security Holders.
No matters were submitted to a vote of the Corporation's security holders
during the last quarter of 1997.
14
PART II.
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
The common stock of the Corporation is listed for trading on the New York
Stock Exchange. At February 27, 1998, there were approximately 155,619 holders
of record of such common stock.
The following table sets forth for the periods indicated the dividends
paid per share of common stock and the high and low sales prices of such shares
reported by the New York Stock Exchange Composite Transactions:
Dividends
1997 Per Share (a) Stock Price Range
- ------------------- --------------- ----------------------
High Low
---------- -----------
First Quarter .. $.40 $ 48 $ 43 3/8
Second Quarter . .40 48 42 1/8
Third Quarter .. .55 51 1/8 47 11/16
Fourth Quarter . .55 56 3/16 45 3/4
Dividends
1996 Per Share (a) Stock Price Range
- ------------------ --------------- --------------------
High Low
--------- ----------
First Quarter ... $.38 $53 $46 7/8
Second Quarter .. .39 51 1/2 45 3/4
Third Quarter ... .40 51 3/8 45 3/4
Fourth Quarter .. .40 49 1/8 43 3/8
- ---------
(a) Financial information reflects accounting for the merger with PanEnergy
Corp as a pooling of interests. As a result, the financial information
gives effect to the merger as if it had occurred January 1, 1996.
Item 6. Selected Financial Data.
1997 (a) 1996 (a) 1995 (a) 1994 (a) 1993 (a)
-------------- -------------- ------------- ------------- -------------
In Millions (except per share amounts)
Income Statement
Operating Revenues ....................................... $ 16,308.9 $ 12,302.4 $ 9,694.7 $ 9,115.0 $ 8,784.3
Operating Expenses ....................................... 14,338.9 10,143.8 7,626.4 7,309.0 7,068.6
---------- ---------- ---------- ---------- ----------
Operating Income ......................................... 1,970.0 2,158.6 2,068.3 1,806.0 1,715.7
Other Income and Expenses ................................ 138.1 135.6 122.2 101.0 137.5
---------- ---------- ---------- ---------- ----------
Earnings Before Interest and Taxes ....................... 2,108.1 2,294.2 2,190.5 1,907.0 1,853.2
Interest Expense ......................................... 471.8 499.2 508.2 484.5 526.3
Minority Interests ....................................... 23.0 6.2 -- -- --
---------- ---------- ---------- ---------- ----------
Earnings Before Income Taxes ............................. 1,613.3 1,788.8 1,682.3 1,422.5 1,326.9
Income Taxes ............................................. 638.9 697.8 664.2 558.4 528.9
---------- ---------- ---------- ---------- ----------
Income Before Extraordinary Item ......................... 974.4 1,091.0 1,018.1 864.1 798.0
Extraordinary Item ....................................... -- 16.7 -- -- --
----------- ---------- ---------- ---------- ----------
Net Income ............................................... 974.4 1,074.3 1,018.1 864.1 798.0
Dividends and Premiums on Redemptions of Preferred and
Preference Stock ........................................ 72.8 44.2 48.9 49.7 52.4
----------- ---------- ---------- ---------- ----------
Earnings for Common Stockholders ......................... $ 901.6 $ 1,030.1 $ 969.2 $ 814.4 $ 745.6
=========== ========== ========== ========== ==========
Common Stock Data
Shares of common stock
Year-end ................................................ 359.8 359.4 361.8 360.6 359.1
Average ................................................. 359.8 361.2 361.2 360.2 353.6
Basic earnings per share (before extraordinary item) ..... $ 2.51 $ 2.90 $ 2.68 $ 2.26 $ 2.11
Basic earnings per share ................................. $ 2.51 $ 2.85 $ 2.68 $ 2.26 $ 2.11
Dividends per share ...................................... $ 1.90 $ 1.57 $ 1.50 $ 1.44 $ 1.39
Balance Sheet
Total Assets ............................................. $ 24,028.8 $ 22,366.2 $ 20,867.9 $ 20,254.2 $ 19,717.4
Long-term Debt ........................................... $ 6,530.0 $ 5,485.1 $ 5,803.0 $ 5,930.8 $ 5,370.9
Preferred Stock with Sinking Fund Requirements ........... $ 149.0 $ 234.0 $ 234.0 $ 279.5 $ 281.0
- ---------
(a) Financial information reflects accounting for the merger with PanEnergy
Corp as a pooling of interests. As a result, the financial information
gives effect to the merger as if it had occurred January 1, 1993.
15
Item 7. Management's Discussion and Analysis of Results of Operations and
Financial Condition.
INTRODUCTION
On June 18, 1997, Duke Power Company (Duke Power) changed its name to Duke
Energy Corporation (the Corporation) in accordance with the terms of a merger
agreement with PanEnergy Corp (PanEnergy), pursuant to which the Corporation
issued 158.3 million shares of its common stock in exchange for all of the
outstanding common stock of PanEnergy (the merger). PanEnergy was involved in
the gathering, processing, transportation and storage of natural gas, the
production of natural gas liquids and the marketing of natural gas,
electricity, liquefied petroleum gases and related energy services. Pursuant to
the merger, each share of PanEnergy common stock outstanding was converted into
the right to receive 1.0444 shares of the Corporation's common stock. In
addition, each outstanding option to purchase PanEnergy common stock became an
option to purchase common stock of the Corporation, adjusted accordingly.
As a result of the merger, the Corporation is an integrated energy and
energy services provider with the ability to offer physical delivery and
management of both electricity and natural gas throughout the United States and
abroad. The Corporation provides these services through four business segments:
Electric Operations, Natural Gas Transmission, Energy Services, and Other
Operations.
The Electric Operations segment is engaged in the generation,
transmission, distribution and sale of electric energy in central and western
North Carolina and the western portion of South Carolina. 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).
The Natural Gas Transmission segment is involved in interstate
transportation and storage of natural gas for customers primarily in the
Mid-Atlantic, New England and Midwest states. The interstate natural gas
transmission and storage operations are also subject to the rules and
regulations of the FERC.
The Energy Services segment is comprised of several separate business
units: Field Services gathers and processes natural gas, produces and markets
natural gas liquids and transports and trades crude oil; Trading and Marketing
markets natural gas, electricity and other energy-related products; Global
Asset Development develops, owns and operates energy-related facilities
worldwide; and Other Energy Services provides engineering consulting,
construction and integrated energy solutions.
Other Operations include the real estate operations of Crescent Resources,
Inc. (Crescent Resources), communications services, corporate costs and
intersegment eliminations.
The merger was accounted for as a pooling of interests and, accordingly,
the Consolidated Financial Statements included in this Annual Report are
presented as if the merger was consummated as of the beginning of the earliest
period presented. Portions of the following discussion provide information
related to material changes in the Corporation's consolidated results of
operations and financial condition between the periods presented, based on the
combined historical information of Duke Power and PanEnergy.
Management's Discussion and Analysis should be read in conjunction with
the Consolidated Financial Statements of the Corporation.
RESULTS OF OPERATIONS
Earnings available for common stockholders of the Corporation decreased
12% in 1997 as compared to 1996, from $1,030.1 million or $2.85 per share in
1996 to $901.6 million or $2.51 per share in 1997. The decrease was due
primarily to increases in non-recurring merger related costs, a provision for
non-recurring severance costs associated with the work force reduction in
Electric Operations, premiums associated with the redemption and tender offer
for ten issues of preferred stock and higher expenses as a result of increased
outages at the Electric Operations' nuclear stations. Partially offsetting the
decrease were lower expenses in 1997 as compared to 1996 when major storms
affected the Electric Operations' distribution costs.
In 1996, earnings available for common stockholders increased 6% over
1995, from $969.2 million or $2.68 per share in 1995 to $1,030.1 million or
$2.85 per share in 1996. Contributing to the increase were Electric Operations'
customer growth, business expansion projects placed in service in both the
Natural Gas Transmission and the Energy Services segments and increased volumes
in Energy Services due primarily to the joint venture formed with Mobil
Corporation (Mobil)
16
in August 1996. Partially offsetting the increase were expenses related to
major storms in 1996, which affected the Electric Operations' distribution
costs, non-recurring merger related costs and an extraordinary item related to
the early retirement of debt in 1996.
Operating income of the Corporation for 1997 was $1,970 million compared
to $2,158.6 million in 1996 and $2,068.3 million in 1995. Earnings before
interest and taxes (EBIT) were $2,108.1 million, $2,294.2 million and $2,190.5
million for 1997, 1996 and 1995, respectively. Operating income and earnings
before interest and taxes are not materially different, and are affected by the
same fluctuations for the Corporation and each of its business segments.
Earnings before interest and taxes by business segment are summarized below,
and the explanation of these results by business segment are discussed
thereafter.
Earnings Before Interest and Taxes by Business Segment is as follows:
1997 1996 1995
------------- ------------- -------------
In Millions
Electric Operations
Duke Power ................................ $ 1,266.1 $ 1,404.8 $ 1,370.9
Nantahala Power and Light Company ......... 15.7 14.7 10.3
---------- ---------- ----------
Total Electric Operations ............... 1,281.8 1,419.5 1,381.2
---------- ---------- ----------
Natural Gas Transmission
Northeast Pipelines ....................... 420.5 399.4 370.5
Midwest Pipelines ......................... 203.9 196.1 197.1
---------- ---------- ----------
Total Natural Gas Transmission .......... 624.4 595.5 567.6
---------- ---------- ----------
Energy Services
Field Services ............................ 157.0 151.6 106.1
Trading and Marketing ..................... 44.4 57.9 17.1
Global Asset Development .................. 4.5 -- 26.8
Other Energy Services ..................... 18.2 20.0 23.7
---------- ---------- ----------
Total Energy Services ................... 224.1 229.5 173.7
---------- ---------- ----------
Crescent Resources ......................... 97.6 87.7 64.0
Other Operations ........................... (119.8) (38.0) 4.0
---------- ---------- ----------
Consolidated EBIT .......................... $ 2,108.1 $ 2,294.2 $ 2,190.5
========== ========== ==========
Net income for 1997 is net of a full year of the minority interests
associated with the August 1996 joint venture with Mobil in the Trading and
Marketing operations of the Energy Services segment (see Note 3 to the
Consolidated Financial Statements).
Included in the amounts discussed below are intercompany transactions that
do not have a material impact on consolidated earnings before interest and
taxes.
Electric Operations
1997 1996 1995
------------- ------------- -------------
Dollars In Millions
Revenue ............................... $ 4,401.7 $ 4,498.4 $ 4,512.4
Operating Expenses .................... 3,221.4 3,194.8 3,203.7
---------- ---------- ----------
Operating Income ...................... 1,180.3 1,303.6 1,308.7
Other Income, Net of Expenses ......... 101.5 115.9 72.5
---------- ---------- ----------
EBIT .................................. $ 1,281.8 $ 1,419.5 $ 1,381.2
========== ========== ==========
Volumes, GWh Sales (a) ................ 77,541 76,852 76,737
- ---------
(a) Gigawatt-hour sales
In 1997, earnings before interest and taxes for the Electric Operations
segment declined 10% as compared to 1996 primarily as a result of the provision
for non-recurring severance costs associated with the work force reduction and
the increase in nuclear expenses, due primarily to increased outage days. Also
contributing to the decrease were lower electric revenues,
17
which were due primarily to mild weather and to the South Carolina rate
reduction, which was effective June 1, 1996. Partially offsetting the decrease
in earnings were lower expenses in 1997 as compared to 1996 when major storms
affected distribution costs.
Although the unusually mild weather reduced residential sales during the
year, general service and industrial sales continued to show strong growth.
Residential kilowatt-hour sales, the most sensitive to weather, declined 4.7%
during the year. Textile sales increased 3.0% and other industrial sales were
up 1.3%, for a total growth in industrial sales of 2.0%. Sales to general
service customers increased 0.5%. The number of customers in the Electric
Operations' service territory increased 2.7% over 1996.
In 1996, earnings before interest and taxes for Electric Operations
increased 3% over 1995 due to growth in the number of residential and general
service customers and increased retail kilowatt-hour sales to weather-sensitive
customer classes. Increased retail sales were partially offset by the South
Carolina rate reduction, which was effective June 1, 1996 and by a 16% decrease
in wholesale sales primarily due to a decrease of 24% in supplemental sales
requirements to the other joint owners of the Catawba Nuclear Station
(Catawba). The effect on earnings before interest and taxes of the decrease in
supplemental sales was partially offset by declines in purchased power expense
from the other joint owners.
For more information on the Catawba joint ownership, see Note 6 to the
Consolidated Financial Statements.
Natural Gas Transmission
1997 1996 1995
------------- ------------- -------------
Dollars In Millions
Revenue ............................... $ 1,572.1 $ 1,556.3 $ 1,533.4
Operating Expenses .................... 964.4 972.5 971.1
---------- ---------- ----------
Operating Income ...................... 607.7 583.8 562.3
Other Income, Net of Expenses ......... 16.7 11.7 5.3
---------- ---------- ----------
EBIT .................................. $ 624.4 $ 595.5 $ 567.6
========== ========== ==========
Volumes, TBtu (a) ..................... 2,862 2,939 2,703
- ---------
(a) Trillion British thermal units
During 1997, the Natural Gas Transmission segment completed the
organization of its operations into the Northeast Pipelines, which includes
Texas Eastern Transmission Corporation (TETCO) and Algonquin Gas Transmission
Company (Algonquin), and the Midwest Pipelines, which includes Panhandle
Eastern Pipe Line Company (PEPL) and Trunkline Gas Company (Trunkline).
Earnings before interest and taxes for the Natural Gas Transmission segment
increased 5% in 1997 over the prior year, with increases in earnings at
Northeast Pipelines and Midwest Pipelines of 5% and 4%, respectively. Earnings
before interest and taxes increased primarily due to market-expansion projects
placed in service and the favorable resolution of regulatory matters in 1997 in
amounts in excess of those resolved in 1996. The resolution of regulatory
matters was reflected as additional revenue and other income. The increases
were partially offset by certain litigation expenses recorded in 1997.
In 1996, earnings before interest and taxes for the Natural Gas
Transmission segment increased 5% over 1995. This was primarily due to a 9%
increase in throughput resulting from new pipeline expansion projects placed in
service in late 1995 and due to colder weather, which increased revenues.
Operating expenses in 1995 included a charge for higher Order 636 transition
cost estimates, partially offset by the benefit of lower-than-projected PCB
(polychlorinated biphenyl) clean-up costs (see Note 5 to the Consolidated
Financial Statements).
Energy Services
Earnings before interest and taxes for the Energy Services segment in 1997
decreased slightly as compared to 1996, which was 32% higher than 1995 earnings
before interest and taxes. During 1997, 1996 and 1995, these fluctuations were
driven primarily by the results of operations of Field Services and Trading and
Marketing.
18
Field Services
1997 1996 1995
------------- ------------- -------------
Dollars In Millions
Revenue ............................................ $ 3,054.6 $ 2,636.5 $ 1,791.4
Operating Expenses ................................. 2,897.9 2,487.1 1,694.6
---------- ---------- ----------
Operating Income ................................... 156.7 149.4 96.8
Other Income, Net of Expenses ...................... 0.3 2.2 9.3
---------- ---------- ----------
EBIT ............................................... $ 157.0 $ 151.6 $ 106.1
========== ========== ==========
Volumes
Natural Gas Gathered/Processed, TBtu/d (a) ......... 3.4 2.9 1.9
NGL Production, MBbl/d (b) ......................... 103.9 76.5 54.8
- ---------
(a) Trillion British thermal units per day
(b) Thousand barrels per day
Field Services' earnings before interest and taxes increased 4% for 1997
over 1996 primarily due to higher volumes as a result of acquisitions in 1996.
Natural gas gathered and processed volumes increased 17% and natural gas
liquids (NGL) production increased 36%. Partially offsetting these increases
were higher natural gas prices, which increased operating expenses, and a
decrease in NGL prices of 8%, which decreased revenues.
Earnings before interest and taxes for Field Services increased 43% in
1996 as compared with 1995. Strong processing margins and increased gathering
and processing volumes related to expansion projects and asset acquisitions,
primarily the acquisition of assets from Mobil, contributed to the increase in
revenues. Average NGL prices increased 30%, while NGL production increased 40%.
These improvements were partially offset by increased operating expenses and
depreciation as a result of the Mobil asset acquisition and other projects
placed in service. A gain on the sale of an investment in Seagull Shoreline
System in 1995 caused a comparative reduction in other income.
Trading and Marketing
1997 1996 1995
------------- ------------- -------------
Dollars In Millions
Revenue ............................... $ 7,488.7 $ 3,814.0 $ 1,866.7
Operating Expenses .................... 7,446.0 3,757.7 1,846.7
---------- ---------- ----------
Operating Income ...................... 42.7 56.3 20.0
Other Income, Net of Expenses ......... 1.7 1.6 (2.9)
---------- ---------- ----------
EBIT .................................. $ 44.4 $ 57.9 $ 17.1
========== ========== ==========
Volumes
Natural Gas Marketed, TBtu/d .......... 6.9 5.5 3.6
Electricity Marketed, GWh (a) ......... 64,650 4,229 513
- ---------
(a) Gigawatt-hours
A wholly owned subsidiary of the Corporation acquired the remaining 50%
ownership interest in the Duke/Louis Dreyfus, L.L.C. (D/LD) joint venture in
June 1997. This acquisition, coupled with a full year of operations of the
joint venture with Mobil formed in August 1996, accounted for the significant
increases in Trading and Marketing revenues, related operating expenses and
volumes in 1997 over 1996. Natural gas marketed volumes increased 25%, in
addition to increases in natural gas margins from trading activities, which
were largely offset by the emerging electric power trading and marketing
activities. Higher operating expenses, driven mainly by increased personnel
levels and system development costs to provide the necessary infrastructure for
growth in the trading and marketing business, resulted in a decrease in
earnings before interest and taxes in 1997 as compared to 1996.
In 1996, Trading and Marketing's earnings before interest and taxes
increased $40.8 million as compared to 1995 primarily as a result of expanded
operations due to the joint venture with Mobil formed in August 1996. The
increase resulted primarily from higher gas volumes, improved margins resulting
from colder weather and gas price volatility, and higher trading margins. Total
gas volumes marketed increased 53%. The increase in margins was partially
offset by higher operating expenses related to the joint venture with Mobil.
19
Other Operations
Earnings before interest and taxes for Crescent Resources increased 11% in
1997 over 1996. The increase is primarily due to gains associated with bulk
land sales in 1997. In 1996, earnings before interest and taxes for Crescent
Resources increased 37% over 1995 resulting from increased developed lot sales
as well as bulk land sales.
Earnings before interest and taxes for Other Operations, excluding
Crescent Resources, declined $81.8 million in 1997 as compared to 1996.
Contributing to the decrease were merger related expenses of $71.2 million in
1997, compared to 1996 merger expenses of $13.9 million, and the 1997
amortization of goodwill associated with the purchase of the remaining 50%
ownership interest of the D/LD joint venture. This decline was partially offset
by the sale of the Corporation's ownership interest in the Midland Cogeneration
Venture in 1997.
In 1996, earnings before interest and taxes for Other Operations,
excluding Crescent Resources, decreased $42 million as compared to 1995
primarily as a result of 1996 expenses related to the merger and losses related
to the start-up activities of a wireless communications joint venture.
Other Impacts on Earnings Available for Common Stockholders
In 1997, interest expense decreased $27.4 million, or 5%, as compared to
1996 as a result of lower interest rates. Interest expense in 1996 decreased 2%
compared with 1995 as a result of lower average interest rates and lower
average debt balances outstanding.
Minority interests in 1997 and 1996 relate primarily to the joint venture
with Mobil formed in August 1996.
On October 1, 1996, a subsidiary of the Corporation redeemed its $150
million, 10% debentures and its $100 million, 10 1/8% debentures both due 2011.
The Corporation recorded a non-cash extraordinary item of $16.7 million (net of
income tax of $10.3 million) related to the unamortized discount on this early
retirement of debt.
In December 1997, the Corporation redeemed four issues of preferred stock
and commenced a tender offer to purchase a portion of an additional six issues
of preferred stock. Premiums related to these redemptions were included in
Dividends and Premiums on Redemptions of Preferred and Preference Stock in the
Consolidated Statements of Income.
LIQUIDITY AND CAPITAL RESOURCES
OPERATING CASH FLOW. Operating cash flows decreased $195.1 million from
1996 to 1997. This decrease primarily reflects the cash impact of costs
associated with the merger and natural gas transition cost recoveries.
Operating cash flows increased $503 million from 1995 to 1996. This
increase primarily reflects the cash impact of purchased capacity levelization
and natural gas transition cost recoveries. Additionally, improved working
capital caused cash flows from operations to increase in 1996.
Assets and liabilities recorded in the Consolidated Balance Sheets related
to purchased capacity levelization and the natural gas transition cost
recoveries and the related cash flow impacts are effected by state and federal
regulatory initiatives and specific agreements. For more information on the
purchased capacity levelization and the natural gas transition cost recoveries,
see Notes 6 and 5, respectively, to the Consolidated Financial Statements.
INVESTING CASH FLOW. Capital and investment expenditures were
approximately $2.0 billion in 1997 compared with approximately $1.6 billion in
1996. Increased capital and investment expenditures were partially due to the
acquisition of the remaining 50% ownership interest in the D/LD joint venture
and the acquisition of an ownership interest in American Ref-Fuel Company.
Additionally, increased Electric Operations' construction costs, primarily due
to steam generator replacements at certain of the Corporation's nuclear plants
and increased distribution line construction and business expansion for the
Natural Gas Transmission segment caused expenditures to increase. These
increases were partially offset by the 1996 acquisition of certain assets from
Mobil.
The Corporation participated in the marketing of electric power and
natural gas through its 50% ownership interest in D/LD. On June 17, 1997, the
Corporation, through one of its subsidiaries, acquired the remaining 50%
ownership interest in D/LD from affiliates of Louis Dreyfus Corp. for $247
million. The purchase price substantially represents goodwill, which will be
amortized over 10 years.
Also in June 1997, the Corporation signed a letter of intent to build a
$265 million, 520-megawatt combined cycle natural gas fired merchant generation
plant in Bridgeport, Connecticut. The Corporation will be majority owner, with
the first phase of the project scheduled to provide power in mid-1998. The
project is currently under construction.
20
During December 1997, a wholly owned subsidiary of the Corporation formed
a joint venture with UAE Ref-Fuel L.L.C. (UAE), a wholly owned subsidiary of
United American Energy Corp. The Corporation owns a 65% interest in the joint
venture, with UAE owning a 35% minority interest. The joint venture acquired a
50% ownership interest in American Ref-Fuel Company, a waste-to-energy firm,
with operations primarily in New York and New Jersey. Thus, the Corporation has
an indirect 32.5% ownership interest in American Ref-Fuel Company and provided
$237 million of investment and financing to the venture.
During 1997, the Corporation sold its ownership in trading and marketing
operations in the United Kingdom and its equity interest in certain affiliates.
Proceeds from these sales were $87 million.
Capital and investment expenditures in 1996 included the acquisition of
certain assets of Mobil for approximately $300 million by Field Services. The
increase in capital and investment expenditures in 1996 over 1995 was a result
of this acquisition and other Energy Services expansion projects, partially
offset by decreased Electric Operations' construction costs as a result of the
completion of certain generating facilities in 1995.
The Corporation plans to maintain its regulated facilities and pursue
business expansion of its regulated operations as opportunities arise.
Projected 1998 capital and investment expenditures for the Electric Operations
and the Natural Gas Transmission segments, including allowance for funds used
during construction, are approximately $700 million and $300 million,
respectively. These projections are subject to periodic review and revisions.
Actual expenditures incurred may vary from such estimates due to various
factors, including revised electric load estimates, business expansion
opportunities, environmental matters and cost and availability of capital.
The Energy Services segment plans to spend approximately $100 million in
1998 for required capital expenditures at its existing facilities. In addition,
the Corporation is seeking to significantly grow its Energy Services
businesses, primarily through the Global Asset Development business unit. One
expansion opportunity includes the 520-megawatt combined cycle natural gas
fired merchant generation plant in Bridgeport, Connecticut already under
construction. Another growth opportunity includes the recently announced
agreement to purchase from Pacific Gas & Electric Company three power plants in
California. The power plants have a combined capacity of 2,645 megawatts. The
purchase price is estimated at approximately $500 million and the transaction
is expected to close during 1998. Other similar initiatives in 1998 will likely
require significant capital and investment expenditures, which will be subject
to periodic review and revision and may vary significantly depending on the
value-added opportunities presented.
Projected capital and investment expenditures for 1998 of the Other
Operations segment are approximately $200 million. These projected capital and
investment expenditures are subject to periodic review and revision and may
vary significantly depending on the value-added opportunities presented.
FINANCING CASH FLOW. The Corporation's consolidated capital structure at
December 31, 1997, including short-term debt, was 45% debt, 3% preferred stock,
50% common equity and 2% other capitalization. Fixed charges coverage, using
the SEC method, was 4.1 times for 1997 compared to 4.3 and 4.0 times for 1996
and 1995, respectively.
Subsequent to the merger, several rating agencies reviewed and in some
cases revised their debt ratings for the Corporation and its subsidiaries
PanEnergy, PEPL, and TETCO. As of December 31, 1997, Duke Energy Corporation's
senior indebtedness ratings were as follows: AA- by Standard & Poor's Group and
Fitch Investors Service; Aa3 by Moody's Investors Service; and AA by Duff &
Phelps. The Corporation's intent is to maintain these current credit ratings.
During August 1997, the Corporation instituted a new commercial paper
program, increasing its available commercial paper facilities to $2.5 billion.
The commercial paper facilities consist of $1.25 billion for the Corporation
and $1.25 billion for Duke Capital Corporation (Duke Capital), a wholly owned
subsidiary of the Corporation. Duke Capital serves as the parent for the
Corporation's business segments except the Electric Operations and certain
other operations. The Corporation's total commercial paper facilities were $780
million at December 31, 1996. These facilities are supported by various bank
credit agreements which totaled $2.7 billion and $1.5 billion at December 31,
1997 and 1996, respectively. As a result of the revised commercial paper
program and the related credit facilities, the Corporation terminated the prior
commercial paper program and related bank facilities held by the Corporation
and PanEnergy. At December 31, 1997, $1.7 billion of commercial paper and $93
million of bank borrowings were outstanding.
On December 8, 1997, Duke Energy Capital Trust I (the Trust), a business
trust which is treated as a subsidiary of the Corporation for financial
reporting purposes, issued $350 million of its 7.2% trust preferred securities,
at an $11 million discount, representing preferred undivided beneficial
interests in the assets of the Trust. Payment of distributions on such
preferred securities is guaranteed by the Corporation, but only to the extent
the Trust has funds legally and immediately available to make such
distributions.
21
Since December 31, 1996, $647.6 million of the Corporation's first and
refunding mortgage bonds and $114.5 million of the Corporation's medium term
notes matured or were redeemed. These retirements were funded primarily through
the Corporation's commercial paper facilities.
During July 1996, the Corporation began purchasing shares of its common
stock. In 1996, the Corporation repurchased approximately 3.3 million shares of
common stock for $159 million. On January 28, 1997, the Board of Directors
amended the program to expressly limit the number of shares authorized for
repurchase under the program, from the initiation of the program through a date
two years after the consummation of the merger, to an amount not to exceed 15
million shares. No repurchases of common stock were made in 1997, and none are
anticipated in the future.
The Corporation plans to use authorized but unissued shares of its common
stock to meet 1998 employee benefit plan contribution requirements instead of
purchasing shares on the open market.
The Corporation and its subsidiaries have authority to issue up to $1.3
billion aggregate principal amount of debt and other securities under shelf
registration statements filed with the Securities and Exchange Commission. Such
securities may be issued as First and Refunding Mortgage Bonds, Senior Notes,
Subordinated Debentures, or Preferred Stock.
Dividends and debt repayments, along with operating and investing
requirements, are expected to be funded by cash from operations, debt and
commercial paper issuances and available credit facilities. As noted
previously, the Corporation is seeking to significantly grow its Energy
Services businesses, which will likely require significant additional
financing.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
INTEREST RATE RISK. The Corporation is exposed to changes in interest
rates as a result of significant financing through its issuance of
variable-rate debt, fixed-rate debt, commercial paper and auction market
preferred stock, as well as fixed-to-floating interest rate swaps. The
Corporation manages its interest rate exposure by limiting its variable-rate
exposure to a certain percentage of total capitalization, as set by policy, and
by monitoring the effects of market changes in interest rates. (See Notes 11
and 14 to the Consolidated Financial Statements.)
If market interest rates average 1% more in 1998 than in 1997, the
Corporation's interest expense, after considering the effect of the interest
rate swap agreements, would increase, and income before taxes would decrease by
approximately $23.6 million. This amount has been determined by considering the
impact of the hypothetical interest rates on the Corporation's variable-rate
debt balances, commercial paper balances, auction market preferred stock
balances and interest rate swap agreements as of December 31, 1997. These
analyses do not consider the effects of the reduced level of overall economic
activity that could exist in such an environment. In the event of a significant
change in interest rates, management would likely take actions to further
mitigate its exposure to the change. However, due to the uncertainty of the
specific actions that would be taken and their possible effects, the
sensitivity analysis assumes no changes in the Corporation's financial
structure.
COMMODITY PRICE RISK. The Corporation, substantially through its
subsidiaries, is exposed to the impact of market fluctuations in the price and
transportation costs of natural gas, electricity and petroleum products
marketed and employs established policies and procedures to manage its risks
associated with these market fluctuations using various commodity derivatives,
including futures, swaps and options. (See Note 8 to the Consolidated Financial
Statements.) The Corporation measures the risk in its commodity derivative
portfolio on a daily basis utilizing a Value-at-Risk (VAR) model to determine
the maximum potential one-day favorable or unfavorable impact on its earnings
and monitors its risk in comparison to established thresholds. The Corporation
also utilizes other measures to monitor the risk in its commodity derivative
portfolio on a monthly, quarterly and annual basis. The VAR computations are
based on an historical simulation, which utilizes price movements over a
specified period to simulate forward price curves in the energy markets to
estimate the favorable or unfavorable impact of one-day's price movement on the
existing portfolio. The VAR computations utilize several key assumptions,
including the confidence level for the resultant price movement and the holding
period chosen for the calculation. The Corporation's calculation includes
commodity derivative instruments held for trading purposes and excludes the
effects of written and embedded physical options in the trading portfolio. At
December 31, 1997, the Corporation's estimated potential one-day favorable or
unfavorable impact on income before taxes, as measured by VAR, related to its
commodity derivatives held for trading purposes was approximately $2 million.
Changes in markets inconsistent with historical trends could cause actual
results to exceed predicted limits. Market risks associated with commodity
derivatives held for purposes other than trading were not material at December
31, 1997.
Subsidiaries of the Corporation are also exposed to market fluctuations in
the price of natural gas liquids (NGLs) related to their ongoing gathering and
processing operating activities. Because the Corporation generally does not
maintain an
22
inventory of NGLs or actively trade commodity derivatives related to NGLs, the
Corporation was not exposed to this risk at December 31, 1997. However, the
Corporation closely monitors the risks associated with NGL price changes on its
future operations.
EQUITY PRICE RISK. The Corporation maintains trust funds, as required by
the Nuclear Regulatory Commission, to fund certain costs of nuclear
decommissioning. (See Note 12 to the Consolidated Financial Statements.) As of
December 31, 1997, these funds were invested primarily in domestic and
international equity securities, fixed-rate, fixed income securities and cash
and cash equivalents. By maintaining a portfolio that includes long-term equity
investments, the Corporation is maximizing the returns to be utilized to fund
nuclear decommissioning, which in the long-term will better correlate to
inflationary increases in decommissioning costs. However, the equity securities
included in the Corporation's portfolio are exposed to price fluctuation in
equity markets, and the fixed-rate, fixed income securities are exposed to
changes in interest rates. The Corporation actively monitors its portfolio by
benchmarking the performance of its investments against certain indexes and by
maintaining, and periodically reviewing, established target allocation
percentages of the assets in its trusts to various investment options. Because
the accounting for nuclear decommissioning recognizes that costs are recovered
through the Corporation's Electric Operations' rates, fluctuations in equity
prices or interest rates do not affect the earnings of the Corporation.
FOREIGN OPERATIONS RISK. The Corporation has investments in several
international operations, many of which are joint ventures. At December 31,
1997, the Corporation had investments in international affiliates of $230.1
million. These investments represent primarily investments in affiliates which
own energy-related production, generation and transmission facilities.
The Corporation is exposed to foreign currency risk, sovereign risk and
other foreign operations risks, primarily through investments in affiliates of
$43.6 million in Asia and $100.7 million in South America. In order to mitigate
risks associated with foreign currency fluctuations, the majority of contracts
entered into by the Corporation or its affiliates are denominated in or indexed
to the U.S. dollar. Other exposures to foreign currency risk, sovereign risk or
other foreign operations risk are periodically reviewed by management and were
not material to the Corporation's consolidated results of operations or
financial position during the period.
CURRENT ISSUES
OPERATIONS OUTLOOK. The Electric Operations segment is expected to grow
moderately, consistent with historical trends. Expansion will be primarily as a
result of continued economic growth in its service territory. In 1997, as a
result of the merger, the Corporation signed various agreements with the NCUC,
PSCSC and the FERC in which the Corporation agreed to cap base rates to retail
and wholesale electric customers at existing levels through 2000. In addition,
the Corporation signed agreements with the other joint owners of Catawba
providing for a cap on certain rates charged under interconnection agreements.
In response to these rate agreements and competitive pressures, the Electric
Operations segment is striving to maintain low costs and competitive rates for
its customers and to provide high quality customer service. The Corporation
does not expect a negative impact as a result of such agreements on its results
of operations or financial position. (See further discussion in the Electric
Competition section below.)
Due to increased competition, especially for the Midwest Pipelines,
relatively slow growth is expected for future operations of the Corporation's
Natural Gas Transmission segment. The Natural Gas Transmission segment
continues to offer selective discounting to maximize revenues from existing
capacity and to advance projects that provide expanded services to meet the
specific needs of customers. Several projects have been announced that position
the Natural Gas Transmission segment to meet increasing demand for gas in
northeast markets by providing continuous paths from new supplies in both
eastern and western Canada in addition to traditional domestic supply basins.
The Corporation is seeking to significantly grow its Energy Services
segment. Deregulation of energy markets in the U.S. and abroad is providing
substantial opportunities for the Energy Services business units to capitalize
on their broad capabilities. Growth is expected to be achieved through
acquisitions, construction of greenfield projects and expansion of existing
facilities as value-added opportunities present themselves.
The strong real estate market in the southeast continues to present
substantial growth opportunities for Crescent Resources. In 1997, Crescent
Resources initiated development of significant office and industrial facilities
in each of its established markets to capitalize on market conditions.
ELECTRIC COMPETITION. The Energy Policy Act of 1992 (EPACT) and the FERC's
subsequent rulemaking activities are major drivers towards a more competitive
market for electric operations. EPACT amended provisions of the Public Utility
23
Holding Corporation Act of 1935 (PUHCA) and Part II of the Federal Power Act to
remove certain barriers to electric competition. EPACT permits utilities to
participate in the development of independent electric generating plants for
sales to wholesale customers, and also permits the FERC to order transmission
access for third parties to transmission facilities owned by another entity. It
does not, however, permit the FERC to issue an order requiring transmission
access to retail customers. The FERC, responsible in large measure for
implementation of the EPACT, has moved vigorously to implement its mandate,
interpreting the statute broadly and issuing orders for third-party
transmission service and a number of rules of general applicability, including
Orders 888 and 889.
Open-access transmission for wholesale customers as defined by the FERC's
final rules provides energy suppliers, including the Corporation, with
opportunities to sell and deliver capacity and energy at market-based prices.
The Corporation and several of the Corporation's non-regulated subsidiaries
were granted authority by the FERC to act as power marketers in late 1995. The
Electric Operations obtained from the FERC open-access rights to sell at
market-based rates up to 2,500 megawatts of capacity and energy from its own
assets. Open-access provides another supply option through which the
Corporation can purchase at attractive rates a portion of capacity and energy
requirements resulting in lower overall costs to customers and thus improving
the Corporation's competitive position. Open-access also provides the
Corporation's existing wholesale customers with competitive opportunities to
seek other suppliers for their capacity and energy requirements.
Wholesale sales represented approximately 9.4 percent of the Corporation's
total gigawatt-hour sales for the Electric Operations segment in 1997.
Supplemental sales to the other joint owners of Catawba comprised the majority
of wholesale sales. Such supplemental sales will continue to decline in 1998 as
a result of the retention of larger portions of ownership entitlement by the
other joint owners. Two of the Catawba joint owners gave notice of their intent
to end their supplemental capacity requirements on January 1, 2001 and January
1, 2002, respectively. In addition, as a result of the merger, the other joint
owners have the right to end their supplemental capacity requirements as of
January 1, 2001 with written notice to the Corporation due by December 31,
1999. Another joint owner gave notice of its intent to end its interconnection
agreement with the Corporation effective January 1, 2006 (see Note 6 to the
Consolidated Financial Statements).
Competition for retail electric customers is not generally allowed in the
Corporation's service territory. However, there are discussions and events at
the national level and within certain states regarding retail competition which
are resulting in changes in the industry. Such changes will impact all entities
owning electric generating assets. During 1997, both North and South Carolina
have taken steps to address retail competition among electric utilities.
In May 1997, North Carolina passed a bill that created a study commission
to assess deregulation of electric utilities in the state. The commission's
report to the state General Assembly is expected to be completed by early 1999.
Members of the study commission include legislators, utility representatives,
customers and a member of an environmental group.
South Carolina has considered several proposals during 1997 to restructure
the electric industry, the most significant of which would have provided retail
customers with a choice of suppliers by January 1, 1998. None of these
proposals has been approved. However, in May 1997, the PSCSC requested
interested parties to file restructuring proposals for the electric industry.
On June 30, 1997, the Corporation filed its proposal for introducing electric
competition in South Carolina with the PSCSC. The Corporation's plan proposes
that electric generation be deregulated while transmission and distribution
continue to be regulated by the FERC and the PSCSC, respectively, providing for
an orderly transition to competition that takes all stakeholders into
consideration. The Corporation's plan also provides for recovery of stranded
investment. The PSCSC held hearings on August 19, 1997 on the various
restructuring proposals it received and presented its report to the state
legislature on February 3, 1998. The report proposes a five year transition
period before starting full-fledged electric competition. In addition,
customers could receive two separate electric bills, one from the distribution
company, and one from the generator or supplier of electricity. The report
leaves the final decisions to the General Assembly of South Carolina.
Currently, the electric utility industry is predominantly regulated on a
basis designed to recover the cost of providing electric power to its
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. The regulatory assets of the
Corporation are included in the Consolidated Balance Sheets. The portion of
these regulatory assets related to electric operations is $1.7 billion,
including primarily purchased capacity costs, debt expense, and deferred taxes
related to regulatory assets. Currently, the Corporation is recovering
substantially all of these regulatory assets through its wholesale and retail
electric rates and would attempt to continue to recover these assets should
cost-based regulation be discontinued. In addition, the Corporation would seek
to recover the costs of its electric generating facilities in excess of the
market price of power at the time of transition.
24
The Corporation seeks to move toward an orderly transition to retail
competition that provides for consideration of the interests of all
stakeholders in the retail electric sales arena. Management cannot predict the
potential impact, if any, of these competitive forces on the Corporation's
future financial position and consolidated results of operations.
NUCLEAR DECOMMISSIONING COSTS. The Corporation's estimated site-specific
nuclear decommissioning costs, including the cost of decommissioning plant
components not subject to radioactive contamination, total approximately $1.3
billion stated in 1994 dollars based on decommissioning studies completed in
1994. In order to fund these costs, the Corporation contributes to an external
decommissioning trust fund and maintains an internal reserve.
The balance of the external funds as of December 31, 1997 and 1996, was
$471.1 million and $362.6 million respectively. The balance of the internal
reserve as of December 31, 1997 and 1996, was $210.8 million and $207.8
million, respectively, and is reflected in Accumulated Depreciation and
Amortization in the Consolidated Balance Sheets.
Both the NCUC and the PSCSC have granted the Corporation recovery of
estimated decommissioning costs through retail rates over the expected
remaining service periods of the Corporation's nuclear plants. Management is of
the opinion that funding of the decommissioning costs will not have a material
adverse effect on the consolidated results of operations and financial position
of the Corporation. (See Note 12 to the Consolidated Financial Statements.)
ENVIRONMENTAL. The Corporation is subject to 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. The Corporation was an
operator of manufactured gas plants until the early 1950s. The Corporation has
entered into a cooperative effort with the State of North Carolina and other
owners of certain former manufactured gas plant sites to investigate and, where
necessary, remediate these contaminated sites. The State of South Carolina has
expressed interest in entering into a similar arrangement. The Corporation is
considered by regulators to be a potentially responsible party and may be
subject to future liability at nine federal Superfund sites and one state
Superfund site. While the cost of remediation of the remaining sites may be
substantial, the Corporation will share in any liability associated with
remediation of contamination at such sites with other potentially responsible
parties. Management is of the opinion that resolution of these matters will not
have a material adverse effect on the consolidated results of operations or
financial position of the Corporation.
PCB (Polychlorinated Biphenyl) Assessment and Clean-up Programs. TETCO, a
wholly owned subsidiary of the Corporation, is currently conducting PCB
assessment and clean-up programs at certain of its compressor station sites
under conditions stipulated by a U.S. Consent Decree. The programs include on-
and off-site assessment, installation of on-site source control equipment and
groundwater monitoring wells, and on- and off-site clean-up work. TETCO expects
to complete these clean-up programs during 1998. Groundwater monitoring
activities will continue at several sites beyond 1998.
In 1987, the Commonwealth of Kentucky instituted a suit in state court
against TETCO, alleging improper disposal of PCBs at TETCO's three compressor
station sites in Kentucky. This suit is still pending. In 1996, TETCO completed
clean-up of these sites under the U.S. Consent Decree.
The Corporation has also identified environmental contamination at certain
sites on the PEPL and Trunkline systems and is undertaking clean-up programs at
these sites. The contamination resulted from the past use of lubricants
containing PCBs and the prior use of wastewater collection facilities and other
on-site disposal areas. Soil and sediment testing, to date, has detected no
significant off-site contamination. The Corporation has communicated with the
Environmental Protection Agency (EPA) and appropriate state regulatory agencies
on these matters. Environmental clean-up programs are expected to continue
until 2002.
At December 31, 1997 and 1996, the Corporation had accrued liabilities for
remaining estimated clean-up costs on the TETCO, PEPL and Trunkline systems,
which were included in Environmental Clean-up Liabilities in the Consolidated
Balance Sheets. These cost estimates represent gross clean-up costs expected to
be incurred, have not been discounted or reduced by customer recoveries and do
not include fines, penalties or third-party claims. Costs expected to be
recovered from customers are included in the Consolidated Balance Sheets as of
December 31, 1997 and 1996, as Regulatory Assets and Deferred Debits.
The federal and state clean-up programs are not expected to interrupt or
diminish the Corporation's ability to deliver natural gas to customers. Based
on the Corporation's experience to date and costs incurred for clean-up
operations, management believes the resolution of matters relating to the
environmental issues discussed above will not have a material adverse effect on
the consolidated results of operations or financial position of the
Corporation.
25
Air Quality Control. The Clean Air Act Amendments of 1990 require a
two-phase reduction by electric utilities in aggregate annual emissions of
sulfur dioxide and nitrogen oxide by 2000. The Corporation currently meets all
requirements of Phase I. The Corporation supports the national objective of
protecting air quality in the most cost-effective manner, and has already
reduced emissions by operating plants efficiently, using nuclear and
hydroelectric generation and implementing various compliance strategies. To
meet Phase II requirements by 2000, the Corporation's current strategy includes
using low-sulfur coal, purchasing sulfur dioxide emission allowances, and
installing low-nitrogen oxide burners and emission monitoring equipment.
Construction activities needed to comply with Phase II requirements are
substantially complete, and future one-time capital costs associated with
meeting Phase II requirements range from $14 million to $24 million. Additional
annual operating expenses of approximately $25 million for low-sulfur coal
premiums, emission allowance purchases and other compliance activities will
occur after 2000. This strategy is contingent upon developments in future
markets for emission allowances, low-sulfur coal, future regulatory and
legislative actions, and advances in clean air technologies.
Additionally, the Corporation would be effected by a proposed call for new
State Implementation Plans (SIP) issued by the EPA to 22 states related to
existing and new national ambient air quality standards for ozone. Costs to the
Corporation related to the SIP call may range from $123 million to $517
million, depending on final EPA implementation plans and schedules.
In 1994, the State of Missouri issued a Notice of Violation to PEPL
alleging violations of Missouri air pollution regulations at the Corporation's
Houstonia compressor station. The Corporation is in negotiations with the State
to resolve this matter. The State is seeking a penalty and correction of the
alleged violations.
In December 1997, the United Nations held negotiations in Kyoto, Japan to
determine how to achieve worldwide stabilization of greenhouse gas emissions,
including carbon dioxide emissions from fossil-fired generating facilities.
Because this matter is in the early stages of discussion, the Corporation
cannot estimate the effects on future consolidated results of operations or
financial position of the Corporation.
LITIGATION AND CONTINGENCIES. For information concerning litigation and
other commitments and contingencies, see Note 15 to the Consolidated Financial
Statements.
COMPUTER SYSTEMS CHANGES FOR THE YEAR 2000. The Corporation is incurring
incremental costs to modify existing computer systems to accommodate the year
2000 and beyond. The Corporation is currently making modifications to its
programs and is of the opinion that remaining modifications will be completed
before they become problematic. Management is of the opinion that the costs
associated with these modifications will not have a material adverse effect on
the consolidated results of operations or financial position of the
Corporation.
FORWARD-LOOKING STATEMENTS. From time to time, the Corporation may make
statements regarding its expectations, intent or beliefs about future events.
These statements are intended as "forward-looking statements" under the Private
Securities Litigation Reform Act of 1995. The Corporation cautions that
assumptions, projections and expectations about future events may and often do
vary from actual results, the differences between assumptions, projections and
expectations and actual results can be material, and there can be no assurance
that the forward-looking statements will be realized. The following are some of
the factors that could cause actual achievements and events to differ
materially from those expressed or implied in such forward-looking statements:
state and federal legislative and regulatory initiatives that affect cost and
investment recovery, have an impact on rate structures, and affect the speed
and degree to which competition enters the electric and natural gas industries;
industrial, commercial and residential growth in the service territories of the
Corporation and its subsidiaries; the weather and other natural phenomena; the
timing and extent of changes in commodity prices and interest rates; changes in
environmental and other laws and regulations to which the Corporation and its
subsidiaries are subject or other external factors over which the Corporation
has no control; the results of financing efforts; growth in opportunities for
the Corporation's subsidiaries and diversified operations; and the effect of
the Corporation's accounting policies, in each case during the periods covered
by the forward-looking statements.
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."
26
Item 8. Financial Statements and Supplementary Data.
DUKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
Years Ended December 31
------------------------------------------
1997 1996 1995
------------- ------------- --------------
(In Millions, except per share amounts)
Operating Revenues
Natural gas and petroleum products (Notes 2 and 5)
Sales, trading and marketing of natural gas and petroleum products ........... $ 8,150.7 $ 5,848.0 $ 3,397.2
Transportation and storage of natural gas .................................... 1,503.5 1,522.9 1,500.6
Electric (Notes 2 and 5)
Generation, transmission and distribution .................................... 4,334.5 4,436.6 4,454.6
Trading and marketing of electricity ......................................... 1,664.9 77.8 9.8
Other (Note 9) ................................................................. 655.3 417.1 332.5
---------- ---------- ----------
Total operating revenues .................................................... 16,308.9 12,302.4 9,694.7
---------- ---------- ----------
Operating Expenses
Natural gas and petroleum products purchased (Note 2) .......................... 7,705.2 5,414.3 3,119.3
Fuel used in electric generation (Note 2) ...................................... 742.8 758.5 744.2
Net interchange and purchased power (Notes 2, 5 and 6) ......................... 1,960.2 456.8 480.2
Other operation and maintenance (Notes 5, 12 and 15) ........................... 2,720.9 2,382.8 2,209.0
Depreciation and amortization (Notes 2 and 6) .................................. 841.0 789.4 737.1
Property and other taxes ....................................................... 368.8 342.0 336.6
---------- ---------- ----------
Total operating expenses .................................................... 14,338.9 10,143.8 7,626.4
---------- ---------- ----------
Operating Income ................................................................ 1,970.0 2,158.6 2,068.3
---------- ---------- ----------
Other Income and Expenses
Deferred returns and allowance for funds used during construction (Note 2) ..... 109.4 104.8 113.9
Other, net ..................................................................... 28.7 30.8 8.3
---------- ---------- ----------
Total other income and expenses ............................................. 138.1 135.6 122.2
---------- ---------- ----------
Earnings Before Interest and Taxes .............................................. 2,108.1 2,294.2 2,190.5
Interest Expense (Notes 8 and 11) ............................................... 471.8 499.2 508.2
Minority Interests (Note 3) ..................................................... 23.0 6.2 --
---------- ---------- -----------
Earnings Before Income Taxes .................................................... 1,613.3 1,788.8 1,682.3
Income Taxes (Notes 2 and 7) .................................................... 638.9 697.8 664.2
---------- ---------- -----------
Income Before Extraordinary Item ................................................ 974.4 1,091.0 1,018.1
Extraordinary Item (net of tax) ................................................. -- 16.7 --
---------- ---------- -----------
Net Income ...................................................................... 974.4 1,074.3 1,018.1
---------- ---------- -----------
Dividends and Premiums on Redemptions of Preferred
and Preference Stock (Note 14) ................................................. 72.8 44.2 48.9
---------- ---------- -----------
Earnings Available for Common Stockholders ...................................... $ 901.6 $ 1,030.1 $ 969.2
========== ========== ===========
Common Stock Data (Note 2)
Average shares outstanding ..................................................... 359.8 361.2 361.2
Earnings per share (before extraordinary item)
Basic ........................................................................ $ 2.51 $ 2.90 $ 2.68
Dilutive ..................................................................... $ 2.50 $ 2.88 $ 2.67
Earnings per share
Basic ........................................................................ $ 2.51 $ 2.85 $ 2.68
Dilutive ..................................................................... $ 2.50 $ 2.83 $ 2.67
Dividends per share ............................................................ $ 1.90 $ 1.57 $ 1.50
See Notes to Consolidated Financial Statements.
27
DUKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31
-----------------------------------------
1997 1996 1995
------------- ------------- -------------
(In Millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income ....................................................... $ 974.4 $ 1,074.3 $ 1,018.1
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization .................................... 982.5 964.9 953.8
Deferred income taxes and investment tax credit amortization ..... 105.7 74.7 115.2
Purchased capacity levelization .................................. 56.4 73.5 (33.1)
Transition cost recoveries ....................................... (35.6) 90.9 (85.2)
(Increase) Decrease in
Receivables ..................................................... (266.5) (645.6) (286.0)
Inventory ....................................................... (6.6) 45.1 (26.2)
Other current assets ............................................ (18.4) 16.7 90.5
Increase (Decrease) in
Accounts payable ................................................ ( 72.1) 576.7 53.5
Taxes accrued ................................................... 50.0 (11.0) 25.7
Interest accrued ................................................ ( 13.1) (18.5) 5.6
Other current liabilities ....................................... 326.2 (10.0) 17.7
Other, net ....................................................... 57.2 103.5 (17.4)
---------- ---------- ----------
Net cash provided by operating activities ....................... 2,140.1 2,335.2 1,832.2
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures ............................................. (1,323.2) (1,393.9) (1,223.0)
Investment expenditures .......................................... (704.4) (156.1) (67.7)
Decommissioning, retirements and other ........................... 33.9 (18.2) (26.9)
---------- ---------- ----------
Net cash used in investing activities ........................... (1,993.7) (1,568.2) (1,317.6)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of
Long-term debt .................................................. 1,617.6 362.8 421.5
Guaranteed preferred beneficial interests in Corporation's
subordinated notes ............................................. 339.0 -- --
Common stock and stock options .................................. 14.9 11.8 16.5
Payments for the redemption of
Long-term debt .................................................. (868.5) (527.0) (480.9)
Common stock .................................................... (25.4) (159.0) --
Preferred stock ................................................. (223.6) -- (100.5)
Net change in notes payable and commercial paper ................. (290.2) 159.3 193.2
Dividends paid ................................................... (726.4) (609.3) (590.5)
Other ............................................................ (40.4) (12.1) (4.8)
---------- ---------- ----------
Net cash used in financing activities ........................... (203.0) (773.5) (545.5)
---------- ---------- ----------
Net decrease in cash and cash equivalents ........................ (56.6) (6.5) (30.9)
Cash and cash equivalents at beginning of year ................... 166.0 172.5 203.4
---------- ---------- ----------
Cash and cash equivalents at end of year ......................... $ 109.4 $ 166.0 $ 172.5
========== ========== ==========
Supplemental Disclosures
Cash paid for interest (net of amount capitalized) ............... $ 475.9 $ 493.1 $ 481.6
Cash paid for income taxes ....................................... $ 469.8 $ 549.9 $ 519.9
See Notes to Consolidated Financial Statements.
28
DUKE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31
---------------------------
1997 1996
------------- -------------
(In Millions)
ASSETS
Current Assets (Note 2)
Cash and cash equivalents (Note 8) ............................ $ 109.4 $ 166.0
Receivables (Note 8) .......................................... 2,280.8 1,888.0
Inventory ..................................................... 440.1 433.5
Current portion of natural gas transition costs ............... 66.9 67.9
Current portion of purchased capacity costs ................... 76.2 51.3
Unrealized gains on mark to market transactions (Note 8) ...... 551.3 397.2
Other (Note 8) ................................................ 160.5 142.1
---------- ----------
Total current assets ......................................... 3,685.2 3,146.0
---------- ----------
Investments and Other Assets
Investments in affiliates (Notes 9 and 15) .................... 685.9 502.9
Nuclear decommissioning trust funds (Notes 8 and 12) .......... 471.1 362.6
Pre-funded pension costs (Note 18) ............................ 337.5 360.6
Goodwill, net (Notes 2, 3 and 7) .............................. 503.6 222.1
Notes receivable .............................................. 239.6 63.5
Other ......................................................... 209.9 108.0
---------- ----------
Total investments and other assets ........................... 2,447.6 1,619.7
---------- ----------
Property, Plant and Equipment (Notes 2, 6, 10, 11, 12 and 15)
Cost .......................................................... 25,448.1 24,468.2
Less accumulated depreciation and amortization ................ 9,712.2 9,199.1
---------- ----------
Net property, plant and equipment ............................ 15,735.9 15,269.1
---------- ----------
Regulatory Assets and Deferred Debits (Note 2)
Purchased capacity costs (Note 6) ............................. 759.4 840.7
Debt expense .................................................. 253.1 244.0
Regulatory asset related to income taxes ...................... 511.0 493.5
Natural gas transition costs .................................. 193.7 250.0
Environmental clean-up costs .................................. 103.6 153.2
Other ......................................................... 339.3 350.0
---------- ----------
Total regulatory assets and deferred debits .................. 2,160.1 2,331.4
---------- ----------
Total Assets .................................................... $ 24,028.8 $ 22,366.2
========== ==========
See Notes to Consolidated Financial Statements.
29
DUKE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS -- (Continued)
December 31
---------------------------
1997 1996
------------- -------------
(In Millions)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable ....................................................................... $ 1,358.7 $ 1,286.5
Notes payable and commercial paper (Notes 8 and 11) .................................... 169.5 459.7
Taxes accrued (Note 2) ................................................................. 124.8 74.8
Interest accrued ....................................................................... 111.2 124.3
Current portion of natural gas transition liabilities (Note 2) ......................... 35.0 84.4
Current portion of environmental clean-up liabilities (Notes 2 and 15) ................. 26.4 32.4
Current maturities of long-term debt (Note 11) ......................................... 77.3 350.6
Unrealized losses on mark to market transactions (Notes 2 and 8) ....................... 537.8 388.5
Other (Note 2) ......................................................................... 834.5 508.3
---------- ----------
Total current liabilities ............................................................. 3,275.2 3,309.5
---------- ----------
Long-term Debt (Notes 8 and 11) .......................................................... 6,530.0 5,485.1
---------- ----------
Deferred Credits and Other Liabilities (Note 2)
Deferred income taxes (Note 7) ......................................................... 3,706.5 3,568.5
Investment tax credit (Note 7) ......................................................... 238.9 250.1
Nuclear decommissioning costs externally funded (Notes 8 and 12) ....................... 471.1 362.6
Natural gas transition liabilities ..................................................... 78.4 121.9
Environmental clean-up liabilities (Note 15) ........................................... 157.6 188.9
Other .................................................................................. 1,035.1 971.0
---------- ----------
Total deferred credits and other liabilities .......................................... 5,687.6 5,463.0
---------- ----------
Minority Interests (Note 3) .............................................................. 168.3 83.4
---------- ----------
Guaranteed Preferred Beneficial Interests in Corporation's Subordinated Notes
(Notes 8 and 13) ....................................................................... 339.0 --
---------- ----------
Preferred and Preference Stock (Notes 8 and 14)
Preferred and preference stock with sinking fund requirements .......................... 149.0 234.0
Preferred and preference stock without sinking fund requirements ....................... 340.0 450.0
---------- ----------
Total preferred and preference stock .................................................. 489.0 684.0
---------- ----------
Commitments and Contingencies (Notes 6, 12 and 15)
Common Stockholders' Equity (Notes 16 and 17)
Common stock, no par, 500 million shares authorized; 359.8 million and 359.4 million
shares outstanding at December 31, 1997 and 1996, respectively ........................... 4,283.7 4,289.3
Retained earnings ...................................................................... 3,256.0 3,051.9
---------- ----------
Total common stockholders' equity ..................................................... 7,539.7 7,341.2
---------- ----------
Total Liabilities and Stockholders' Equity ............................................... $ 24,028.8 $ 22,366.2
========== ==========
See Notes to Consolidated Financial Statements.
30
DUKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
Years Ended December 31
-----------------------------------------
1997 1996 1995
------------- ------------- -------------
(In Millions)
Common Stock
Balance at beginning of year ....................................................... $ 4,289.3 $ 4,296.8 $ 4,275.8
Stock issued for purchase of assets ................................................ -- -- 2.5
Stock repurchased (Note 16) ........................................................ -- (30.8) --
Dividend reinvestment and employee benefits ........................................ (9.9) 23.3 18.5
Other capital stock transactions, net .............................................. 4.3 -- --
---------- ---------- ----------
Balance at end of year ............................................................ 4,283.7 4,289.3 4,296.8
---------- ---------- ----------
Retained Earnings
Balance at beginning of year ....................................................... 3,051.9 2,715.7 2,292.2
Net income ......................................................................... 974.4 1,074.3 1,018.1
Common stock dividends ............................................................. (682.2) (565.6) (542.2)
Preferred and preference stock dividends and premiums on redemptions (Note 14) ..... (72.8) (44.2) (48.9)
Other capital stock transactions, net .............................................. (15.3) (128.3) (3.5)
---------- ---------- ----------
Balance at end of year ............................................................ 3,256.0 3,051.9 2,715.7
---------- ---------- ----------
Total Common Stockholders' Equity .................................................... $ 7,539.7 $ 7,341.2 $ 7,012.5
========== ========== ==========
See Notes to Consolidated Financial Statements.
31
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For The Years Ended December 31, 1997, 1996 and 1995
NOTE 1. NATURE OF OPERATIONS
On June 18, 1997, Duke Power Company (Duke Power) changed its name to Duke
Energy Corporation (the Corporation) in accordance with the terms of a merger
agreement with PanEnergy Corp (PanEnergy), pursuant to which the Corporation
issued 158.3 million shares of its common stock in exchange for all of the
outstanding common stock of PanEnergy (the merger). PanEnergy was involved in
the gathering, processing, transportation and storage of natural gas, the
production of natural gas liquids, and the marketing of natural gas,
electricity, liquefied petroleum gases and related energy services. Pursuant to
the merger, each share of PanEnergy common stock outstanding was converted into
the right to receive 1.0444 shares of the Corporation's common stock. In
addition, each outstanding option to purchase PanEnergy common stock became an
option to purchase common stock of the Corporation, adjusted accordingly. The
merger was accounted for as a pooling of interests and, accordingly, the
consolidated financial statements for periods prior to the combination were
restated to include the operations of PanEnergy.
Operating revenues and net income previously reported by the separate
companies and the combined amounts presented in the accompanying consolidated
financial statements for the years ended December 31, 1996 and 1995 are as
follows:
Duke Power PanEnergy Adjustments Combined
-------------- -------------- ------------- ---------------
In Millions
1996
Operating revenues ........................ $ 4,758.0 $ 7,505.6 $ 38.8 $ 12,302.4
Net income before extraordinary item ...... $ 729.9 $ 361.1 -- $ 1,091.0
Net income ................................ $ 729.9 $ 344.4 -- $ 1,074.3
1995
Operating revenues ........................ $ 4,676.6 $ 4,967.5 $ 50.6 $ 9,694.7
Net income ................................ $ 714.5 $ 303.6 -- $ 1,018.1
The adjustment to operating revenues reflects a reclassification of
PanEnergy's equity in earnings of unconsolidated affiliates from other income
to revenues to be consistent with the Corporation's financial statement
presentation.
The Corporation is an integrated energy and energy services provider with
the ability to offer physical delivery and management of both electricity and
natural gas throughout the United States and abroad. The Corporation provides
these services through its four business segments:
Electric Operations -- Generation, transmission, distribution and sale of
electric energy in central and western North Carolina and the western portion
of South Carolina. Duke Energy Corporation (doing business as Duke Power) and
its wholly owned subsidiary Nantahala Power and Light Company serve this area.
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 -- Interstate transportation and storage of
natural gas for customers in the Mid-Atlantic, New England and Midwest states.
The interstate natural gas transmission and storage operations of the
Corporation's wholly owned subsidiaries Texas Eastern Transmission Corporation
(TETCO), Algonquin Gas Transmission Company (Algonquin), Panhandle Eastern Pipe
Line Company (PEPL), and Trunkline Gas Company (Trunkline) are also subject to
the rules and regulations of the FERC.
Energy Services -- Comprised of several separate business units: Field
Services -- gathers and processes natural gas, produces and markets natural gas
liquids and transport and trades crude oil; Trading and Marketing -- markets
natural gas, electricity and other energy-related products; Global Asset
Development -- develops, owns and operates energy-related facilities worldwide;
and Other Energy Services -- provides engineering consulting, construction and
integrated energy solutions.
Other Operations -- Real estate operations of Crescent Resources, Inc.,
communications services, corporate costs and intersegment eliminations.
32
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION. The consolidated financial statements reflect consolidation
of all of the Corporation's majority-owned subsidiaries after the elimination
of intercompany transactions. Investments in other entities that are not
majority owned and where the Company has significant influence over operations
are accounted for using the equity method.
The consolidated financial statements are prepared in conformity with
generally accepted accounting principles appropriate in the circumstances to
reflect in all material respects the substance of events and transactions which
should be included. In preparing these statements, management makes informed
judgments and estimates of the expected effects of events and transactions that
are currently being reported. However, actual results could differ from these
estimates.
CASH AND CASH EQUIVALENTS. All liquid investments with maturities at date
of purchase of three months or less are considered cash equivalents.
INVENTORY. Inventory consists primarily of materials and supplies, gas
held for transmission, processing and sales commitments and coal held for
electric generation. Inventory is recorded at the lower of cost or market,
primarily using the average cost method.
COMMODITY DERIVATIVE INSTRUMENTS. The Corporation, primarily through its
subsidiaries, holds and issues instruments that reduce exposure to market
fluctuations in the price and transportation costs of natural gas, petroleum
products and electric power marketed. The Corporation uses futures, swaps and
options to manage and hedge price and location risk related to market
exposures. In order to qualify as a hedge, the price movements in the commodity
derivatives must be highly correlated with the underlying hedged commodity.
Gains and losses related to commodity derivatives which qualify as hedges of
commodity commitments are recognized in income when the underlying hedged
physical transaction closes (the deferral method) and are included in Natural
Gas and Petroleum Products Purchased or Net Interchange and Purchased Power in
the Consolidated Statements of Income. Gains and losses related to such
instruments, to the extent not yet settled in cash, are reported as Current
Assets or Liabilities, as appropriate, in the Consolidated Balance Sheets until
recognized in income. If the derivative instrument is no longer sufficiently
correlated to the underlying commodity, or if the underlying commodity
transaction closes earlier than anticipated, the deferred gains or losses are
recognized in income.
In addition to non-trading activities, the Corporation also engages in the
trading of commodity derivatives and therefore experiences net open positions.
Gains and losses on derivatives utilized for trading are recognized in income
on a current basis (the mark to market method) and are also included in Natural
Gas and Petroleum Products Purchased or Net Interchange and Purchased Power.
GOODWILL AMORTIZATION. The Corporation amortizes goodwill related to the
purchases of Duke/Louis Dreyfus, L.L.C. (D/LD) and Texas Eastern Corporation
(TEC), and certain other natural gas gathering, transmission and processing
facilities and engineering consulting businesses on a straight-line basis over
10 years, 40 years, and 15 years, respectively. Accumulated amortization of
goodwill at December 31, 1997 and 1996 was $123.6 million and $99.7 million,
respectively.
PROPERTY, PLANT AND EQUIPMENT. Property, plant and equipment is stated at
original cost. The Corporation capitalizes all construction-related direct
labor and materials, as well as indirect construction costs. Indirect costs
include general engineering, taxes and the cost of money. The cost of renewals
and betterments that extend the useful life of property is also capitalized.
The cost of repairs and replacements is charged to expense. Depreciation is
generally computed using the straight-line method. The Corporation's composite
weighted-average depreciation rates, excluding nuclear fuel, were
3.67, 3.77 and 3.97 percent for 1997, 1996, and 1995, respectively.
At the time property, plant and equipment maintained by the Corporation's
regulated operations are retired, the original cost plus the cost of
retirement, less salvage, is charged to accumulated depreciation and
amortization. When entire regulated operating units are sold or non-regulated
properties are retired or sold, the property and related accumulated
depreciation and amortization accounts are reduced and any gain or loss is
recorded in income, unless otherwise required by the FERC.
33
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- Continued
UNAMORTIZED DEBT PREMIUM, DISCOUNT AND EXPENSE. Expenses incurred in
connection with the issuance of presently outstanding long-term debt, and
premiums and discounts relating to such debt, are amortized over the terms of
the respective issues. Also, 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 these items.
ENVIRONMENTAL EXPENDITURES. Expenditures that relate to an existing
condition caused by past operations, and do not contribute to current or future
revenue generation, are expensed. Environmental expenditures relating to
current or future revenues are expensed or capitalized as appropriate.
Liabilities are recorded when environmental assessments and/or clean-ups are
probable and the costs can be reasonably estimated. Certain of these
environmental assessments and clean-up costs have been deferred and are
included in Regulatory Assets and Deferred Debits as they are expected to be
recovered from Natural Gas Transmission customers.
COST-BASED REGULATION. The regulated operations of the Corporation are
subject to the provisions of Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation."
Accordingly, the Corporation records certain assets and liabilities that result
from the effects of the ratemaking process that would not be recorded under
generally accepted accounting principles for non-regulated entities. The
regulatory assets and regulatory liabilities of the Corporation are classified
as Regulatory Assets and Deferred Debits and Deferred Credits and Other
Liabilities, respectively, in the Consolidated Balance Sheets. The Corporation
regularly evaluates the continued applicability of SFAS No. 71, considering
such factors as regulatory changes and the impact of competition.
Discontinuance of cost-based regulation or increased competition might require
entities to reduce their asset balances to reflect a market basis less than
cost and would also require entities to write off their associated regulatory
assets. Management cannot predict the potential impact, if any, of
discontinuance of cost-based regulation or increased competition on the
Corporation's future financial position and results of operations. However, the
Corporation continues to position itself to effectively meet these challenges
by maintaining prices that are competitive.
COMMON STOCK OPTIONS. The Corporation follows the intrinsic value method
of accounting for common stock options and awards issued to employees.
REVENUES. The Corporation recognizes revenues on sales of electricity and
transportation and storage of natural gas as service is provided and on sales
of natural gas and petroleum products in the period of delivery. Receivables on
the Consolidated Balance Sheets included $231.6 million and $210 million as of
December 31, 1997 and 1996, respectively, for electric service that has been
provided but not yet billed to customers. When rate cases associated with the
transportation of natural gas are pending final FERC approval, a portion of the
revenues collected by the interstate natural gas pipelines is subject to
possible refund. The Corporation has established reserves where required for
such cases.
NUCLEAR FUEL. Amortization of nuclear fuel is included in Fuel Used in
Electric Generation in the Consolidated Statements of Income. The amortization
is recorded using the units-of-production method.
DEFERRED RETURNS AND ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC).
Deferred returns represent the estimated financing costs associated with
funding certain regulatory assets. These regulatory assets primarily arose from
the Corporation's 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.
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 cost of Property, Plant and Equipment,
with offsetting credits to Other Income and Expenses and to Interest Expense.
After construction is completed, the Corporation is permitted to recover these
costs, including a fair return, through their inclusion in rate base and in the
provision for depreciation.
Rates used for capitalization of deferred returns and AFUDC by the
Corporation's regulated operations are calculated in compliance with FERC
rules.
DERIVATIVE FINANCIAL INSTRUMENTS. The Corporation uses interest rate swaps
to manage the interest rate characteristics of its outstanding debt. Interest
rate differentials to be paid or received as interest rates change are accrued
and recognized
34
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- Continued
as an adjustment of interest expense related to the designated debt (the
accrual method). The amount payable to or receivable from counterparties
related to the interest rate differential is included in Regulatory Assets and
Deferred Debits in the Consolidated Balance Sheets. The fair values of interest
rate swaps are not recognized in the financial statements.
INCOME TAXES. Prior to the merger, Duke Power and PanEnergy filed separate
consolidated federal income tax returns. Subsequent to the merger, the
Corporation and its subsidiaries file a consolidated federal income tax return.
Federal income taxes have been provided by the Corporation on the basis of its
separate company income and deductions in accordance with established practices
of the consolidated group.
Deferred income taxes have been provided for temporary differences.
Temporary differences occur when events and transactions recognized for
financial reporting result in taxable or tax-deductible amounts in different
periods. Duke Power's investment tax credits have been deferred and are being
amortized over the estimated useful lives of the related properties.
EARNINGS PER COMMON SHARE. The Financial Accounting Standards Board issued
SFAS No. 128, "Earnings per Share" which replaces the presentation of primary
and fully diluted earnings per share with basic and diluted earnings per share.
Basic earnings per share is computed by dividing net earnings available for
common stockholders by the weighted average number of common shares outstanding
for the year. Basic earnings per share in the Consolidated Statements of Income
is identical to the primary earnings per share previously presented for all
periods. Diluted earnings per share reflects the potential dilution that could
occur if securities or other agreements to issue common stock were exercised or
converted into common stock. Dilutive earnings per share is computed based upon
the weighted average number of common shares and dilutive common equivalent
shares outstanding. Common stock options, which are common stock equivalents,
had a dilutive effect on earnings per share and increased the weighted average
number of common shares by 1.9 million, 2.3 million and 2.6 million shares for
1997, 1996, and 1995, respectively. The weighted average number of common
shares, for dilutive purposes, was 361.7 million, 363.5 million and 363.8
million shares for 1997, 1996 and 1995, respectively.
RECLASSIFICATIONS. Certain amounts have been reclassified in the
consolidated financial statements to conform to the current presentation.
NOTE 3. BUSINESS COMBINATIONS AND ACQUISITIONS
DUKE/LOUIS DREYFUS, L.L.C. (D/LD). On June 17, 1997, a wholly owned
subsidiary of the Corporation acquired the remaining 50% ownership interest in
D/LD from affiliates of Louis Dreyfus Corp. for $247 million. D/LD markets
electric power, natural gas and energy-related services to utilities,
municipalities and other large energy users in North America. The acquisition
was accounted for by the purchase method, and the assets and liabilities and
results of operations of D/LD have been consolidated in the Corporation's
financial statements since the date of purchase. The purchase price
substantially represents goodwill.
DUKE/UAE L.L.C. During December 1997, a wholly owned subsidiary of the
Corporation formed a joint venture with UAE Ref-Fuel L.L.C. (UAE), a wholly
owned subsidiary of United American Energy Corp. The Corporation owns a 65%
interest in the joint venture, with UAE owning a 35% minority interest. The
joint venture acquired a 50% ownership interest in American Ref-Fuel Company, a
waste-to-energy firm with operations primarily in New York and New Jersey.
Thus, the Corporation has an indirect 32.5% ownership interest in American
Ref-Fuel Company and provided $237 million of investment and financing to the
venture.
DUKE ENERGY TRADING AND MARKETING, L.L.C. On August 1, 1996, a wholly
owned subsidiary of the Corporation formed a natural gas and power marketing
joint venture with Mobil Corporation (Mobil) affiliates. The marketing company
(DETM) conducts business as Duke Energy Trading and Marketing, L.L.C. (formerly
PanEnergy Trading and Market Services, L.L.C.) in the United States and as Duke
Energy Marketing L.P. (formerly PanEnergy Marketing L.P.) in Canada. The
Corporation operates the joint venture and owns a 60% interest, with Mobil
owning a 40% minority interest.
35
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 4. BUSINESS SEGMENTS
Business segment financial information follows for each of the three years
in the period ended December 31, 1997. Other Operations include intersegment
eliminations.
Unaffiliated Intersegment Total
Revenues Revenues Revenues
-------------- -------------- --------------
1997 In Millions
Electric Operations ................ $ 4,401.7 $ -- $ 4,401.7
Natural Gas Transmission ........... 1,467.8 104.3 1,572.1
Energy Services
Trading and Marketing ............. 7,411.0 77.7 7,488.7
Field Services .................... 2,480.5 574.1 3,054.6
Global Asset Development .......... 109.2 14.2 123.4
Other Energy Services ............. 342.8 32.8 375.6
Energy Services' Eliminations ..... -- (655.1) (655.1)
----------- ---------- -----------
Total Energy Services ........... 10,343.5 43.7 10,387.2
Other Operations ................... 95.9 (148.0) (52.1)
----------- ---------- -----------
Total Consolidated ................ $ 16,308.9 $ -- $ 16,308.9
=========== ========== ===========
1996
Electric Operations ................ $ 4,498.4 $ -- $ 4,498.4
Natural Gas Transmission ........... 1,470.2 86.1 1,556.3
Energy Services
Trading and Marketing ............. 3,773.5 40.5 3,814.0
Field Services .................... 2,215.6 420.9 2,636.5
Global Asset Development .......... 65.0 6.6 71.6
Other Energy Services ............. 182.8 21.4 204.2
Energy Services' Eliminations ..... -- (456.5) (456.5)
----------- ---------- -----------
Total Energy Services ........... 6,236.9 32.9 6,269.8
Other Operations ................... 96.9 (119.0) (22.1)
----------- ---------- -----------
Total Consolidated ................ $ 12,302.4 $ -- $ 12,302.4
=========== ========== ===========
1995
Electric Operations ................ $ 4,512.4 $ -- $ 4,512.4
Natural Gas Transmission ........... 1,480.3 53.1 1,533.4
Energy Services
Trading and Marketing ............. 1,838.3 28.4 1,866.7
Field Services .................... 1,607.1 184.3 1,791.4
Global Asset Development .......... 75.3 4.0 79.3
Other Energy Services ............. 94.5 0.8 95.3
Energy Services' Eliminations ..... -- (216.9) (216.9)
----------- ---------- -----------
Total Energy Services ........... 3,615.2 0.6 3,615.8
Other Operations ................... 86.8 (53.7) 33.1
----------- ---------- -----------
Total Consolidated ................ $ 9,694.7 $ -- $ 9,694.7
=========== ========== ===========
Operating Earnings Before Depreciation &
Income Interest & Taxes Amortization
-------------- ------------------ ---------------
1997 In Millions
Electric Operations ................ $ 1,180.3 $ 1,281.8 $ 497.8
Natural Gas Transmission ........... 607.7 624.4 229.6
Energy Services
Trading and Marketing ............. 42.7 44.4 7.0
Field Services .................... 156.7 157.0 71.4
Global Asset Development .......... (6.4) 4.5 8.7
Other Energy Services ............. 23.2 18.2 5.8
Energy Services' Eliminations ..... -- -- --
----------- ----------- ---------
Total Energy Services ........... 216.2 224.1 92.9
Other Operations ................... (34.2) (22.2) 20.7
----------- ----------- ---------
Total Consolidated ................ $ 1,970.0 $ 2,108.1 $ 841.0
=========== =========== =========
1996
Electric Operations ................ $ 1,303.6 $ 1,419.5 $ 481.1
Natural Gas Transmission ........... 583.8 595.5 228.2
Energy Services
Trading and Marketing ............. 56.3 57.9 3.8
Field Services .................... 149.4 151.6 58.7
Global Asset Development .......... (1.2) -- 6.9
Other Energy Services ............. 19.9 20.0 3.5
Energy Services' Eliminations ..... -- -- --
----------- ----------- ---------
Total Energy Services ........... 224.4 229.5 72.9
Other Operations ................... 46.8 49.7 7.2
----------- ----------- ---------
Total Consolidated ................ $ 2,158.6 $ 2,294.2 $ 789.4
=========== =========== =========
1995
Electric Operations ................ $ 1,308.7 $ 1,381.2 $ 451.2
Natural Gas Transmission ........... 562.3 567.6 228.5
Energy Services
Trading and Marketing ............. 20.0 17.1 2.3
Field Services .................... 96.8 106.1 40.3
Global Asset Development .......... 24.9 26.8 6.8
Other Energy Services ............. 23.6 23.7 0.8
Energy Services' Eliminations ..... -- -- --
----------- ----------- ---------
Total Energy Services ........... 165.3 173.7 50.2
Other Operations ................... 32.0 68.0 7.2
----------- ----------- ---------
Total Consolidated ................ $ 2,068.3 $ 2,190.5 $ 737.1
=========== =========== =========
36
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 4. BUSINESS SEGMENTS -- Continued
Capital and Investment Expenditures Identifiable Assets
-------------------------------------- -------------------------------
1997 1996 1995 1997 1996
------------ ------------ ------------ --------------- ---------------
In Millions
Electric Operations .................... $ 742.6 $ 609.8 $ 704.0 $ 12,958.5 $ 12,625.2
Natural Gas Transmission ............... 247.3 194.0 230.5 5,088.9 5,216.4
Energy Services
Trading and Marketing ................. 17.9 6.6 15.3 1,857.3 1,403.5
Field Services ........................ 156.5 530.8 187.2 1,979.8 1,769.4
Global Asset Development .............. 348.3 34.8 53.5 987.6 522.3
Other Energy Services ................. 47.2 39.1 1.0 223.2 130.1
Energy Services' Eliminations ......... -- -- -- (169.1) (247.0)
---------- ---------- ---------- ------------ ------------
Total Energy Services ............... 569.9 611.3 257.0 4,878.8 3,578.3
Other Operations ....................... 467.8 134.9 99.2 1,102.6 946.3
---------- ---------- ---------- ------------ ------------
Total Consolidated .................... $ 2,027.6 $ 1,550.0 $ 1,290.7 $ 24,028.8 $ 22,366.2
========== ========== ========== ============ ============
NOTE 5. REGULATORY MATTERS
Electric Operations. The NCUC and the PSCSC approve rates for retail
electric sales within their respective states. The FERC approves the
Corporation's rates for electric sales to wholesale customers. Electric sales
to the other joint owners of the Catawba Nuclear Station (Catawba), which
represent a substantial majority of the Corporation's electric wholesale
revenues, are set through contractual agreements.
In 1997, the Corporation signed stipulation agreements with the NCUC and
the PSCSC as a result of the merger in which the Corporation agreed to cap the
base electric rates at existing levels through 2000, with very limited
exceptions, for retail customers. The Corporation also signed an agreement with
the FERC to freeze rates, except for the market-based rates, for the
Corporation's transmission and wholesale electric sales. In addition, the
Corporation signed agreements with the other joint owners of Catawba providing
for a cap on the rates charged under interconnection agreements and on the
reimbursement of certain costs related to administration and general expenses
and general plant costs under operation and fuel agreements. Management is of
the opinion that these agreements will not have a material adverse effect on
the consolidated results of operations or financial position of the
Corporation.
Fuel costs are reviewed semiannually in the wholesale jurisdiction and
annually in the South Carolina retail jurisdiction, with provisions for
changing such costs in base rates. In the North Carolina retail jurisdiction, a
review of fuel costs in rates is required annually and during general rate case
proceedings. All jurisdictions allow the Corporation to adjust electric rates
for past over- or under-recovery of fuel costs. Therefore, the Corporation
reflects in revenues the difference between actual fuel costs incurred for
electric operations and fuel costs recovered through rates. The stipulation
agreements related to the merger do not apply to the fuel cost adjustments.
The PSCSC, on May 7, 1996, ordered a rate reduction in the form of a
decrement rider of 0.432 cents per kilowatt-hour, or an average of
approximately 8 percent, affecting South Carolina retail customers. South
Carolina retail sales represent approximately 30 percent of the Corporation's
total regulated electric sales. The rate reduction was reflected on bills
rendered on or after June 1, 1996. This net decrement rider reflects an interim
true-up decrement adjustment associated with the levelization of Catawba
purchased capacity costs and an interim true-up increment associated with
amortization of the demand-side management deferral account. The rate
adjustment was made because, in the South Carolina retail jurisdiction,
cumulative levelized revenues associated with the recovery of Catawba purchased
capacity costs had exceeded purchased capacity payments and accrual of deferred
returns, and certain demand-side costs had exceeded the level reflected in
rates.
Certain of the Corporation's electric wholesale customers, excluding the
other Catawba joint owners, initiated proceedings in 1995 before the FERC
concerning rate related matters. The Corporation and nine of its eleven
wholesale customers entered into a settlement in July 1996 which reduced the
customers' electric rates by approximately 9 percent and renewed their
contracts with the Corporation through 2000. Both of the customers that did not
enter into the settlement have signed
37
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 5. REGULATORY MATTERS -- Continued
agreements and have begun purchasing electricity from other suppliers in 1997.
Early in 1998, the Corporation reached agreements, subject to FERC approval,
with both of these former customers to recover the stranded costs incurred to
serve these customers. Management is of the opinion that these agreements will
not have a material adverse impact on the consolidated results of operations or
financial position of the Corporation.
Natural Gas Operations.
FERC Order 636 and Natural Gas Transition Costs. The Corporation's
interstate natural gas pipelines primarily provide transportation and storage
services pursuant to FERC Order 636. Order 636 allows pipelines to recover
eligible costs resulting from implementation of the order (transition costs).
In 1994, the FERC approved TETCO's settlement resolving regulatory issues
related primarily to Order 636 transition costs and a number of other issues
related to services prior to Order 636. TETCO's liability for transition costs
is estimated based on the amount of producers' natural gas reserves and other
factors. TETCO's final and nonappealable settlement provides for the recovery
of certain of these transition costs from customers through volumetric and
reservation charges through 2002 and beyond, if necessary. Pursuant to the
settlement, TETCO will absorb a certain portion of the transition costs, the
amount of which continues to be subject to change dependent upon natural gas
prices and deliverability levels. In 1995, based upon producers' discoveries of
additional natural gas reserves, TETCO increased the estimated liabilities for
transition costs by $125.8 million. Under the terms of the existing settlement,
regulatory assets were increased $85.8 million for amounts expected to be
collected from customers and TETCO recognized a $40 million charge to operating
expenses ($26 million after tax).
On July 16, 1996, the U.S. Court of Appeals for the District of Columbia
upheld, in general, all aspects of Order 636 and remanded certain issues for
further explanation. One of the issues remanded for further explanation is
whether pipelines should be entitled to recover 100% of gas supply realignment
(GSR) costs. This matter is substantially mitigated by TETCO's transition cost
settlements.
The Corporation believes the exposure associated with gas purchase
contract commitments is substantially mitigated by transition cost recoveries
pursuant to customer settlements, Order 636 and other mechanisms, and that this
issue will not have a material adverse effect on consolidated results of
operations or financial position of the Corporation.
Jurisdictional Transportation and Sales Rates. On April 1, 1992 and
November 1, 1992, PEPL placed into effect, subject to refund, general rate
increases. On February 26, 1997, the FERC approved PEPL's settlement agreement
which provided final resolution of refund matters and established prospective
rates. The agreement terminated other actions relating to these proceedings as
well as PEPL's restructuring of rates and transition cost recoveries related to
FERC Order 636. The settlement will not have a material impact on future
operating revenues or financial position of the Corporation.
As a result of the resolution of these and certain other proceedings, PEPL
recorded earnings before interest and taxes of $32.7 million, $8 million, and
$20.6 million in 1997, 1996, and 1995, respectively.
NOTE 6. JOINT OWNERSHIP OF GENERATING FACILITIES
The Corporation previously sold interests in both units of Catawba. The
other owners of portions of Catawba and supplemental information regarding
their ownership are as follows:
Owner Ownership Interest in the Station
- --------------------------------------------------------------- ----------------------------------
North Carolina Municipal Power Agency Number 1 (NCMPA) .. 37.5%
North Carolina Electric Membership Corporation (NCEMC) .. 28.125%
Piedmont Municipal Power Agency (PMPA) .................. 12.5%
Saluda River Electric Cooperative, Inc. (Saluda River) .. 9.375%
Each owner has provided its own financing for its ownership interest in
Catawba.
The Corporation retains a 12.5 percent ownership interest in Catawba. As
of December 31, 1997, $507.8 million of Property, Plant and Equipment
represented the Corporation's investment in Units 1 and 2. Accumulated
depreciation and
38
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 6. JOINT OWNERSHIP OF GENERATING FACILITIES -- Continued
amortization of $198.3 million associated with Catawba was recorded as of
year-end 1997. The Corporation's share of operating costs of Catawba is
included in the Consolidated Statements of Income.
In connection with the joint ownership, the Corporation has entered into
contractual interconnection agreements with the other joint owners to purchase
declining percentages of the generating capacity and energy from the plant.
These purchased power agreements were effective beginning with the commercial
operation of each unit. Units 1 and 2 began commercial operation in June 1985
and August 1986, respectively. The purchased power agreements were established
for 15 years for NCMPA and PMPA and 10 years for NCEMC and Saluda River. While
the purchased power agreements with NCMPA and PMPA extend for 15 years, a
significant decrease in the percentage of capacity and energy the Corporation
is obligated to purchase occurs in the 11th calendar year of operation for each
unit. This significant decrease occurred in 1995 for Unit 1 and 1996 for Unit
2.
The interconnection agreements also provide for supplemental power sales
by the Corporation to the other joint owners. Such power sales are to satisfy
capacity and energy needs of the other joint owners beyond the capacity and
energy which they retain from Catawba or potentially acquire in the form of
other resources. The agreements further provide the other joint owners the
ability to secure such supplemental requirements outside of these contractual
agreements following an appropriate notice period. NCEMC and Saluda River have
given appropriate notice that they intend to acquire their supplemental
capacity requirements outside of these agreements effective January 1, 2001 and
January 1, 2002, respectively, thus relieving the Corporation of the obligation
to serve this portion of load. In addition, as a result of the merger, the
other joint owners of Catawba have the right to end their supplemental capacity
requirements as of January 1, 2001 with written notice to the Corporation due
by December 31, 1999. As the joint owners retain more capacity and energy from
Catawba or a third party, supplemental power sales are expected to decline.
Management is of the opinion that this will not have a material adverse effect
on the consolidated results of operations or the financial position of the
Corporation.
The interconnection agreements with each of the other joint owners include
provisions that the Corporation will provide generating reserves to backstand
the other joint owners' retained capacity in the Catawba plant at the system
average cost of installed capacity. Additionally, the agreements include
certain reliability exchanges designed to manage outage-related risks by
exchanging energy entitlements between Catawba and the McGuire Nuclear Station,
impacting the Corporation as well as all the other joint owners. The agreements
also provide the other joint owners the ability to terminate the
interconnection agreements in their entirety upon eight years written notice to
the Corporation. PMPA has rendered such notice effective January 1, 2006. This
termination will relieve the Corporation of the obligation to serve this
portion of load as well as provide the reserves associated with PMPA's retained
capacity. Management is of the opinion that this will not have a material
adverse effect on the consolidated results of operations or the financial
position of the Corporation.
Purchased energy cost payments are based on variable operating costs and
are a function of the generation output of Catawba. Purchased capacity payments
are based on the fixed costs of the plant and include the capital costs and
fixed operating and maintenance costs. Actual purchased capacity costs for 1997
and projected obligations through 2000, the last year of the purchase
buy-backs, are $99.8 million, $72 million, $52.9 million and $6.6 million,
respectively.
Effective in its November 1991 rate order, the NCUC reaffirmed the
Corporation's recovery from retail electric customers, on a levelized basis, of
the capital costs and fixed operating and maintenance costs of capacity
purchased from the other joint owners. The PSCSC in its November 1991 rate
order reaffirmed the Corporation's recovery on a levelized basis of the capital
costs of capacity purchased from the other joint owners. Levelization was
reaffirmed through inclusion in rates approved in March 1992 by the FERC. The
portion of purchased capacity subject to levelization not currently recovered
in rates is being deferred, and the Corporation is recording a deferred return
on the accumulated balance. The Corporation is recovering the accumulated
balance, including the deferred return, when the sum of the declining purchased
capacity payments and accrual of deferred returns for the current period drops
below the levelized revenues. Jurisdictional levelizations are intended to
recover total costs, including deferred returns, and are subject to
adjustments, including final true-ups. The Corporation recovers the costs of
purchased energy and the non-levelized portion of purchased capacity on a
current basis.
The current levelized revenues approved in the Corporation's last general
rate proceedings are $211.4 million, $94.1 million and $6.8 million for North
Carolina retail, South Carolina retail and Other Wholesale (FERC),
respectively. Purchased power costs, subject to levelization, are deferred
based on allocation factors of approximately 62 percent, 26 percent
39
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 6. JOINT OWNERSHIP OF GENERATING FACILITIES -- Continued
and 2 percent for North Carolina retail, South Carolina retail and Other
Wholesale (FERC), respectively. The PSCSC, on May 7, 1996, ordered a rate
reduction in the form of a decrement rider for an interim true-up adjustment.
The Corporation also recovers an allocated amount of purchased power costs in
the pricing of supplemental sales made to the other joint owners on a current
basis.
During 1996, in the North Carolina retail and the FERC wholesale
jurisdictions, annual levelized revenues exceeded purchased capacity payments
and the accrual of deferred returns for the first time. In the South Carolina
retail jurisdiction, cumulative levelized revenues have exceeded purchased
capacity payments and accrual of deferred returns.
For the years ended December 31, 1997, 1996 and 1995, the Corporation
recorded purchased capacity and energy costs from the other joint owners of
$120.1 million, $151.2 million, and $388.2 million, respectively. These
amounts, after adjustments for the costs of capacity purchased not reflected in
current rates, are included in Net Interchange and Purchased Power in the
Consolidated Statements of Income. As of December 31, 1997 and 1996, $835.6
million and $892 million, respectively, associated with the cost of capacity
purchased but not reflected in current rates have been accumulated in the
Consolidated Balance Sheets as Purchased Capacity Costs and Current Portion of
Purchased Capacity Costs.
NOTE 7. INCOME TAXES
Income tax expense as presented in the Consolidated Statements of Income
is summarized as follows:
1997 1996 1995
------------ ------------ ------------
In Millions
Current income taxes
Federal ................................... $ 432.7 $ 514.3 $ 452.0
State ..................................... 100.5 108.8 97.0
--------- --------- ---------
Total current income taxes ............... 533.2 623.1 549.0
--------- --------- ---------
Deferred income taxes, net
Federal ................................... 111.9 73.1 105.2
State ..................................... 8.9 12.8 21.2
--------- --------- ---------
Total deferred income taxes, net ......... 120.8 85.9 126.4
--------- --------- ---------
Investment tax credit amortization .......... (15.1) (11.2) (11.2)
--------- --------- ---------
Total income tax expense .................... $ 638.9 $ 697.8 $ 664.2
========= ========= =========
Total income tax differs from the amount computed by applying the federal
income tax rate of 35% to income before income taxes. The reasons for this
difference are as follows:
1997 1996 1995
------------ ------------ ------------
In Millions
Income tax, computed at the statutory rate .......... $ 564.7 $ 626.1 $ 588.8
Adjustments resulting from:
State income tax, net of federal income tax effect 70.8 78.6 76.5
Other items, net .................................. 3.4 (6.9) (1.1)
-------- --------- ---------
Total income tax expense ............................ $ 638.9 $ 697.8 $ 664.2
======== ========= =========
Effective tax rate .................................. 39.6% 39.0% 39.5%
40
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 7. INCOME TAXES -- Continued
The tax effects of temporary differences that resulted in deferred income
tax assets and liabilities, and a description of the significant items that
created these differences as of December 31, 1997 and 1996, are as follows:
1997 1996
--------------- ---------------
In Millions
Deferred credits and other liabilities ..................... $ 408.4 $ 418.2
Alternative minimum tax credit carryforward ................ 30.3 72.6
Other ...................................................... 46.3 --
----------- -----------
Total deferred income tax assets ......................... 485.0 490.8
Valuation allowance and other tax reserves ................. (146.1) (141.1)
----------- -----------
Net deferred income tax assets ........................... 338.9 349.7
----------- -----------
Investments and other assets ............................... (263.1) (208.8)
Property, plant and equipment .............................. (2,357.7) (2,268.7)
Regulatory assets and deferred debits ...................... (623.2) (642.6)
Regulatory asset related to restating to pre-tax basis ..... (437.8) (433.2)
Other ...................................................... -- (5.9)
----------- -----------
Total deferred income tax liabilities .................... (3,681.8) (3,559.2)
----------- -----------
State deferred income tax, net of federal tax effect ....... (363.6) (359.0)
----------- -----------
Net deferred income tax liability .......................... $ (3,706.5) $ (3,568.5)
============ ============
The alternative minimum tax credit carryforward can be carried forward
indefinitely.
In 1990, PanEnergy established a provision for certain tax issues related
to the purchase of TEC, which resulted in an increase in goodwill and deferred
income tax liability. Following discussions with the Internal Revenue Service,
PanEnergy revised its estimates in 1995 and 1996 with respect to these issues.
As a result, the related goodwill and deferred income tax liability were
reduced by approximately $40 million and $100 million in 1996 and 1995,
respectively. If tax benefits relating to the valuation allowance for deferred
income tax assets and other tax reserves are recognized subsequent to December
31, 1997, approximately $29.4 million will be allocated as an adjustment to
goodwill.
NOTE 8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
FINANCIAL INSTRUMENTS. In order to obtain variable rate financing at an
attractive cost, the Corporation entered into interest rate swap agreements in
which the Corporation effectively exchanged $200 million of 8% Series B First
and Refunding Mortgage Bonds for floating rate debt at the three month London
Interbank Offered Rate (LIBOR) plus a .074% margin and $100 million of 7.5%
Series B First and Refunding Mortgage Bonds for floating rate debt at three
month LIBOR plus a 1.1272% margin. The interest rate swaps expire in 1999 and
2000, respectively, and rates are reset quarterly. As a result of the interest
rate swap contracts, interest expense on the Consolidated Statements of Income
is recognized at the weighted average rate for the year tied to LIBOR. The
weighted average rates for 1997, 1996 and 1995 are as follows (dollars in
millions):
Weighted Average Rate
--------------------------------
Series Issued Year Due Face Value 1997 1996 1995
- ----------------------------- -------- ---------- ------------ ---------- ---------- ----------
8% Series B ........... 1994 1999 $ 200 5.78% 5.64% 6.14%
7.5% Series B ......... 1995 2025 $ 100 6.83% 6.69% 7.06%
In 1996, TETCO received $98.6 million from the financing of the right to
collect certain Order 636 natural gas transition costs, with limited recourse.
At December 31, 1997 and 1996, $52.8 million and $87.3 million, respectively,
remained outstanding related to the transition cost recovery rights and were
included in Other Current Liabilities in the Consolidated Balance Sheets. In
the opinion of management, the probability that the Corporation will be
required to perform under the recourse provisions is remote.
41
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT -- Continued
During 1997, the Corporation terminated its agreement to sell accounts
receivable which was entered into in 1996. Also in 1997, the LNG settlement
receivables sale agreement, which was entered into in 1993, expired, as all the
receivables were collected. Amounts outstanding at December 31, 1996 under
these agreements were $100 million and $29.9 million, respectively.
FAIR VALUE OF FINANCIAL INSTRUMENTS. The fair value of the Corporation's
financial instruments is summarized below. Judgment is required in interpreting
market data to develop the estimates of fair value. Accordingly, the estimates
determined as of December 31, 1997 and 1996 are not necessarily indicative of
the amounts the Corporation could have realized in current market exchanges.
1997 1996
Assets (Liabilities) Assets (Liabilities)
---------------------------- -----------------------------
Approximate Approximate
Book Value Fair Value Book Value Fair Value
-------------- ------------- -------------- --------------
In Millions
Long-term debt (a) ............................. $ (6,607.3) $ (6,842.8) $ (5,835.7) $ (5,999.0)
Interest rate swaps (b) ........................ -- 9.5 -- 12.0
Guaranteed preferred beneficial interests in
Corporation's subordinated notes (a) .......... (339.0) (356.2) -- --
Preferred stock (a) ............................ (489.0) (530.2) (684.0) (699.0)
- ---------
(a) The majority of the estimated fair value amounts of long-term debt,
guaranteed preferred beneficial interests in Corporation's subordinated
notes and preferred stock were obtained from independent parties.
(b) Amounts shown for interest rate swaps represent estimated amounts the
Corporation would receive if agreements were settled at current market
rates.
The fair value of cash and cash equivalents, notes receivable, notes
payable and commercial paper and nuclear decommissioning trust funds are not
materially different from their carrying amounts because of the short-term
nature of these instruments or the stated rates approximating market rates.
The following financial instruments have no book value associated with
them and there are no fair values readily determinable since quoted market
prices are not available: guarantees made to affiliates or recourse provisions
from affiliates and sales agreements for trade accounts receivables, LNG
project settlement and Order 636 natural gas transition cost recovery.
COMMODITY DERIVATIVE INSTRUMENTS. At December 31, 1997 and 1996, the
Corporation held or issued several instruments that reduce exposure to market
fluctuations relative to price and transportation costs of natural gas,
electricity and petroleum products. The Corporation's market exposure,
primarily within DETM and D/LD, arises from natural gas storage inventory
balances and fixed-price purchase and sale commitments that extend for periods
of up to 9 years. The Corporation uses futures, swaps and options to manage and
hedge price and location risk related to these market exposures.
DETM and D/LD also provide risk management services to its customers
through a variety of energy commodity instruments including forward contracts
involving physical delivery of an energy commodity, energy commodity futures,
over-the-counter swap agreements and options. In addition to hedging
activities, the Corporation also engages in the trading of such instruments,
and therefore experiences net open positions. The Corporation manages open
positions with strict policies which limit its exposure to market risk and
require daily reporting to management of potential financial exposure. These
policies include statistical risk tolerance limits using historical price
movements to calculate a daily earnings at risk as well as a total
Value-at-Risk (VAR) measurement. The weighted-average life of the Corporation's
commodity risk portfolio was approximately 7 months at December 31, 1997.
Energy commodity futures involve the buying or selling of natural gas,
electricity or other energy-related commodities at a fixed price.
Over-the-counter swap agreements require the Corporation to receive or make
payments based on the difference between a specified price and the actual price
of the underlying commodity. The Corporation uses futures and swaps to manage
margins on underlying fixed-price purchase or sale commitments for physical
quantities of natural gas, electricity and other energy-related commodities.
Energy commodity options held to mitigate price risk provide the right, but not
42
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT -- Continued
the requirement, to buy or sell energy-related commodities at a fixed price.
The Corporation utilizes options to manage margins and to limit overall price
risk exposure. DETM and D/LD account for these activities using the mark to
market method of accounting.
At December 31, 1997 and 1996, the Corporation had outstanding futures,
swaps and options for an absolute notional contract quantity of 4,810 billion
cubic feet (Bcf) and 3,425 Bcf of natural gas, respectively, some of which were
in place to offset the risk of price fluctuations under fixed-price commitments
for purchasing and delivering natural gas. At December 31, 1997 and 1996,
outstanding futures, swaps and options related to electric contracts and other
energy-related commodities were not material. The gains, losses and costs
related to those commodity instruments that qualify as a hedge are not
recognized until the underlying physical transaction occurs. At December 31,
1997 and 1996, the Corporation had current unrecognized net gains of $13.5
million and $8.7 million, respectively, related to commodity instruments. The
fair value of energy commodity swaps held at December 31, 1997 was a liability
of $158.6 million.
During 1997, 1996 and 1995, the Corporation recognized net gains of $33.6
million, $25.4 million, and $10.5 million, respectively, from trading
activities. The values of energy commodity futures, swaps and options held for
trading purposes were as follows:
1997 1996
------------------------ ---------------------
Assets Liabilities Assets Liabilities
---------- ------------- -------- ------------
In Millions
Fair value at December 31 ........... $ 1,626 $ 1,470 $ 833 $ 941
Notional amount at December 31 ...... 2,009 1,825 407 530
Average fair value for the year ..... 595 700 588 653
MARKET AND CREDIT RISK. New York Mercantile Exchange (Exchange) traded
futures and option contracts are guaranteed by the Exchange and have nominal
credit risk. On all other transactions described above, the Corporation is
exposed to credit risk in the event of nonperformance by the counterparties.
For each counterparty, the Corporation analyzes the financial condition prior
to entering into an agreement, establishes credit limits and monitors the
appropriateness of these limits on an ongoing basis. The change in market value
of Exchange-traded futures and options contracts requires daily cash settlement
in margin accounts with brokers. Swap contracts and most other over-the-counter
instruments are generally settled at the expiration of the contract term and
may be subject to margin requirements with the counterparty.
NOTE 9. INVESTMENT IN AFFILIATES
Certain investments, where the Corporation's ownership in domestic and
international affiliates is 50 percent or less, are accounted for by the equity
method. These investments include undistributed earnings of $20.6 million in
1997 and $49.7 million in 1996. The Corporation's proportionate share of net
income from these affiliates for the years ended December 31, 1997, 1996 and
1995 was $38.4 million, $32.7 million, and $59.8 million, respectively. These
amounts are reflected in Other Operating Revenues in the Consolidated
Statements of Income. Investment in affiliates as of December 31, 1997 and 1996
includes the following:
43
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 9. INVESTMENT IN AFFILIATES -- Continued
1997 1996
----------- -----------
In Millions
Natural Gas Transmission -- domestic ......... $ 67.5 $ 46.5
-------- --------
Energy Services
Field Services -- domestic .................. 159.8 129.6
Global Asset Development
Domestic .................................. 174.5 14.5
International ............................. 207.8 183.5
Other Energy Services
Domestic .................................. 15.9 49.5
International ............................. 9.7 1.4
-------- --------
Total Energy Services .................... 567.7 378.5
-------- --------
Other Operations
Domestic .................................... 38.1 65.3
International ............................... 12.6 12.6
-------- --------
Total Other Operations ................... 50.7 77.9
-------- --------
Total Investments in Affiliates .............. $ 685.9 $ 502.9
======== ========
NATURAL GAS TRANSMISSION. Investments primarily include ownership
interests in natural gas pipeline joint ventures which transport gas from
Canada to the United States.
FIELD SERVICES. Among other investments, Field Services holds an interest
in a partnership which owns natural gas gathering systems in the Gulf of
Mexico, a master limited partnership that owns and operates a petroleum
pipeline, and a joint venture that provides gathering, processing and marketing
services for natural gas producers in Oklahoma.
GLOBAL ASSET DEVELOPMENT. Global Asset Development has investments in
various natural gas and electric generation and transmission facilities
world-wide, and in a joint venture that owns and operates a methanol plant and
a MTBE (methyl tertiary butyl ether) plant in Jubail, Saudi Arabia.
OTHER ENERGY SERVICES. Investments include the participation in various
construction and support activities for fossil-fueled generating plants.
OTHER OPERATIONS. This segment holds investments in various real estate
development projects and a joint venture that provides wireless personal
communication services.
44
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 9. INVESTMENT IN AFFILIATES -- Continued
Summarized combined balance sheet and income statement information of the
entities that are accounted for using the equity method are as follows:
1997 1996 1995
------------- -------------- ------------
In Millions
Assets
Current Assets ........................ $ 642.0 $ 1,025.2 $ 617.0
Noncurrent Assets ..................... 5,867.8 5,660.5 5,090.2
---------- ----------- ----------
Total Assets ......................... $ 6,509.8 $ 6,685.7 $ 5,707.2
========== =========== ==========
Liabilities and Equity
Current Liabilities ................... $ 757.4 $ 879.3 $ 468.5
Noncurrent Liabilities ................ 3,257.2 3,461.4 3,376.0
Equity ................................ 2,495.2 2,345.0 1,862.7
---------- ----------- ----------
Total Liabilities and Equity ......... $ 6,509.8 $ 6,685.7 $ 5,707.2
========== =========== ==========
Income
Operating Revenues .................... $ 905.0 $ 3,133.2 $ 1,391.2
Operating Expenses .................... 702.8 2,494.1 667.1
Net Income ............................ 72.4 160.1 236.2
The Corporation had outstanding loans to certain affiliates of $87.1
million and $2.9 million at December 31, 1997 and 1996, respectively.
45
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 10. PROPERTY, PLANT AND EQUIPMENT
A summary of property, plant and equipment by classification as of
December 31, 1997 and 1996 is as follows:
1997 1996
-------------- --------------
In Millions
Electric Plant In Service
Production ............................................................. $ 7,575.5 $ 7,278.4
Transmission ........................................................... 1,566.3 1,543.7
Distribution ........................................................... 4,517.5 4,303.9
General plant .......................................................... 1,118.6 1,068.3
Nuclear fuel ........................................................... 643.9 604.8
Construction work in progress .......................................... 222.5 389.0
----------- -----------
Total electric plant in service ....................................... 15,644.3 15,188.1
----------- -----------
Natural Gas Plant In Service
Transmission ........................................................... 6,094.4 5,994.1
Gathering .............................................................. 812.5 643.0
Processing ............................................................. 502.4 508.4
Underground storage .................................................... 488.8 450.6
LNG facilities and vessels ............................................. 751.7 751.0
General plant .......................................................... 310.7 348.7
Construction work in progress .......................................... 159.9 126.7
----------- -----------
Total natural gas plant in service .................................... 9,120.4 8,822.5
----------- -----------
Other Property and Equipment ............................................. 683.4 457.6
----------- -----------
Total Property, Plant and Equipment ...................................... 25,448.1 24,468.2
Less accumulated depreciation (including amortization of nuclear fuel:
1997-- $370.0 million; 1996 -- $363.3 million).......................... 9,712.2 9,199.1
----------- -----------
Net property, plant and equipment ..................................... $ 15,735.9 $ 15,269.1
=========== ===========
A summary of accumulated depreciation for property, plant and equipment by
classification as of December 31, 1997 and 1996 is as follows:
1997 1996
-------------- --------------
In Millions
Electric Plant In Service ............ $ 6,067.7 $ 5,801.8
Natural Gas Plant In Service ......... 3,602.9 3,365.8
Other Property and Equipment ......... 41.6 31.5
----------- -----------
Total Accumulated Depreciation ......... $ 9,712.2 $ 9,199.1
=========== ===========
46
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 11. DEBT AND CREDIT FACILITIES
The following credit facilities were available to the Corporation at
December 31, 1997 and 1996:
1997 1996
-------------------------- -------------------------
Credit Credit
Facilities Outstanding Facilities Outstanding
------------ ------------- ------------ ------------
In Millions
Annually renewable facilities .......... $ 54.0 $ 16.3 $ 64.9 $ 8.6
364-day facilities ..................... 300.0 -- 400.0 --
Two-year revolving facilities (a) ...... 40.0 -- 40.0 --
Four-year revolving facilities (b) ..... 125.0 77.0 235.0 42.0
Five-year revolving facilities ......... 2,200.0 -- 755.0 --
---------- -------- ---------- -------
Total Consolidated ................... $ 2,719.0 $ 93.3 $ 1,494.9 $ 50.6
========== ======== ========== =======
- ---------
(a) At December 31, 1997 and 1996, the Corporation had $40 million of pollution
control bonds, included in long-term debt, backed by the two-year
revolving facilities.
(b) The outstanding balance was included in long-term debt.
The 364-day and five-year credit facilities support the Corporation's
commercial paper facilities of $2.5 billion and $780 million at December 31,
1997 and 1996, respectively. Amounts outstanding under the commercial paper
facilities at December 31, 1997 and 1996 were as follows:
1997 1996
-------------- ------------
In Millions
Total commercial paper outstanding ......... $ 1,749.2 $ 324.2
Less portion classified as short-term ...... 149.2 194.2
----------- ---------
Portion classified as long-term debt ....... $ 1,600.0 $ 130.0
=========== =========
In addition to amounts borrowed under the credit facilities and commercial
paper facilities, the Corporation had $251.9 million of short-term borrowings
from banks outstanding at December 31, 1996. Also, at December 31, 1997 and
1996, the Corporation had a note payable to an affiliate of $4 million and $5
million, respectively.
A summary of short-term debt is as follows:
1997 1996 1995
------------ ------------ ------------
Dollars In Millions
Amount outstanding at end of year .................. $ 169.5 $ 459.7 $ 300.3
Weighted-average rate at end of year ............... 6.04% 6.16% 6.09%
Maximum amount outstanding during the year ......... $ 889.1 $ 501.4 $ 409.3
Average amount outstanding during the year ......... $ 417.6 $ 182.4 $ 152.8
Weighted-average interest rate for the year --
computed on a daily basis ......................... 5.65% 5.92% 6.15%
47
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 11. DEBT AND CREDIT FACILITIES -- Continued
Year Due 1997 1996
----------- ------------ -------------
In Millions
Duke Energy Corporation (a)
First and refunding mortgage bonds:
5.17% ................................................................. 1998 $ 50.0 $ 50.0
5.76% - 8% ............................................................ 1999 425.0 425.0
7% .................................................................... 2000 200.0 200.0
5 7/8% - 7.41% ........................................................ 2001-2004 600.0 600.0
6 3/8% - 7% ........................................................... 2005-2008 325.0 325.0
6 3/4% - 8.30% ........................................................ 2023-2025 878.0 878.0
7% - 8.95% ............................................................ 2027-2033 165.5 165.6
Mortgage bonds redeemed or matured during 1997 ........................ -- 647.6
Pollution control bonds -- 3.58% - 7.75% ................................ 2012-2017 172.0 172.0
Commercial paper, 5.9% and 6.23% weighted average rate at
December 31, 1997 and 1996, respectively .............................. 800.0 130.0
Other debt .............................................................. 25.7 27.8
Duke Capital Corp.
Commercial paper, 6.03% weighted-average rate at December 31, 1997 ...... 800.0 --
PanEnergy
Bonds:
7 3/4% ................................................................ 2022 328.0 328.0
8 5/8% Debentures ..................................................... 2025 100.0 100.0
Notes:
9.55%, maturing serially .............................................. 1996-1999 27.5 41.3
9.9%, maturing serially ............................................... 2000-2003 45.0 45.0
7% - 8 5/8% ........................................................... 1999-2006 450.0 450.0
Notes converted or matured during 1997 ................................ -- 124.5
TETCO
Notes:
8% - 10 3/8% .......................................................... 2000-2004 500.0 500.0
Medium term, Series A, 7.64 - 9.07% ................................... 1999-2012 100.0 100.0
Algonquin
9.13% Notes ............................................................. 2001-2003 100.0 100.0
PEPL
7 7/8% Notes ............................................................ 2004 100.0 100.0
7.2% - 7.95% Debentures ................................................. 2023-2024 200.0 200.0
Crescent Resources, Inc. (b)
Construction and mortgage loans, 6.02% - 7.10% .......................... 1998-2011 116.7 76.0
Revolving credit facilities, 6.30% and 5.95% weighted-average rate at
December 31, 1997 and 1996, respectively .............................. 2001 77.0 42.0
Nantahala Power and Light Company
6.90% - 9.21% Senior Notes, maturing serially ........................... 2011-2016 67.3 68.0
Other ................................................................... 1998-2001 .2 .4
Unamortized debt discount and premium, net .............................. (45.6) (60.5)
---------- ----------
Total long-term debt .................................................... 6,607.3 5,835.7
Current maturities of long-term debt .................................... (77.3) (350.6)
---------- ----------
Total long-term portion ................................................. $ 6,530.0 $ 5,485.1
========== ==========
- ---------
(a) Substantially all of the Corporation's electric plant was mortgaged as of
December 31, 1997.
(b) Substantial amounts of Crescent Resources, Inc.'s real estate development
projects, land and buildings are pledged as collateral.
48
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 11. DEBT AND CREDIT FACILITIES -- Continued
The annual maturities of consolidated long-term debt at December 31, 1997
were $77.3 million, $612.1 million, $427 million, $403 million and $192.5
million for 1998 through 2002, respectively.
On October 1, 1996, TETCO redeemed its $150 million, 10% debentures and
its $100 million, 10 1/8% debentures due 2011. TETCO recorded a non-cash
extraordinary item of $16.7 million (net of income tax of $10.3 million)
related to the unamortized discount on this early retirement of debt. Earnings
per common share for 1996 were reduced $0.05 as a result of this charge.
NOTE 12. NUCLEAR DECOMMISSIONING COSTS & SPENT NUCLEAR FUEL
NUCLEAR DECOMMISSIONING COSTS. Estimated site-specific nuclear
decommissioning costs, including the cost of decommissioning plant components
not subject to radioactive contamination, total approximately $1.3 billion
stated in 1994 dollars based on decommissioning studies completed in 1994. This
amount includes the Corporation's 12.5 percent ownership in Catawba. The other
joint owners of Catawba are responsible for decommissioning costs related to
their ownership interests in the station. Both the NCUC and the PSCSC have
granted the Corporation recovery of estimated decommissioning costs through
retail rates over the expected remaining service periods of the Corporation's
nuclear plants. Such estimates presume each unit will be decommissioned as soon
as possible following the end of its license life. Although subject to
extension, the current operating licenses for the Corporation's nuclear units
expire as follows: Oconee 1 and 2 - 2013, Oconee 3 - 2014; McGuire 1 - 2021,
McGuire 2 - 2023; and Catawba 1 - 2024, Catawba 2 - 2026.
During 1997 and 1996, the Corporation expensed approximately $56.5 million
which was contributed to the external funds for decommissioning costs and
accrued an additional $3.0 million and $1.6 million to the internal reserve in
1997 and 1996, respectively. Nuclear units are depreciated at an annual rate of
4.7 percent, of which 1.61 percent is for decommissioning. The balance of the
external funds as of December 31, 1997 and 1996, was $471.1 million and $362.6
million respectively. The balance of the internal reserve as of December 31,
1997 and 1996, was $210.8 million and $207.8 million, respectively, and is
reflected in Accumulated Depreciation and Amortization in the Consolidated
Balance Sheets. Management's opinion is that the decommissioning costs being
recovered through rates, when coupled with assumed after-tax fund earnings of
5.5 to 5.9 percent, are currently 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 uranium enrichment plants of the
Department of Energy (DOE). Licensees are subject to an annual assessment for
15 years based on their pro rata share of past enrichment services. The annual
assessment is recorded as Fuel Used in Electric Generation in the Consolidated
Statements of Income. The Corporation paid $9.7 million during 1997 and has
paid $54.7 million cumulatively related to its ownership interests in nuclear
plants. The Corporation has reflected the remaining liability and regulatory
asset of $87.1 million and $94.7 million in the Consolidated Balance Sheets at
December 31, 1997 and 1996, respectively, and were classified as Deferred
Credits and Other Liabilities and Regulatory Assets and Deferred Debits,
respectively.
SPENT NUCLEAR FUEL. Under provisions of the Nuclear Waste Policy Act of
1982, the Corporation has entered into contracts with the DOE for the disposal
of spent nuclear fuel. The DOE delayed in accepting the waste materials on the
contract date of January 31, 1998. The Corporation has satisfactory plans in
place to provide storage of spent nuclear fuel if the DOE cannot accept it.
Payments made to the DOE for disposal costs are based on nuclear output and are
included in Fuel Used in Electric Generation in the Consolidated Statements of
Income.
NOTE 13. GUARANTEED PREFERRED BENEFICIAL INTERESTS IN CORPORATION'S
SUBORDINATED NOTES
On December 8, 1997, Duke Energy Capital Trust I (the Trust), issued $350
million of its 7.2% trust preferred securities, at an $11 million discount,
representing preferred undivided beneficial interests in the assets of the
Trust. Payment of distributions on such preferred securities is guaranteed by
the Corporation, but only to the extent the Trust has funds legally and
immediately available to make such distributions. The Trust is a statutory
business trust, of which the Corporation owns all the common securities,
established for the purpose of issuing and selling such preferred securities
and investing the gross proceeds in the 7.2% Series A Junior Subordinated Notes
of the Corporation due September 30, 2037.
49
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 14. PREFERRED AND PREFERENCE STOCK
The following shares of stock were authorized with or without sinking fund
requirements as of December 31, 1997 and 1996:
Shares
Par Value (in millions)
----------- --------------
Preferred Stock ............. $100 12.5
Preferred Stock A ........... $ 25 10.0
Preference Stock ............ $100 1.5
As of December 31, 1997 and 1996, there were no shares of preference stock
outstanding. Preferred stock with sinking fund requirements as of December 31,
1997 and 1996, was as follows (dollars in millions):
Rate/Series Year Issued Shares Outstanding 1997 1996
- ---------------------------------- ------------- -------------------- ----------- -----------
5.95% B (Preferred Stock A) 1992 800,000 $ 20.0 $ 20.0
6.10% C (Preferred Stock A) 1992 800,000 20.0 20.0
6.20% D (Preferred Stock A) 1992 800,000 20.0 20.0
6.20% T .................... 1992 130,000 13.0 13.0
6.30% U .................... 1992 130,000 13.0 13.0
6.40% V .................... 1992 130,000 13.0 13.0
6.75% X .................... 1993 500,000 50.0 50.0
7.50% R .................... 1992 850,000 -- 85.0
-------- --------
Total .................... $ 149.0 $ 234.0
======== ========
The annual sinking fund requirements for 1998 through 2002 are $0, $20.0
million, $33.0 million, $33.0 million and $13.0 million, respectively. Some
additional redemptions are permitted at the Corporation's option.
The call provisions for the outstanding preferred stock specify various
redemption prices not exceeding 104 percent of par value, plus accumulated
dividends to the redemption date.
Preferred stock without sinking fund requirements as of December 31, 1997
and 1996, was as follows (dollars in millions):
Rate/Series Year Issued Shares Outstanding 1997 1996
- --------------------------------------- ------------- -------------------- ----------- -----------
4.50% C ......................... 1964 350,000 $ 35.0 $ 35.0
7.85% S ......................... 1992 600,000 60.0 60.0
7.00% W ......................... 1993 500,000 50.0 50.0
7.04% Y ......................... 1993 600,000 60.0 60.0
6.375% (Preferred Stock A) ...... 1993 2,400,000 60.0 60.0
Auction Series A ................ 1990 750,000 75.0 75.0
5.72% D ......................... 1966 350,000 -- 35.0
6.72% E ......................... 1968 350,000 -- 35.0
7.72% (Preferred Stock A) ....... 1992 1,600,000 -- 40.0
-------- --------
Total ......................... $ 340.0 $ 450.0
======== ========
During December 1997, the Corporation redeemed approximately 3.2 million
shares of preferred stock for $203.4 million. On December 18, 1997, the
Corporation also commenced a tender offer to purchase a portion of six of its
preferred issues totaling $315 million. The tender offer expired on February 3,
1998, with acceptances limited to a maximum of 50 percent of the outstanding
shares of each issue. The premiums related to these redemptions were included
in Dividends and Premiums on Redemptions of Preferred and Preference Stock in
the Consolidated Statements of Income.
50
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 15. COMMITMENTS AND CONTINGENCIES
FUTURE CONSTRUCTION COSTS. The Corporation plans to maintain its regulated
facilities, and pursue business expansion of its regulated operations as
opportunities arise. Projected 1998 capital and investment expenditures for the
Electric Operations and the Natural Gas Transmission segments, including AFUDC,
are approximately $700 million and $300 million, respectively. These
projections are subject to periodic review and revisions. Actual expenditures
incurred may vary from such estimates due to various factors, including revised
electric load estimates, business expansion opportunities, environmental
matters and cost and availability of capital.
The Energy Services segment plans to spend approximately $100 million in
1998 for required capital expenditures at its existing facilities. In addition,
the Corporation is seeking to significantly grow its Energy Services
businesses, primarily through the Global Asset Development business unit. One
opportunity includes the 520-megawatt combined cycle natural gas fired merchant
generation plant in Bridgeport, Connecticut already under construction. Another
growth opportunity includes the recently announced agreement to purchase from
Pacific Gas & Electric Company three power plants in California. The power
plants have a combined capacity of 2,645 megawatts. The purchase price is
estimated at approximately $500 million and this transaction is expected to
close during 1998. Other similar initiatives in 1998 will likely require
significant capital and investment expenditures which will be subject to
periodic review and revision and may vary significantly depending on the
value-added opportunities presented.
Projected capital and investment expenditures for 1998 of the Other
Operations segment are approximately $200 million. These projected capital and
investment expenditures are also subject to periodic review and revision and
may vary significantly depending on the value-added opportunities presented.
NUCLEAR INSURANCE. The Corporation owns and operates the McGuire and
Oconee nuclear facilities with two and three nuclear reactors, respectively,
and operates and has a partial ownership interest in the Catawba nuclear
facility with two nuclear reactors. The Corporation maintains nuclear insurance
coverage in three program areas: liability coverage; property, decontamination
and decommissioning coverage; and business interruption and/or extra expense
coverage. The Corporation is being reimbursed by the other joint owners of
Catawba for certain expenses associated with nuclear insurance premiums paid by
the Corporation.
Pursuant to the Price-Anderson Act, the Corporation is required to insure
against public liability claims resulting from nuclear incidents to the full
limit of liability of approximately $8.9 billion.
Primary Liability Insurance. The maximum required private primary
liability insurance of $200 million has been purchased along with a like amount
to cover certain worker tort claims.
Excess Liability Insurance. This policy currently provides approximately
$8.7 billion of coverage through the Price-Anderson Act's mandatory
industry-wide excess secondary insurance program of risk pooling. The $8.7
billion of coverage is the sum of the current potential cumulative
retrospective premium assessments of $79.3 million per licensed commercial
nuclear reactor. This $8.7 billion will be increased by $79.3 million as each
additional commercial nuclear reactor is licensed, or reduced by $79.3 million
for certain nuclear reactors that are 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 nation. If such an incident
occurs and public liability damages exceed primary insurances, licensees may be
assessed up to $79.3 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 $79.3 million amount is subject to indexing for inflation and may be
subject to state premium taxes.
The Corporation is a member of Nuclear Electric Insurance Limited (NEIL),
which provides property and business interruption insurance coverages for the
Corporation's nuclear facilities under the following three policy programs:
Primary Property Insurance. This policy provides $500 million in primary
property damage coverage for each of the Corporation's nuclear facilities.
Excess Property Insurance. This policy provides excess property,
decontamination and decommissioning liability insurance in the following
amounts; $2.25 billion for Catawba and $1.5 billion for each of the Oconee and
McGuire Nuclear Stations.
51
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 15. COMMITMENTS AND CONTINGENCIES -- Continued
Business Interruption Insurance. This policy provides business
interruption and/or extra expense coverage resulting from an accidental outage
of a nuclear unit. Each unit of the McGuire and Catawba Nuclear Stations is
insured for up to approximately $3.5 million per week and the Oconee Nuclear
Station units are insured for up to approximately $2.8 million per week.
Coverage amounts per unit decline if more than one unit is involved in an
accidental outage. Initial coverage begins after a 17-week deductible period
and continues at 100 percent for 52 weeks and 80 percent for the next 104
weeks.
If NEIL's losses ever exceed its reserves for any of the above three
programs, the Corporation will be liable for assessments of up to five times
the Corporation's annual premiums. The current potential maximum assessments
are as follows: Primary Property Insurance - $30 million; Excess Property
Insurance - $31 million; Business Interruption Insurance - $27 million.
The other joint owners of Catawba are obligated to assume their pro rata
share of any liabilities 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. The Corporation is subject to federal, state and local
regulations regarding air and water quality, hazardous and solid waste
disposal, and other environmental matters.
TETCO is currently conducting PCB (polychlorinated biphenyl) assessment
and clean-up programs at certain of its compressor station sites under
conditions stipulated by a U.S. Consent Decree. The programs include on- and
off-site assessment, installation of on-site source control equipment and
groundwater monitoring wells, and on- and off-site clean-up work. TETCO expects
to complete these clean-up programs during 1998. Groundwater monitoring
activities will continue at several sites beyond 1998.
In 1987, the Commonwealth of Kentucky instituted a suit in state court
against TETCO, alleging improper disposal of PCBs at TETCO's three compressor
station sites in Kentucky. This suit is still pending. In 1996, TETCO completed
clean-up of these sites under the U.S. Consent Decree.
The Corporation has also identified environmental contamination at certain
sites on the PEPL and Trunkline systems and is undertaking clean-up programs at
these sites. The contamination resulted from the past use of lubricants
containing PCBs and the prior use of wastewater collection facilities and other
on-site disposal areas. Soil and sediment testing, to date, has detected no
significant off-site contamination. The Corporation has communicated with the
Environmental Protection Agency and appropriate state regulatory agencies on
these matters. Environmental clean-up programs are expected to continue until
2002.
At December 31, 1997 and 1996, the Corporation had accrued liabilities for
remaining estimated clean-up costs on the TETCO, PEPL and Trunkline systems
which are included in Environmental Clean-up Liabilities in the Consolidated
Balance Sheets. These cost estimates represent gross clean-up costs expected to
be incurred, have not been discounted or reduced by customer recoveries and do
not include fines, penalties or third-party claims. Costs to be recovered from
customers are included in the Consolidated Balance Sheets as of December 31,
1997 and 1996, as Regulatory Assets and Deferred Debits.
The federal and state clean-up programs are not expected to interrupt or
diminish the Corporation's ability to deliver natural gas to customers. Based
on the Corporation's experience to date and costs incurred for clean-up
operations, management believes the resolution of matters relating to the
environmental issues discussed above will not have a material adverse effect on
results of operations or financial position of the Corporation.
LITIGATION. In December 1996, TETCO received notification that Marathon
Oil Company (Marathon) intended to commence substitution of other gas reserves,
deliverability and leases for those dedicated to a certain natural gas purchase
contract (the Marathon Contract) with TETCO. In TETCO's view, the tendered
substitute gas reserves, deliverability and leases are not subject to the
Marathon Contract; therefore TETCO filed a declaratory judgment action on
December 17, 1996 in the U.S. District Court for the Eastern District of
Louisiana seeking a ruling that Marathon's interpretation of the Marathon
Contract is incorrect. Marathon filed a counterclaim seeking a declaratory
judgment enforcing its interpretation of the Marathon Contract. On January 7,
1997, Marathon filed an answer and a counterclaim to TETCO's complaint seeking
declaratory judgment enforcing its interpretation of the Marathon Contract.
52
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 15. COMMITMENTS AND CONTINGENCIES -- Continued
On February 18, 1997, Amerada Hess Corporation (Amerada Hess) notified
TETCO that it intended to commence substitution of other gas reserves,
deliverability and leases for those dedicated to its natural gas purchase
contract (the Amerada Hess Contract) with TETCO. On the same date, Amerada Hess
also filed a petition in the District Court of Harris County, Texas, 157th
Judicial District, seeking a declaratory judgment that its interpretation of
the Amerada Hess Contract, which covers the same leases and reserves as the
Marathon Contract, is correct. TETCO filed a declaratory judgment action with
respect to Amerada Hess' contentions in the U.S. District Court for the Eastern
District of Louisiana on February 21, 1997. The two actions have been
transferred to the judge presiding over the Marathon Contract matter.
On September 26, 1997, the judge presiding over the Marathon and Amerada
Hess contract matters issued summary judgments in both actions in favor of
TETCO. Marathon and Amerada Hess subsequently filed notices of appeal of the
summary judgments. On January 5, 1998, TETCO entered into an agreement with
Marathon settling all issues associated with the Marathon Contract. The
potential liability of the Company associated with the Amerada Hess Contract
should TETCO be contractually obligated to purchase natural gas based upon the
substitute gas reserves, deliverability and leases, and the effect of
transition cost recoveries pursuant to TETCO's Order 636 settlement involves
numerous complex legal and factual matters which will take a substantial period
of time to resolve. However, the Corporation does not believe that Amerada Hess
will prevail on its appeal of the lower court's summary judgment. Management is
of the opinion that the final disposition of this matter will not have a
material adverse effect on the consolidated results of operations or financial
position of the Corporation.
On April 25, 1997, a group of affiliated plaintiffs that own and/or
operate various pipeline and marketing companies and partnerships primarily in
Kansas filed suit against PEPL in the U.S. District Court for the Western
District of Missouri. The plaintiffs allege that PEPL has engaged in unlawful
and anti-competitive conduct with regard to requests for interconnects with the
PEPL system for service to the Kansas City area. Asserting that PEPL has
violated the antitrust laws and tortiously interfered with the plaintiffs'
contracts with third parties, the plaintiffs seek compensatory and punitive
damages in unspecified amounts. Periodically, similar disputes arise with other
natural gas marketers and pipeline companies concerning interconnections and
other issues involving access to the Corporation's natural gas transmission
systems. Management is of the opinion that the final disposition of these
proceedings will not have a material adverse effect on the consolidated results
of operations or financial position of the Corporation.
The Corporation and its subsidiaries are also involved in legal, tax and
regulatory proceedings before various courts, regulatory commissions and
governmental agencies regarding matters arising in the ordinary course of
business, some of which involve substantial amounts. Where appropriate, the
Corporation has made accruals in accordance with SFAS No. 5, "Accounting for
Contingencies," in order to provide for such matters. Management is of the
opinion that the final disposition of these matters will not have a material
adverse effect on the consolidated results of operations or financial position
of the Corporation.
OTHER COMMITMENTS AND CONTINGENCIES. The Corporation has a 10% ownership
interest in TEPPCO Partners, L.P., a master limited partnership (MLP) that owns
and operates a petroleum products pipeline. A subsidiary partnership of the MLP
had $326.5 million in First Mortgage Notes outstanding at December 31, 1997
with recourse to the general partner, a subsidiary of the Corporation.
In January 1998, the Corporation acquired a 9.8% ownership in Alliance
Pipeline. This pipeline is designed to transport natural gas from western
Canada to the Chicago-area market center for distribution throughout North
America. The pipeline is scheduled to begin commercial operation in late 1999,
provided the necessary U.S. and Canadian regulatory approvals are secured. In
addition to buying an ownership interest in the pipeline project, the
Corporation has a contractual commitment for 67.25 million cubic feet per day
of capacity on the line over 15 years for an estimated total of $315 million.
Periodically, the Corporation may become involved in contractual disputes
with natural gas transmission customers involving potential or threatened
abrogation of contracts by the customers, including for example attempted
transfers of contractual obligations to less creditworthy subsidiaries of the
customers. If the customers are successful, the Corporation may not receive the
full value of anticipated benefits under the contracts.
53
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 15. COMMITMENTS AND CONTINGENCIES -- Continued
In the normal course of business, certain of the Corporation's affiliates
enter into various contracts, including agreements for debt, natural gas
transmission service and construction contracts, which contain certain schedule
and performance requirements. Such affiliates use risk management techniques to
mitigate their exposure associated with such contracts. Certain subsidiaries of
the Corporation have guaranteed performance by such affiliates under some of
these contracts.
Management is of the opinion that these commitments and contingencies will
not have a material adverse effect on the consolidated results of operations or
the financial position of the Corporation.
LEASES. The Corporation utilizes assets under operating leases in several
areas of operations. Consolidated rental expense amounted to $91.7 million,
$84.2 million, and $61.7 million in 1997, 1996, and 1995, respectively. Future
minimum rental payments under the Corporation's various operating leases for
the years 1998 through 2002 are $87.4 million, $76.3 million, $68.9 million,
$66.5 million, and $48.7 million, respectively.
NOTE 16. COMMON STOCK
On February 27, 1996, the Board of Directors authorized the Corporation to
repurchase up to $1 billion of its common stock over the next five years. As of
December 31, 1996, approximately 3.3 million shares had been repurchased for
$159 million. On January 28, 1997, the Board of Directors amended the program
to expressly limit the number of shares authorized for repurchase under the
program, from the initiation of the program through a date two years after the
consummation of the merger, to an amount not to exceed 15 million shares. No
repurchases of common stock were made in 1997, and none are anticipated in the
future.
NOTE 17. STOCK BASED COMPENSATION
STOCK OPTIONS AND AWARDS. Effective with the merger, each share of
PanEnergy common stock outstanding immediately prior to the merger was
converted into the right to receive 1.0444 shares of the Corporation's common
stock. Each option to purchase PanEnergy common stock that was outstanding
prior to the merger was assumed by the Corporation and became exercisable upon
the same terms as under the applicable PanEnergy stock option plan and option
agreement, except that such options became an option to purchase shares of the
Corporation's common stock, appropriately adjusted. Each award of restricted
shares of PanEnergy common stock outstanding and not vested prior to the merger
was assumed by the Corporation and such restricted shares of PanEnergy common
stock were exchanged for restricted shares of the Corporation's common stock.
Under the Corporation's 1996 Stock Incentive Plan, stock options and
awards for up to two million shares of common stock may be granted to key
employees. Under the plan, the exercise price of each option granted equals the
market price of the Corporation's common stock on the date of grant. Vesting
periods range from one to five years with a maximum exercise term of 10 years.
In 1997, the Corporation granted 115,615 shares of performance-based stock
awards and 1,000 fixed stock awards with an average grant date fair value of
$44 per share. The Corporation recognized compensation expense of $4.4 million
in 1997, $8.3 million in 1996 and none in 1995 for such stock awards.
54
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 17. STOCK BASED COMPENSATION -- Continued
A summary of the Corporation's stock option grants follows:
Options Average
(000's) Exercise Price
----------- ---------------
Outstanding at December 31, 1994 3,737 $ 16
Granted ........................ 959 20
Exercised ...................... (1,075) 13
Forfeited ...................... (62) 22
------
Outstanding at December 31, 1995 3,559 18
Granted ........................ 498 28
Exercised ...................... (712) 16
Forfeited ...................... (71) 22
------
Outstanding at December 31, 1996 3,274 20
Granted ........................ 388 44
Exercised ...................... (873) 19
Forfeited ...................... (60) 27
------
Outstanding at December 31, 1997 2,729 24
======
The Corporation had 2.2 million options and 2.4 million options
exercisable at December 31, 1996 and 1995, with average exercise prices of $19
and $16 per option, respectively. Details of stock options outstanding and
options exercisable at December 31, 1997 follows:
Outstanding Exercisable
----------------------------------- -------------------
Average Average Average
Range of Number Remaining Exercise Number Exercise
Exercise Prices (000's) Life (Years) Price (000's) Price
- --------------------------- --------- -------------- ---------- --------- ---------
$10 to $14 ......... 193 3.5 $ 11 193 $ 11
$15 to $20 ......... 966 5.8 18 966 18
$21 to $25 ......... 808 5.6 22 808 22
$26 to $31 ......... 396 8.1 28 396 28
$41 to $50 ......... 366 9.1 44 14 42
--- ---
Total ............. 2,729 2,377 21
===== =====
FAIR VALUE INFORMATION. The weighted-average fair value of options granted
was $10, $9, and $7 per option during 1997, 1996 and 1995, respectively. The
fair value of each option grant was estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted-average
assumptions used for 1997, 1996 and 1995, respectively: stock dividend yield of
3.5%, 2.6% and 2.6%; expected stock price volatility of 20.7%, 26% and 26%;
risk-free interest rates of 6.5%, 5.7% and 7.7%; and expected option lives of
seven years. Had compensation expense for stock-based compensation been
determined based on the fair value at the grant dates, the Corporation's 1997
net income would have been $971.4 million, or $2.50 per share; 1996 net income
would have been $1,073.7 million, or $2.85 per share; and 1995 net income would
have been $1,016.9 million, or $2.68 per share.
NOTE 18. BENEFIT PLANS
RETIREMENT PLANS. The Corporation and its subsidiaries have multiple
non-contributory defined benefit retirement plans covering most employees with
minimum service requirements. Effective January 1, 1997, the Duke Power
retirement plan was amended to a plan under which benefits are based upon a
cash balance formula. Under a cash balance formula, a plan participant
accumulates a benefit based upon a percentage of current salary, which may vary
with age and years of service, and interest credits. Prior to January 1, 1997,
the Duke Power retirement plan benefits were based on an age-related formula
which took into account years of benefit accrual service and the employee's
highest average eligible earnings.
55
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 18. BENEFIT PLANS -- Continued
The PanEnergy plan provides retirement benefits (i) for eligible employees
of certain subsidiaries that are generally based on an employee's years of
benefit accrual service and highest average eligible earnings, and (ii) for
eligible employees of certain other subsidiaries under a cash balance formula.
The Corporation's policy is to fund amounts, as necessary, on an actuarial
basis to provide assets sufficient to meet benefits to be paid to plan members.
On December 30, 1997 assets and related liabilities of $235.6 million and $204
million, respectively, for certain PanEnergy participants were transferred to
the Duke Power plan. As a result of this transfer, no contributions to the Duke
Power plan were necessary in 1997.
Net periodic pension cost includes the following components for the years
ended December 31, 1997, 1996 and 1995:
1997 1996 1995
------------- ------------- -------------
In Millions
Actual return on plan assets ...................... $ (455.3) $ (302.6) $ (413.1)
Amount deferred for recognition ................... 246.5 110.4 237.4
---------- ---------- ----------
Expected return on plan assets .................... (208.8) (192.2) ( 175.7)
Service cost benefit earned during the year ....... 62.2 62.7 57.8
Interest cost on projected benefit obligation ..... 163.7 152.8 147.9
Net amortization .................................. 7.8 6.4 3.3
---------- ---------- ----------
Net periodic pension cost ....................... $ 24.9 $ 29.7 $ 33.3
========== ========== ==========
A reconciliation of the funded status of the plans to the amounts
recognized in the Consolidated Balance Sheets as of December 31, 1997 and 1996
is as follows:
1997 1996
--------------- ---------------
In Millions
Accumulated benefit obligation
Vested benefits ............................. $ (2,011.9) $ (1,814.9)
Nonvested benefits .......................... (18.3) (26.7)
------------ ------------
Accumulated benefit obligation ................ $ (2,030.2) $ (1,841.6)
============ ============
Fair market value of plan assets (a) .......... $ 2,724.7 $ 2,445.3
Projected benefit obligation .................. (2,372.1) (2,126.4)
Unrecognized net experience loss .............. 81.3 123.1
Unrecognized prior service cost reduction ..... (64.8) (45.1)
Unrecognized net asset ........................ (31.6) (36.3)
------------ ------------
Pre-funded pension cost ..................... $ 337.5 $ 360.6
============ ============
- ---------
(a) Principally equity and fixed income securities
Assumptions used in the Corporation's pension accounting (reflecting
weighted averages across all plans) include:
1997 1996 1995
--------- --------- ---------
Percent (%)
Discount rate ................................... 7.25 7.50 7.50
Salary increase ................................. 4.15 4.80 4.81
Expected long-term rate of return on plan assets 9.25 9.18 9.18
During 1995, the Corporation offered to certain employees an Enhanced
Vested Benefits program (EVB). The Corporation recorded an additional one-time
expense for special termination benefits associated with the EVB of
approximately $42.2 million, including $21.6 million of additional retirement
plan costs.
56
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 18. BENEFIT PLANS -- Continued
The Corporation also sponsors employee savings plans which cover
substantially all employees. The Corporation expensed plan contributions of
$52.8 million, $34.8 million and $34.9 million in 1997, 1996 and 1995,
respectively.
OTHER POSTRETIREMENT BENEFITS. The Corporation and most of its
subsidiaries provide certain health care and life insurance benefits for
retired employees on a contributory and non-contributory basis. Employees
become eligible for these benefits if they have met certain age and service
requirements at retirement, as defined in the plans.
The Corporation accrues such benefit costs over the active service period
of employees to the date of full eligibility for the benefits. The net
unrecognized transition obligation, resulting from the implementation of
accrual accounting, is being amortized over approximately 20 years.
The Corporation is using an investment account under section 401(h) of the
Internal Revenue Code, a retired lives reserve (RLR) and multiple voluntary
employees' beneficiary association (VEBA) trusts under section 501(c)(9) of the
Internal Revenue Code to partially fund postretirement benefits. The 401(h)
vehicles, which provide for tax deductions for contributions and tax-free
accumulation of investment income, partially fund the Corporation's
postretirement health care benefits. The Corporation uses the RLR, which has
tax attributes similar to 401(h) funding, to partially fund its postretirement
life insurance obligations. Certain subsidiaries use the VEBA trusts to
partially fund accrued postretirement health care benefits and fund
postretirement life insurance obligations.
Net periodic postretirement benefit cost of the plans include the
following components for the years ended December 31, 1997, 1996 and 1995:
1997 1996 1995
------------ ------------ ------------
In Millions
Actual return on plan assets ....................................... $ (45.1) $ (20.5) $ (29.6)
Amount deferred for recognition .................................... 26.4 4.2 16.2
--------- --------- ---------
Expected return on plan assets ..................................... (18.7) (16.3) (13.4)
Service cost benefit earned during the year ........................ 10.0 8.4 7.6
Interest cost on accumulated postretirement benefit obligation ..... 46.2 43.3 43.5
Net amortization ................................................... 20.3 19.3 16.5
--------- --------- ---------
Net periodic postretirement benefit cost ......................... $ 57.8 $ 54.7 $ 54.2
========= ========= =========
A reconciliation of the funded status of the plans to the amounts
recognized in the Consolidated Balance Sheets as of December 31, 1997 and 1996
is as follows:
1997 1996
------------- -------------
In Millions
Accumulated postretirement benefit obligation
Retirees ............................................ $ (428.6) $ (440.5)
Fully eligible active plan participants ............. (57.0) (42.6)
Other active plan participants ...................... (181.4) (158.6)
---------- ----------
Accumulated post retirement benefit obligation ..... (667.0) (641.7)
Fair market value of plan assets (a) .................. 266.2 225.3
Unrecognized prior service cost ....................... 64.6 66.7
Unrecognized net experience loss ...................... 3.7 27.0
Unrecognized transitional obligation .................. 255.9 273.0
---------- ----------
Accrued postretirement benefit cost ................. $ (76.6) $ (49.7)
========== ==========
- ---------
(a) Principally equity and fixed income securities
57
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
NOTE 18. BENEFIT PLANS -- Continued
Assumptions used in the Corporation's postretirement benefits accounting
(reflecting weighted-averages across all plans) include:
1997 1996 1995
--------- --------- ---------
Percent (%)
Discount rate ..................................... 7.25 7.50 7.50
Salary increase ................................... 4.33 4.84 4.84
Expected long-term rate of return on 401(h) assets 9.25 9.00 9.00
Expected long-term rate of return on RLR assets ... 6.75 6.50 8.00
Expected long-term rate of return on VEBA assets .. 9.25 9.50 9.50
Assumed tax rate (a) .............................. 39.60 39.60 39.60
- ---------
(a) Health care portion of postretirement benefits in VEBA trusts.
The weighted-average health care cost trend rate used to estimate
postretirement benefits was 7.75% in 1997. This rate is expected to decrease,
with a 4.75% weighted-average ultimate trend rate expected to be achieved by
2005. The effect of a 1% increase in the assumed health care cost trend rate
for each future year would result in a $2.4 million increase in the annual
aggregate postretirement benefit cost and a $29.5 million increase in the
accumulated postretirement benefit obligation at December 31, 1997.
NOTE 19. QUARTERLY FINANCIAL DATA (UNAUDITED)
First Quarter Second Quarter
--------------- ----------------
In Millions
(except per share data)
1997
Operating revenues ............................... $ 3,785.8 $ 3,112.8
Operating income ................................. 610.0 352.0
Net income ....................................... 311.7 168.6
Basic earnings per share ......................... $ 0.84 $ 0.43
1996
Operating revenues ............................... $ 2,859.1 $ 2,559.3
Operating income ................................. 575.7 479.2
Income before extraordinary item ................. 293.1 237.1
Net income ....................................... 293.1 237.1
Basic earnings per share (before extraordinary
item) ........................................... $ 0.78 $ 0.62
Basic earnings per share ......................... $ 0.78 $ 0.62
Third Quarter Fourth Quarter Total
--------------- ---------------- ---------------
In Millions
(except per share data)
1997
Operating revenues ............................... $ 4,820.6 $ 4,589.7 $ 16,308.9
Operating income ................................. 606.3 401.7 1,970.0
Net income ....................................... 309.5 184.6 974.4
Basic earnings per share ......................... $ 0.83 $ 0.41 $ 2.51
1996
Operating revenues ............................... $ 3,133.4 $ 3,750.6 $ 12,302.4
Operating income ................................. 653.1 450.6 2,158.6
Income before extraordinary item ................. 351.2 209.6 1,091.0
Net income ....................................... 351.2 192.9 1,074.3
Basic earnings per share (before extraordinary
item) ........................................... $ 0.94 $ 0.56 $ 2.90
Basic earnings per share ......................... $ 0.94 $ 0.51 $ 2.85
Amounts reported on a quarterly basis are not necessarily indicative of
amounts expected for the respective years due to the effects of seasonal
temperature variations on energy consumption and the timing of maintenance of
certain electric generating units.
58
DUKE ENERGY CORPORATION
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Allowance for Doubtful
Accounts (a) Other Reserves (a), (b)
----------------------- ------------------------
In Millions
Balance at December 31, 1997 ...... $ 22.5 $ 306.2
Balance at December 31, 1996 ...... 20.0 261.4
Balance at December 31, 1995 ...... 16.5 271.1
- ---------
(a) Financial information reflects accounting for the merger with PanEnergy
Corp as a pooling of interests. As a result, the financial information
gives effect to the merger as if it had occurred December 31, 1995.
(b) Principally consists of injuries and damages reserves, property insurance
reserves and litigation and other contingency reserves which are included
in "Other Current Liabilities" or "Deferred Credits and Other Liabilities"
in the Consolidated Balance Sheets.
59
INDEPENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS AND STOCKHOLDERS OF DUKE ENERGY CORPORATION
We have audited the consolidated balance sheets of Duke Energy Corporation
and subsidiaries (the Corporation) as of December 31, 1997 and 1996, and the
related consolidated statements of income, common stockholders' equity, and cash
flows for each of the three years in the period ended December 31, 1997. Our
audits also included the consolidated financial statement schedule listed in the
accompanying index at Item 14. These financial statements and financial
statement schedule are the responsibility of the Corporation's management. Our
responsibility is to express an opinion on the financial statements and
financial statement schedule based on our audits. The consolidated financial
statements and consolidated financial statement schedule give retroactive effect
to the merger of Duke Power Company and PanEnergy Corp, which has been accounted
for as a pooling of interests as described in Note 1 to the consolidated
financial statements. We did not audit the balance sheet of PanEnergy Corp and
subsidiaries as of December 31, 1996, or the related statements of income,
common stockholders' equity, and cash flows of PanEnergy Corp and subsidiaries
for each of the two years in the period ended December 31, 1996, which
statements reflect total assets of (in millions) $8,567.8 as of December 31,
1996 and total operating revenues of (in millions), $7,536.8 and $4,967.5 for
the years ended December 31, 1996, and 1995, respectively. Those financial
statements were audited by other auditors whose report has been furnished to us,
and our opinion, insofar as it relates to the amounts included for PanEnergy
Corp and subsidiaries for 1996, and 1995, is based solely on the report of such
other auditors.
We conducted our audits in accordance with generally accepted auditing
standards. 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 and the report of the other
auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other auditors,
the consolidated financial statements referred to above present fairly, in all
material respects, the financial position of the Corporation as of December 31,
1997 and 1996, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 1997 in conformity with
generally accepted accounting principles. Also, in our opinion, such
consolidated 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 13, 1998
RESPONSIBILITY FOR FINANCIAL STATEMENTS
The financial statements of Duke Energy Corporation are prepared by
management, which is responsible for their integrity and objectivity. The
statements are prepared in conformity with generally accepted accounting
principles appropriate in the circumstances to reflect in all material respects
the substance of events and transactions which should be included. The other
information in the annual report is consistent with the financial statements.
In preparing these statements, management makes informed judgments and
estimates of the expected effects of events and transactions that are currently
being reported.
The Corporation'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, the Corporation's 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. The
Corporation's accounting controls are continually reviewed for effectiveness.
In addition, written policies, standards and procedures, and a strong internal
audit program augment the Corporation's accounting controls.
The Board of Directors pursues its oversight role for the financial
statements through the audit committee, which is composed entirely of directors
who are not employees of the Corporation. The audit committee meets with
management and internal auditors periodically to review the work of each group
and to monitor each group's discharge of its responsibilities. The audit
committee also meets periodically with the Corporation'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.
JEFFREY L. BOYER
Vice President and Controller
60
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 the Corporation" included in
"Item 1. Business" of this report. See "Election of Directors", "Information
Regarding the Board of Directors" and "Other Matters" in the proxy statement
relating to the Corporation's 1998 annual meeting of shareholders (the Proxy
Statement), incorporated herein by reference.
Item 11. Executive Compensation.
See "Executive Compensation" and "Compensation of Directors" in the Proxy
Statement, incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
See "Security Ownership of Nominees, Directors and Executive Officers" in
the Proxy Statement, incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions.
See "Information Regarding the Board of Directors" in the Proxy Statement,
incorporated herein by reference.
61
PART IV.
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) Consolidated Financial Statements, Supplemental Financial Data and
Supplemental Schedules included in Part II of this annual report are as
follows:
Consolidated Financial Statements
Consolidated Statements of Income for the Years Ended December 31, 1997,
1996 and 1995
Consolidated Statements of Cash Flows for the Years Ended December 31,
1997, 1996 and 1995
Consolidated Balance Sheets as of December 31, 1997 and 1996
Consolidated Statements of Common Stockholders' Equity for the Years
Ended December 31, 1997, 1996 and 1995
Notes to Consolidated Financial Statements
Quarterly Financial Data (unaudited) (included in Note 19 to the
Consolidated Financial Statements)
Consolidated Financial Statement Schedule
Schedule II -- Valuation and Qualifying Accounts and Reserves for the
Years Ended December 31, 1997, 1996 and 1995
All other schedules are omitted because of the absence of the conditions
under which they are required or because the required information is
included in the financial statements or notes thereto.
(b) Reports on Form 8-K
A Current Report on Form 8-K filed on November 18, 1997 contained
disclosures under Item 5, Other Events, and Item 7, Financial Statements and
Exhibits.
A Current Report on Form 8-K filed on December 4, 1997 contained
disclosures under Item 7, Financial Statements and Exhibits. The following
audited consolidated financial statements were filed as Exhibit 99.1 to such
report:
Consolidated Statements of Income for the Years Ended December 31, 1996,
1995 and 1994
Consolidated Statements of Cash Flows for the Years Ended December 31,
1996, 1995 and 1994
Consolidated Balance Sheets as of December 31, 1996 and 1995
Consolidated Statements of Common Stockholders' Equity for the Years
Ended December 31, 1996, 1995 and 1994
Notes to Consolidated Financial Statements
Independent Auditors' Report
(c) Exhibits -- See Exhibit Index immediately following the signature
page.
62
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 27, 1998
DUKE ENERGY CORPORATION
(Registrant)
By: RICHARD B. PRIORY
Richard B. Priory
Chairman of the Board
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 and Chief Executive Officer
(ii) Principal financial officer:
Richard J. Osborne
Executive Vice President and Chief Financial Officer
(iii) Principal accounting officer:
Jeffrey L. Boyer
Vice President and Corporate Controller
(iv) A majority of the Directors:
Richard B. Priory
Paul M. Anderson
G. Alex Bernhardt, Sr.
Robert J. Brown
William A. Coley
William T. Esrey
Ann Maynard Gray
Dennis R. Hendrix
George Dean Johnson, Jr.
Max Lennon
Leo E. Linbeck, Jr.
James G. Martin
Buck Mickel
Russell M. Robinson, II
Date: March 27, 1998
Richard J. Osborne, 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/ RICHARD J. OSBORNE
------------------------------------
Richard J. Osborne
Attorney-In-Fact
63
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 -- 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)).
3-A -- 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-B -- By-Laws of registrant, as amended (filed with Form S-8, No. 333-34655, effective August 29, 1997, as
Exhibit 4(D)).
4-B-1 -- First and Refunding Mortgage from registrant to Guaranty Trust Company of New York, Trustee, dated as of
December 1, 1927 (filed with Form S-1, File No. 2-7224, effective October 15, 1947, as Exhibit 7(a)).
4-B-2 -- Supplemental Indenture, dated as of March 12, 1930, supplementing said Mortgage (filed with Form S-1,
File No. 2-7224, effective October 15, 1947, as Exhibit 7(b)).
4-B-5 -- Supplemental Indenture, dated as of September 1, 1936, supplementing said Mortgage (filed with Form S-1,
File No. 2-7224, effective October 15, 1947, as Exhibit 7(e)).
4-B-6 -- Supplemental Indenture, dated as of January 1, 1941, supplementing said Mortgage (filed with Form S-1,
File No. 2-7224, effective October 15, 1947, as Exhibit 7(f)).
4-B-7 -- Supplemental Indenture, dated as of April 1, 1944, supplementing said Mortgage (filed with Form S-1, File
No. 2-7224, effective October 15, 1947, as Exhibit 7(g)).
4-B-8 -- Supplemental Indenture, dated as of September 1, 1947, supplementing said Mortgage (filed with Form S-1,
File No. 2-7224, effective October 15, 1947, as Exhibit 7(h)).
4-B-9 -- Supplemental Indenture, dated as of September 8, 1947, supplementing said Mortgage (filed with Form S-1,
File No. 2-10401, effective August 21, 1953, as Exhibit 4-B-9).
4-B-10 -- Supplemental Indenture, dated as of February 1, 1949, supplementing said Mortgage (filed with Form S-1,
File No. 2-7808, effective February 3, 1949, as Exhibit 7(j)).
4-B-11 -- Supplemental Indenture, dated as of March 1, 1949, supplementing said Mortgage (filed with Form S-1, File
No. 2-8877, effective April 6, 1951, as Exhibit 7(k)).
4-B-14 -- Supplemental Indenture, dated as of October 1, 1954, supplementing said Mortgage (filed with Form S-9,
File No. 2-11297, effective December 30, 1954, as Exhibit 2-B-14).
4-B-17 -- Supplemental Indenture, dated as of January 1, 1960, supplementing said Mortgage (filed with Form 10,
effective June 29, 1961, as Exhibit 3-B-18).
4-B-18 -- Supplemental Indenture, dated as of February 1, 1960, supplementing said Mortgage (filed with Form 10,
effective June 29, 1961, as Exhibit 3-B-19).
4-B-21 -- Supplemental Indenture, dated as of June 15, 1964, supplementing said Mortgage (filed with Form S-1, File
No. 2-25367, effective August 3, 1966, as Exhibit 4-B-20).
4-B-24 -- Supplemental Indenture, dated as of February 1, 1968, supplementing said Mortgage (filed with Form S-9,
File No. 2-31304, effective January 21, 1969, as Exhibit 2-B-26).
4-B-48 -- Supplemental Indenture, dated as of September 1, 1983, supplementing said Mortgage (filed with Form S-3,
File No. 2-95931, effective April 1, 1985, as Exhibit 4-B-48).
4-B-49 -- Supplemental Indenture, dated as of September 1, 1984, supplementing said Mortgage (filed with Form S-3,
File No. 2-95931, effective April 1, 1985, as Exhibit 4-B-49).
4-B-56 -- Supplemental Indenture, dated as of February 15, 1987, supplementing said Mortgage (filed with Form 10-K
for the year ended December 31, 1986, File No. 1-4928, as Exhibit 4-B-56).
4-B-58 -- Supplemental Indenture, dated as of October 1, 1987, supplementing said Mortgage (filed with Form 10-K
for the year ended December 31, 1987, File No. 1-4928, as Exhibit 4-B-58).
4-B-60 -- Supplemental Indenture, dated as of March 1, 1990, supplementing said Mortgage (filed with Form 10-K for
the year ended December 31, 1990, File No. 1-4928, as Exhibit 4-B-60).
4-B-62 -- Supplemental Indenture, dated as of May 15, 1990, supplementing said Mortgage (filed with Form 10-K for
the year ended December 31, 1990, File No. 1-4928, as Exhibit 4-B-62).
4-B-64 -- Supplemental Indenture, dated as of July 1, 1991, supplementing said Mortgage (filed with Form S-3, File
No. 33-45501, effective February 13, 1992, as Exhibit 4-B-64).
4-B-67 -- Supplemental Indenture, dated as of June 1, 1992, supplementing said Mortgage (filed with Form S-3, File
No. 33-50592, effective August 11, 1992, as Exhibit 4-B-67).
64
Exhibit
Number
- --------
4-B-68 -- Supplemental Indenture, dated as of July 1, 1992, supplementing said Mortgage (filed with Form S-3, File
No. 33-50592, effective August 11, 1992, as Exhibit 4-B-68).
4-B-69 -- Supplemental Indenture, dated as of September 1, 1992, supplementing said Mortgage (filed with Form S-3,
File No. 33-53308, effective November 24, 1992, as Exhibit 4-B-69).
4-B-70 -- Supplemental Indenture, dated as of February 1, 1993, supplementing said Mortgage (filed with Form 10-K
for the year ended December 31, 1992, File No. 1-4928, as Exhibit 4-B-70).
4-B-71 -- Supplemental Indenture, dated as of March 1, 1993, supplementing said Mortgage (filed with Form S-3, File
No. 33-59448, effective March 17, 1993, as Exhibit 4-B-71).
4-B-72 -- Supplemental Indenture, dated as of April 1, 1993, supplementing said Mortgage (filed with Form S-3, File
No. 33-50543, effective October 20, 1993, as Exhibit 4-B-72).
4-B-73 -- Supplemental Indenture, dated as of May 1, 1993, supplementing said Mortgage (filed with Form S-3, File
No. 33-50543, effective October 20, 1993, as Exhibit 4-B-73).
4-B-74 -- Supplemental Indenture, dated as of June 1, 1993, supplementing said Mortgage (filed with Form S-3, File
No. 33-50543, effective October 20, 1993, as Exhibit 4-B-74).
4-B-75 -- Supplemental Indenture, dated as of July 1, 1993, supplementing said Mortgage (filed with Form S-3, File
No. 33-50543, effective October 20, 1993, as Exhibit 4-B-75).
4-B-76 -- Supplemental Indenture, dated as of August 1, 1993, supplementing said Mortgage (filed with Form S-3, File
No. 33-50543, effective October 20, 1993, as Exhibit 4-B-76).
4-B-77 -- Supplemental Indenture, dated as of August 20, 1993, supplementing said Mortgage (filed with Form S-3,
File No. 33-50543, effective October 20, 1993, as Exhibit 4-B-77).
4-B-78 -- Supplemental Indenture, dated as of May 1, 1994, supplementing said Mortgage (filed with Form 10-K for
the year ended December 31, 1994, File No. 1-4928, as Exhibit 4-B-78).
4-B-79 -- Supplemental Indenture, dated as of November 1, 1994, supplementing said Mortgage (filed with Form 10-K
for the year ended December 31, 1994, File No. 1-4928, as Exhibit 4-B-79).
4-B-80 -- Supplemental Indenture, dated as of August 1, 1995, supplementing said Mortgage (filed with Form 10-K for
the year ended December 31, 1995, File No. 1-4928, as Exhibit 4-B-80).
4-C -- Instrument of Resignation, Appointment and Acceptance among Duke Power Company, Morgan Guaranty
Trust Company of New York, as Trustee, and Chemical Bank, as Successor Trustee, dated as of August 30,
1994 (filed with Form 10-K for the year ended December 31, 1994, File No. 1-4928, as Exhibit 4-C).
10-A -- 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-B -- 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-C -- 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-D -- 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-E** -- Employee Incentive Plan (filed with Form 10-K for the year ended December 31, 1993, File No. 1-4928, as
Exhibit 10-F).
10-F** -- 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-G** -- Estate Conservation Plan (filed with Form 10-K for the year ended December 31, 1992, File No. 1-4928, as
Exhibit 10-R).
10-H** -- Supplemental Insurance Plan (filed with Form 10-K for the year ended December 31, 1992, File No. 1-4928,
as Exhibit 10-S).
10-I** -- Executive Short-Term Incentive Plan (filed with Form 10-K for the year ended December 31, 1994, File No.
1-4928, as Exhibit 10-V).
10-J** -- Executive Savings Plan (filed with Form 10-K for the year ended December 31, 1996, File No. 1-4928, as
Exhibit 10-Z).
10-K** -- Executive Cash Balance Plan (filed with Form 10-K for the year ended December 31, 1996, File No. 1-4928,
as Exhibit 10-AA).
10-L** -- Directors' Savings Plan (filed with Form 10-K for the year ended December 31, 1996, File No. 1-4928, as
Exhibit 10-BB).
10-M** -- Duke Power Company Stock Incentive Plan (filed as Appendix A to Schedule 14A of registrant, March 18,
1996, File No. 1-4928).
10-N** -- 1989 Nonemployee Directors Stock Option Plan of Panhandle Eastern
Corporation, adopted February 1, 1989 (filed with Form S-8
Registration Statement of Panhandle Eastern Corporation File No.
33-28912, as Exhibit 28(a)).
65
Exhibit
Number
- --------
10-O** -- 1982 Key Employee Stock Option Plan of Panhandle Eastern Corporation, as amended through December 3,
1986 (and related Agreement) (filed with Form 10-K of Panhandle Eastern Corporation for the year ended
December 31, 1986, File No. 1-8157, as Exhibit 10(g)).
10-P** -- Employees Savings Plan of Panhandle Eastern Corporation and Participating Affiliates (filed with Form 10-K
of Panhandle Eastern Corporation for the year ended December 31, 1990, File No. 1-8157, as Exhibit 10.12).
10-Q** -- Panhandle Eastern Corporation 1994 Long Term Incentive Plan (filed with Form 10-K of Panhandle Eastern
Corporation for the year ended December 31, 1993, File No. 1-8157, as Exhibit 10.18).
*10-R -- $1,250,000,000 Five-Year Credit Agreement dated as of August 25, 1997, among registrant, the banks listed
therein and Morgan Guaranty Trust Company of New York, as Administrative Agent.
*10-S -- $950,000,000 Five-Year Credit Agreement dated as of August 25, 1997, among Duke Capital Corporation,
the banks listed therein and The Chase Manhattan Bank, as Administrative Agent.
*10-T -- $300,000,000 364-Day Credit Agreement dated as of August 25, 1997, among Duke Capital Corporation, the
banks listed therein and The Chase Manhattan Bank, as Administrative Agent.
10-U** -- Employment Agreement by and between the registrant and Richard B. Priory dated November 24, 1996
(incorporated by reference to Exhibit C-1 of Exhibit 2 to this Form 10-K), and the First Amendment thereto
dated October 22, 1997, filed herewith.
10-V** -- Employment Agreement by and among PanEnergy Corp, the registrant and Paul M. Anderson dated
November 24, 1996 (incorporated by reference to Exhibit B-1 of Exhibit 2 to this Form 10-K), and the First
Amendment thereto dated October 24, 1997, filed herewith.
10-W** --- Employment Agreement by and among PanEnergy Corp, the registrant and James T. Hackett dated
November 24, 1996 (incorporated by reference to Exhibit B-2 of Exhibit 2 to this Form 10-K), and the First
Amendment thereto dated October 24, 1997, filed herewith.
10-X** -- Employment Agreement by and between the registrant and William A. Coley dated November 24, 1996
(incorporated by reference to Exhibit C-2 of Exhibit 2 to this Form 10-K), and the First Amendment thereto
dated October 24, 1997, filed herewith.
10-Y** -- Employment Agreement by and between the registrant and Richard J. Osborne dated November 24, 1996
(incorporated by reference to Exhibit C-3 of Exhibit 2 to this Form 10-K), and the First Amendment thereto
dated October 27, 1997, filed herewith.
10-Z** -- 1990 Long-Term Incentive Plan of Panhandle Eastern Corporation (filed with Form 10-K of Panhandle Eastern
Corporation for the year ended December 31, 1990, File No. 1-8157, as Exhibit 10.14).
10-AA -- 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).
*12 -- Computation of Ratio of Earnings to Fixed Charges.
*21 -- List of Subsidiaries.
*23(a) -- Consent of Deloitte & Touche LLP.
*23(b) -- Consent of KPMG Peat Marwick LLP.
*24(a) -- Power of attorney authorizing Richard J. Osborne 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.
*27 -- Financial Data Schedule.
*99 -- Independent Auditors' Report of KPMG Peat Marwick LLP to the Board of Directors of PanEnergy Corp,
dated January 16, 1997.
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.
66