<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[x] ANNUAL REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION
13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
Commission File Number 1-4928
DUKE POWER COMPANY
(Exact name of registrant as specified in its charter)
<TABLE>
<S> <C>
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 28242-0001
(Address of principal executive offices) (Zip Code)
</TABLE>
704-594-0887
(Registrant's Telephone Number, Including Area Code)
Securities Registered Pursuant To Section 12(b) Of The Act:
<TABLE>
<CAPTION>
Title Of Each Class Name Of Each Exchange
On Which Registered
<S> <C>
Common Stock, without par value New York Stock Exchange, Inc.
Preferred Stock A, par value $25
7.72%, 1992 Series New York Stock Exchange, Inc.
6.375%, 1993 Series New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 5-3/8% Due 1997 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, 7-7/8% Due 2024 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 8% Series B Due 1999 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 8% Due 2004 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 8-3/8% Series B Due 2021 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 8-5/8% Due 2022 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 8-3/4% Due 2021 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 7-1/2% Series B Due 2025 New York Stock Exchange, Inc.
</TABLE>
Securities Registered Pursuant To Section 12(g) Of The Act:
Title Of Class
Preferred Stock, par value $100
<PAGE>
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months and (2) has been subject to such filing
requirements for the past 90 days. Yes (x) No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. (x)
Estimated aggregate market value of the voting stock held by nonaffiliates of
the registrant at
<TABLE>
<S> <C>
March 8, 1996............................................................................. $9,850,948,807
Number of shares of Common Stock, without par value, outstanding at March 8, 1996.............. 204,859,339
</TABLE>
Documents Incorporated By Reference:
The registrant is incorporating herein by reference certain sections of its
proxy statement relating to the 1996 annual meeting of shareholders to provide
information required by the following parts of this annual report:
Part III -- Item 10., Directors and Executive Officers of the Registrant
-- Item 11., Executive Compensation
-- Item 12., Security Ownership of Certain Beneficial
Owners and Management
-- Item 13., Certain Relationships and Related Transactions
<PAGE>
DUKE POWER COMPANY
FORM 10-K
ANNUAL REPORT TO
THE SECURITIES AND EXCHANGE COMMISSION
FOR THE YEAR ENDED DECEMBER 31, 1995
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Item Page
<S> <C>
PART I.
1 Business. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Executive Officers of the Company. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2 Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3 Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4 Submission of Matters to a Vote of Security Holders. . . . . . . . . . . . . . . . . . . . . . . . . . .
PART II.
5 Market for the Registrant's Common Equity and Related Stockholder Matters. . . . . . . . . . . . . . . .
6 Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7 Management's Discussion and Analysis of Results of Operations and Financial Condition. . . . . .
8 Financial Statements and Supplementary Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. . . . . . . . . . .
PART III.
10 Directors and Executive Officers of the Registrant. . . . . . . . . . . . . . . . . . . . . . . . . . .
11 Executive Compensation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12 Security Ownership of Certain Beneficial Owners and Management. . . . . . . . . . . . . . . . . . . . .
13 Certain Relationships and Related Transactions. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART IV.
14 Exhibits, Consolidated Financial Statement Schedules, and Reports on Form 8-K. . . . . . . . . . . . .
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exhibit Index. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
</TABLE>
<PAGE>
DUKE POWER COMPANY
PART I.
Item 1. Business.
Duke Power Company (the Company) is primarily engaged in the
generation, transmission, distribution and sale of electric energy in the
central portion of North Carolina and the western portion of South Carolina,
comprising the area in both states known as the Piedmont Carolinas. It is one of
the nation's largest investor-owned electric utilities.
The Company is also engaged in a variety of diversified operations,
most of which are organized in separate subsidiaries. The Company's subsidiaries
and diversified activities are in the Associated Enterprises Group (AEG). AEG
includes Church Street Capital Corp.; Crescent Resources, Inc.; Duke Energy
Group, Inc.; Duke Engineering & Services, Inc.; Duke/Fluor Daniel; Duke
Merchandising; DukeNet Communications, Inc.; Duke Water Operations; and
Nantahala Power and Light Company (NP&L). For additional information on
subsidiaries and diversified activities, see "Subsidiaries and Diversified
Activities", "Management's Discussion and Analysis of Results of
Operations and Financial Condition, Current Issues -- Subsidiaries and
Diversified Operations" and "Subsidiaries and Diversified Activities
Highlights".
During 1995, the Company's operating revenues, including AEG, were $4.7
billion. The Company's executive offices are located in the Power Building, 422
South Church Street, Charlotte, North Carolina 28242-0001 (Telephone No.
704-594-0887).
Service Area
The Company's service area (excluding NP&L), approximately two-thirds
of which lies in North Carolina, covers about 20,000 square miles with an
estimated population of 5.0 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. The Company supplies
electric service directly to approximately 1.8 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 former wholesale municipal or cooperative customers of
the Company who had purchased portions of the Catawba Nuclear Station
(collectively, the "other Catawba joint owners") (See "Joint Ownership of
Generating Facilities.") NP&L services an additional 53,000 mostly residential
customers in five counties in western North Carolina.
The Company's 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 $494 million of the
Company's revenues for 1995, representing 11 percent of electric revenues and 39
percent of industrial revenues.
<PAGE>
Energy Requirements And Capability
The following table sets forth the Company's generating capability as
of December 31, 1995, its sources of electric energy for 1995 and certain
information presently projected for 1996:
<TABLE>
<CAPTION>
Source Generating Capability Generation MWH
MW(a)(b)(c) (thousands)(c)
Actual Projected Actual
December 31, 1995 December 31, 1996 1995
<S> <C> <C> <C>
Coal. . . . . . . . . . . . . . . . . . . . . . 7,699 7,699 32,389
Nuclear (d) . . . . . . . . . . . . . . . . . . 5,078 5,078 39,836
Hydro and other. . . . . . . . . . . . . . . . . 4,166 4,466(e) 1,940
Total . . . . . . . . . . . . . . . . . . . . . 16,943 17,243 74,165
Plus: Purchases from other Catawba joint owners . 6,070
Purchased power and net interchange . . . . . 1,175
Total . . . . . . . . . . . . . . . . . . 81,410
</TABLE>
(a) The data relating to capability does not reflect the possible
unavailability or reduction of capability of facilities at any given
time because of scheduled maintenance, repair requirements or
regulatory restrictions.
(b) Excludes firm purchases and sales. (See "Energy Management and Future
Power Needs.")
(c) Excludes NP&L.
(d) Nuclear capability and related generation for 1995 and related
projections for 1996 reflect the Company's 12.5% ownership share of
the Catawba Nuclear Station. (See "Joint Ownership of Generating
Facilities".)
(e) Includes four units of the Lincoln Combustion Turbine Station with
generating capacity of 300 MW which were placed into commercial
operation in early 1996. (See "Capital Requirements.")
NP&L operates 11 hydroelectric stations with a total capacity of 100
megawatts and also purchases supplemental power. The Company supplies
supplemental power to NP&L under the terms of an interconnection agreement
approved by the Federal Energy Regulatory Commission (FERC).
The Company has a bulk power sales agreement with Carolina Power &
Light Company (CP&L) to provide CP&L 400 megawatts of capacity as well as
associated energy when needed for a six-year period which began July 1, 1993.
Electric rates in all regulatory jurisdictions were reduced by adjustment riders
to reflect capacity revenues received from this CP&L bulk power agreement.
According to 1994 industry statistics published in 1996, the Company
ranked first in the nation in terms of efficiency of its steam-fossil generating
system as measured by the conversion of fuel energy to electric energy.
Published rankings indicate that individual units at Marshall Steam Station and
Belews Creek Steam Station ranked first, third, fourth, fifth, eighth and tenth
most efficient in the nation in 1994. The Company's nuclear system continued its
tradition of operating efficiency, operating at 90 percent of capacity for 1995,
in comparison with the industry's latest available average capacity factor of 74
percent for 1994. The Company's system nuclear capacity factor reflects the
Company's 12.5% ownership share of the Catawba Nuclear Station.
The Company normally experiences seasonal peak loads in summer and
winter which are relatively in balance. The Company currently forecasts a 1.8
percent compound annual growth in peak load through 2010. An all-time peak load
of 15,542 MW occurred on August 14, 1995 during exceptionally warm summer
weather. This peak load excludes the portion of the demand of the other joint
owners of the Catawba Nuclear Station met by their retained ownership.
<PAGE>
Rate Matters
The North Carolina Utilities Commission (NCUC) and the Public Service
Commission of South Carolina (PSCSC) must approve the Company's rates for retail
sales within their respective states. The FERC must approve the Company's rates
for sales to wholesale customers, including the contractual arrangements between
the Company and the other Catawba joint owners.
The most recent general rate increase requests in the Company's retail
jurisdictions were filed and approved in 1991. The Company also filed its most
recent general rate increase request within the FERC wholesale jurisdiction in
1991. A negotiated settlement between the Company and the wholesale customers
was approved by the FERC in 1992.
In its most recent general rate case, the NCUC authorized a
jurisdictional rate of return on common equity of 12.50 percent, and the PSCSC
authorized a jurisdictional rate of return on common equity of 12.25 percent.
During 1992, NP&L filed an application for a general rate increase with
the NCUC. A general rate increase was approved in June 1993.
Fuel And Purchased Power Cost Adjustment Procedures. Duke Power has
procedures in all three of its regulatory jurisdictions to adjust rates for
fluctuations in fuel expense. The North Carolina legislature enacted a statute
in 1987 assuring the legality of adjustments of past over- and under-recovery of
fuel costs in rates. The North Carolina legislature repealed the expiration
provision of this statute in March 1995. In the North Carolina retail
jurisdiction, a review of fuel costs in rates is required annually and during
general rate case proceedings. Fuel costs are reviewed semiannually in the
wholesale and South Carolina retail jurisdictions. All jurisdictions allow Duke
Power to adjust rates for past over- or under-recovery of fuel costs. Therefore,
Duke Power reflects in revenues the difference between actual fuel costs
incurred and fuel costs recovered through rates.
Purchased power costs of NP&L are reviewed annually and during general
rate case proceedings by the NCUC. NP&L is allowed to adjust rates for past
over- or under-recovery of purchased power costs. Therefore, NP&L defers the
difference between actual purchased power costs incurred and those recovered
through rates.
Construction Work In Progress (CWIP). The NCUC is permitted in its
discretion to include CWIP in rate base after giving consideration to the public
interest and the Company's financial stability. The PSCSC may include CWIP in
rate base in its discretion.
Energy Management And Future Power Needs
The Company's strategy for meeting customers' present and future energy
needs is composed of three components: demand-side resources, purchased power
resources and supply-side resources. By utilizing these resources, the Company
expects to maintain a reserve margin of approximately 18 to 20 percent of its
anticipated peak load requirements through 2000. The Company continues to engage
in a comprehensive energy management program as part of its Integrated Resource
Plan (IRP). Integrated resource planning is the process used by utilities to
evaluate a variety of resources. The goal is to provide adequate and reliable
electricity in an environmentally responsible manner through cost-effective
power management. The Company files an IRP with the NCUC and the PSCSC once
every three years. During each of the intervening years, the Company files a
Short Term Action Plan which updates the IRP for any changes in projections for
the next three years. The PSCSC issued an order on December 14, 1995 approving
the Company's 1995 IRP. On February 20, 1996, the NCUC issued a similar order.
Demand-side management (DSM) programs benefit the Company and its
customers by promoting energy efficiency, providing for load control through
interruptible control features, shifting usage to off-peak periods and
increasing strategic sales of electricity. In return for participation in
demand-side management programs, customers may be eligible to receive various
incentives which help reduce their net investment in high-efficiency equipment
or their electric bills. The November 1991 rate orders of the NCUC and the PSCSC
provided for recovery in rates of a designated level of costs for DSM programs
and allowed the deferral for later recovery of certain DSM costs that exceed the
level reflected in rates, including a return on deferred costs. In 1993, the
NCUC and the PSCSC issued orders approving "shared savings" mechanisms for
accomplishments achieved in the Company's DSM programs,
<PAGE>
and deferral of such shared savings. The Company ultimately expects recovery
through rates of associated deferred costs, not to exceed $75 million including
deferred returns in the North Carolina retail jurisdiction. The annual costs
deferred, including the return, were approximately $27 million in 1995 and $25
million in 1994. The total costs deferred, including the return, are $58 million
and $38 million in North Carolina and South Carolina, respectively.
The purchase of capacity and energy is an integral part of meeting
future power needs. As of December 31, 1995, the Company had under contract 300
MW of capacity from other generators of electricity, including 62 MW from
qualifying facilities. In 1995, the Company issued two requests for proposals
(RFP) to solicit competitive bids for its future electric generating capacity
resources. The short-term RFP could provide options for up to 675 megawatts of
capacity with terms of 1 to 4 years. The long-term RFP solicits bids to provide
up to 300 megawatts of purchased power to be available beginning in 1998 or
1999, for contract periods of between 5 and 20 years in duration. The Company
has evaluated a total of 16 proposals received for both the short-term RFP and
the long-term RFP and has begun negotiation with the bidders with the best
proposals. Contracts are expected to be awarded in May 1996.
Capital Requirements
Projected capital expenditures, excluding costs related to portions of
the Catawba Nuclear Station owned by the other Catawba joint owners, for the
years set forth below, as now scheduled, are as follows (in millions):
<TABLE>
<CAPTION>
1996 1997 1998 1999 2000 Total
<S> <C> <C> <C> <C> <C> <C>
Duke Power - Electric
Generation. . . . . . . . . . . . . $ 193 $ 210 $ 124 $ 115 $ 132 $ 774
Transmission. . . . . . . . . . . . 40 41 42 42 42 207
Distribution. . . . . . . . . . . . 199 198 199 200 201 997
Other. . . . . . . . . . . . . . . . 72 64 65 60 60 321
Nuclear Fuel. . . . . . . . . . . . 120 136 116 164 125 661
Total Duke Power - Electric. . . 624 649 546 581 560 2,960
Associated Enterprises Group. . . . . 226 194 178 206 219 1,023
Total Company. . . . . . . . . . . . . $ 850 $ 843 $ 724 $ 787 $ 779 $ 3,983
</TABLE>
The Company's procedures for estimating capital expenditures for Duke
Power - Electric (which include allowance for funds used during construction)
utilize, among other things, past construction experience, current construction
costs, allowances for inflation and the Company's business plan. These
projections are subject to periodic review and revisions. Actual construction
and nuclear fuel costs and capital expenditures incurred may vary from such
estimates. Cost variances for Duke Power - Electric are due to various factors,
including revised load estimates, environmental matters and cost and
availability of capital. Projections of the AEG capital expenditures are subject
to periodic review and revision and may vary significantly as the business plans
of AEG evolve to meet the opportunity presented by its markets.
The Company has substantially completed construction of a combustion
turbine facility in Lincoln County, North Carolina to provide capacity at
periods of peak demand. The Lincoln Combustion Turbine Station consists of
16 combustion turbines with a total generating capacity of 1,200 megawatts. The
estimated total cost of the project is approximately $400 million. Twelve of
the 16 units were placed into commercial operation in 1995, and as of March 1,
1996, the final four units were placed into commercial operation. During
1991, the NCUC granted the Certificate of Public Convenience and Necessity and
the North Carolina Division of Environmental Management issued a final air
permit for the facility. All appeals related to the issuance of the final air
permit were resolved in 1995.
Joint Ownership Of Generating Facilities
In order to reduce its need for external financing, the Company,
through several transactions beginning in 1978, sold an 87 1/2 percent undivided
interest in the Catawba Nuclear Station to the other Catawba joint owners.
<PAGE>
These transactions contemplate that the Company will operate the
facility, interconnect its transmission system, wheel a certain portion of the
capacity and energy of such facility to the respective participants, provide
back-up services for such capacity, buy for its own use (whether or not the
facility is generating electricity) that portion of the capacity not then
contractually required by the respective participants, and provide supplemental
power as required by the purchasers to enable them to provide service on a firm
basis. The transactions also include a reliability exchange between the Catawba
Nuclear Station and the McGuire Nuclear Station of the Company, which provides
for an exchange of 50 percent of each other Catawba joint owner's retained
capacity from its ownership interest in the Catawba units for like amounts of
capability and output from units of the McGuire Nuclear Station. The
implementation of the reliability exchange has not had, nor does the Company
anticipate that such implementation will have, a material effect on earnings.
(See Note 3, "Notes to Consolidated Financial Statements.")
The Company and North Carolina Municipal Power Agency Number 1 (NCMPA)
and Piedmont Municipal Power Agency (PMPA), two of the four other joint owners
of the Catawba Nuclear Station, entered into a settlement in September 1995
which resolved outstanding issues related to how certain calculations affecting
bills under the Catawba joint ownership contractual agreements should be
performed. The settlement was approved by the NCUC on January 16, 1996 and the
PSCSC on January 23, 1996. As part of the settlement, the Company agreed to
purchase additional megawatts (MW) of Catawba capacity during the period 1996
through 1999 and remove certain restrictions related to sales of surplus energy
by these two joint owners. The additional capacity purchases are 215 MW in 1996,
165 MW in 1997, 120 MW in 1998 and 100 MW in 1999. The Company expects to
recover the costs associated with this settlement as part of the purchased
capacity levelization, consistent with prior orders of the retail regulatory
commissions. Therefore, the Company believes these matters should not have a
material adverse effect on the results of operations or financial position of
the Company.
The Company and all four of the other joint owners of the Catawba
Nuclear Station entered into settlement agreements in 1994 which resolved all
issues in contention in arbitration proceedings related to the Catawba joint
ownership contractual agreements. The basic contention in each proceeding was
that certain calculations affecting bills under these agreements should be
performed differently. These items are covered by the agreements between the
Company and the other Catawba joint owners which have been previously approved
by the Company's retail regulatory commissions. (For additional information on
Catawba joint ownership, see Note 3, "Notes to Consolidated Financial
Statements.") In 1994, the Company settled its cumulative net obligation through
1993 of approximately $205 million related to these settlement agreements.
Billings for 1994 and later years will conform to the settlement agreements,
which have been approved by the Company's retail regulatory commissions. Because
the Company expects the costs associated with these settlements to be recovered
as part of the purchased capacity levelization, which has been approved by the
Company's retail regulatory commissions, the Company included approximately $205
million as an increase to "Purchased capacity costs" on its Consolidated Balance
Sheets in 1994. Therefore, the Company believes these matters should not have a
material adverse effect on the results of operations or financial position of
the Company.
Fuel Supply
The Company presently relies principally on nuclear fuel and coal for
the generation of electric energy. The Company's reliance on oil and gas is
minimal and will remain minimal even with the addition of the Lincoln Combustion
Turbine Station, which is designed to operate on either natural gas or oil.
<PAGE>
Information regarding the utilization of sources of power and cost of
fuels is set forth in the following table:
<TABLE>
<CAPTION>
Generation by Source Cost of Fuel per Net KWH Generated
(Cents)
Year Ended December 31 Year Ended December 31
1995 1994 1993 1995 1994 1993
<S> <C> <C> <C> <C> <C> <C>
Coal. . . . . . . . . . . . . . . . . . . . . . . . . 43.7% 46.9% 48.6% 1.56 1.54 1.61
Nuclear (1) . . . . . . . . . . . . . . . . . . . . . 53.7% 51.0% 49.1% 0.57 0.56 0.53
Oil and gas . . . . . . . . . . . . . . . . . . . . . -- -- -- -- -- --
All Fuels (cost based on weighted average) (1) . . 97.4% 97.9% 97.7% 1.03 1.03 1.07
Hydroelectric (2) . . . . . . . . . . . . . . . . . . 2.6% 2.1% 2.3%
100.0% 100.0% 100.0%
</TABLE>
(1) Statistics related to nuclear generation and all fuels reflect the
Company's 12.5% ownership in the Catawba Nuclear Station.
(2) Generating figures are net of that output required to replenish pumped
storage units during off-peak periods and do not include NP&L.
Coal. The Company obtains a large amount of its coal under long-term
supply contracts with mining operators utilizing both underground and surface
mining. The Company has on hand an adequate supply of coal. The Company's
long-term supply contracts, all of which have price adjustment provisions, have
expiration dates ranging from 1996 to 2003. The Company 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 quantities and qualities of coal
required. The coal covered by the Company's long-term supply contracts is
produced from mines located in eastern Kentucky, southern West Virginia and
southwestern Virginia. The Company's requirements not met by long-term supply
contracts have been and will be fulfilled with spot market purchases. The
average sulfur content of coal being purchased by the Company is approximately 1
percent. Such coal satisfies the current emission limitation for sulfur dioxide
for existing facilities. (See "Management's Discussion and Analysis of Results
of Operations and Financial Condition, Current Issues -- The Clean Air Act
Amendments of 1990.")
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. The Company 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 the Company's
requirements through the following years:
<TABLE>
<CAPTION>
Uranium Conversion Enrichment Fabrication
Nuclear Station Material Service Service Service
<S> <C> <C> <C> <C>
Oconee . . . . . . . . . . . . . . . . . . 1997 1998 2000 2006
McGuire . . . . . . . . . . . . . . . . . 1997 1998 2000 2009
Catawba . . . . . . . . . . . . . . . . . 1997 1998 2000 2009
</TABLE>
Uranium material requirements will be met through various supplier
contracts, with uranium material produced primarily in the U.S. and Canada. The
Company believes that it will be able to renew contracts as they expire or to
enter into similar contractual arrangements with other nuclear fuel materials
and services suppliers. Requirements not met by long-term supply contracts have
been and will be fulfilled with uranium spot market purchases.
The Department of Energy (DOE) recently requested Expressions of
Interest (EOI) to facilitate in the disposal of plutonium. The Company and
Commonwealth Edison, along with the other joint owners of the Catawba
<PAGE>
Nuclear Station, responded to the EOI in early 1996. As this project is in its
early developmental stage, management cannot predict the outcome of this
process. However, the Company believes these matters should not have a material
effect on the results of operations or financial position of the Company.
The Nuclear Waste Policy Act of 1982 requires that the DOE begin
disposing of spent fuel no later than January 31, 1998. The Company has entered
into the required contracts with the DOE for the disposal of nuclear fuel and
began making payments in July 1983 for disposal costs of fuel currently being
utilized. These payments, combined with a one-time payment for disposal costs of
fuel consumed prior to April 7, 1983, have totaled about $510 million through
1995 related to the Company's ownership interest in nuclear plants. In December
1995, the DOE released a report which indicated that it expects a facility for
spent fuel disposal will not be available until the year 2015. The DOE continues
to pursue a centralized interim storage facility, with a target operation date
of 1998, for earlier acceptance of spent fuel from utilities. The Company
believes that it will be able to provide adequate on-system storage capacity
until such time as the DOE begins receiving spent fuel.
Regulation
The Company is subject to the jurisdiction of the NCUC and the PSCSC
which, among other things, must approve the issuance of securities. The Company
also is subject, as to some phases of its business, to the jurisdiction of the
FERC, the Environmental Protection Agency (EPA) and state environmental agencies
and to the jurisdiction of the Nuclear Regulatory Commission (NRC) as to design,
construction and operation of its nuclear power facilities. The Company is
exempt from regulation as a holding company under the Public Utility Holding
Company Act of 1935, except with respect to the acquisition of the securities of
other public utilities.
Environmental Matters. The Company is subject to federal, state, and
local regulations with regard to air and water quality, hazardous and solid
waste disposal, and other environmental matters. North Carolina has enacted a
declaration of environmental policy requiring all state agencies to administer
their responsibilities in accordance with such policy. The NCUC has adopted
rules requiring consideration of environmental effects in determining whether
certificates of public convenience and necessity will be granted for proposed
generation facilities. South Carolina law also requires consideration by the
PSCSC of environmental effects in determining whether certificates of public
convenience and necessity will be granted for proposed major utility facilities,
which include certain generation and transmission facilities. All of the
Company's facilities which are currently under construction have been designed
to comply with presently applicable environmental regulations. Such compliance
has, however, increased the cost of electric service by requiring changes in the
design and operation of existing facilities, as well as changes or delays in the
design, construction and operation of new facilities. In 1995, the Company's
construction costs for environmental protection totaled approximately $52
million, while the on-going environmental operation costs were approximately $25
million. The Company's 1996-2000 construction program includes costs for
environmental protection which are estimated to be approximately $40 million,
including $9.8 million in 1996, $4.1 million in 1997, $7.4 million in 1998, $9.7
million in 1999 and $9.4 million in 2000. These costs include expenditures
associated with the Clean Air Act Amendments of 1990. However, governmental
regulations establishing environmental protection standards are continually
evolving and have not, in some cases, been fully established. These projections
are subject to periodic review and revisions. Actual construction costs and
capital expenditures incurred may vary from such estimates. Cost variances are
due to various factors, including cost and availability of capital.
AIR QUALITY. See "Management's Discussion and Analysis of Results of
Operations and Financial Condition, Current Issues -- The Clean Air Act
Amendments of 1990" for a discussion of the Company's plans for compliance with
federal clean air standards.
WATER QUALITY. The Federal Water Pollution Control Act Amendments of
1987 (referred to herein as the "Clean Water Act") require permits for
facilities that discharge into waters. The Company holds numerous such permits,
which are issued periodically. The issuance of such permits is delegated by the
EPA to state agencies in North and South Carolina. The Clean Water Act has been
scheduled for review and reauthorization by Congress since 1994, but no
legislation has been enacted. Until Congress acts upon the reauthorization,
management will be unable to assess what effect, if any, such reauthorization
will have on the Company's operations.
OTHER ENVIRONMENTAL REGULATIONS. Contingencies associated with
environmental matters are principally related to possible obligations to remove
or mitigate the effects on the environment resulting from the disposal of
certain substances at contamination sites.
<PAGE>
The Comprehensive Environmental Response, Compensation and Liability
Act (CERCLA), commonly known as "Superfund", requires any individual or entity
which may have owned or operated a contaminated site, as well as transporters or
generators of hazardous wastes which were sent to such site, to assume joint and
several responsibility for remediation of the site. Such parties are known as
"potentially responsible parties" (PRPs). Some contamination sites are
remediated pursuant to state acts which are similar to CERCLA. The Company has
participated in site remediation activities in the past as a PRP at Superfund
sites or similar state sites in the Charlotte area, near Chester, S.C., and in
Pennsylvania and West Virginia. The Company's involvement in one Superfund site
and one state site was resolved in early 1996. The Company is currently
participating in PRP groups with regard to Superfund sites in Concord, North
Carolina and Lenoir, North Carolina. While the total cost of remediation at
these federal and state contamination sites may be substantial, the Company
shares probable liability with other PRPs, many of which have substantial
assets. Management is of the opinion that resolution of these matters will not
have a material adverse effect on the results of operations or financial
position of the Company.
Other contamination sites in which the Company is involved arise from
the operation of manufactured gas plant (MGP) sites, which were commonplace in
the Carolinas until the 1950s. Some such sites are still owned by the Company,
and others are now owned by third parties. In North Carolina, the Company is
participating in a state-sponsored program to investigate and, where
appropriate, remediate MGP sites. In South Carolina, the Company is in the
process of remediating an MGP site in Greenville. Management is of the opinion
that resolution of these matters will not have a material adverse effect on the
results of operations or financial position of the Company.
CERCLA has been scheduled for review and reauthorization by Congress
since 1994, but has not been examined outside of the legislative committee
structure. Until CERCLA reform occurs, management will be unable to assess what
effect, if any, such reauthorization will have on the Company's operations.
GENERAL. Over the past few decades, the issue of the possible health
effects of electric and magnetic fields has generated a number of generally
inconclusive studies, some public concern and litigation as well as legislative
action in some states regarding high voltage transmission lines. The impact of
this issue on the Company cannot presently be determined.
Nuclear Facilities. The Company's nuclear facilities are subject to
continuing regulation by the NRC.
Stress corrosion cracking (SCC) has occurred in the steam generators of
Units 1 and 2 at the McGuire Nuclear Station and Unit 1 at the Catawba Nuclear
Station. Catawba Unit 2, which has certain design differences and came into
service at a later date, has not yet shown the degree of SCC which has occurred
in McGuire Units 1 and 2 and Catawba Unit 1. It is, however, too early in the
life of Catawba Unit 2 to determine the extent to which SCC may be a problem.
Although the Company has taken steps to mitigate the effects of SCC, the
inherent potential for future SCC in the McGuire and Catawba steam generators
still exists. The Company is planning for the replacement of steam generators at
three units that have experienced SCC and has signed an agreement with Babcock &
Wilcox International to purchase replacement steam generators. The current
schedule for completion of the effort is as follows: Catawba Unit 1 -- 1996,
McGuire Unit 1 -- 1997 and McGuire Unit 2 -- 1997. The order of replacement is
subject to change based on operational and project circumstances. The Catawba
Unit 2 steam generators have not been scheduled for replacement. Steam generator
replacement at each unit is expected to take approximately four months and cost
approximately $170 million per unit, excluding the cost of replacement power and
the reimbursement of applicable costs by the other Catawba joint owners for
Catawba Unit 1. The $170 million per unit cost estimate includes the cost of
removal of steam generators being replaced. Stress corrosion problems are
excluded under the Company's nuclear insurance policies.
The Company, in connection with its McGuire and Catawba stations and on
behalf of the other joint owners, began a legal action in 1990, alleging that
Westinghouse Electric Corporation knowingly supplied to the McGuire and Catawba
Stations steam generators that were defective in design, workmanship and
materials, requiring replacement well short of their stated design life. The
lawsuit was settled in 1994. While the court order does not allow disclosure of
the terms of the settlement, the Company believes the litigation was settled on
terms that provided satisfactory consideration to the Company and will not have
a material effect on the results of operations or financial position of the
Company.
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
<PAGE>
stated in 1994 dollars based on decommissioning studies completed in 1994. This
amount includes the Company's 12.5 percent ownership in the Catawba Nuclear
Station. The other joint owners of the Catawba Nuclear Station are responsible
for decommissioning costs related to their ownership interests in the station.
Both the NCUC and the PSCSC have granted the Company recovery of the estimated
decommissioning costs through retail rates over the expected remaining service
periods of the Company's nuclear plants. Such estimates presume that units will
be decommissioned as soon as possible following the end of their license life.
Although subject to extension, the current operating licenses for the Company'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.
The NRC issued a rulemaking in 1988 which requires an external
mechanism to fund the estimated cost to decommission certain components of a
nuclear unit subject to radioactive contamination. In addition to the required
external funding, the Company maintains an internal reserve to provide for
decommissioning costs of plant components not subject to radioactive
contamination. During 1995, the Company expensed approximately $56 million,
which was contributed to the external funds and accrued an additional $1 million
to the internal reserve. The balance of the external funds as of December 31,
1995, was $273 million. The balance of the internal reserve as of December 31,
1995, was $206 million and is reflected in accumulated depreciation and
amortization on 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 percent 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 DOE's uranium enrichment plants.
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 expense. The Company paid approximately $9.2 million during 1995 and $35.6
million cumulatively related to its ownership interest in nuclear plants. The
Company has reflected the remaining liability and regulatory asset of
approximately $101 million in the Consolidated Balance Sheets at December 31,
1995.
Nuclear Insurance. For a discussion of the Company's nuclear insurance
coverage, see "Note 13, Notes to Consolidated Financial Statements, Commitments
and Contingencies -- Nuclear Insurance."
Hydroelectric Licenses. The principal hydroelectric projects of the
Company are licensed by FERC under Part I of the Federal Power Act. Eleven
developments on the Catawba-Wateree River in North Carolina and South Carolina,
with a nameplate rating of approximately 805 MW, are licensed for a term
expiring in 2008. The Company also holds a license for the Keowee-Toxaway
Project for a term expiring in 2016, covering the Keowee Hydro Station and the
Jocassee Pumped Storage Station for a combined total of approximately 770 MW, on
the upper tributaries of the Savannah River in northwestern South Carolina.
Additionally, the Company is the licensee through 2027 for the Bad Creek
Hydroelectric Station which uses Lake Jocassee as its lower reservoir and has a
nameplate rating of 1,065 MW. NP&L holds licenses for 11 hydroelectric projects
with a nameplate rating of 100 MW with license terms expiring 2001-2006. The
Federal Power Act provides, among other things, that, upon the expiration of any
license issued thereunder, the United States may (a) grant a new license to the
licensee for the project, (b) take over the project upon payment to the licensee
of its "net investment" in the project (but not in excess of the fair value
thereof) plus severance damages, or (c) grant a license for the project to a new
licensee subject to payment to the former licensee of the amount specified in
(b) above.
Interconnections
The Company has major interconnections and arrangements with its
neighboring utilities which it currently considers adequate for coordinated
planning, emergency assistance, exchange of capacity and energy, and reliability
of power supply.
Competition
The Company currently 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.
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 power companies and rural electric cooperatives. Substantially all of
the territory comprising the Company's service area has been so assigned. The
remaining areas have been designated as unassigned and in such areas the Company
remains subject to competition. A decision of
<PAGE>
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, the Company is
engaged in continuing competition with various natural gas providers.
The Energy Policy Act of 1992 (EPACT) is a major driver towards a more
competitive market for wholesale sales of power. EPACT reformed provisions of
the Public Utility Holding Company Act of 1935 (PUHCA) and Part II of the
Federal Power Act to remove certain barriers to competition for the supply of
electricity. For example, EPACT allows utilities to develop independent electric
generating plants in the United States for sales to wholesale customers, as well
as to contract for utility projects internationally, without becoming subject to
regulation under PUHCA as an electric utility holding company. In addition,
EPACT permits the FERC to order transmission access for third parties to
transmission facilities owned by another entity so that independent suppliers
can sell at wholesale to customers wherever located. 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
in issuing orders for third-party transmission service and issuing a number of
rules of general applicability. The FERC, in late March of 1995, issued a Notice
of Proposed Rulemaking (the "NOPR") in which it announced its intent to impose a
final rule, applicable to all electric utilities subject to its jurisdiction,
which will require all such utilities to adopt open-access transmission tariffs
containing identical terms and conditions. The FERC should issue its final rule
in 1996.
Open transmission access for wholesale customers as contemplated by the
FERC's NOPR would provide energy suppliers, including the Company, with
opportunities to sell and deliver capacity and energy at market-based prices.
Engaging in such transactions could result in improved utilization of the
Company's existing assets. In addition, such access would provide another supply
option through which the Company can buy capacity and energy at attractive
rates, influencing its competitive price position. However, sales to existing
wholesale customers of the Company could be impacted by open access as
contemplated by the NOPR either due to competitive pressure on the wholesale
price of electricity, or the potential loss of sales as wholesale customers seek
other options to meet their capacity and energy requirements at market-based
prices. Wholesale sales, excluding transactions with other utilities,
represented approximately 6.7 percent of the Company's total kilowatt-hour sales
in 1995. Supplemental sales to the other joint owners of the Catawba Nuclear
Station comprised the majority of such sales. Such supplemental sales will be
declining in 1996 as a result of the retention of significantly larger portions
of ownership entitlement by the other joint owners. (For additional information
on Catawba joint ownership, see Note 3 to the Consolidated Financial
Statements.)
In early 1995, prior to issuance of the FERC's NOPR, the Company and
certain of its affiliates filed three applications with the FERC, all of which
are designed to enable effective participation in the competitive environment of
the changing electric utility industry. Duke Power filed an application for
permission to sell at market-based rates up to 2,500 megawatts of capacity and
energy from its own assets. Two of the Company's affiliates, Duke Energy
Marketing Corporation (DEMC) and Duke/Louis Dreyfus L.L.C. (D/LD), filed
applications with the FERC to become power marketers. All of the applications
were supported by transmission tariffs which establish the rates, terms and
conditions for transmission service to third parties on the Company's
transmission system.
Late in 1995, the FERC granted the applications of Duke, DEMC, and
D/LD; accepted Duke's transmission tariffs; and ordered a hearing on the rates
to be charged for service under those tariffs. The terms and conditions of
service are subject to the outcome of the FERC's final rule, and the rates are
subject to the outcome of hearings before the FERC.
Wheeling of third party energy to a retail customer is not generally
allowed in the Company's service territory. However, there are discussions and
events at the national level and within certain states regarding retail
competition which could result in changes in the industry.
Currently, the electric utility industry is predominantly regulated on
a basis designed to recover the cost of providing electric power to its retail
and wholesale customers. If cost-based regulation were to be discontinued in the
industry for any reason, including competitive pressure on the cost-based price
of electricity, profits could be reduced and utilities might be required to
reduce their recorded 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
<PAGE>
regulatory assets. The regulatory assets of the Company are classified as
"Deferred debits" on the Consolidated Balance Sheets. Substantially all of the
"Deferred debits" are regulatory assets. Management cannot predict the potential
impact, if any, of these competitive forces on the Company's future financial
position and results of operations. However, the Company continues to position
itself to effectively meet these challenges by maintaining prices that are
locally, regionally and nationally competitive.
Subsidiaries And Diversified Activities
The Company continues to aggressively pursue both domestic and
international diversified business opportunities that are synergistic with the
Company's core business to provide additional value to the Company's
shareholders. Although these opportunities are primarily concentrated in areas
that utilize the Company's expertise, they present different and potentially
greater risks than does the Company's core business. The Company only pursues
opportunities in which the expected returns are commensurate with the risks and
makes efforts to mitigate such risks. The Company undertakes a continuous
evaluation of the various lines of business it may enter or exit, with the
objectives of enhancing shareholder value and managing any associated risk. (See
"Subsidiaries and Diversified Activities Highlights".)
Major subsidiaries and diversified activities include the following:
Crescent Resources, Inc. (Crescent) pursues both residential and
commercial real estate development, in addition to providing forest management
activities focused on growing trees suitable for use in the construction,
furniture and paper industries. At December 31, 1995, Crescent owned
approximately 2,398,000 square feet of office, retail and warehouse space and
had approximately 400,000 square feet of commercial properties under
construction. Additionally, Crescent had approximately 250,000 acres of land
under its management at year end.
Duke Energy Group, Inc. (Duke Energy) develops, owns and manages
electric power facilities in the United States and abroad. Duke Energy also
markets electric power and natural gas through a joint venture with Louis
Dreyfus Electric Power. Domestically, Duke Energy concentrates on advanced
fossil-fueled generation including pulverized coal, circulating fluidized bed,
coal gasification and natural gas technologies. Internationally, Duke Energy
pursues advanced coal-fueled, hydroelectric and gas-fueled generation as well as
transmission projects. Duke Energy has equity interests in two U.S. electric
generation facilities and four international projects.
Nantahala Power and Light Company (NP&L) is a franchised electric
utility which operates 11 hydroelectric plants with a total capacity of 100
megawatts. NP&L has approximately 53,000 customers in western North Carolina.
NP&L sold 949,000 MWH in 1995 compared to 907,000 MWH in 1994,
excluding sales to Duke Power.
Other Business Units include Church Street Capital Corp., which manages
investment funds and provides equity funding and credit enhancements for its
subsidiaries; Duke Engineering & Services, Inc., which markets engineering,
construction, quality assurance, consulting and other engineering-related
services for facilities other than coal-fired generating plants, both nationally
and internationally; Duke/Fluor Daniel, a joint venture with Fluor Daniel, Inc.,
which provides engineering, construction and support of operating and
maintenance activities, primarily for coal-fired generating plants, both
nationally and internationally; Duke Merchandising, which sells and services
quality electric appliances and electronics; DukeNet Communications, Inc., which
develops and manages communications systems; and Duke Water Operations, which
provides franchised water services for Anderson, South Carolina and
Rutherfordton, North Carolina.
Employees
At December 31, 1995, the Company had 17,121 full-time employees, which
included 1,355 full-time employees of subsidiaries and diversified activities.
About 1,950 electrical operating employees are represented by the International
Brotherhood of Electrical Workers (IBEW). During the last quarter of 1995, the
Company reached new labor agreements with the IBEW for one year terms.
The number of full-time employees has decreased to the 1995 year-end
level from 19,945 at year-end 1990. (See "Management's Discussion and Analysis
of Results of Operations and Financial Condition, Current Issues -- Resource
Optimization.")
<PAGE>
Subsequent Event
The Company's Board of Directors has authorized the implementation
of a program to repurchase up to $1 billion of the Company's Common Stock from
time to time over the next five years. The repurchases will be made either on
the open market (in accordance with applicable regulations) or through privately
negotiated transactions. The Board's authorization provides flexibility for the
Company's management to undertake the repurchase program at its discretion, and
does not establish a target stock price or timetable for repurchases. The timing
and amount of repurchases will be determined by cash available to the Company
for such purpose and by the availability of alternative investment
opportunities.
<PAGE>
(A Map of North Carolina and South Carolina appears here showing Duke Power's
service area. The legend is as follows:)
LEGEND
(star)REGION OFFICE
(circle) FOSSIL-FUELED STATION
(triangle) HYDROELECTRIC STATION
(square) NUCLEAR ELECTRIC STATION
(open box) NANTAHALA POWER AND LIGHT
<PAGE>
DUKE POWER COMPANY
OPERATING STATISTICS
<TABLE>
<CAPTION>
Year ended December 31
1995 1994 1993 1992 1991
<S> <C> <C> <C> <C> <C>
Sources of Electric Energy (d)
Millions of kilowatt-hours:
Generated--net output:
Coal............................................. 32,389 32,714 34,097 28,999 26,455
Nuclear (a)...................................... 39,836 35,587 34,390 33,925 37,048
Hydro (b)........................................ 1,685 1,460 1,582 1,834 1,545
Oil and gas (c).................................. 255 35 43 5 7
Total generation.............................. 74,165 69,796 70,112 64,763 65,055
Purchased power and net interchange............... 1,175 1,276 1,750 1,403 587
Total output.................................. 75,340 71,072 71,862 66,166 65,642
Plus: Purchases from other Catawba joint owners... 6,070 9,046 8,810 9,466 8,525
Total sources of energy....................... 81,410 80,118 80,672 75,632 74,167
Line loss and company usage....................... 4,673 4,555 4,614 4,590 4,280
Total kilowatt-hour sales..................... 76,737 75,563 76,058 71,042 69,887
Average cost per ton of coal burned................... $ 41.72 $ 40.68 $ 42.21 $ 43.47 $ 45.21
Electric Energy Sales (d)
Millions of kilowatt-hours:
Residential....................................... 19,669 18,870 19,465 17,789 17,918
General service................................... 18,160 17,289 16,904 15,818 15,586
Industrial
Textile......................................... 12,151 12,285 11,954 11,685 11,315
Other........................................... 17,631 17,005 16,244 15,356 14,955
Other energy and wholesale (e).................... 8,330 10,274 11,337 10,360 10,132
Total kilowatt-hour sales billed.............. 75,941 75,723 75,904 71,008 69,906
Unbilled kilowatt-hour sales...................... 796 (160) 154 34 (19)
Total kilowatt-hour sales..................... 76,737 75,563 76,058 71,042 69,887
Electric Revenue (d)
Thousands of dollars:
Residential.......................................$1,441,362 $1,379,740 $1,424,173 $1,312,227 $1,272,322
General service................................... 1,076,791 1,031,061 1,014,124 964,853 921,337
Industrial
Textile......................................... 494,066 498,190 487,576 482,172 475,191
Other........................................... 766,750 745,154 726,399 696,413 668,765
Other energy and wholesale (e).................... 461,367 540,256 476,862 460,849 441,777
Other electric revenue............................ 182,102 84,928 152,742 44,970 37,568
Total electric revenues.......................$4,422,438 $4,279,329 $4,281,876 $3,961,484 $3,816,960
Number of Customers--end of year (d)
Residential....................................... 1,526,323 1,493,166 1,460,876 1,439,845 1,415,605
General service (f)............................... 246,276 239,355 232,272 227,675 222,917
Industrial
Textile......................................... 1,390 1,422 1,396 1,390 1,385
Other........................................... 7,320 7,320 7,338 7,314 7,255
Other energy and wholesale........................ 8,470 8,187 7,957 7,773 7,605
Total customers............................... 1,789,779 1,749,450 1,709,839 1,683,997 1,654,767
Residential Customer Statistics (d)
Average number for the year....................... 1,514,434 1,483,497 1,455,609 1,431,403 1,409,775
Average annual use--KWH........................... 12,988 12,720 13,372 12,427 12,710
Average annual billing............................$ 951.75 $ 930.06 $ 978.40 $ 916.74 $ 902.50
Average annual billed revenue per KWH (d)
Cents:
Residential....................................... 7.33 7.31 7.32 7.38 7.10
General service................................... 5.93 5.96 6.00 6.10 5.91
Industrial........................................ 4.23 4.24 4.31 4.36 4.35
Other energy and wholesale (e).................... 5.54 5.26 4.21 4.45 4.36
</TABLE>
<PAGE>
(a) Includes 12.5% of Catawba generation.
(b) 1991 includes KWH of the Bad Creek Hydroelectric Station prior to
commercial operation.
(c) 1995 includes KWH of the Lincoln Combustion Turbine Station prior to
commercial operation.
(d) Does not include operating statistics of NP&L.
(e) Includes sales to NP&L.
(f) 1991 restated to eliminate certain duplicate customers.
EXECUTIVE OFFICERS OF THE COMPANY
WILLIAM H. GRIGG, 63, Chairman of the Board and Chief Executive
Officer. Mr. Grigg served as Chairman of the Board, President and Chief
Executive Officer, effective April 28, 1994, until July 27, 1994 when he assumed
his present position. He served as Vice Chairman of the Board beginning in 1991,
and Executive Vice President, Customer Group, beginning in 1988.
STEVE C. GRIFFITH, JR., 62, Vice Chairman of the Board and General
Counsel. Mr. Griffith served as Executive Vice President and General Counsel
from 1991 until he assumed his present position in July 1994. He served as
Senior Vice President and General Counsel from 1982 until 1991.
RICHARD B. PRIORY, 49, President and Chief Operating Officer. Mr.
Priory served as Executive Vice President, Power Generation Group, from 1991
until he assumed his present position in July 1994. He was Senior Vice
President, Generation and Information Services, from 1988 to 1991.
WILLIAM A. COLEY, 52, President, Associated Enterprises Group. Mr.
Coley was named Senior Vice President, Power Delivery, in 1988; Senior Vice
President, Customer Group, in 1990; and Executive Vice President, Customer
Group, in 1991. He was named to his present position in July 1994.
RICHARD J. OSBORNE, 44, Senior Vice President and Chief Financial
Officer. Prior to assuming his current position in July 1994, Mr. Osborne served
as Vice President and Chief Financial Officer beginning in 1991 and Vice
President, Finance, from 1988 to 1991.
JEFFREY L. BOYER, 39, Controller. Mr. Boyer served as Director of
Corporate Accounting for more than five years prior to assuming his present
position in July 1994.
Executive officers are elected annually by the Board of Directors and
serve until the first meeting of the Board of Directors following the next
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.
There have been no events under any bankruptcy act, no criminal
proceedings and no judgments or injunctions material to the evaluation of the
ability and integrity of any executive officer during the past five years.
ITEM 2. Properties.
At December 31, 1995, the Company operated three nuclear generating
stations, eight coal-fired stations and twenty-seven hydroelectric stations, all
of which are located in North Carolina or South Carolina.
<PAGE>
The following is a list of the major generating stations owned by the Company at
December 31, 1995:
FACILITY ENERGY SOURCE NET MW
- -------------------------------------------------------- ----------------
Oconee Nuclear 2,538
McGuire Nuclear 2,258
Catawba(a) Nuclear 282
Belews Creek Coal 2,240
Marshall Coal 2,090
Allen Coal 1,140
Cliffside Coal 760
Others Coal 1,469
Bad Creek Hydroelectric 1,065
Jocassee Hydroelectric 610
Others Hydroelectric 1,007
Combustion turbines (b) Oil and gas 1,484
(a) Represents Duke's 12.5% ownership share in Catawba Nuclear Station.
(b) Includes 900 MW of the Lincoln Combustion Turbine Station which were in
commercial operation as of December 31, 1995.
The Company has substantially completed the construction of the Lincoln
Combustion Turbine Station, a 16-turbine facility designed to provide capacity
at periods of peak demand. The station has a total generating capacity of
1,200 megawatts. Twelve of the 16 units were placed into commercial operation in
1995, and as of March 1, 1996, the final four units were placed into commercial
operation. The facility is designed to operate on either natural gas or oil.
In addition to the electric generating plants described above, the
Company owned, as of December 31, 1995, approximately 8,300 conductor miles of
transmission lines and approximately 73,500 conductor miles of distribution
lines. As of such date, the Company's transmission and distribution systems
comprised approximately 1,600 substations with an installed transformer capacity
of approximately 84,200,000 kVA.
NP&L's generation facilities consist of eleven hydroelectric plants
with an aggregate nameplate capacity of approximately 100 MW. The transmission
backbone of the system is a 161 kV line from Santeetlah to substations at
Robbinsville, Nantahala Plant, Oak Grove, Webster and Thorpe Plant.
The map found at the end of Item 1 shows the location of the Company's
and NP&L's service area and generating stations.
Substantially all electric plant is mortgaged under the Indenture
relating to the First and Refunding Mortgage Bonds of the Company.
For additional information concerning the properties of the Company,
see "Business -- Energy Requirements and Capability."
ITEM 3. Legal Proceedings.
Reference is made to "Business -- Regulation", "Management's Discussion
and Analysis of Results of Operations and Financial Condition, Current Issues --
Commitments and Contingencies" and "Note 13, Notes to Consolidated Financial
Statements, Commitments and Contingencies -- Other".
<PAGE>
ITEM 4. Submission Of Matters To A Vote Of Security Holders.
No matters were submitted to a vote of the Company's security holders
during the last quarter of 1995.
PART II.
ITEM 5. Market For The Registrant's Common Equity And Related Stockholder
Matters.
The Common Stock of the Company is traded on the New York Stock
Exchange. At December 31, 1995, there were approximately 129,265 holders of
shares 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:
<TABLE>
<CAPTION>
Stock Price
Dividends Range
Per
Common Stock Share High Low
<S> <C> <C> <C>
1995 By Quarter
Fourth. . . . . . . . . . . $0.51 $47 7/8 $43 1/8
Third . . . . . . . . . . . . 0.51 43 3/4 40
Second . . . . . . . . . . . 0.49 42 3/4 38 1/4
First . . . . . . . . . . . 0.49 40 3/4 37 3/8
1994 By Quarter
Fourth. . . . . . . . . . . $0.49 $42 1/8 $38
Third . . . . . . . . . . . . 0.49 39 7/8 35 1/2
Second . . . . . . . . . . . 0.47 37 32 7/8
First . . . . . . . . . . . 0.47 43 35 3/4
</TABLE>
<PAGE>
ITEM 6.
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
1995 1994 1993 1992 1991
<S> <C> <C> <C> <C> <C>
Condensed consolidated statements of income
(thousands)
Operating revenues . . . . . . . . . . $ 4,676,684 $ 4,488,913 $ 4,466,233 $ 4,122,503 $ 3,962,605
Operating expenses . . . . . . . . . . 3,327,633 3,309,087 3,258,422 3,087,422 2,968,239
Operating income . . . . . . . . . . . 1,349,051 1,179,826 1,207,811 1,035,081 994,366
Interest expense and other income . . (168,072) (143,931) (171,419) (223,028) (117,725)
Income before income taxes . . . . . . 1,180,979 1,035,895 1,036,392 812,053 876,641
Income taxes . . . . . . . . . . . . . 466,441 397,019 409,977 303,970 293,018
Net income . . . . . . . . . . . . . . 714,538 638,876 626,415 508,083 583,623
Dividends on preferred and preference
stock . . . . . . . . . . . . . . 48,903 49,724 52,429 56,407 54,683
Earnings for common stock . . . . . . $ 665,635 $ 589,152 $ 573,986 $ 451,676 $ 528,940
Common stock data
Shares of common stock
year-end (thousands) . . . . . . . 204,859 204,859 204,859 204,859 204,699
average (thousands) . . . . . . . 204,859 204,859 204,859 204,819 203,431
Per share of common stock
Earnings . . . . . . . . . . . . . $ 3.25 $ 2.88 $ 2.80 $ 2.21 $ 2.60
Dividends . . . . . . . . . . . . $ 2.00 $ 1.92 $ 1.84 $ 1.76 $ 1.68
Book value -- year-end . . . . . . $ 23.36 $ 22.13 $ 21.17 $ 20.26 $ 19.86
Market price -- high-low . . . . . $ 47 7/8 - 37 3/8 $ 43 - 32 7/8 $44 7/8 - 35 3/8 $37 1/2 - 31 3/8 $ 35 - 26 3/4
-- year-end . . . . . $ 47 3/8 $ 38 1/8 $ 42 3/8 $ 36 1/8 $ 35
Balance sheet data
(thousands)
Total assets. . . . . . . . . . . . . $ 13,358,484 $ 12,862,228 $ 12,293,605 $ 11,012,795 $ 10,617,552
Long-term debt . . . . . . . . . . . . $ 3,711,405 $ 3,567,122 $ 3,285,397 $ 3,288,111 $ 3,235,492
Preferred stock with sinking fund
requirements . . . . . . . . . . . $ 234,000 $ 279,500 $ 281,000 $ 279,519 $ 228,650
</TABLE>
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION.
RESULTS OF OPERATIONS
EARNINGS AND DIVIDENDS
Earnings per share increased 13 percent from $2.88 in 1994 to $3.25 in 1995. The
increase was primarily due to increased kilowatt-hour sales to weather sensitive
classes.
Earnings per share increased from $2.80 in 1993 to $3.25 in 1995,
indicating an average annual growth rate of 8 percent. Total Company earned
return on average common equity was 14.3 percent in 1995 compared to 13.3
percent in 1994 and 13.6 percent in 1993.
The Company continued its practice of annually increasing the common stock
dividend. Common dividends per share increased at an average annual rate of 4
percent from $1.84 in 1993 to $2.00 in 1995. Indicated annual dividends per
share increased to $2.04.
REVENUES AND SALES
Operating revenues increased at an average annual rate of 2 percent from 1993 to
1995, primarily because of increased retail kilowatt-hour sales to weather
sensitive classes and growth in the general service and industrial customer
classes. As discussed below, increased retail sales were partially offset by
decreased sales to wholesale customers. Revenues from subsidiaries and
diversified operations contributed $73 million to the increase in revenues over
the three-year period, primarily from increased developed lot and land sales and
engineering services and construction fees.
Wholesale revenues declined in 1995 and are expected to decline again in
1996 as a result of the retention of significantly larger portions of ownership
entitlement by the other joint owners of the Catawba Nuclear Station. This
increased retention reduces the joint owners' supplemental requirements supplied
by the Company. The effect on earnings of such wholesale revenue declines is
partially offset by declines in purchased power costs from the other joint
owners which are not subject to levelization. (For additional information on
Catawba joint ownership, see Note 3 to the Consolidated Financial Statements.)
Kilowatt-hour sales from Duke Power electric operations increased 2 percent
in 1995 compared to 1994. Sales to residential, general service and other
industrial customers increased by 4 percent, 5 percent and 4 percent,
respectively, as a result of warmer summer weather, cooler winter weather and
continued economic growth in Duke Power's service area. However, sales to
textile customers decreased 1 percent. Wholesale sales decreased 19 percent
primarily due to a decrease of 36 percent in supplemental sales requirements to
the other joint owners of the Catawba Nuclear Station. A new record peak demand
of 15,542 megawatts was set in August 1995 during warmer than normal
temperatures.
OPERATING EXPENSES
From 1994 to 1995, other operation and maintenance expenses increased 5 percent.
Increased activities of the subsidiaries and diversified operations associated
with both engineering services and other project development efforts contributed
to this increase. Increases in distribution and transmission expenses were
offset by reductions in nuclear and fossil outage costs. In 1995 and 1994, the
Company had relatively constant costs associated with work force reduction
programs and certain claims that are expected to be non-recurring in nature.
Other operation and maintenance expenses increased at an average annual
rate of 6 percent from 1993 to 1995. Costs associated with the enhanced vested
retirement benefit program in 1995 as well as other non-recurring costs
contributed to this increase in addition to increased activities of the
subsidiaries and diversified operations associated with engineering services and
other project development efforts. (For additional information on the vested
retirement program, see Current Issues, "Resource Optimization.")
Fuel expense increased at an average annual rate of 1 percent from 1993 to
1995. The increase was due primarily to higher system production requirements,
offset by improved nuclear generation.
Net interchange and purchased power expenses decreased from $535 million in
1993 to $468 million in 1995, an average annual decrease of 6 percent. This
decrease was primarily the result of lower purchased power costs from the other
joint owners not subject to levelization as the other joint owners retained
significantly larger portions of their ownership entitlement. In 1996, net
interchange and purchased power is expected to decrease again as purchased power
costs from the other joint owners continue to decline.
From 1993 to 1995, depreciation and amortization expense decreased at an
average annual rate of 4 percent, primarily because the reduction in the
amortization of property losses more than offset increased depreciation
associated with additional investments. These investments were primarily
associated with distribution plant, including investment to support customer
growth, commercial operation of 12 units of the Lincoln Combustion Turbine
Station, and fossil plant resulting from bringing refurbished units back
on-line. (For additional information on the Lincoln Combustion Turbine Station,
see Capital Needs, "Meeting Future Power Needs.")
INTEREST EXPENSE AND OTHER INCOME
Interest expense increased at an average annual rate of 3 percent
from 1993 to 1995, primarily due to long-term debt financing
activities in 1994.
Allowance for funds used during construction (AFUDC) and other deferred
returns, net of associated taxes, represented 13 percent of earnings for common
stock in 1995 compared to 10 percent in 1993. AFUDC and other deferred returns
are expected to be less than 11 percent of total earnings during the next three
years.
The deferred return, net of associated taxes, on the purchased capacity
levelization deferral related to the joint ownership of the Catawba Nuclear
Station represented 7 percent of earnings for common stock in 1995, compared to
7 percent in 1994 and 6 percent in 1993. The growth in this return is due
to the increasing cumulative impact of the Company's funding of purchased power
costs through 1995, which the Company expects to collect through current rates
in future periods. The deferred purchased capacity balance is expected to begin
to decline in 1996. (For additional information on purchased capacity
levelization, see Capital Needs, "Purchased Capacity Levelization.")
AFUDC, net of associated taxes, represented 5 percent of earnings for
common stock in 1995 compared to 6 percent in 1994 and 4 percent in 1993. The
changes were primarily the result of the construction and subsequent commercial
operation of the Lincoln Combustion Turbine Station as 12 units were brought
on-line at various times during 1995. (For additional information on the Lincoln
Combustion Turbine Station, see Capital Needs, "Meeting Future Power Needs.")
LIQUIDITY AND RESOURCES
DUKE POWER COMPANY RATE MATTERS
The Company's most recent general rate increase requests in the North Carolina
and South Carolina retail jurisdictions were filed and approved in 1991.
Additionally, Duke Power has a bulk power sales agreement with Carolina Power &
Light Company (CP&L) to provide CP&L 400 megawatts of capacity as well as
associated energy when needed for a six-year period which began July 1, 1993.
Electric rates in all of Duke Power's regulatory jurisdictions were reduced by
adjustment riders to reflect capacity revenues received from this CP&L bulk
power sales agreement.
CATAWBA SETTLEMENTS
The Company and North Carolina Municipal Power Agency Number 1 (NCMPA) and
Piedmont Municipal Power Agency (PMPA), two of the four other joint owners of
the Catawba Nuclear Station, entered into a settlement in September 1995 which
resolved outstanding issues related to how certain calculations affecting bills
under the Catawba joint ownership contractual agreements should be performed.
The settlement was approved by the North Carolina Utilities Commission (NCUC) on
January 16, 1996 and the Public Service Commission of South Carolina (PSCSC) on
January 23, 1996. As part of the settlement, the Company agreed to purchase
additional megawatts (MW) of Catawba capacity during the period 1996 through
1999 and remove certain restrictions related to sales of surplus energy by these
two joint owners. The additional capacity purchases are 215 MW in 1996, 165 MW
in 1997, 120 MW in 1998 and 100 MW in 1999. The Company expects to recover the
costs associated with this settlement as part of the purchased capacity
levelization, consistent with prior orders of the retail regulatory commissions.
Therefore, the Company believes these matters should not have a material adverse
effect on the results of operations or the financial position of the Company.
The Company and all four of the other joint owners of the Catawba Nuclear
Station entered into settlement agreements in 1994 which resolved all issues in
contention in arbitration proceedings related to the Catawba joint ownership
contractual agreements. The basic contention in each proceeding was that certain
calculations affecting bills under these agreements should be performed
differently. These items are covered by the agreements between the Company and
the other Catawba joint owners, which previously have been approved by the
Company's retail regulatory commissions. (For additional information on Catawba
joint ownership, see Note 3 to the Consolidated Financial Statements.) In 1994,
the Company settled its cumulative net obligation through 1993 of approximately
$205 million related to these settlement agreements. Billings for 1994 and later
years will conform to the settlement agreements, which were approved by the
Company's retail regulatory commissions. Because the Company expects the costs
associated with these settlements to be recovered as part of the purchased
capacity levelization, which has been approved by the Company's retail
regulatory commissions, the Company included approximately $205 million as an
increase to "Purchased capacity costs" on its Consolidated Balance Sheets in
1994. Therefore, the Company believes these matters should not have a material
adverse effect on the results of operations or financial position of the
Company.
CASH FROM OPERATIONS
Consolidated net cash provided by operating activities in 1995 accounted for 81
percent of total cash from operating, financing and investing activities
compared with 67 percent in 1994 and 46 percent in 1993. When 1993 and 1995
refinancing activities are excluded, substantially all of the Company's capital
needs were met by cash generated from operating activities. Refinancing
activities were insignificant in 1994.
FINANCING AND INVESTING ACTIVITIES
The Company's consolidated capital structure at year-end 1995, including
subsidiary long-term debt, was 52 percent common equity, 40 percent long-term
debt and 8 percent preferred stock. This structure is consistent with the
Company's target to maintain a double-A credit rating. As of December 31, 1995,
Duke Power's bonds were rated "AA" by Fitch Investors Service, "Aa2" by Moody's
Investors Service, and "AA-" by Standard & Poor's Group and Duff & Phelps.
The Company had total credit facilities of $669.9 million and $440.0
million as of December 31, 1995 and 1994, respectively. The Company had unused
credit facilities of $440.6 million and $259.9 million as of December 31, 1995
and 1994, respectively.
In response to favorable market conditions in 1993, the Company issued $1.5
billion in long-term debt and $220 million in preferred stock, most of which was
used to retire higher cost debt and preferred stock. In 1995, the Company issued
$178 million of long-term debt, of which $72 million was used to retire higher
cost long-term debt. The Company also retired $96 million of preferred stock
and $80 million of long-term debt in 1995.
Capital Structure
Billions of dollars
(Bar graph appears here with the following plot points:)
1990 1991 1992 1993 1994 1995
Long-term debt 40% 40% 40% 39% 40% 40%
Preferred and preference stock 10% 9% 9% 9% 9% 8%
Common equity 50% 51% 51% 52% 51% 52%
Total Amount 7.7 8.0 8.2 8.4 8.9 9.2
In order to obtain variable rate financing at an attractive cost, the
Company entered into interest rate swap agreements associated with the November
29, 1994 issuance of $200 million aggregate principal amount of its First and
Refunding Mortgage Bonds 8% Series B due 1999 and the August 21, 1995 issuance
of $100 million aggregate principal amount of its First and Refunding Mortgage
Bonds 7 1/2% Series B due 2025. The interest rate swaps are reset quarterly
based upon the three-month London Interbank Offered Rate (LIBOR). As a result
of the interest rate swap contracts, interest expense is recognized at the
weighted average rate for the year tied to the LIBOR rate. The weighted average
rates at December 31, 1995 and 1994 were 6.14% and 5.95%, respectively, for the
8% Series B due 1999 and 7.06% in 1995 for the 7 1/2% Series B due 2025.
The Company has also entered into a hedge transaction to offset currency
fluctuations between the U.S. dollar and the Japanese yen associated with
various steam generator purchase contracts. The hedge transaction with a
notional amount of approximately $25 million at December 31, 1994, was fully
liquidated by November 1995. The Company recorded any gains or losses associated
with the hedge as an adjustment to the capitalized cost of the steam generators.
Duke Energy Group, Inc. has entered into a hedge transaction to offset
currency fluctuations between the U.S. dollar and the Chilean peso associated
with expected equity contributions over the next two years to a joint venture.
The hedge transaction had a notional amount of approximately $17 million at
December 31, 1995. Duke Energy Group, Inc. records gains or losses associated
with the hedge as an adjustment to investments in joint ventures.
Duke Power's embedded cost of long-term debt, excluding debt of
subsidiaries, was 7.94 percent for 1995 compared to 7.98 percent in 1994 and
8.01 percent in 1993. The embedded cost of preferred stock was 7.06 percent in
1995 compared to 6.99 percent in 1994 and 6.76 percent in 1993. The decreases in
the embedded cost of long-term debt are primarily the result of the Company's
refinancing activities and the resulting lower-cost debt. The increase in the
embedded cost of preferred stock from 1993 to 1995 reflects the impact of
increased adjustable dividend rates on a certain series of preferred stock and
the retirement of preferred stock in 1995.
FIXED CHARGES COVERAGE
Consolidated fixed charges coverage using the SEC method increased to 4.94 times
for 1995 compared to 4.72 and 4.68 times in 1994 and 1993, respectively.
Coverage increased primarily because of higher earnings. Consolidated fixed
charges coverage, excluding AFUDC and other deferred returns, was 4.52 times for
1995 compared with 4.32 in 1994 and 4.39 in 1993 and the Company goal of 3.5
times. Coverage was higher in 1995 than 1994 and 1993 as a result of increased
earnings excluding AFUDC and other deferred returns.
Fixed Charges Coverage
Times
(Graph appears here with the following plot points:)
<TABLE>
<CAPTION>
1990 1991 1992 1993 1994 1995
<S> <C> <C> <C> <C> <C> <C>
SEC method 3.65 3.83 3.49 4.68 4.72 4.94
SEC method excluding
AFUDC and other
deferred returns 3.15 3.44 3.27 4.39 4.32 4.52
</TABLE>
CAPITAL NEEDS
PROPERTY ADDITIONS AND RETIREMENTS
Additions to property and nuclear fuel of $794 million and retirements of $288
million resulted in an increase in gross plant of $506 million in 1995.
Since January 1, 1993, additions to property and nuclear fuel of $2.4
billion and retirements of $864 million have resulted in an increase in gross
plant of $1.5 billion.
Duke Power Construction
Costs* Millions of dollars
(Graph appears here with the following plot points:)
<TABLE>
<CAPTION>
1990 1991 1992 1993 1994 1995
<S> <C> <C> <C> <C> <C> <C>
Nuclear fuel 141.2 193.0 127.8 121.8 128.6 89.4
Construction 909.7 606.6 464.0 547.6 650.3 583.1
Total 1050.9 799.6 591.8 669.4 778.9 672.5
</TABLE>
*Includes AFUDC and excludes NP&L and Duke Power's other subsidiaries.
CONSTRUCTION EXPENDITURES
Plant construction costs for generating facilities supporting Duke Power
electric operations, including AFUDC, increased from $182 million in 1993 to
$281 million in 1995, primarily because of construction of the Lincoln
Combustion Turbine Station and the steam generator replacement project. (For
more information, see Capital Needs, "Meeting Future Power Needs" and
Current Issues, "Stress Corrosion Cracking.") Construction costs for
distribution plant, including AFUDC, decreased from $240 million in 1993 to $221
million in 1995.
Projected construction and nuclear fuel costs for Duke Power's electric
operations, both including AFUDC, are $2.3 billion and $661 million,
respectively, for 1996 through 2000. These construction expenditures are
primarily for distribution and production related activities representing $997
million and $774 million, respectively. These projections are subject to
periodic reviews and revisions. Actual construction and nuclear fuel costs and
capital expenditures incurred may vary from such estimates. Cost variances are
due to various factors, including revised load estimates, environmental matters
and cost and availability of capital.
Projected capital expenditures of subsidiaries and diversified activities
are $1.0 billion for 1996 through 2000 of which a significant portion is for
real estate development. These projections are subject to periodic review and
revision and may vary significantly as the business plans of the Associated
Enterprises Group evolve to meet the opportunity presented by its markets.
For 1996 through 2000, the Company anticipates substantially funding its
projected construction and capital expenditures through the internal generation
of funds.
PURCHASED CAPACITY LEVELIZATION
The rates established in Duke Power's electric retail jurisdictions permit
recovery of its investment in both units of the Catawba Nuclear Station and
the costs associated with contractual purchases of capacity from the other
joint owners of the Catawba
Nuclear Station. The contracts relating to the sales of portions of the
station obligate the Company to purchase a declining amount of capacity from
the other joint owners. In the North Carolina retail jurisdiction, regulatory
treatment of these contracts provides revenue for recovery of the capital
costs and the fixed operating and maintenance costs of purchased capacity on
a levelized basis. In the South Carolina retail jurisdiction, revenues are
provided for the recovery of the capital costs of purchased capacity on a
levelized basis, while current rates include recovery of fixed operating and
maintenance expenses.
Such rate treatments require the Company to fund portions of the purchased
capacity payments until these costs, including returns, are recovered at a later
date. The Company recovers the accumulated costs and returns when the sum of the
declining purchased capacity payments and accrual of returns for the current
period drop below the levelized revenues. In the North Carolina retail
jurisdiction, and wholesale jurisdiction regulated by the Federal Energy
Regulatory Commission (FERC), purchased capacity payments and the accrual of
deferred returns continue to exceed levelized revenues. However, in 1996, the
levelized revenues are expected to exceed the purchased capacity payments and
accrual of deferred returns. In the South Carolina retail jurisdiction,
cumulative levelized revenues have exceeded purchased capacity payments and
accrual of deferred returns. Jurisdictional levelizations are intended to
recover total costs, including returns, and are subject to adjustments,
including final true-ups.
MEETING FUTURE POWER NEEDS
The Company's strategy for meeting customers' present and future energy needs
consists of three components: supply-side resources, demand-side resources and
purchased power resources. To assist in determining the optimal combination of
these three resources, the Company uses an integrated resource planning process.
The goal is to provide adequate and reliable electricity in an environmentally
responsible, cost-effective manner.
The Company is constructing a combustion turbine facility in Lincoln
County, North Carolina. The Lincoln Combustion Turbine Station, designed to
provide capacity at periods of peak demand, will consist of 16 combustion
turbines with a total generating capacity of 1,200 megawatts. The estimated
total cost of the project is approximately $400 million. Units 1 through 12
began commercial operation during 1995 and the remaining four units are
scheduled to begin commercial operation in 1996.
In 1995, the Company issued two requests for proposals (RFP) to solicit
competitive bids for its future electric generating capacity resources. The
short-term RFP could provide options for up to 675 megawatts of capacity with
terms of 1 to 4 years. The long-term RFP solicits bids to provide up to 300
megawatts of purchased power to be available beginning in 1998 or 1999, for
contract periods of between 5 and 20 years in duration. The Company has
evaluated a total of 16 proposals received for both the short-term RFP and the
long-term RFP and has begun negotiation with the bidders with the best
proposals. Contracts are expected to be awarded in May 1996.
The purchase of capacity and energy is also an integral part of meeting
future power needs. As of January 1, 1996, the Company has 300 megawatts of firm
purchased capacity from other generators of electricity under contract,
including 62 megawatts from qualifying facilities.
Demand-side management programs benefit the Company and its customers by
promoting energy efficiency, providing for load control through interruptible
control features, shifting usage to off-peak periods and increasing strategic
sales of electricity. In return for participation in demand-side management
programs, customers may be eligible to receive various incentives which help
reduce their net investment in high-efficiency equipment or their electric
bills. The November 1991 rate orders of the NCUC and the PSCSC provided for
recovery in rates of a designated level of costs for demand-side management
programs and allowed the deferral for later recovery of certain demand-side
management costs that exceed the level reflected in rates, including a return on
the deferred costs. The Company ultimately expects recovery through rates of
associated deferred costs, not to exceed $75 million including deferred returns
in the North Carolina retail jurisdiction. The annual costs deferred, including
the return, were approximately $16 million and $11 million in North Carolina and
South Carolina, respectively, in 1995 and $15 million and $10 million in North
Carolina and South Carolina, respectively, in 1994. As of December 31, 1995, the
balance of deferred demand-side management costs as presented on the
Consolidated Balance Sheets in "Other deferred debits" is $58 million and $38
million in North Carolina and South Carolina, respectively.
CURRENT ISSUES
While the Company improved its financial performance in 1995 compared to 1994,
its ability to maintain and improve its current level of earnings will depend on
several factors. As the industry becomes increasingly competitive, the Company's
ability to control costs will be an important factor in maintaining a pricing
structure that is both attractive to customers and profitable to the Company.
Wheeling of third party energy to a retail customer is not generally allowed in
the Company's service territory. However, there are discussions and events at
the national level and within certain states regarding retail competition which
could result in changes in the industry. (For additional information on
competition, see Current Issues, "Competition.") Management cannot
predict the outcome of these matters and their impact, if any, on the Company's
future financial position and results of operation. The Company is focusing on
providing competitive prices to its industrial customers, as well as to
wholesale customers who have access to alternative sources of energy. Other
significant factors impacting the Company's future earnings levels include
continued economic growth in the Piedmont Carolinas, the success of the
Company's subsidiaries and diversified activities, and the outcomes of various
legislative and regulatory actions.
RESOURCE OPTIMIZATION. The Company has been engaged in a concentrated effort to
more efficiently and effectively use its resources through better work
practices. In 1995, the Company offered to certain employees an Enhanced Vested
Benefits program (EVB) which gave targeted employees, who left the Company, an
enhanced vested retirement package and the Company's standard severance pay
based on years of service. This program will result in the departure of
approximately 900 employees by the end of the first quarter of 1996. During
1994, the Company offered an Enhanced Voluntary Separation program (EVS) which
gave most employees the option of leaving the Company for a lump-sum payment
and the Company's standard severance pay based on years of service. This
program resulted in the departure of approximately 1,300 employees in 1994.
Implementing various efficiency practices has resulted in streamlined workflows
and provided the opportunity for work force reduction programs such as EVB and
EVS. The number of full-time employees has decreased from 19,945 at year-end
1990 to 17,121 at year-end 1995.
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 Company's 12.5 percent ownership in the Catawba Nuclear Station. The other
joint owners of the Catawba Nuclear Station are responsible for decommissioning
costs related to their ownership interests in the station. 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 Company'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.
The Nuclear Regulatory Commission issued a rule-making in 1988 which
requires an external mechanism to fund the estimated cost to decommission
certain components of a nuclear unit subject to radioactive contamination. In
addition to the required external funding, the Company maintains an internal
reserve to provide for decommissioning costs of plant components not subject to
radioactive contamination. During 1995, the Company expensed approximately $56
million, which was contributed to the external funds, and accrued an additional
$1 million to the internal reserve. The balance of the external funds as of
December 31, 1995, was $273 million. The balance of the internal reserve as of
December 31, 1995, was $206 million and is reflected in accumulated depreciation
and amortization on the Consolidated Balance Sheets.
Both the NCUC and the PSCSC have granted the Company recovery of estimated
decommissioning costs through retail rates over the expected remaining service
periods of the Company's nuclear plants. Management's opinion is that the
decommissioning costs being recovered through rates, when coupled with assumed
after-tax fund earnings of 5.5 percent to 5.9 percent, are currently sufficient
to provide for the cost of decommissioning.
ENVIRONMENTAL ISSUES. The Company is subject to federal, state and local
regulations regarding air and water quality, hazardous and solid waste disposal,
and other environmental matters. The Company was an operator of manufactured gas
plants until the early 1950s. The Company 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 Company is considered by regulators to
be a potentially responsible party and may be subject to liability at three
federal Superfund sites and one comparable state site. While the cost of
remediation of these sites may be substantial, the Company will share in any
liability associated with remediation of contamination at such sites with other
potentially responsible parties. Management is of the opinion that resolution of
these matters will not have a material adverse effect on the results of
operations or financial position of the Company.
THE CLEAN AIR ACT AMENDMENTS OF 1990. The Clean Air Act Amendments of 1990
require a two-phase reduction by electric utilities in the aggregate annual
emissions of sulfur dioxide and nitrogen oxide by the year 2000. The Company
currently meets all requirements of Phase I. The Company supports the national
objective of clean air in the most cost-effective manner and has already reduced
emissions through the use of low-sulfur coal in its fossil plants, efficient
plant operations and by using nuclear generation. The sulfur dioxide provisions
of the Act allow utilities to choose among various alternatives for compliance.
To meet the Phase II requirements by 2000, the Company's current strategy
includes the use of lower sulfur coal, emission allowance purchases, low
nitrogen oxide burners and emission monitoring equipment. A one-time cost
associated with bringing the Company into compliance with the Act could range
from $94 million to $320 million. Additional operating expenses of approximately
$55 million will be incurred for fuel premiums and emission allowance purchases
each year after 2000. This strategy is contingent upon developments in the
emissions allowance market, lower sulfur coal fuel premiums, future regulatory
and legislative actions, and advances in clean air technology.
STRESS CORROSION CRACKING. Stress corrosion cracking (SCC) has occurred in the
steam generators of Units 1 and 2 at the McGuire Nuclear Station and Unit 1 at
the Catawba Nuclear Station. Catawba Unit 2, which has certain design
differences and came into service at a later date, has not yet shown the degree
of SCC which has occurred in McGuire Units 1 and 2 and Catawba Unit 1. It is,
however, too early in the life of Catawba Unit 2 to determine the extent to
which SCC may be a problem. Although the Company has taken steps to mitigate the
effects of SCC, the inherent potential for future SCC in the McGuire and Catawba
steam generators still exists. The Company is planning for the replacement of
steam generators at three units that have experienced SCC and has signed an
agreement with Babcock & Wilcox International to purchase replacement steam
generators. The current schedule for completion of the effort is as follows:
Catawba Unit 1 - 1996, McGuire Unit 1 - 1997 and McGuire Unit 2 - 1997. The
order of replacement is subject to change based on operational and project
circumstances. The Catawba Unit 2 steam generators have not been scheduled for
replacement. Steam generator replacement at each unit is expected to take
approximately four months and cost approximately $170 million, excluding the
cost of replacement power and the reimbursement of applicable costs by the other
joint owners of Catawba Unit 1. Stress corrosion problems are excluded under the
Company's nuclear insurance policies.
The Company, in connection with its McGuire and Catawba stations and on
behalf of the other joint owners of the Catawba Station, began a legal action in
1990, alleging that Westinghouse Electric Corporation knowingly supplied to the
McGuire and Catawba stations steam generators that were defective in design,
workmanship, and materials, requiring replacement well short of their stated
design life. The lawsuit was settled in 1994. While the court order does not
allow disclosure of the terms of the settlement, the Company believes the
litigation was settled on terms that provided satisfactory consideration to the
Company and will not have a material effect on the Company's results of
operations or financial position.
COMPETITION. The Energy Policy Act of 1992 (EPACT) is a major driver towards a
more competitive market for wholesale sales of power. EPACT reformed provisions
of the Public Utility Holding Company Act of 1935 (PUHCA) and Part II of the
Federal Power Act to remove certain barriers to competition for the supply of
electricity. For example, EPACT allows utilities to develop independent electric
generating plants in the United States for sales to wholesale customers, as well
as to contract for utility projects internationally, without becoming subject to
regulation under PUHCA as an electric utility holding company. In addition,
EPACT permits the FERC to order transmission access for third parties to
transmission facilities owned by another entity so that independent suppliers
can sell at wholesale to customers wherever located. 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 in
issuing orders for third-party transmission service and issuing a number of
rules of general applicability. The FERC in late March of 1995 issued a Notice
of Proposed Rulemaking (the "NOPR") in which it announced its intent to impose a
final rule, applicable to all electric utilities subject to its jurisdiction,
which will require all such utilities to adopt open-access transmission tariffs
containing identical terms and conditions. The FERC should issue its final rule
in 1996.
Open transmission access for wholesale customers as contemplated by the
FERC's NOPR would provide energy suppliers, including the Company, with
opportunities to sell and deliver capacity and energy at market-based prices.
Engaging in such transactions could result in improved utilization of the
Company's existing assets. In addition, such access would provide another supply
option through which the Company can buy capacity and energy at attractive
rates, influencing its competitive price position. However, sales to existing
wholesale customers of the Company could be impacted by open access as
contemplated by the NOPR either due to competitive pressure on the wholesale
price of electricity, or the potential loss of sales as wholesale customers seek
other options to meet their capacity and energy requirements at market-based
prices. Wholesale sales, excluding transactions with other utilities,
represented approximately 6.7 percent of the Company's total kilowatt-hour sales
in 1995. Supplemental sales to the other joint owners of the Catawba Nuclear
Station comprised the majority of such sales. Such supplemental sales will be
declining in 1996 as a result of the retention of significantly larger portions
of ownership entitlement by the other joint owners. (For additional information
on Catawba joint ownership, see Note 3 to the Consolidated Financial
Statements.)
In early 1995, prior to issuance of the FERC's NOPR, the Company and
certain of its affiliates filed three applications with the FERC, all of which
are designed to enable effective participation in the competitive environment of
the changing electric utility industry. Duke Power filed an application for
permission to sell at market-based rates up to 2,500 megawatts of capacity and
energy from its own assets. Two of the Company's affiliates, Duke Energy
Marketing Corporation (DEMC) and Duke/Louis Dreyfus L.L.C. (D/LD), filed
applications with the FERC to become power marketers. All of the applications
were supported by transmission tariffs which establish the rates, terms and
conditions for transmission service to third parties on the Company's
transmission system.
Late in 1995, the FERC granted the applications of Duke, DEMC, and D/LD;
accepted Duke's transmission tariffs; and ordered a hearing on the rates to be
charged for service under those tariffs. The terms and conditions of service are
subject to the outcome of the FERC's final rule, and the rates are subject to
the outcome of hearings before the FERC.
Wheeling of third party energy to a retail customer is not generally
allowed in the Company's service territory. However, there are discussions and
events at the national level and within certain states regarding retail
competition which could result in changes in the industry.
Currently, the electric utility industry is predominantly regulated on a
basis designed to recover the cost of providing electric power to its retail and
wholesale 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 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
Company are classified as "Deferred debits" on the Consolidated Balance Sheets.
Substantially all of the "Deferred debits" are regulatory assets. Management
cannot predict the potential impact, if any, of these competitive forces on the
Company's future financial position and results of operations. However, the
Company continues to position itself to effectively meet these challenges by
maintaining prices that are locally, regionally and nationally competitive.
COMMITMENTS AND CONTINGENCIES. The Company is 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 may involve substantial amounts. Where appropriate, the
Company has made accruals in accordance with Statement of Financial Accounting
Standards No. 5, "Accounting for Contingencies," in order to provide for such
matters. Management is of the opinion that the final disposition of these
proceedings will not have a material adverse effect on the results of operations
or the financial position of the Company.
SUBSIDIARIES AND DIVERSIFIED OPERATIONS. The Company continues to aggressively
pursue both domestic and international diversified business opportunities that
are synergistic with the Company's core business to provide additional value to
the Company's shareholders. Among the Company's current industry pursuits are:
ownership of electric power facilities, power marketing, real estate,
communications, engineering consulting and various energy services. Although
these opportunities are primarily concentrated in areas that utilize the
Company's expertise, they present different and potentially greater risks than
does the Company's core business. The Company only pursues opportunities in
which the expected returns are commensurate with the risks and makes efforts to
mitigate such risks. The Company undertakes a continuous evaluation of the
various lines of business it may enter or exit, with the objectives of enhancing
shareholder value and managing any associated risk.
Domestically, non-electric property of the Company's subsidiaries and
diversified activities was $335 million and $286 million at December 31, 1995
and 1994, respectively. The Company had equity investments in joint ventures,
which own assets within the United States, of $58 million and $14 million at
December 31, 1995 and 1994, respectively.
Internationally, the Company had equity investments in joint ventures,
which own generation and transmission facilities, of $105 million and $94
million at December 31, 1995 and 1994, respectively. Additionally, the Company,
through its nonregulated subsidiaries, had loaned $23 million to certain of
these joint ventures at December 31, 1995.
The Company's subsidiaries and diversified activities contributed $54
million to net income in 1995 compared with $52 million in 1994 and $22 million
in 1993. From 1993 to 1995, increased developed lot and land sales, and
engineering services and construction fees generated additional income. These
increases were offset by personal communications services joint venture
losses in 1995. Additionally, a one-time gain on the sale of an investment in
preferred stock of an independent power development company in 1994
contributed to the increase in diversified income from 1993 to 1994.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
DUKE POWER COMPANY
INDEX
<TABLE>
<CAPTION>
PAGE
<S> <C>
Consolidated Financial Statements:
Consolidated Statements of Income for the Three Years Ended December 31, 1995. . . . . . . . . . . . . . . .
Consolidated Statements of Retained Earnings for the Three Years Ended December 31, 1995. . . . . . . . . .
Consolidated Statements of Cash Flows for the Three Years Ended December 31, 1995. . . . . . . . . . . . . .
Consolidated Balance Sheets -- December 31, 1995 and 1994. . . . . . . . . . . . . . . . . . . . . . . . . .
Notes to Consolidated Financial Statements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Independent Auditors' Report. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Responsibility for Financial Statements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selected Quarterly Financial Data (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subsidiaries and Diversified Activities Highlights. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Financial Statement Schedule:
Schedule II -- Valuation and Qualifying Accounts and Reserves for the Three Years Ended
December 31, 1995. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
</TABLE>
<PAGE>
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
Dollars in Thousands Year ended December 31, 1995 1994 1993
<S> <C> <C> <C>
OPERATING REVENUES (Notes 1, 2 and 11)............................................ $4,676,684 $4,488,913 $4,466,233
OPERATING EXPENSES
Fuel used in electric generation (Note 1)...................................... 744,226 705,019 732,246
Net interchange and purchased power (Notes 2 and 3)............................ 468,293 553,355 535,125
Other operation and maintenance................................................ 1,403,547 1,341,659 1,254,028
Depreciation and amortization (Note 1)......................................... 458,131 459,781 496,971
General taxes.................................................................. 253,436 249,273 240,052
Total operating expenses.................................................... 3,327,633 3,309,087 3,258,422
OPERATING INCOME................................................................. 1,349,051 1,179,826 1,207,811
INTEREST EXPENSE AND OTHER INCOME (Note 1)
Interest expense............................................................... (289,318) (270,217) (274,051)
Allowance for funds used during construction and other deferred returns........ 125,040 111,872 82,600
Other, net..................................................................... (3,794) 14,414 20,032
Total interest expense and other income..................................... (168,072) (143,931) (171,419)
INCOME BEFORE INCOME TAXES........................................................ 1,180,979 1,035,895 1,036,392
INCOME TAXES (Notes 1 and 4)...................................................... 466,441 397,019 409,977
NET INCOME........................................................................ 714,538 638,876 626,415
Dividends on preferred and preference stock.................................... 48,903 49,724 52,429
EARNINGS FOR COMMON STOCK......................................................... $ 665,635 $ 589,152 $ 573,986
COMMON STOCK DATA (Note 6)
Average shares outstanding (thousands)......................................... 204,859 204,859 204,859
Earnings per share............................................................. $3.25 $2.88 $2.80
Dividends per share............................................................ $2.00 $1.92 $1.84
</TABLE>
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<TABLE>
<CAPTION>
Dollars in Thousands Year ended December 31, 1995 1994 1993
<S> <C> <C> <C>
BALANCE --Beginning of year........................................................ $2,605,920 $2,410,825 $2,223,718
ADD -- Net income.................................................................. 714,538 638,876 626,415
Total.................................................................... 3,320,458 3,049,701 2,850,133
DEDUCT
Dividends
Common stock................................................................ 409,716 393,370 376,937
Preferred and preference stock.............................................. 48,903 49,724 52,429
Capital stock transactions, net................................................ 3,564 687 9,942
Total deductions......................................................... 462,183 443,781 439,308
BALANCE -- End of year............................................................. $2,858,275 $2,605,920 $2,410,825
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Dollars in Thousands Year ended December 31, 1995 1994 1993
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income..................................................................... $ 714,538 $ 638,876 $ 626,415
Adjustments to reconcile net income to net cash provided by operating
activities:
Non-cash items
Depreciation and amortization............................................... 674,816 647,515 664,355
Deferred income taxes and investment tax credit amortization................ 5,989 94,261 62,897
Allowance for equity funds used during construction......................... (23,082) (27,411) (17,221)
Purchased capacity levelization............................................. (33,149) (268,925) (20,049)
Other, net.................................................................. 76,029 22,460 73,607
(Increase) Decrease in
Accounts receivable...................................................... (136,838) 47,586 (37,131)
Inventory................................................................ (14,549) (28,568) 24,904
Prepayments.............................................................. (7,178) (435) (2,396)
Increase (Decrease) in
Accounts payable......................................................... 11,694 (52,506) (28,184)
Taxes accrued............................................................ 14,454 (51,641) 25,797
Interest accrued and other liabilities................................... 28,934 14,523 30,508
Total adjustments........................................................... 597,120 396,859 777,087
Net cash provided by operating activities............................. 1,311,658 1,035,735 1,403,502
CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures and other property additions......................... (713,299) (772,452) (599,759)
Investment in nuclear fuel..................................................... (76,603) (108,711) (111,731)
External funding for decommissioning........................................... (56,470) (52,524) (52,524)
Pre-funded pension cost........................................................ -- (30,000) (50,000)
Investment in joint ventures................................................... (54,945) (6,718) (70,345)
Net change in investment securities............................................ 54,425 17,922 46,489
Net cash used in investing activities................................. (846,892) (952,483) (837,870)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of
First and refunding mortgage bonds.......................................... 173,839 343,824 1,395,682
Preferred stock............................................................. -- -- 215,633
Pollution control bonds..................................................... -- -- 76,265
Short-term notes payable, net............................................... 48,200 86,300 (105,200)
Construction loans and other................................................ 47,643 57,032 13,280
Payments for the redemption of
First and refunding mortgage bonds.......................................... (157,365) (81,781) (1,399,336)
Preferred stock............................................................. (100,516) (1,500) (224,295)
Pollution control bonds..................................................... -- -- (79,310)
Construction loans and other................................................ (9,416) (18,885) (12,454)
Dividends paid................................................................. (458,018) (443,633) (427,868)
Other.......................................................................... (1,153) (20,991) (6,752)
Net cash used in financing activities................................. (456,786) (79,634) (554,355)
Net increase in cash.............................................................. 7,980 3,618 11,277
Cash at beginning of year......................................................... 37,430 33,812 22,535
CASH AT END OF YEAR............................................................... $ 45,410 $ 37,430 $ 33,812
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
<PAGE>
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
Dollars in Thousands December 31, 1995 1994
<S> <C> <C>
CURRENT ASSETS
Cash (Notes 5 and 10)...................................................................... $ 45,410 $ 37,430
Short-term investments (Notes 1 and 10).................................................... 76,300 132,692
Receivables (less allowance for losses: 1995 - $6,352; 1994 - $6,637) (Note 1)............ 689,703 552,865
Inventory -- at average cost............................................................... 341,841 319,385
Prepayments and other...................................................................... 22,900 15,722
Total current assets................................................................. 1,176,154 1,058,094
INVESTMENTS AND OTHER ASSETS
Investments in joint ventures (Note 11).................................................... 163,274 108,330
Other investments, at cost or less (Note 10)............................................... 85,194 83,226
Nuclear decommissioning trust funds (Notes 10 and 14)...................................... 273,466 172,390
Pre-funded pension cost (Note 12).......................................................... 80,000 80,000
Total investments and other assets................................................... 601,934 443,946
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 3, 9, 13 and 14)
Electric plant in service (at original cost)
Production.............................................................................. 7,154,332 6,747,397
Transmission............................................................................ 1,532,302 1,439,435
Distribution............................................................................ 4,105,513 3,965,393
Other................................................................................... 1,030,226 1,020,192
Electric plant in service............................................................ 13,822,373 13,172,417
Less accumulated depreciation and amortization.......................................... 5,122,192 4,810,004
Electric plant in service, net....................................................... 8,700,181 8,362,413
Nuclear fuel............................................................................ 731,691 757,983
Less accumulated amortization........................................................... 453,921 415,560
Nuclear fuel, net.................................................................... 277,770 342,423
Construction work in progress (including nuclear fuel in process:
1995 - $25,500; 1994 - $52,273)......................................................... 382,582 558,730
Total electric plant, net............................................................ 9,360,533 9,263,566
Other property -- at cost (less accumulated depreciation:
1995 - $29,956; 1994 - $24,137)......................................................... 354,713 302,383
Total property, plant and equipment, net............................................. 9,715,246 9,565,949
DEFERRED DEBITS (Notes 1, 3, 4 and 13)
Purchased capacity costs................................................................... 965,473 932,324
Debt expense............................................................................... 180,930 186,306
Regulatory asset related to income taxes................................................... 490,676 489,292
Regulatory asset related to DOE assessment fee............................................. 101,274 102,467
Other...................................................................................... 126,797 83,850
Total deferred debits................................................................ 1,865,150 1,794,239
TOTAL ASSETS.................................................................................. $ 13,358,484 $ 12,862,228
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
<PAGE>
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
Dollars in Thousands December 31, 1995 1994
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable..............................................................................$ 343,692 $ 343,688
Notes payable (Notes 5 and 10)................................................................ 155,300 107,100
Taxes accrued (Note 1)........................................................................ 34,884 29,999
Interest accrued.............................................................................. 73,675 72,157
Current maturities of long-term debt and preferred stock (Notes 8 and 9)...................... 12,071 93,759
Other (Note 13)............................................................................... 149,555 121,539
Total current liabilities............................................................... 769,177 768,242
LONG-TERM DEBT (Notes 5, 9 and 10)............................................................... 3,711,405 3,567,122
ACCUMULATED DEFERRED INCOME TAXES (Notes 1 and 4)................................................ 2,382,204 2,348,631
DEFERRED CREDITS AND OTHER LIABILITIES
Investment tax credit (Notes 1 and 4)......................................................... 261,347 272,594
DOE assessment fee (Note 1)................................................................... 101,274 102,467
Nuclear decommissioning costs externally funded (Note 14)..................................... 273,466 172,390
Other......................................................................................... 390,427 318,453
Total deferred credits and other liabilities............................................ 1,026,514 865,904
PREFERRED AND PREFERENCE STOCK WITH SINKING FUND REQUIREMENTS (Notes 8 and 10)................... 234,000 279,500
PREFERRED AND PREFERENCE STOCK WITHOUT SINKING FUND REQUIREMENTS (Notes 7 and 10)................ 450,000 500,000
COMMITMENTS AND CONTINGENCIES (Note 13)..........................................................
COMMON STOCKHOLDERS' EQUITY (Note 6)
Common stock, no par, 300,000,000 shares authorized;
204,859,339 shares outstanding for 1995 and 1994........................................... 1,926,909 1,926,909
Retained earnings............................................................................. 2,858,275 2,605,920
Total common stockholders' equity....................................................... 4,785,184 4,532,829
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.......................................................$ 13,358,484 $ 12,862,228
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. NATURE OF OPERATIONS
The Company is primarily engaged in the generation, transmission, distribution
and sale of electric energy in the central portion of North Carolina and the
western portion of South Carolina, comprising the area in both states known as
the Piedmont Carolinas. The Company is one of the nation's largest
investor-owned electric utilities.
The Company is also engaged in a variety of diversified operations, most of
which are organized in separate subsidiaries. The Company's subsidiaries and
diversified activities are in the Associated Enterprises Group (AEG). AEG
includes Church Street Capital Corp.; Crescent Resources, Inc.; Duke Energy
Group, Inc.; Duke Engineering & Services, Inc.; Duke/Fluor Daniel; Duke
Merchandising; DukeNet Communications, Inc.; Duke Water Operations; and
Nantahala Power and Light Company. Certain of these subsidiaries have invested
in both domestic and international joint ventures. (See Note 11.)
The 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.
B. REVENUES
Electric revenues are recorded as service is rendered to customers.
"Receivables" on the Consolidated Balance Sheets include $206,792,000 and
$163,270,000 as of December 31, 1995 and 1994, respectively, for electric
service that has been rendered but not yet billed to customers.
C. ADDITIONS TO ELECTRIC PLANT
The Company 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 (allowance for funds used during construction).
The cost of renewals and betterments of units of property is capitalized.
The cost of repairs and replacements representing less than a unit of
property is charged to electric expenses. The original cost of property retired,
together with removal costs less salvage value, is charged to accumulated
depreciation.
D. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds necessary
to finance the construction of new regulated facilities. AFUDC, a non-cash item,
is recognized as a cost of "Construction work in progress," with an offsetting
credit to "Interest expense and other income." After construction is completed,
the Company is permitted to recover these construction costs, including a fair
return, through their inclusion in rate base and in the provision for
depreciation.
The AFUDC rates of 9.3, 9.6 and 9.3 percent for Duke Power for 1995, 1994
and 1993, respectively, include a component for debt cost on a pre-tax basis.
Rates for all periods are compounded semiannually.
E. OTHER DEFERRED RETURNS
Other deferred returns represent the estimated financing costs associated with
funding certain regulatory assets. These regulatory assets primarily arise from
the Company's funding of purchased capacity costs above levels collected in
rates. Other deferred returns are non-cash items. They are primarily recognized
as an addition to "Purchased capacity costs" and as an offsetting credit to
"Interest expense and other income."
F. DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT
Provisions for electric plant depreciation are recorded using the straight-line
method. The year-end composite weighted-average depreciation rates were 3.48,
3.46 and 3.47 percent for 1995, 1994 and 1993, respectively.
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.
Under provisions of the Nuclear Waste Policy Act of 1982, the Company has
entered into contracts with the Department of Energy (DOE) for the disposal of
spent nuclear fuel. 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.
A provision in the Energy Policy Act of 1992 established a fund for the
decontamination and decommissioning of the DOE's uranium enrichment plants.
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 expense. The Company paid $9,205,000 during 1995 and has paid $35,551,000
cumulatively related to its ownership interest in nuclear plants. The Company
has reflected the remaining liability and regulatory asset of $101,274,000 in
the Consolidated Balance Sheets at December 31, 1995.
G. SUBSIDIARIES
The Company's consolidated financial statements reflect consolidation of all of
its majority-owned subsidiaries. Intercompany transactions have been eliminated
in consolidation.
H. INCOME TAXES
The Company and its subsidiaries file a consolidated federal income tax return.
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 future
periods. Investment tax credits have been deferred and are being amortized over
the estimated useful lives of the related properties.
I. UNAMORTIZED DEBT PREMIUM, DISCOUNT AND EXPENSE
Expenses incurred in connection with the issuance of presently outstanding
long-term debt issued for regulated operations, and premiums and discounts
relating to such debt, are being 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 being amortized over the lives of the new issues of long-term
debt.
J. CONSOLIDATED STATEMENTS OF CASH FLOWS
For purposes of the Consolidated Statements of Cash Flows,
the Company's short-term investments in highly liquid debt instruments, with an
original maturity of three months or less, are included in cash flows from
investing activities and thus are not considered cash equivalents.
Total income taxes paid were $441,440,000, $372,416,000 and $354,981,000
for the years ended December 31, 1995, 1994 and 1993, respectively.
Interest paid, net of amounts capitalized, was $258,698,000, $236,696,000
and $249,659,000 for the years ended December 31, 1995, 1994 and 1993,
respectively.
K. COST-BASED REGULATION
As a regulated entity, the Company is subject to the provisions of SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." Accordingly, the
Company 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. Currently, the electric
utility industry is predominantly regulated on a basis designed to recover the
cost of providing electric power to its retail and wholesale 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 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 the affected utilities to write off their
associated regulatory assets. The regulatory assets of the Company are
classified as "Deferred debits" on the Consolidated Balance Sheets.
Substantially all of the "Deferred debits" are regulatory assets. Management
cannot predict the potential impact, if any, of these competitive forces on the
Company's future financial position and results of operations. However, the
Company continues to position itself to effectively meet these challenges by
maintaining prices that are locally, regionally and nationally competitive.
NOTE 2. RATE MATTERS
DUKE POWER COMPANY
The North Carolina Utilities Commission (NCUC) and the Public Service Commission
of South Carolina must approve rates for retail sales within their respective
states. The Federal Energy Regulatory Commission (FERC) must approve Duke
Power's rates for sales to wholesale customers. Sales to the other joint owners
of the Catawba Nuclear Station, which represent a substantial majority of Duke
Power's wholesale revenues, are set through contractual agreements. (See Note
3.)
The most recent general rate increase requests in the Company's retail
jurisdictions were filed and approved in 1991. The Company also filed its most
recent general rate increase request within the FERC wholesale jurisdiction in
1991. A negotiated settlement between the Company and the wholesale customers
was approved by the FERC in 1992.
Fuel costs are reviewed semiannually in the wholesale and South Carolina
retail jurisdictions, 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 Duke Power to adjust rates for past over- or
under-recovery of fuel costs. Therefore, Duke Power reflects in revenues the
difference between actual fuel costs incurred and fuel costs recovered through
rates.
A bill ratified by the North Carolina legislature in 1987 to assure the
legality of such adjustments in rates had its expiration provision repealed in
March 1995.
Duke Power has a bulk power sales agreement with Carolina Power & Light
Company (CP&L) to provide CP&L 400 megawatts of capacity as well as associated
energy when needed for a six-year period which began July 1, 1993. Electric
rates in all regulatory jurisdictions were reduced by adjustment riders to
reflect capacity revenues received from this CP&L bulk power sales agreement.
NANTAHALA POWER AND LIGHT COMPANY
During 1992, Nantahala Power and Light Company (NP&L) filed an application for a
general rate increase with the NCUC. A general rate increase was approved in
June 1993 which resulted in additional annual revenues of $4.3 million.
Purchased power costs of NP&L are reviewed annually and during general rate case
proceedings by the NCUC. NP&L is allowed to adjust rates for past over- or
under-recovery of purchased power costs. Therefore, NP&L defers the difference
between actual purchased power costs incurred and those recovered through rates.
NOTE 3. JOINT OWNERSHIP OF GENERATING FACILITIES
The Company previously sold interests in both units of the Catawba Nuclear
Station. The other owners of portions of the Catawba Nuclear Station and
supplemental information regarding their ownership are as follows:
Ownership Interest
Owner 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 the
station.
The Company retains a 12.5 percent ownership interest in the Catawba Nuclear
Station. As of December 31, 1995, $499,209,000 of "Electric plant in service"
and "Nuclear fuel" represents the Company's investment in Units 1 and 2.
Accumulated depreciation and amortization of $185,264,000 associated with
Catawba has been recorded as of year-end. The Company's share of operating costs
of Catawba is included in the Consolidated Statements of Income.
In connection with the joint ownership, the Company has entered into
contractual 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. Unit 1 and Unit 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
Company 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 will
occur in 1996 for Unit 2. Certain provisions in the agreements with NCEMC and
Saluda River have moderated the rate of decrease in the percentage of capacity
and energy that the Company is obligated to purchase until 1996 when the Company
has no further obligation to purchase capacity and related energy.
The agreements also provide for supplemental power sales by the Company 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. As the joint
owners retain more capacity and energy from Catawba, or a third party,
supplemental power sales are expected to decline.
The agreements with each of the other joint owners include provisions that
the Company 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 the Catawba Nuclear Station and the McGuire Nuclear
Station, impacting the Company as well as all the other joint owners.
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 1995 and
projected obligations for 1996 through 2000, including the impact of the 1995
settlement agreement with NCMPA and PMPA (See Note 13), are as follows (dollars
in thousands):
PURCHASED CAPACITY PURCHASED CAPACITY TOTAL PURCHASED
YEAR CAPITAL COST FIXED O&M CAPACITY
1995 Actual $237,978 $83,358 $321,336
1996 Projected $ 83,870 $41,510 $125,380
1997 Projected $ 65,803 $35,042 $100,845
1998 Projected $ 47,609 $26,541 $ 74,150
1999 Projected $ 34,752 $19,646 $ 54,398
2000 Projected $ 4,217 $ 2,542 $ 6,759
Effective in its November 1991 rate order, the North Carolina Utilities
Commission reaffirmed the Company's recovery, on a levelized basis, of the
capital costs and fixed operating and maintenance costs of capacity purchased
from the other joint owners. The Public Service Commission of South Carolina in
its November 1991 rate order reaffirmed the Company'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 Federal Energy Regulatory Commission (FERC). The portion of purchased
capacity subject to levelization not currently recovered in rates is being
deferred, and the Company is recording a return on the accumulated balance. The
Company recovers the accumulated balance, including the
return, when the sum of the declining purchased capacity payments and accrual of
returns for the current period drops below the levelized revenues.
Jurisdictional levelizations are intended to recover total costs, including
returns, and are subject to adjustments, including final true-ups. The Company
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 Company's last general rate
proceedings are $211,423,000, $94,137,000 and $6,815,000 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 and 2 percent for North Carolina
retail, South Carolina retail and Other Wholesale (FERC), respectively. The
Company 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.
In 1995, in the North Carolina retail and FERC wholesale jurisdictions,
purchased capacity payments and the accrual of deferred returns continued to
exceed levelized revenues. However, in 1996, the levelized revenues are expected
to exceed the purchased capacity payments and accrual of deferred returns. 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, 1995, 1994 and 1993, the Company recorded
purchased capacity and energy costs from the other joint owners of $388,246,000,
$604,505,000 and $547,899,000, 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, 1995 and 1994, $965,473,000 and $932,324,000,
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."
NOTE 4. INCOME TAX EXPENSE
Accumulated deferred income taxes consist primarily of the following (dollars in
thousands):
<TABLE>
<CAPTION>
December 31, 1995 December 31, 1994
<S> <C> <C> <C> <C>
Excess tax over book depreciation at historical tax rates $ 1,387,925 $ 1,343,605
Regulatory liability related to adjusting deferred taxes
to the current statutory tax rate .................... (114,538)* (120,422)*
Net excess tax over book depreciation .............. $ 1,273,387 $ 1,223,183
Regulatory asset related to restating to a pre-tax basis 605,214* 609,714*
Deferred Catawba purchased capacity costs ............... 374,112 361,018
Book versus tax basis difference ........................ 60,443 89,058
Loss on bond redemptions ................................ 68,135 70,067
Other ................................................... 913 (4,409)
Total deferred income taxes ........................ $ 2,382,204 $ 2,348,631
</TABLE>
* The net regulatory asset related to income taxes is $490,676,000 for 1995 and
$489,292,000 for 1994.
Total deferred income tax liability was $2,946,711,000 as of December 31, 1995,
and $2,873,373,000 as of December 31, 1994. Total deferred income tax asset was
$564,507,000 as of December 31, 1995, and $524,742,000 as of December 31, 1994.
Income tax expense for the years ended December 31, 1995, 1994 and 1993
consisted of the following (dollars in thousands):
<TABLE>
<CAPTION>
1995 1994 1993
<S> <C> <C> <C>
Current income taxes
Federal.................................................................... $377,237 $249,968 $283,930
State...................................................................... 83,215 52,790 63,150
Total current income taxes................................................ 460,452 302,758 347,080
Deferred taxes, net
Federal.................................................................... 13,466 83,359 59,267
State...................................................................... 3,770 22,153 14,887
Total deferred taxes, net................................................. 17,236 105,512 74,154
Investment tax credit amortization........................................... (11,247) (11,251) (11,257)
Total income tax expense.................................................. $466,441 $397,019 $409,977
</TABLE>
Income taxes differ from amounts computed by applying the statutory tax rate to
pre-tax income for the years ended December 31, 1995, 1994 and 1993 as follows
(dollars in thousands):
<TABLE>
<CAPTION>
1995 1994 1993
<S> <C> <C> <C>
Income taxes on pre-tax income at the statutory federal rate of 35%....... $413,343 $362,563 $362,737
Increase (reduction) in tax resulting from:
Allowance for funds used during construction (AFUDC).................... (8,079) (9,594) (6,027)
Amortization of investment tax credit deferrals......................... (11,247) (11,251) (11,257)
AFUDC in book depreciation/amortization................................. 21,057 19,027 25,694
Deferred income tax flowback at rates higher than statutory............. (5,675) (5,530) (9,091)
State income taxes, net of federal income tax benefits.................. 56,210 47,872 51,289
Other items, net........................................................ 832 (6,068) (3,368)
Total income tax expense......................................... $466,441 $397,019 $409,977
</TABLE>
NOTE 5. SHORT-TERM BORROWINGS AND CREDIT FACILITIES
The following credit facilities were available to the Company at December 31,
1995 and 1994, with 25 and 26 commercial banks, respectively:
<TABLE>
<CAPTION>
Line of Credit at Outstanding at Line of Credit at Outstanding at
Type of Facility December 31, 1995 December 31, 1995 December 31, 1994 December 31, 1994
<S> <C> <C> <C> <C>
Annually renewable lines of credit $ 64,900,000 $ 29,300,000 $ 44,980,000 $ 10,100,000
Two-year revolving facilities (a) 40,000,000 -- 40,000,000 --
Three-year revolving facilities (b) 355,000,000 -- 355,000,000 --
Four-year revolving facilities (c) 210,000,000 30,043,000 -- --
$669,900,000 $59,343,000 $439,980,000 $10,100,000
</TABLE>
(a) The Company had $40,000,000 in pollution control bonds, included in
long-term debt, outstanding throughout 1995 and 1994 backed by the unused
portion of these facilities.
(b) The Company had $130,000,000 in commercial paper, included in long-term
debt, outstanding throughout 1995 and 1994 backed by the unused portion of these
facilities.
(c) The outstanding balance of $30,043,000 is included in long-term debt.
Cash balances maintained at the banks on deposit were $17,120,000 as of
December 31, 1995, and $13,214,000 as of December 31, 1994. Cash balances and
fees compensate banks for their services, even though the Company has no formal
compensating-balance arrangements. To compensate certain banks for credit
facilities, the Company maintained balances of $45,000 and $49,000 as of
December 31, 1995 and 1994, respectively. The Company retains the right of
withdrawal with respect to the funds used for compensating-balance arrangements.
A summary of short-term borrowings is as follows (dollars in thousands):
<TABLE>
<CAPTION>
Twelve Months Ended
December 31, 1995 December 31, 1994 December 31, 1993
<S> <C> <C> <C>
Amount outstanding at end of period -- average rate of 5.91% as of December 31,
1995, 6.02% as of December 31, 1994,
and 3.55% as of December 31, 1993............................. $ 155,300 $ 107,100 $ 20,800
Maximum amount outstanding during the period .................... $ 264,300 $ 143,400 $ 180,800
Average amount outstanding during the period .................... $ 88,470 $ 24,161 $ 35,366
Weighted-average interest rate for the period -- computed
on a daily basis.............................................. 6.05% 4.58% 3.19%
</TABLE>
NOTE 6. COMMON STOCK AND RETAINED EARNINGS
Common Stock
As of December 31, 1995, a total of 7,004,659 shares was reserved for issuance
for stock plans.
Retained Earnings
As of December 31, 1995, substantially all of the Company's retained earnings
were unrestricted as to the declaration or payment of dividends.
NOTE 7. PREFERRED AND PREFERENCE STOCK WITHOUT SINKING FUND REQUIREMENTS
The following shares of stock were authorized with or without sinking fund
requirements as of December 31, 1995 and 1994:
<TABLE>
<CAPTION>
Par Value Shares
<S> <C> <C>
Preferred Stock $100 12,500,000
Preferred Stock A 25 10,000,000
Preference Stock 100 1,500,000
</TABLE>
As of December 31, 1995 and 1994, there were no shares of preference stock
outstanding. Preferred stock without sinking fund requirements as of December
31, 1995 and 1994, was as follows (dollars in thousands):
<TABLE>
<CAPTION>
Year Shares
Rate/Series Issued Outstanding 1995 1994
<S> <C> <C> <C> <C> <C>
4.50% C ............................................................ 1964 350,000 $ 35,000 $ 35,000
5.72% D............................................................. 1966 350,000 35,000 35,000
6.72% E ............................................................ 1968 350,000 35,000 35,000
7.85% S ............................................................ 1992 600,000 60,000 60,000
7.00% W............................................................. 1993 500,000 50,000 50,000
7.04% Y............................................................. 1993 600,000 60,000 60,000
7.72% (Preferred Stock A)................................................ 1992 1,600,000 40,000 40,000
6.375% (Preferred Stock A)............................................... 1993 2,400,000 60,000 60,000
Adjustable Rate A........................................................ 1986 500,000 -- 50,000
Auction Series A......................................................... 1990 750,000 75,000 75,000
Total.............................................................. $450,000 $500,000
</TABLE>
NOTE 8. PREFERRED AND PREFERENCE STOCK WITH SINKING FUND REQUIREMENTS
The following shares of stock were authorized with or without sinking fund
requirements as of December 31, 1995 and 1994:
Par Value Shares
Preferred Stock $100 12,500,000
Preferred Stock A 25 10,000,000
Preference Stock 100 1,500,000
As of December 31, 1995 and 1994, there were no shares of preference stock
outstanding. Preferred stock with sinking fund requirements as of December 31,
1995 and 1994, was as follows (dollars in thousands):
<TABLE>
<CAPTION>
Year Shares
Rate/Series Issued Outstanding 1995 1994
<S> <C> <C> <C> <C> <C>
5.95% B (Preferred Stock A) ........................................ 1992 800,000 $ 20,000 $ 20,000
6.10% C (Preferred Stock A) ........................................ 1992 800,000 20,000 20,000
6.20% D (Preferred Stock A) ........................................ 1992 800,000 20,000 20,000
7.12% Q............................................................. 1987 470,000 -- 47,000
7.50% R............................................................. 1992 850,000 85,000 85,000
6.20% T............................................................. 1992 130,000 13,000 13,000
6.30% U............................................................. 1992 130,000 13,000 13,000
6.40% V............................................................. 1992 130,000 13,000 13,000
6.75% X............................................................. 1993 500,000 50,000 50,000
Less: Current sinking fund requirements
7.12% Q.............................................................. -- (1,500)
Total.............................................................. $234,000 $279,500
</TABLE>
The annual sinking fund requirements through 2000 are $0 in 1996 and 1997,
$4,250,000 in 1998, $24,250,000 in 1999 and $37,250,000 in 2000. Some additional
redemptions are permitted at the Company's option.
The call provisions for the outstanding preferred stock specify various
redemption prices not exceeding 105 percent of par value, plus accumulated
dividends to the redemption date.
NOTE 9. LONG-TERM DEBT
Long-term debt outstanding as of December 31, 1995 and 1994, was as follows
(dollars in thousands):
<TABLE>
<CAPTION>
Series Year Due 1995 1994
<S> <C> <C> <C>
FIRST AND REFUNDING MORTGAGE BONDS:
6.47%-6.60% 1995 $ -- $ 40,300
4 1/2% 1995 -- 40,000
6.59% 1996 3,000 3,000
5 3/8% 1997 72,600 72,600
5 5/8% 1997 100,000 100,000
5.17% 1998 50,000 50,000
7.5% 1999 100,000 100,000
6 1/4% 1999 65,000 65,000
5.76% 1999 5,000 5,000
5.78% 1999 25,000 25,000
5.79% 1999 30,000 30,000
8% B 1999 200,000 200,000
7% 2000 100,000 100,000
7% B 2000 100,000 100,000
5 7/8% 2001 150,000 150,000
6 5/8% B 2003 100,000 100,000
5 7/8% C 2003 75,000 75,000
6.125% 2003 75,000 75,000
8% 2004 75,000 75,000
6 1/4% B 2004 100,000 100,000
7.37%-7.41% 2004 100,000 100,000
7% 2005 200,000 200,000
6 3/8% 2008 125,000 125,000
9 5/8% 2020 -- 46,982
10 1/8% B 2020 -- 24,854
8 3/4% 2021 150,000 150,000
8 3/8% B 2021 150,000 150,000
8 5/8% 2022 100,000 100,000
7 3/8% 2023 200,000 200,000
6 7/8% B 2023 200,000 200,000
7 7/8% 2024 150,000 150,000
6 3/4% 2025 150,000 150,000
7 1/2% B 2025 $ 100,000 $ --
8.27% 2025 21,000 --
8.27 % 2025 50,000 --
8.28% 2025 2,000 --
8.30% 2025 5,000 --
8.95% 2027 15,681 15,769
7% 2033 150,000 150,000
POLLUTION CONTROL BONDS:
7.70% 2012 20,000 20,000
7.75% B 2017 10,000 10,000
7.50% 2017 25,000 25,000
3.76% 2014 40,000 40,000
5.80% 2014 77,000 77,000
Subtotal 3,466,281 3,440,505
OTHER LONG-TERM DEBT:
Capitalized leases 7,477 26,039
Other long-term debt 147,410 130,000
Unamortized debt discount
and premium, net (61,674) (62,918)
Current maturities of
long-term debt (4,295) (81,926)
Subtotal (a) 3,555,199 3,451,700
SUBSIDIARY LONG-TERM DEBT:
Crescent Resources, Inc. (b) 130,694 92,102
Nantahala Power and Light 33,288 33,653
Current maturities of
long-term debt (7,776) (10,333)
Subtotal 156,206 115,422
Total long-term debt $3,711,405 $3,567,122
</TABLE>
(a) Substantially all of Duke Power's Electric Plant was mortgaged as of
December 31, 1995.
(b) Substantial amounts of Crescent Resources, Inc.'s Real Estate Development
projects, land and buildings are pledged as collateral.
As of December 31, 1995 and 1994, the Company had $40,000,000 in pollution
control revenue bonds backed by an unused, two-year revolving credit facility of
$40,000,000. In addition, the Company had $130,000,000 in commercial paper
outstanding throughout 1995 and 1994 backed by unused three-year revolving
credit facilities. These facilities are on a fee basis. Both the $40,000,000 in
pollution control bonds and the $130,000,000 in commercial paper are included in
long-term debt.
As of December 31, 1995, Crescent Resources, Inc. had $65,526,000 in
mortgage loans which mature through 2000 and $35,125,000 in mortgage loans
maturing in 2001 or thereafter. Additionally, Crescent Resources, Inc. had
$30,043,000 outstanding at December 31, 1995, included in long-term debt on a
$50,000,000 four-year revolving credit facility. Interest rates are variable and
at December 31, 1995, ranged from 5.50 percent to 7.10 percent. As of December
31, 1995, Nantahala Power and Light Company had $33,000,000 in senior notes
maturing in 2011 and 2012. The two notes carry fixed interest rates of 9.21
percent and 7.45 percent and require monthly payments of principal beginning in
1997 and 1998, respectively.
The annual maturities of consolidated long-term debt, including capitalized
lease principal payments through 2000, are $12,071,000 in 1996; $215,476,000 in
1997; $63,097,000 in 1998; $473,326,000 in 1999; and $206,583,000 in 2000.
NOTE 10. FINANCIAL INSTRUMENTS
The carrying amounts of "Cash," "Short-term investments," and "Notes payable" on
the Consolidated Balance Sheets approximate fair value primarily because of the
short maturities of these instruments. "Other investments" substantially consist
of notes receivable issued at fixed rates with maturities up to 30 years for
which there are no quoted market prices. Due to the numerous outstanding notes,
it was not practicable or cost beneficial for the Company to estimate the fair
value of these instruments. The majority of estimated fair value amounts of
long-term debt and preferred stock as disclosed below were obtained from
independent parties. Judgment is required in interpreting market data to develop
the estimates of fair value. Accordingly, the estimates determined as of
December 31, 1995 and 1994, are not necessarily indicative of the amounts the
Company could have realized in current market exchanges.
External funds have been established, as required by the Nuclear Regulatory
Commission, as a mechanism to fund certain costs of nuclear decommissioning.
(See Note 14.) Currently, these nuclear decommissioning trust funds are invested
in U.S. stocks, bonds and cash equivalents. "Nuclear decommissioning trust
funds" are presented on the Consolidated Balance Sheets at amounts that
approximate fair value.
The carrying amounts and estimated fair values of long-term debt and preferred
stocks are as follows (dollars in thousands):
<TABLE>
<CAPTION>
December 31, 1995 December 31, 1994
Carrying Amount Fair Value Carrying Amount Fair Value
<S> <C> <C> <C> <C>
Long-term debt............................. $3,777,672 $3,879,000 $3,696,260 $3,392,000
Preferred stock............................ $ 684,000 $ 689,000 $ 781,000 $ 697,000
</TABLE>
In order to obtain variable rate financing at an attractive cost, the Company
entered into interest rate swap agreements associated with the November 29,
1994, issuance of $200 million aggregate principal amount of its First and
Refunding Mortgage Bonds, 8% Series B due 1999 and the August 21, 1995, issuance
of $100 million aggregate principal amount of its First and Refunding Mortgage
Bonds, 7 1/2% Series B due 2025. The interest rate swaps are reset quarterly
based upon the London Interbank Offered Rate (LIBOR). 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 the
LIBOR rate.
The weighted average rates are as follows (dollars in thousands):
Weighted Average Rate
Series Year Due Face Value 1995 1994
8% Series B 1999 $200,000 6.14% 5.95%
7 1/2% Series B 2025 $100,000 7.06% --
The Company also entered into a hedge transaction to offset currency
fluctuations between the U.S. dollar and the Japanese yen associated with
various steam generator contracts. The hedge transaction, with a notional amount
of approximately $25 million at December 31, 1994, was fully liquidated by
November 1995. The Company recorded any gains or losses associated with the
hedge as an adjustment to the capitalized cost of the steam generators.
Duke Energy Group, Inc. has entered into a hedge transaction to offset
currency fluctuations between the U.S. dollar and the Chilean peso associated
with expected equity contributions over the next two years to a joint venture.
The hedge transaction had a notional amount of approximately $17 million at
December 31, 1995. Duke Energy Group, Inc. records any gains or losses
associated with the hedge as an adjustment to investments in joint ventures.
NOTE 11. INVESTMENTS IN JOINT VENTURES
Certain investments in joint ventures are accounted for by the equity method.
The Company's ownership in domestic and international joint ventures is 50
percent or less. The Company's proportionate share of net income in joint
ventures for the years ended December 31, 1995, 1994 and 1993 was $9,237,000,
$7,049,000 and $2,601,000, respectively. These amounts are reflected in
"Operating revenues" on the Consolidated Statements of Income.
A summary of assets and liabilities of joint ventures follows (dollars in
thousands):
<TABLE>
<CAPTION>
December 31, 1995 December 31, 1994
Company's Company's
Proportionate Proportionate
Total Share Total Share
<S> <C> <C> <C> <C>
Assets of joint ventures........................................ $1,445,600 $351,376 $1,117,449 $272,836
Liabilities of joint ventures................................... $ 615,452 $188,102 $ 504,029 $164,506
</TABLE>
Of the $615,452,000 and $504,029,000 of total liabilities outstanding at
December 31, 1995 and 1994, respectively, $528,289,000 and $407,605,000
represent non-recourse debt at December 31, 1995 and 1994, respectively, for
which the Company bears no responsibility beyond the loss of its investment and
loans made to certain joint ventures in the event the joint venture defaults on
the debt. These loans were approximately $23,170,000 at December 31, 1995.
NOTE 12. RETIREMENT BENEFITS
A. RETIREMENT PLAN
The Company and its operating subsidiaries, with the exception of Nantahala
Power and Light Company, which maintains its own retirement plans, have a
non-contributory, defined benefit retirement plan covering substantially all
their employees. The benefit is based upon an age-related formula which takes
into account years of creditable service and the employee's average compensation
based upon the highest compensation during a consecutive sixty-month period. The
benefit is reduced by an adjustment which is based upon the employee's social
security wages. Normal retirement age under the Plan is age 65; however, early
retirement benefits are payable as early as age 55 with 10 years of creditable
service or age 51 if the employee has at least 30 years of creditable service.
The Company's policy is to fund pension costs as accrued. During 1994, the
Company made additional contributions of $30,000,000 to enhance the funded
position of the plan.
Net periodic pension cost for the years ended December 31, 1995, 1994 and 1993,
include the following components (dollars in thousands):
<TABLE>
<CAPTION>
1995 1994 1993
<S> <C> <C> <C> <C> <C> <C>
Service cost benefit earned during the year.............. $ 46,402 $43,098 $39,514
Interest cost on projected benefit obligation............ 111,110 96,521 93,347
Actual return on plan assets.............................(253,314) (6,138) (117,898)
Amount deferred for recognition.......................... 144,022 (86,995) 35,652
Expected return on plan assets........................... (109,292) (93,133) (82,246)
Net amortization......................................... 6,161 7,657 4,137
Net periodic pension cost.......................... $ 54,381 $54,143 $54,752
</TABLE>
A reconciliation of the funded status of the plan to the amounts recognized in
the Consolidated Balance Sheets as of December 31, 1995 and 1994, is as follows
(dollars in thousands):
<TABLE>
<CAPTION>
1995 1994
<S> <C> <C>
Accumulated benefit obligation:
Vested benefits............................................................................... $ (1,289,459) $ (1,070,355)
Nonvested benefits............................................................................ (6,216) (4,420)
Accumulated benefit obligation............................................................. $ (1,295,675) $ (1,074,775)
Fair market value of plan assets,
consisting primarily of short-term investments and cash equivalents,
common stocks, real estate investments and government and industrial bonds ................... $ 1,424,148 $ 1,167,158
Projected benefit obligation .................................................................... (1,596,747) (1,368,740)
Unrecognized net experience loss ................................................................ 286,837 319,519
Unrecognized prior service cost reduction ....................................................... (35,039) (38,872)
Remaining unrecognized transitional obligation .................................................. 801 935
Pre-funded pension cost ................................................................... $ 80,000 $ 80,000
</TABLE>
In determining the projected benefit obligation, the weighted-average assumed
discount rate used was 7.50 percent in 1995, 8.25 percent in 1994 and 7.50
percent in 1993. The assumed increase in future compensation level is determined
on an age-related basis. The weighted-average salary increase was 4.75 percent
in 1995, 5.40 percent in 1994 and 4.50 percent in 1993. The expected long-term
rate of return on plan assets used in determining pension cost was 9.00 percent
in 1995, 9.00 percent in 1994 and 8.40 percent in 1993.
During 1995, the Company offered to certain employees an Enhanced Vested
Benefits program (EVB). The Company recorded an additional one-time expense for
special termination benefits associated with EVB of approximately $42,196,000,
including $21,600,000 of additional retirement plan costs.
During 1993, the Company offered an enhanced early retirement option, Limited
Period Separation Opportunity (LPSO), for eligible employees. The Company
recorded an additional one-time expense for special termination benefits
associated with LPSO of approximately $7,611,000.
B. POSTRETIREMENT BENEFITS
The Company and its operating subsidiaries, with the exception of Nantahala
Power and Light Company (NP&L), which has maintained its own postretirement
benefit plans, currently provide certain health care and life insurance benefits
for retired employees. However, NP&L employees who retire after January 1, 1996,
will be covered by Duke Power Company's postretirement benefit plan. Employees
become eligible for these benefits if they retire at age 55 or greater with 10
years of service or if they retire as early as age 51 with 30 years or more of
service. Employees retiring after January 1, 1992, receive a fixed Company
allowance, based on years of service, to be used to pay medical insurance
premiums. The Company reserves the right to terminate, suspend, withdraw, amend
or modify the plans in whole or in part at any time.
In 1992, the Company commenced funding the maximum amount allowable under
section 401(h) of the Internal Revenue Code, which provides for tax deductions
for contributions and tax-free accumulation of investment income. Such amounts
partially fund the Company's medical and dental postretirement benefits. The
Company has also established a Retired Lives Reserve, which has tax attributes
similar to 401(h) funding, to partially fund its postretirement life insurance
obligation. The Company contributed $23,000,000 into these funding mechanisms in
1995 and $12,269,000 in 1994.
Net periodic postretirement benefit cost for the years ended December 31, 1995,
1994 and 1993, include the following components
(dollars in thousands):
<TABLE>
<CAPTION>
1995 1994 1993
<S> <C> <C> <C> <C> <C> <C>
Service cost benefit earned during the year.................... $ 5,874 $ 5,415 $ 4,974
Interest cost on accumulated postretirement benefit obligation. 27,201 25,321 25,482
Actual return on plan assets................................... (14,726) (1,451) (4,143)
Amount deferred for recognition................................ 7,260 (3,469) 334
Expected return on plan assets................................. (7,466) (4,920) (3,809)
Straight-line -- 20 year amortization of transitional obligation 13,293 13,293 13,479
Other amortization............................................. 555 366 278
Net periodic postretirement benefit cost.................... $ 39,457 $ 39,475 $ 40,404
</TABLE>
A reconciliation of the funded status of the plan to the amounts recognized in
the Consolidated Balance Sheets as of December 31, 1995 and 1994, is as follows
(dollars in thousands):
<TABLE>
<CAPTION>
<S> <C> <S> <C> <C>
Fair market value of plan assets, 1995 1994
consisting primarily of short-term investments and cash equivalents, common
stocks, real estate investments and government and industrial bonds...... $ 105,506 $ 69,987
Actives eligible to retire..................................................... (25,780) (11,902)
Actives not eligible to retire................................................. (97,389) (90,499)
Retirees and surviving spouses.................................................(253,688) (239,978)
Accumulated postretirement benefit obligation ................................. (376,857) (342,379)
Unrecognized prior service cost................................................ 712 783
Unrecognized net experience loss .............................................. 25,955 14,448
Unrecognized transitional obligation........................................... 212,695 225,988
(Accrued) postretirement benefit cost....................................... $ (31,989) $ (31,173)
</TABLE>
In determining the accumulated postretirement benefit obligation (APBO), the
weighted-average assumed discount rate used was 7.50 percent in 1995, 8.25
percent in 1994 and 7.50 percent in 1993. The assumed increase in future
compensation level is determined on an age-related basis. The weighted-average
salary increase was 4.75 percent in 1995, 5.40 percent in 1994 and 4.50 percent
in 1993. The expected long-term rate of return on 401(h) assets used in
determining postretirement benefits cost was 9.00 percent in 1995, 9.00 percent
in 1994 and 8.40 percent in 1993. For Retired Lives Reserve assets, 8.00 percent
was used in 1995, 6.50 percent in 1994 and 7.13 percent in 1993.
The assumed medical inflation rate was approximately 10.5 percent in 1995.
This rate decreases by 0.5 percent to 1.0 percent per year until a rate of 5.5
percent is achieved in the year 2001, which remains fixed thereafter.
A 1.0 percent increase in the medical and dental trend rates produces a 4.81
percent ($1,589,000) increase in the aggregate service and interest cost. The
increase in the APBO attributable to a 1.0 percent increase in the medical and
dental trend rates is 9.22 percent ($38,281,000) as of December 31, 1995.
NOTE 13. COMMITMENTS AND CONTINGENCIES
A. CONSTRUCTION PROGRAM
Projected construction and nuclear fuel costs for Duke Power's electric
operations, both including allowance for funds used during construction, are
$2.3 billion and $661 million, respectively, for 1996 through 2000. These
projections are subject to periodic review and revisions. Actual construction
and nuclear fuel costs and capital expenditures incurred may vary from such
estimates. Cost variances are due to various factors, including revised load
estimates, environmental matters and cost and availability of capital.
Projected capital expenditures of subsidiaries and diversified activities
are $1.0 billion for 1996 through 2000. These projections are subject to
periodic review and revisions and may vary significantly as the business plans
of the Associated Enterprises Group evolve to meet the opportunity presented by
its markets.
B. NUCLEAR INSURANCE
The Company maintains nuclear insurance coverage in three areas: liability
coverage, property, decontamination and decommissioning coverage, and extended
accidental outage coverage to cover increased generating costs and/or
replacement power purchases. The Company is being reimbursed by the other joint
owners of the Catawba Nuclear Station for certain expenses associated with
nuclear insurance premiums paid by the Company.
Pursuant to the Price-Anderson Act, the Company is required to insure
against public liability claims resulting from nuclear incidents to the full
limit of liability of approximately $8.9 billion. The maximum required private
primary insurance of $200 million has been purchased along with a like amount to
cover certain worker tort claims. The remaining amount, currently $8.7 billion,
which will be increased by $79.3 million as each additional commercial nuclear
reactor is licensed, has been provided through a mandatory industry-wide excess
secondary insurance program of risk pooling. The $8.7 billion could also be
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. This amount is
further subject to a surcharge of 5 percent (which is included in the above $8.7
billion figure) if funds are insufficient to pay claims and associated costs. If
retrospective premiums were to be assessed, the other joint owners of the
Catawba Nuclear Station are obligated to assume their pro rata share of such
assessment.
The Company is a member of Nuclear Mutual Limited (NML), which provides $500
million in primary property damage coverage for each of the Company's nuclear
facilities. If NML's losses ever exceed its reserves, the Company will be
liable, on a pro rata basis, for additional assessments of up to $36 million.
This amount represents 5 times the Company's annual premium to NML. The other
joint owners of Catawba are obligated to assume their pro rata share of any
liability for retrospective premiums and other premium assessments resulting
from the NML policies applicable to Catawba.
The Company is also a member of Nuclear Electric Insurance Limited (NEIL)
and purchases insurance through NEIL's excess property, decontamination and
decommissioning liability insurance program. NEIL provides excess insurance
coverage of $2.25 billion for the Catawba Nuclear Station and $1.5 billion for
each of the Oconee and McGuire Nuclear Stations. If losses ever exceed the
accumulated funds available to NEIL for the excess property, decontamination and
decommissioning liability program, the Company will be liable, on a pro rata
basis, for additional assessments of up to $61 million. This amount is limited
to 7.5 times the Company's annual premium to NEIL for excess property,
decontamination and decommissioning liability insurance. The other joint owners
of Catawba are obligated to assume their pro rata share of any liability for
retrospective premiums and other premium assessments resulting from the NEIL
policies applicable to Catawba.
The Company participates in a NEIL program that provides insurance for the
increased cost of generation and/or purchased power resulting from an accidental
outage of a nuclear unit. Each unit of the Oconee, McGuire and Catawba Nuclear
Stations is insured for up to approximately $3.5 million per week, after a
21-week deductible period, with declining amounts per unit where more than one
unit is involved in an accidental outage. Coverages continue at 100 percent for
52 weeks and 80 percent for the next 104 weeks. If NEIL's losses for this
program ever exceed its reserves, the Company will be liable, on a pro rata
basis, for additional assessments of up to $30 million. This amount represents 5
times the Company's annual premium to NEIL for insurance for the increased cost
of generation and/or purchased power resulting from an accidental outage of a
nuclear unit. The other joint owners of Catawba are obligated to assume their
pro rata share of any liability for retrospective premiums and other premium
assessments resulting from the NEIL policies applicable to the joint ownership
agreements.
C. OTHER
The Company and North Carolina Municipal Power Agency Number 1 and Piedmont
Municipal Power Agency, two of the four other joint owners of the Catawba
Nuclear Station, entered into a settlement in September 1995 which resolved
outstanding issues related to how certain calculations affecting bills under the
Catawba joint ownership contractual agreements should be performed. The
settlement was approved by the North Carolina Utilities Commission on January
16, 1996 and the Public Service Commission of South Carolina on January 23,
1996. As part of the settlement, the Company agreed to purchase additional
megawatts (MW) of Catawba capacity during the period 1996 through 1999 and
remove certain restrictions related to sales of surplus energy by these two
joint owners. The additional capacity purchases are 215 MW in 1996, 165 MW in
1997, 120 MW in 1998 and 100 MW in 1999. The Company expects to recover the
costs associated with this settlement as part of the purchased capacity
levelization, consistent with prior orders of the retail regulatory commissions.
Therefore, the Company believes these matters should not have a material adverse
effect on the results of operations or financial position of the Company.
The Company and all four of the other joint owners of the Catawba Nuclear
Station entered into settlement agreements in 1994 which resolved all issues in
contention in arbitration proceedings related to the Catawba joint ownership
contractual agreements. The basic contention in each proceeding was that certain
calculations affecting bills under these agreements should be performed
differently. These items are covered by the agreements between the Company and
the other Catawba joint owners which have been previously approved by the
Company's retail regulatory commissions. (For additional information, see Note
3.) In 1994, the Company settled its cumulative net obligation through 1993 of
approximately $205 million related to these settlement agreements. Billings for
1994 and later years will conform to the settlement agreements, which have been
approved by the Company's retail regulatory commissions. Because the Company
expects the costs associated with these settlements to be recovered as part of
the purchased capacity levelization, which has been approved by the Company's
retail regulatory commissions, the Company included approximately $205 million
as an increase to "Purchased capacity costs" on its Consolidated Balance Sheets
in 1994. Therefore, the Company believes these matters should not have a
material adverse effect on the results of operations or financial position of
the Company.
The Company is 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 Company has made accruals in
accordance with Statement of Financial Accounting Standards No. 5, "Accounting
for Contingencies," in order to provide for such matters. Management is of the
opinion that the final disposition of these proceedings will not have a material
adverse effect on the results of operations or financial position of the
Company.
NOTE 14. 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 Company's 12.5 percent
ownership in the Catawba Nuclear Station. The other joint owners of the Catawba
Nuclear Station are responsible for decommissioning costs related to their
ownership interests in the station. Both the North Carolina Utilities Commission
and the Public Service Commission of South Carolina have granted the Company
recovery of estimated decommissioning costs through retail rates over the
expected remaining service periods of the Company's nuclear plants. Such
estimates presume each unit will be decommissioned as soon as possible following
the end of their license life. Although subject to extension, the current
operating licenses for the Company'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.
The Nuclear Regulatory Commission issued a rule-making in 1988 which requires
an external mechanism to fund the estimated cost to decommission certain
components of a nuclear unit subject to radioactive contamination. In addition
to the required external funding, the Company maintains an internal reserve to
provide for decommissioning costs of plant components not subject to radioactive
contamination. During 1995, the Company expensed approximately $56,470,000 which
was contributed to the external funds and accrued an additional $1,319,000 to
the internal reserve. Nuclear units are depreciated at a rate of 4.70 percent,
of which 1.61 percent is for decommissioning. The balance of the external funds
as of December 31, 1995, was $273,466,000. The balance of the internal reserve
as of December 31, 1995, was $206,155,000 and is reflected in accumulated
depreciation and amortization on 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 percent to 5.9 percent, are
currently sufficient to provide for the cost of decommissioning.
NOTE 15. RECLASSIFICATION
In the Consolidated Statements of Income and Consolidated Statements of Cash
Flows, certain 1993 information has been reclassified to conform with 1994
classifications.
<PAGE>
INDEPENDENT AUDITORS' REPORT
Duke Power Company:
We have audited the consolidated financial statements of Duke Power
Company and subsidiaries (the Company) listed in the accompanying index
for Item 8. Our audits also included the consolidated financial statement
schedule listed in the accompanying index. These financial statements and
consolidated financial statement schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and consolidated financial statement schedule based on
our audits.
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 provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Company at December 31, 1995
and 1994, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1995 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.
(Signature of Deloitte & Touche LLP)
Deloitte & Touche LLP (Deloitte &
Charlotte, North Carolina Touche LLP
February 9, 1996 logo appears here)
RESPONSIBILITY FOR FINANCIAL STATEMENTS
The financial statements of Duke Power Company 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 Company'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 Company'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 Company's accounting controls are
continually reviewed for effectiveness. In addition, written policies, standards
and procedures, and a strong internal audit program augment the Company'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 Company. 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 Company'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.
(Signature of Jeffrey L. Boyer)
Jeffrey L. Boyer
Controller
<PAGE>
QUARTERLY FINANCIAL DATA
<TABLE>
<CAPTION>
First Second Third Fourth
Dollars in Thousands (except per-share data) Quarter Quarter Quarter Quarter Total
<S> <C> <C> <C> <C> <C>
1995 BY QUARTER
Operating revenues....................................... $1,111,065 $1,052,403 $1,379,978 $1,133,238 $4,676,684
Operating income ........................................ $ 369,414 $ 263,876 $ 504,507 $ 211,254 $1,349,051
Net income .............................................. $ 201,276 $ 137,523 $ 285,200 $ 90,539 $ 714,538
Earnings per share....................................... $0.92 $0.61 $1.33 $0.39 $3.25
1994 BY QUARTER
Operating revenues....................................... $1,099,002 $1,083,310 $1,272,525 $1,034,076 $4,488,913
Operating income ........................................ $ 326,584 $ 242,419 $ 430,861 $ 179,962 $1,179,826
Net income .............................................. $ 173,617 $ 128,002 $ 243,741 $ 93,516 $ 638,876
Earnings per share....................................... $0.79 $0.56 $1.13 $0.40 $2.88
</TABLE>
Generally, quarterly earnings fluctuate with seasonal weather conditions and
maintenance of electric generating units, especially nuclear units.
SUBSIDIARIES AND DIVERSIFIED ACTIVITIES HIGHLIGHTS
During 1994, the Company reorganized, placing all its subsidiaries and
diversified activities into the Associated Enterprises Group (AEG). AEG includes
the following:
o CHURCH STREET CAPITAL CORP. (CSCC) manages investment funds,
serves as the parent company and provides equity funding and credit enhancement
for the non-electric operating subsidiaries. CSCC investment highlights are as
follows (dollars in thousands):
SHORT-TERM INVESTMENTS AND MARKETABLE SECURITIES
1995 1994 1993
$76,300 $170,642 $155,871
INVESTMENT INCOME (AFTER TAX) (A)
1995 1994 1993
$4,783 $7,562 $3,548
O CRESCENT RESOURCES, INC. is engaged in real estate development and forest
management.
O DUKE ENERGY GROUP, INC. develops, owns and manages investments in
electric power facilities, both nationally and internationally, and
markets electric power and natural gas.
o DUKE ENGINEERING & SERVICES, INC. markets engineering, construction, quality
assurance, consulting and other engineering-related services for facilities
other than coal-fired generating plants, both nationally and internationally.
o DUKE/FLUOR DANIEL, a joint venture with Fluor Daniel, Inc., provides
engineering, construction, and support of operating and maintenance
activities, primarily for coal-fired generating plants, both nationally and
internationally.
o DUKE MERCHANDISING sells and services quality appliances and electronics
primarily to Duke Power customers.
o DUKENET COMMUNICATIONS, INC. develops and manages communication systems.
o DUKE WATER OPERATIONS serves areas of Anderson, South Carolina, and
Rutherfordton, North Carolina.
o NANTAHALA POWER AND LIGHT COMPANY provides electric service to a five-county
area in western North Carolina by its operation of eleven hydroelectric
stations and purchase of supplemental power.
OPERATING RESULTS
<TABLE>
<CAPTION>
Dollars in Thousands Year ended December 31, 1995 1994 1993
<S> <C> <C> <C>
OPERATING REVENUES
Crescent Resources, Inc............................................................... $ 85,361 $ 64,724 $ 46,784
Duke Energy Group, Inc. (b)........................................................... 10,017 9,478 6,033
Nantahala Power and Light Company (c)................................................. 62,510 68,595 67,142
All Other Business Units (d).......................................................... 141,337 109,932 106,340
Total Associated Enterprises Group................................................. $ 299,225 $ 252,729 $ 226,299
OPERATING INCOME
Crescent Resources, Inc............................................................... $ 63,973 $ 46,236 $ 30,004
Duke Energy Group, Inc................................................................ (1,422) (1,035) (2,929)
Nantahala Power and Light Company..................................................... 9,262 12,224 8,844
All Other Business Units (d).......................................................... 20,407 15,506 1,939
Total Associated Enterprises Group................................................. $ 92,220 $ 72,931 $ 37,858
NET INCOME
Crescent Resources, Inc............................................................... $ 35,500 $ 26,525 $ 16,327
Duke Energy Group, Inc. (e)........................................................... 170 5,749 (1,949)
Nantahala Power and Light Company..................................................... 4,037 6,169 4,261
All Other Business Units (d).......................................................... 14,550 13,593 2,876
Total Associated Enterprises Group................................................. $ 54,257 $ 52,036 $ 21,515
FINANCIAL POSITION
Dollars in Thousands December 31, 1995 1994 1993
TOTAL ASSETS
Crescent Resources, Inc............................................................... $ 381,073 $ 294,175 $ 219,206
Duke Energy Group, Inc. (f)........................................................... 149,391 110,656 144,499
Nantahala Power and Light Company..................................................... 144,069 125,883 107,872
All Other Business Units (d).......................................................... 283,774 279,430 265,977
Total Associated Enterprises Group................................................. $ 958,307 $ 810,144 $ 737,554
TOTAL LIABILITIES
Crescent Resources, Inc............................................................... $ 185,996 $ 134,574 $ 86,172
Duke Energy Group, Inc................................................................ 9,783 4,672 31,816
Nantahala Power and Light Company..................................................... 86,691 72,542 60,700
All Other Business Units (d).......................................................... 43,498 22,312 30,902
Total Associated Enterprises Group................................................. $ 325,968 $ 234,100 $ 209,590
CASH FLOWS
Dollars in Thousands Year ended December 31, 1995 1994 1993
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
Crescent Resources, Inc............................................................... $ 40,144 $ 37,691 $ 36,254
Duke Energy Group, Inc................................................................ (3,521) (6,614) (1,438)
Nantahala Power and Light Company..................................................... 8,419 12,817 14,869
All Other Business Units (d).......................................................... 1,769 10,589 8,795
Total Associated Enterprises Group................................................. $ 46,811 $ 54,483 $ 58,480
CASH PROVIDED BY INVESTING ACTIVITIES
Crescent Resources, Inc............................................................... $ 5,910 $ 2,524 $ 1,310
Duke Energy Group, Inc. (g)........................................................... 14,253 40,740 28,785
Nantahala Power and Light Company..................................................... -- -- --
All Other Business Units (h).......................................................... 97,793 5,100 21,377
Total Associated Enterprises Group................................................. $ 117,956 $ 48,364 $ 51,472
CASH USED IN INVESTING ACTIVITIES
Crescent Resources, Inc............................................................... $ 84,603 $ 78,689 $ 43,444
Duke Energy Group, Inc................................................................ 44,776 19,575 116,498
Nantahala Power and Light Company..................................................... 23,944 23,989 19,254
All Other Business Units (i).......................................................... 66,768 18,500 1,450
Total Associated Enterprises Group................................................. $ 220,091 $ 140,753 $ 180,646
CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (j)
Crescent Resources, Inc. (k).......................................................... $ 38,521 $ 37,589 $ 945
Duke Energy Group, Inc. (l)........................................................... -- -- --
Nantahala Power and Light Company..................................................... 15,536 10,896 3,206
All Other Business Units (m).......................................................... 5,302 (6,993) 71,537
Total Associated Enterprises Group................................................. $ 59,359 $ 41,492 $ 75,688
OTHER INFORMATION
December 31, 1995 1994 1993
FULL-TIME EMPLOYEES AT YEAR-END
Crescent Resources, Inc............................................................... 94 89 77
Duke Energy Group, Inc................................................................ 43 35 24
Nantahala Power and Light Company..................................................... 182 184 194
All Other Business Units.............................................................. 1,036 703 755
Total Associated Enterprises Group................................................. 1,355 1,011 1,050
</TABLE>
(a) Earnings for 1995, 1994 and 1993 exclude elimination of intercompany
profits of $59,000, $49,000 and $509,000, respectively.
(b) Includes Duke Energy Group, Inc.'s allocable share of net income from
Joint Ventures. (See Note 11.)
(c) Nantahala Power and Light Company's operating revenues include revenues
from the sale of electricity to Duke Power of $1,205,000, $12,131,000
and $13,683,000 for 1995, 1994 and 1993, respectively.
(d) All other business units amounts include Associated Enterprises Group
intercompany eliminations.
(e) 1994 includes a gain of $4,800,000, after tax, from the sale of
preferred stock.
(f) Includes Duke Energy Group, Inc.'s investments in joint ventures. (see
Note 11.)
(g) 1994 includes proceeds from the sale of preferred stock of $32,468,000
and debt securities of $3,360,000. 1993 includes proceeds from the sale
of debt securities of $19,654,000.
(h) 1995 and 1993 include the net change in short-term investments for the
period of $56,392,000 and $20,653,000, respectively. Also, 1995
includes proceeds from the sale of a dividend capture program of
$40,953,000.
(i) 1994 includes the net change in short-term investments for the period
of $12,060,000.
(j) Excludes capital infusion and return of capital transactions between
parent, Church Street Capital Corp., and its subsidiaries.
(k) 1993 excludes capital infusion from parent, Church Street Capital
Corp., of $6,000,000.
(l) 1995 and 1993 exclude net capital infusions from parent, Church Street
Capital Corp., of $33,455,000 and $91,864,000, respectively. 1994
excludes net return of capital to Church Street Capital Corp. of
$12,100,000.
(l) 1993 includes capital infusion from Duke Power to Church Street Capital
Corp. of $75,000,000.
<PAGE>
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
<TABLE>
<CAPTION>
Balance Balance
Description Beginning End
of Year of Year
Dollars in thousands
<S> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1995
Reserves Related to Assets on Balance Sheet. . . . . . . . . . . . . . . . . $ 8,059 $ 7,774
Other Reserves
Operating Reserves (1) . . . . . . . . . . . . . . . . . . . . . . 154,722 176,098
FOR THE YEAR ENDED DECEMBER 31, 1994
Reserves Related to Assets on Balance Sheet. . . . . . . . . . . . . . . . . 10,353 8,059
Other Reserves
Operating Reserves (1) . . . . . . . . . . . . . . . . . . . . . . 107,477 154,722
FOR THE YEAR ENDED DECEMBER 31, 1993
Reserves Related to Assets on Balance Sheet. . . . . . . . . . . . . . . . . 10,730 10,353
Other Reserves
Operating Reserves (1) . . . . . . . . . . . . . . . . . . . . . . 78,103 107,477
</TABLE>
(1) Principally consists of Injuries and Damages reserves and Property Insurance
reserve which are included in "Deferred Credits and Other Liabilities" in the
Consolidated Balance Sheets.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE. No events necessary to be disclosed by the
Company under this item have occurred.
PART III.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Information for this item concerning directors of the Company is set
forth in the sections entitled "Election of Directors", "Information Regarding
the Board of Directors" and "Common Stock Ownership of Certain Beneficial Owners
and Management" in the proxy statement of the Company relating to its 1996
annual meeting of shareholders, which are being incorporated herein by
reference.
Information concerning the executive officers of the Company is set
forth in the section entitled "Executive Officers of the Company" in this annual
report.
ITEM 11. EXECUTIVE COMPENSATION.
Information for this item is set forth in the section entitled
"Executive Compensation" in the proxy statement of the Company relating to its
1996 annual meeting of shareholders, which is being incorporated herein by
reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Information for this item is set forth in the section entitled "Common
Stock Ownership of Certain Beneficial Owners and Management" in the proxy
statement of the Company relating to its 1996 annual meeting of shareholders,
which is being incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information for this item is set forth in the sections entitled
"Information Regarding the Board of Directors" and "Common Stock Ownership of
Certain Beneficial Owners and Management" in the proxy statement of the Company
relating to its 1996 annual meeting of shareholders, which are being
incorporated herein by reference.
PART IV.
ITEM 14. EXHIBITS, CONSOLIDATED 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 Three Years Ended
December 31, 1995
Consolidated Statements of Retained Earnings for the Three
Years Ended December 31, 1995
Consolidated Statements of Cash Flows for the Three Years
Ended December 31, 1995
Consolidated Balance Sheets -- December 31, 1995 and 1994
Notes to Consolidated Financial Statements
Selected Quarterly Financial Data (unaudited)
Consolidated Financial Statement Schedule
Schedule II -- Valuation and Qualifying Accounts and Reserves
for the Three Years Ended December 31, 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
No reports on Form 8-K were filed during the last quarter of
1995.
(c) Exhibits -- See Exhibit Index immediately following signature page.
<PAGE>
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, in the City of
Charlotte and State of North Carolina on the 12th day of March, 1996.
DUKE POWER COMPANY
(Registrant)
By: W. H. GRIGG
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.
<TABLE>
<CAPTION>
Signature Title Date
<S> <C> <C>
W. H. GRIGG Chairman of the Board and Chief March 12, 1996
Executive Officer (Principal
Executive Officer)
RICHARD J. OSBORNE Senior Vice President and Chief Financial March 12, 1996
Officer (Principal Financial Officer)
JEFFREY L. BOYER Controller (Principal Accounting March 12, 1996
Officer)
G. ALEX BERNHARDT
CRANDALL C. BOWLES
ROBERT J. BROWN
W. A. COLEY
STEVE C. GRIFFITH, JR.
W. H. GRIGG
GEORGE DEAN JOHNSON, JR. A Majority of the Directors March 12, 1996
W. W. JOHNSON
MAX LENNON
JAMES G. MARTIN
BUCK MICKEL
R. B. PRIORY
RUSSELL M. ROBINSON, II
</TABLE>
ELLEN T. RUFF, by signing her 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.
/s/ ELLEN T. RUFF
ELLEN T. RUFF, ATTORNEY-IN-FACT
<PAGE>
EXHIBIT INDEX
The following exhibits indicated by an asterisk preceding the exhibit
number are filed herewith. The balance of the exhibits have heretofore been
filed with the Securities and Exchange Commission and pursuant to Rule 12b-32
are incorporated herein by reference.
<TABLE>
<CAPTION>
Exhibit
Number
<S> <C> <C>
3-A -- Restated Articles of Incorporation of registrant, dated as of October 6, 1993 (filed with Form S-3, File
No. 33-50617, effective October 20, 1993, as Exhibit 4(A)).
3-B -- Articles of Amendment of registrant dated November 1, 1993,
relating to the 6.375% Cumulative Preferred Stock A, 1993
Series (filed with Form S-3, No. 33-52479, effective March 29,
1994, as Exhibit 4(B)).
*3-C -- By-Laws of registrant, as amended.
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-23 -- Supplemental Indenture, dated as of April 1, 1967,
supplementing said Mortgage (filed with Form S-9, File No.
2-28023, effective February 15, 1968, as Exhibit 2-B-25).
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-63 -- Supplemental Indenture, dated as of March 1, 1991,
supplementing said Mortgage (filed with Form 10-K for the year
ended December 31, 1990, File No. 1-4928, as Exhibit 4-B-63).
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-65 -- Supplemental Indenture, dated as of December 1, 1991,
supplementing said Mortgage (filed with Form S-3, File No.
33-45501, effective February 13, 1992, as Exhibit 4-B-65).
4-B-66 -- Supplemental Indenture, dated as of March 1, 1992,
supplementing said Mortgage (filed with Form 10-K for the year
ended December 31, 1991, File No. 1-4928, as Exhibit 4-B-66).
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).
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.
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+ -- Employees' Stock Ownership Plan.
10-F++ -- Employee Incentive Plan.
10-G++ -- 1993 Executive Long-Term Incentive Plan.
10-H+ -- Supplemental Security Plan.
10-I+ -- Stock Purchase-Savings Program for Employees.
10-J+ -- Employees' Retirement Plan.
10-K+ -- Supplemental Retirement Plan.
10-L+ -- Compensation Deferral Plan.
10-M+ -- Compensation Deferral Plan for Outside Directors.
10-N+ -- Retirement Plan for Outside Directors.
10-O+ -- Supplementary Defined Contribution Plan for Employees.
10-P+ -- Directors' Charitable Giving Program.
10-Q+ -- Vacation Banking Plan.
10-R+ -- Estate Conservation Plan.
10-S+ -- Supplemental Insurance Plan.
10-T+ -- Group Life Insurance Plan.
10-U+ -- Stock Ownership Plan for Nonemployee Directors.
10-V+ + + -- Executive Short-Term Incentive Plan.
10-W+ + + -- Executive Long-Term Incentive Plan.
*12 -- Computation of Ratio of Earnings to Fixed Charges.
*23 -- Consent of Independent Auditors.
*24(a) -- Power of attorney authorizing Ellen T. Ruff 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.
+ Compensatory plan or arrangement filed with Form 10-K for the year
ended December 31, 1992, File No. 1-4928, under the same exhibit
number as listed herein.
++ Compensatory plan or arrangement filed with Form 10-K for the year ended December 31, 1993, File No.
1-4928, under the same exhibit number as listed herein.
+++ Compensatory plan or arrangement filed with Form 10-K for the year ended December 31, 1994, File
No. 1-4928, under the same exhibit number as listed herein.
</TABLE>
<PAGE>
EXHIBIT 3-C
Amended Effective
September 26, 1995
BY-LAWS
OF
DUKE POWER COMPANY
ARTICLE I
OFFICES
SECTION 1. PRINCIPAL OFFICE. The principal office of the Company shall be
located at 422 South Church Street, Charlotte, North Carolina 28242.
SECTION 2. OTHER OFFICES. The Company may have offices at such other places,
either within or without the State of North Carolina, as the Board of Directors
may designate or as the affairs of the Company may require from time to time.
ARTICLE II
MEETINGS OF SHAREHOLDERS
SECTION 1. PLACE OF MEETINGS. All meetings of shareholders shall be held at such
place, either within or without the State of North Carolina, as shall be
designated in the notice of the meeting.
SECTION 2. ANNUAL MEETINGS. The annual meeting of shareholders for the election
of directors and the transaction of other business shall be held on any day in
each year as determined by the Board of Directors.
SECTION 3. SPECIAL MEETINGS. Special meetings of the shareholders may be called
at any time by the Board of Directors, the Chairman of the Board or the
President.
SECTION 4. NOTICE OF MEETINGS. Written notice stating the time and place of the
meeting shall be delivered not less than ten nor more than sixty days before the
date of any shareholders' meeting, either personally or by mail, by or at the
direction of the Chairman of the Board, the President or the Secretary, to each
shareholder of record entitled to vote at such meeting. In the case of a special
meeting, the notice of meeting shall specifically state the purpose or purposes
for which the meeting is called.
SECTION 5. QUORUM. A majority of the shares of the Company entitled to vote,
represented in person or by proxy, shall constitute a quorum at a meeting of
shareholders.
SECTION 6. VOTING OF SHARES. Each outstanding share entitled to vote
shall be entitled to one vote on each matter submitted to a vote at a meeting of
shareholders. Except in the election of directors, the vote of a majority of
shares voted on any matter at a meeting of shareholders at which a quorum is
present shall be the act of the shareholders on that matter, unless the vote of
a greater number is required by law or by the Articles of Incorporation.
ARTICLE III
BOARD OF DIRECTORS
SECTION 1. GENERAL POWERS. The business and affairs of the Company
shall be managed by its Board of Directors.
<PAGE>
SECTION 2. NUMBER AND QUALIFICATIONS. The number of directors
constituting the Board of Directors shall be not less than twelve nor more than
twenty-four, as may be fixed from time to time by the Board of Directors. A
director must be a shareholder of the Company.
SECTION 3. ELECTION OF DIRECTORS; CLASSES. The directors, other than
those who may be elected by the holders of any class of stock having a
preference over the Common Stock as to dividends or upon liquidation to elect
directors under specified circumstances, shall be classified, with respect to
the time for which they severally hold office into three classes, as nearly
equal in number as possible. Such classes shall originally consist of one class
(Class I) of seven directors who shall be elected at the annual meeting of
shareholders held in 1991 for a term expiring at the annual meeting of
shareholders held in 1992; a second class (Class II) of six directors who shall
be elected at the annual meeting of shareholders held in 1991 for a term
expiring at the annual meeting of shareholders to be held in 1993; and a third
class (Class III) of six directors who shall be elected at the annual meeting of
shareholders held in 1991 for a term expiring at the annual meeting of
shareholders to be held in 1994; with each class to hold office until its
successor is elected and qualified. The Board of Directors shall increase or
decrease the number of directors in one or more classes as may be appropriate
whenever it increases or decreases the number of directors pursuant to the
Articles of Incorporation and Section 2 of Article III of these By-Laws, in
order to ensure that the three classes shall be as nearly equal in number as
possible. At each annual meeting of shareholders, the successors of the class of
directors whose term expires at that meeting shall be elected to hold office for
a term expiring at the annual meeting of shareholders held in the third year
following the year of their election.
SECTION 4. REMOVAL. Subject to the rights of any class of stock having
a preference over the Common Stock as to dividends or upon liquidation to elect
directors under specified circumstances, a director may be removed from office
only with cause. "Cause" for removal of a director under this Section means
fraudulent or dishonest acts, or gross abuse of authority in the discharge of
duties to the Company, and must be established after written notice of specific
charges and an opportunity to meet and refute such charges.
SECTION 5. NEWLY CREATED DIRECTORSHIPS; VACANCIES. Except as may be
otherwise provided for or fixed by or pursuant to any provisions of the Articles
of Incorporation, as amended from time to time, relating to the rights of the
holders of any class of stock having a preference over the Common Stock as to
dividends or upon liquidation to elect directors under specified circumstances,
newly created directorships resulting from any increase in the number of
directors and any vacancies on the Board of Directors resulting from death,
resignation, disqualification, removal or other cause shall be filled only by
the affirmative vote of a majority of the remaining directors then in office,
even though less than a quorum of the Board of Directors. Any director elected
in accordance with the preceding sentence shall hold office until the expiration
of the full term of the class for which such director is elected and until such
director's successor shall have been elected and qualified. No decrease in the
number of directors constituting the Board of Directors shall shorten the term
of any incumbent director.
ARTICLE IV
MEETINGS OF DIRECTORS
SECTION 1. REGULAR MEETINGS. A regular meeting of the Board of
Directors shall be held as soon as practicable following the annual meeting of
shareholders. In addition, the Board of Directors may prescribe the time and
place, either within or without the State of North Carolina, for the holding of
other regular meetings of the Board of Directors.
SECTION 2. SPECIAL MEETINGS. Special meetings of the Board of
Directors may be called by or at the request of the Chairman of the Board or any
three directors. Such a meeting may be held either within or without the State
of North Carolina, as fixed by the person or persons calling the meeting.
SECTION 3. NOTICE OF MEETINGS. Regular meetings of the Board of
Directors may be held without notice. The person or persons calling a special
meeting of the Board of Directors shall, at least two days before the meeting,
give notice thereof by any usual means of communication. Such notice need not
specify the purpose for which the meeting is called.
<PAGE>
SECTION 4. WAIVER OF NOTICE. Any director may waive notice of any
meeting before or after the meeting. The attendance by a director at a meeting
shall constitute a waiver of notice of such meeting, except where a director at
the beginning of the meeting (or promptly upon his or her arrival) objects to
holding the meeting or to transacting any business at the meeting and does not
thereafter vote for or assent to action taken at the meeting.
SECTION 5. QUORUM. A majority of the number of directors fixed
pursuant to these By-Laws shall constitute a quorum for the transaction of
business at any meeting of the Board of Directors.
SECTION 6. MANNER OF ACTING. Except as otherwise provided in these
By-Laws, the act of the majority of the directors present at a meeting at which
a quorum is present shall be the act of the Board of Directors.
SECTION 7. INFORMAL ACTION BY DIRECTORS. Action taken by a required
majority of the directors without a meeting is nevertheless action of the Board
of Directors if written consent to the action in question is signed by all the
directors and filed with the minutes of the proceedings of the Board of
Directors, whether done before or after the action so taken. Any one or more
directors may participate in a meeting of the Board of Directors by means of a
conference telephone or similar communications device, which allows all
directors participating in the meeting to simultaneously hear each other, and
such participation in a meeting shall be deemed presence in person at such
meeting.
ARTICLE V
COMMITTEES OF THE BOARD
SECTION 1. MANAGEMENT COMMITTEE. The Board of Directors shall annually elect
from its members a Management Committee consisting of four or more persons who
are officers of the Company and which shall include the Chairman of the Board
who shall act as Chairman.
The Management Committee may exercise all of the authority of the
Board of Directors, except that the Management Committee shall not have
authority to act on the (1) dissolution, merger or consolidation of the Company,
or disposition of substantially all of its property, (2) designation of any
committee or filling vacancies in the Board of Directors or in any such
committee, (3) adoption, amendment or repeal of these By-Laws, (4) authorization
of distributions, (5) adoption of amendments to the Articles of Incorporation
without shareholder action, (6) authorization or approval of the reacquisition
of shares, except according to a formula or method that is prescribed by the
Board of Directors, (7) authorization or approval of the issuance or sale or
contract for sale of shares, or determination of the designation and relative
rights, preferences, and limitations of a class or series of shares, except
within limits that are specifically prescribed by the Board of Directors, (8)
approval or proposal to the shareholders of an action that is required by the
North Carolina Business Corporation Act to be approved by shareholders, or (9)
amendment or repeal of any resolution of the Board of Directors which by its
terms is not so amendable or repealable. Any resolutions adopted or other action
taken by the Management Committee within the scope of its authority shall be
deemed for all purposes to be adopted or taken by the Board of Directors.
The Management Committee shall fix its own rules of procedure and
shall meet as provided by such rules or at the call of the Chairman or any two
members thereof. The Management Committee shall elect a Secretary who need not
be a member thereof and minutes of its proceedings shall be kept in minute books
provided for that purpose.
SECTION 2. NOMINATING COMMITTEE. The Board of Directors shall annually
elect from its members a Nominating Committee consisting of the Chairman of the
Board (who shall not vote on matters affecting the Chairman of the Board) and
not less than two other members who are not officers of the Company, one of whom
shall be designated as Chairman.
The Nominating Committee, subject to any limitations prescribed by the
Board of Directors, shall select and present to the Board of Directors the
name(s) of a person or persons to be considered for nomination or appointment to
membership on the Board of Directors.
The Nominating Committee shall select and present to the Board of
Directors the name(s) of a person or persons to be considered as successor to
the Chief Executive Officer or the President and in the discretion of the
Nominating Committee, the successors of the immediate associates of such
officers.
<PAGE>
The Nominating Committee shall conduct periodic review of both
management and non-management director performance and should a director's
performance be judged unsatisfactory over a reasonable period of time, work with
the Chairman of the Board and Chief Executive Officer to remedy the situation.
The Nominating Committee will meet at the direction of the Board of
Directors or at the call of its Chairman or any two members thereof. The
Chairman shall designate a person who need not be a member thereof to act as
Secretary.
Minutes of its proceedings shall be kept in minute books provided for that
purpose.
SECTION 3. FINANCE COMMITTEE. The Board of Directors shall annually
elect from its members a Finance Committee consisting of two or more persons.
The Finance Committee, subject to any limitations prescribed by the
Board of Directors, shall have supervision of all the financial and fiscal
affairs of the Company and shall make recommendations to the Board of Directors
with reference to dividend, financing and fiscal policies of the Company, and
such other financial matters as may be assigned from time to time by the Board
of Directors.
The Finance Committee shall elect a Chairman from among its members
and such person as the Chairman shall designate shall act as Secretary. Minutes
of its proceedings shall be kept in minute books provided for that purpose. The
Finance Committee shall hold such meetings as shall be necessary from time to
time to carry out its assigned duties. Meetings may be called by the Chairman or
by any member thereof and shall be held at such time and place as specified in
the call for such meeting.
SECTION 4. AUDIT COMMITTEE. The Board of Directors shall annually
elect from such of its members who are not officers of the Company an Audit
Committee consisting of two or more persons.
The Audit Committee shall select and recommend to the Board of
Directors for its approval outside auditors to conduct interim and annual audits
of the Company's books and report thereon to the Audit Committee. Subject to any
limitations prescribed by the Board of Directors, the Audit Committee shall:
1) Confer with the auditors, determine the scope of the auditing
of the books and accounts of the Company, and receive and
review the reports submitted by the auditors;
2) Meet with the appropriate officers of the Company to review
and examine procedures and methods employed in connection with
the Company's internal audit program and management policies
relating thereto; and
3) Report its findings to the Board of Directors from time to
time with such recommendations as it may deem appropriate.
The Audit Committee shall elect a Chairman from among its members and
a Secretary who need not be a member thereof. Minutes of its proceedings shall
be kept in minute books provided for that purpose. The Audit Committee shall
meet at such time or times as it may consider necessary to perform its assigned
duties. Meetings of the Audit Committee may be called by the Chairman or by any
two members thereof and shall be held at such time and place as specified in the
call for such meeting.
SECTION 5. COMPENSATION COMMITTEE. The Board of Directors shall
annually elect from such of its members who are not officers of the Company a
Compensation Committee consisting of two or more persons, one of whom shall be
designated as Chairman.
The Compensation Committee shall, upon recommendation of the Chairman
of the Board, fix the salaries and other compensation, if any, of all employees
of the Company, except the Chairman of the Board, Vice Chairman of the Board,
President and any other officer the Board of Directors may designate, whose
salaries are at a rate at or above a level determined from time to time by the
Board of Directors. The Committee shall report at the next meeting of the Board
of Directors any action it has taken pursuant to this authority.
The Board of Directors shall, upon recommendation of the Compensation Committee,
fix the salary of the Chairman of the Board, Vice Chairman of the Board and any
President. The Committee shall also recommend to the Board of Directors the fees
to be paid to members of the Board of Directors. The salaries of all other
employees and agents
<PAGE>
of the Company shall be fixed in accordance with procedures adopted from time to
time by the Management Committee. The Chairman of the Board shall periodically
report to the Compensation Committee, in such manner and in such scope as the
Committee shall direct, the salaries so fixed.
The Compensation Committee shall meet on call of its Chairman. An officer of the
Company designated by the Chairman shall act as Secretary and minutes of its
proceedings shall be kept in minute books provided for that purpose.
SECTION 6. CORPORATE PERFORMANCE REVIEW COMMITTEE. The Board of Directors shall
annually elect from such of its members who are not officers of the Company a
Corporate Performance Review Committee consisting of two or more persons, one of
whom shall be designated as Chairman.
The Corporate Performance Review Committee will monitor and make recommendations
for improving the overall performance of the Company. At the policy level, the
committee will determine the adequacy of and support the Company's emphasis on
continuous improvement and will endeavor to increase the knowledge and
understanding by the full Board of Directors of continuous improvement
opportunities internally and external factors which influence company
performance and operations.
The Corporate Performance Review Committee shall meet on call of its Chairman.
An officer of the Company designated by the Chairman shall act as Secretary, and
minutes of its proceedings shall be kept in minute books provided for that
purpose.
SECTION 7. QUORUM AND MANNER OF ACTING OF COMMITTEES. A majority of the members
of a committee of the Board of Directors shall be necessary to constitute a
quorum and the affirmative vote of the majority of the members present at a
meeting at which a quorum is present shall be necessary to constitute action by
the committee. A committee may also act by the written consent of all members
thereof although not convened in a meeting provided that such written consent is
filed with the minute books of the committee.
ARTICLE VI
OFFICERS
SECTION 1. OFFICERS OF THE COMPANY. The officers of the Company shall consist of
a Chairman of the Board, a President, a Secretary, a Treasurer and such Vice
Presidents, Assistant Secretaries, Assistant Treasurers, and other officers as
the Board of Directors may from time to time elect.
SECTION 2. ELECTION AND TERM. The officers of the Company shall be elected by
the Board of Directors and each officer shall hold office until his death,
resignation, retirement, removal, disqualification or his successor shall have
been elected and qualified.
SECTION 3. REMOVAL. Any officer or agent elected or appointed by the Board of
Directors may be removed by the Board whenever in its judgment the best
interests of the Company will be served thereby; but such removal shall be
without prejudice to the contract rights, if any, of the person so removed.
SECTION 4. CHAIRMAN OF THE BOARD. The Chairman of the Board shall be the chief
executive officer of the Company and, subject to the control of the Board of
Directors, shall supervise and manage all of the business and affairs of the
Company. He shall, when present, preside at all meetings of the shareholders and
of the Board of Directors; and in general he shall perform all duties incident
to being the chief executive officer of the Company and such other duties as may
be prescribed by the Board of Directors.
SECTION 5. PRESIDENT. In the absence of the Chairman of the Board, or in the
event of his death or inability to act, the President shall perform the duties
of the Chairman of the Board, and when so acting shall have all the powers of
and be subject to all the restrictions upon the Chairman of the Board. The
President shall perform such other duties as may be assigned to him by the
Chairman of the Board or by the Board of Directors.
<PAGE>
SECTION 6. VICE PRESIDENTS. In the absence of the President or in the event of
his death or inability to act, the Vice President designated by the Chairman of
the Board, unless otherwise determined by the Board of Directors, shall perform
the duties of the President, and when so acting shall have all the powers of and
be subject to all the restrictions upon the President. The Vice Presidents, one
or more of whom may be designated as Executive Vice President or Senior Vice
President, shall perform such duties as may be assigned to them by the Chairman
of the Board or by the Board of Directors.
SECTION 7. SECRETARY. The Secretary shall keep the minutes of the meetings of
shareholders and of the Board of Directors in one or more minute books provided
for that purpose; see that all notices are duly given in accordance with the
provisions of these By-Laws or as required by law; be custodian of the corporate
records and of the seal of the Company and in general perform all duties
incident to the office of Secretary and such other duties as may be assigned to
him by the Chairman of the Board or by the Board of Directors.
SECTION 8. ASSISTANT SECRETARIES. In the absence of the Secretary or in the
event of his death or inability to act, the Assistant Secretaries in the order
of their length of service as such, unless otherwise determined by the Chairman
of the Board or by the Board of Directors, shall perform the duties of the
Secretary, and when so acting shall have all the powers and be subject to all
the restrictions upon the Secretary. They shall perform such other duties as may
be assigned to them by the Secretary or by the Chairman of the Board.
SECTION 9. TREASURER. The Treasurer shall have charge and custody of and be
responsible for all funds and securities of the Company; receive and give
receipts for moneys due and payable to the Company from any source whatsoever,
and deposit all such moneys in the name of the Company in authorized
depositories of the Company and in general perform all of the duties incident to
the office of Treasurer and such other duties as may be assigned to him by the
Chairman of the Board or by the Board of Directors.
SECTION 10. ASSISTANT TREASURERS. In the absence of the Treasurer or in the
event of his death or inability to act, the Assistant Treasurers in the order of
their length of service as such, unless otherwise determined by the Chairman of
the Board or by the Board of Directors, shall perform the duties of the
Treasurer, and when so acting shall have all the powers of and be subject to all
the restrictions upon the Treasurer. They shall perform such other duties as may
be assigned to them by the Treasurer or by the Chairman of the Board.
ARTICLE VII
CHECKS AND DEPOSITS
SECTION 1. CHECKS AND DRAFTS. All checks, drafts or other orders for the payment
of money, issued in the name of the Company, shall be signed by two officers of
the Company or in such other manner as shall from time to time be determined by
the Board of Directors.
SECTION 2. DEPOSITS. All funds of the Company not otherwise employed shall
be deposited to the credit of the Company as the Board of Directors may from
time to time determine.
ARTICLE VIII
GENERAL PROVISIONS
SECTION 1. WAIVER OF NOTICE. Whenever any notice is required to be given to any
shareholder or director by law, by the Articles of Incorporation or by these
By-Laws, a waiver thereof in writing signed by the person or persons entitled to
such notice, whether before or after the time stated therein, shall be
equivalent to the giving of such notice.
SECTION 2. FIXING RECORD DATE. For the purpose of determining shareholders
entitled to notice of or to vote at any meeting of shareholders or any
adjournment thereof, or entitled to receive payment of any dividend, or in order
to make a determination of shareholders for any other proper purpose, the Board
of Directors may fix in advance a
<PAGE>
date as the record date for any such determination of shareholders, such record
date in any case to be not more than seventy days and, in case of a meeting of
shareholders, not less than ten days immediately preceding the date on which the
particular action, requiring such determination of shareholders, is to be taken.
SECTION 3. INDEMNIFICATION. Any person who is or was serving as a director,
officer, employee or agent of the Company or who, at the request of the Company,
is or was serving as a director, officer, employee or agent of another
corporation, partnership, joint venture, trust or other enterprise or as a
trustee or administrator under an employee benefit plan, shall be indemnified by
the Company, to the fullest extent permitted by law, against a) litigation
expenses, including costs, expenses and reasonable attorneys' fees incurred by
him in connection with any threatened, pending or completed action, suit or
proceedings, whether civil, criminal, administrative or investigative, whether
formal or informal, and whether or not brought by or on behalf of the Company,
arising out of his status as such or his activities in any of the foregoing
capacities, b) liability, including payments made by him in satisfaction of any
judgment, money decree, fine (including an excise tax assessed with respect to
an employee benefit plan), penalty or settlement for which he may have become
liable in any such action, suit or proceeding, and c) reasonable costs, expenses
and attorneys' fees incurred by him in connection with the enforcement of the
indemnification rights provided herein. Any person who is or was serving in any
of the foregoing capacities for or on behalf of the Company shall be
conclusively deemed to be doing or to have done so in reliance upon, and as
consideration for, the indemnification rights provided herein.
Any such litigation expenses shall be paid by the Company in advance of the
final disposition of any action, suit or proceeding upon receipt of an unsecured
written promise by or on behalf of any such person to repay such amount unless
it shall ultimately be determined that such person is entitled to be indemnified
by the Company against such expenses.
The rights of indemnification provided herein (which shall be deemed to be a
contract between any such person and the Company enforceable on the part of such
person notwithstanding any subsequent amendment or repeal of this By-Law) shall
inure to the benefit of the estates or legal representatives of any such person
and shall not be exclusive of any other rights to which such person may be
entitled apart from this By-Law, by contract, resolution or otherwise.
SECTION 4. AMENDMENTS. Except as otherwise provided by law, these By-Laws may be
amended or repealed and new By-Laws may be adopted by the affirmative vote of a
majority of the directors then holding office at any regular or special meeting
of the Board of Directors.
* * * *
<PAGE>
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DUKE POWER COMPANY
TO
CHEMICAL BANK,
TRUSTEE
------------------
EIGHTIETH SUPPLEMENTAL INDENTURE
DATED AS OF AUGUST 1, 1995
------------------
CREATING AN ISSUE OF FIRST AND REFUNDING
MORTGAGE BONDS, 7 1/2% SERIES B DUE 2025
------------------
SUPPLEMENTAL TO
FIRST AND REFUNDING MORTGAGE
DATED AS OF DECEMBER 1, 1927
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>
SUPPLEMENTAL INDENTURE, bearing date as of the first day of August, 1995,
made and entered into by and between DUKE POWER COMPANY, a corporation duly
organized and existing under the laws of the State of North Carolina,
hereinafter called the "Company", party of the first part, and CHEMICAL BANK
(successor to Morgan Guaranty Trust Company of New York as Trustee), a
corporation duly organized and existing under the laws of the State of New York,
having its principal place of business in the Borough of Manhattan, City and
State of New York, hereinafter called the "Trustee", as Trustee, party of the
second part.
WHEREAS Duke Power Company, a New Jersey corporation, hereinafter called
the "New Jersey Company", duly executed and delivered its First and Refunding
Mortgage, dated as of December 1, 1927, to Guaranty Trust Company of New York,
as Trustee, to secure its First and Refunding Mortgage Gold Bonds, to be issued
from time to time in series as provided in said Mortgage, and has from time to
time duly executed and delivered supplemental indentures, including supplemental
indentures dated as of September 1, 1947 and February 1, 1949, to Guaranty Trust
Company of New York (the corporate name of which has been changed to Morgan
Guaranty Trust Company of New York), as Trustee, and a supplemental indenture
dated as of February 1, 1960 to Morgan Guaranty Trust Company of New York, as
Trustee, supplementing and modifying said Mortgage (said Mortgage, as so
supplemented and modified, being hereinafter referred to as the "original
indenture"); and
WHEREAS bonds of a series known as the "First and Refunding Mortgage Bonds,
2.65% Series Due 1977" (herein called "bonds of the 2.65% Series"), bonds of a
series known as the "First and Refunding Mortgage Bonds, 2 7/8% Series Due 1979"
(herein called "bonds of the 1979 Series"), bonds of a series known as the
"First and Refunding Mortgage Bonds, 5 3/8% Series Due 1997" (herein called
"bonds of the 1997 Series"), bonds of a series known as the "First and Refunding
Mortgage Bonds, 6 3/8% Series Due 1998" (herein called "bonds of the 1998
Series"), bonds of a series known as the "First and Refunding Mortgage Bonds,
Annual Tender Pollution Control Series 1987 A" (herein called "bonds of the 1987
Pollution Control Series A"), bonds of a series known as the "First and
Refunding Mortgage Bonds, Annual Tender Pollution Control Series 1987 B" (herein
called "bonds of the 1987 Pollution Control Series B"), bonds of a series known
as the "First and Refunding Mortgage Bonds, Annual Tender Pollution Control
Series 1987 C" (herein called "bonds of the 1987 Pollution Control Series C"),
bonds of a series known as the "First and Refunding Mortgage Bonds, Pollution
Control Facilities Revenue Refunding Series Due 2014" (herein called "bonds of
the 1990 Pollution
<PAGE>
2
Control Series"), bonds of a series known as the "First and Refunding Mortgage
Bonds, 8 3/4% Series Due 2021" (herein called "bonds of the 2021 Series"), bonds
of a series known as the "First and Refunding Mortgage Bonds, City of Greensboro
Series Due 2027" (herein called "bonds of the 2027 City of Greensboro Series"),
bonds of a series known as the "First and Refunding Mortgage Bonds, Medium-Term
Notes Series" (herein called "bonds of the Medium-Term Notes Series"), bonds of
a series known as the "First and Refunding Mortgage Bonds, 8 3/8% Series B Due
2021" (herein called "bonds of the 2021 Series B"), bonds of a series known as
the "First and Refunding Mortgage Bonds, 8% Series Due 2004" (herein called
"bonds of the 2004 Series"), bonds of a series known as the "First and Refunding
Mortgage Bonds, 8 5/8% Series Due 2022" (herein called "bonds of the 2022
Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, 7%
Series Due 2000" (herein called "bonds of the 2000 Series"), bonds of a series
known as the "First and Refunding Mortgage Bonds, 7% Series B Due 2000" (herein
called "bonds of the 2000 Series B"), bonds of a series known as the "First and
Refunding Mortgage Bonds, 7% Series Due 2005" (herein called "bonds of the 2005
Series"), bonds of a series known as the "First and Refunding Mortgage Bonds,
6 5/8% Series B Due 2003" (herein called "bonds of the 2003 Series B"), bonds of
a series known as the "First and Refunding Mortgage Bonds, 7 3/8% Series Due
2023" (herein called "bonds of the 2023 Series"), bonds of a series known as the
"First and Refunding Mortgage Bonds, 6 3/8% Series Due 2008" (herein called
"bonds of the 2008 Series"), bonds of a series known as the "First and Refunding
Mortgage Bonds, 5 7/8% Series C Due 2003" (herein called "bonds of the 2003
Series C"), bonds of a series known as the "First and Refunding Mortgage Bonds,
Pollution Control Facilities Revenue Refunding Series Due 2014" (herein called
"bonds of the 1993 Pollution Control Series"), bonds of a series known as the
"First and Refunding Mortgage Bonds, 6 1/4% Series B 2004" (herein called "bonds
of the 2004 Series B"), bonds of a series known as the "First and Refunding
Mortgage Bonds, 5 7/8% Series Due 2001" (herein called "bonds of the 2001
Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, 7%
Series Due 2033" (herein called "bonds of the 2033 Series"), bonds of a series
known as the "First and Refunding Mortgage Bonds, 6 7/8% Series B Due 2023"
(herein called "bonds of the 2023 Series B"), bonds of a series known as the
"First and Refunding Mortgage Bonds, 6 3/4% Series Due 2025" (herein called
"bonds of the 2025 Series"), bonds of a series known as the "First and Refunding
Mortgage Bonds, 7 7/8% Series Due 2024" (herein called "bonds of the 2024
Series") and bonds of a series known as the "First and Refunding Mortgage Bonds,
8% Series B Due 1999" (herein
<PAGE>
3
called "bonds of the 1999 Series B") have heretofore been issued and (except for
bonds of the 2.65% Series, bonds of the 1979 Series and bonds of the 1998 Series
which have been retired in their entirety) are the only bonds now outstanding
under the original indenture as heretofore supplemented; and
WHEREAS the Company has duly executed and delivered a supplemental
indenture, dated as of June 15, 1964, to Morgan Guaranty Trust Company of New
York, as Trustee, for the purpose of evidencing the succession by merger of the
Company to the New Jersey Company and the assumption by the Company of the
covenants and conditions of the New Jersey Company in the original indenture and
to enable the Company to have and exercise the powers and rights of the New
Jersey Company under the original indenture in accordance with the terms thereof
and whereby the Company assumed and agreed to pay duly and punctually the
principal of and interest on the bonds issued under the original indenture in
accordance with the provisions of said bonds and the coupons thereto
appertaining and the original indenture, and agreed to perform and fulfill all
the terms, covenants and conditions of the original indenture binding upon the
New Jersey Company; and
WHEREAS Morgan Guaranty Trust Company of New York resigned as Trustee under
the original indenture as heretofore supplemented and Chemical Bank was
appointed successor Trustee, said resignation and appointment having taken
effect on August 30, 1994 pursuant to an Instrument of Resignation, Appointment
and Acceptance dated as of August 30, 1994 among the Company, Morgan Guaranty
Trust Company of New York, as Trustee, and Chemical Bank, as successor Trustee;
and
WHEREAS the Company desires to create under the original indenture, as
heretofore supplemented and as to be supplemented by this supplemental
indenture, a new series of bonds, to be known as its "First and Refunding
Mortgage Bonds, 7 1/2% Series B Due 2025", and to determine the terms and
provisions and the form of the bonds of such series; and
WHEREAS for the purposes hereinabove recited, and pursuant to due corporate
action, the Company has duly determined to execute and deliver to the Trustee a
supplemental indenture in the form hereof supplementing the original indenture
(the original indenture, as supplemented by the aforesaid supplemental indenture
dated as of June 15, 1964, by supplemental indentures dated as of April 1, 1967,
February 1, 1968, February 15, 1987, October 1, 1987, March 1, 1990, May 15,
1990, March 1, 1991, July 1, 1991, December 1, 1991, March 1, 1992, June 1,
1992, July 1, 1992, September 1, 1992, February 1, 1993, March 1, 1993, April 1,
1993, May 1,
<PAGE>
4
1993, June 1, 1993, July 1, 1993, August 1, 1993, August 20, 1993, May 1, 1994,
November 1, 1994 and as hereby supplemented, being sometimes hereinafter
referred to as the "Indenture"); and
WHEREAS all conditions and requirements necessary to make this supplemental
indenture a valid, legal and binding instrument in accordance with its terms
have been done and performed, and the execution and delivery hereof have been in
all respects duly authorized:
NOW, THEREFORE, THIS INDENTURE WITNESSETH:
That in consideration of the premises and of the sum of one dollar duly
paid by the Company to the Trustee at or before the execution and delivery of
these presents, the receipt whereof is hereby acknowledged, the Company hereby
covenants and agrees with the Trustee and its successors in the trust under the
Indenture as follows:
PART ONE.
BONDS OF THE 7 1/2% SERIES B DUE 2025.
SECTION 1. The Company hereby creates a new series of bonds to be issued
under and secured by the Indenture and known as its First and Refunding Mortgage
Bonds, 7 1/2% Series B Due 2025 (herein called "bonds of the 2025 Series B"),
and the Company hereby establishes, determines and fixes the terms and
provisions of the bonds of the 2025 Series B as hereinafter in this Part One set
forth.
Each bond of the 2025 Series B shall be dated the date of its
authentication (except that if any such bond shall be authenticated on any
interest payment date, it shall be dated the following day) and interest shall
be payable on the principal represented thereby commencing February 1, 1996,
from the February 1 or August 1, as the case may be, next preceding the date
thereof to which interest has been paid, unless such date of authentication is
prior to February 1, 1996, in which case interest shall be payable from August
1, 1995; provided, however, that interest shall be payable on each bond of the
2025 Series B authenticated after the record date (as defined in the next
succeeding paragraph of this Section 1) with respect to any interest payment
date and prior to such interest payment date, only from such interest payment
date.
Interest on any bond of the 2025 Series B shall be paid to the person who,
according to the bond register of the Company, is the registered holder of such
bond of the 2025 Series B at the close of business on the applicable record
date, and such interest payments shall be made by check mailed to such
registered holder at his last address shown on such bond register;
<PAGE>
5
provided, however, that, if the Company shall default in the payment of the
interest due on any interest payment date on any bond of the 2025 Series B, such
defaulted interest shall be paid to the registered holder of such bond (or any
bond or bonds of the 2025 Series B issued upon transfer, exchange or
substitution thereof) on the date of subsequent payment of such defaulted
interest or, at the election of the Company, to the person in whose name such
bond (or any bond or bonds of the 2025 Series B issued upon transfer, exchange
or substitution thereof) is registered on a subsequent record date established
by notice given by mail by or on behalf of the Company to the holders of all
bonds of the 2025 Series B not less than ten (10) days preceding such subsequent
record date. The term "record date" as used in this Section 1 shall mean, with
respect to any semi-annual interest payment date, the close of business on the
January 15 or July 15, as the case may be, next preceding such interest payment
date or, in the case of a payment of defaulted interest, the close of business
on any subsequent record date established as provided above.
SECTION 2. All bonds of the 2025 Series B shall mature as to principal on
August 1, 2025, and shall bear interest at the rate of 7 1/2% per annum, payable
semi-annually on the first day of February and August in each year.
SECTION 3. The bonds of the 2025 Series B shall be fully registered bonds,
without coupons, in denominations of one thousand dollars ($1,000) and any
integral multiple of one thousand dollars ($1,000), all such bonds to be
numbered, and shall be transferable and exchangeable as provided in the form of
bond set forth in this supplemental indenture. The provisions of sec. 1.19 and
any other provision in the Indenture in respect of coupon bonds or reservation
of coupon bond numbers shall be inapplicable to the bonds of the 2025 Series B.
SECTION 4. The bonds of the 2025 Series B are not subject to redemption
(otherwise than through the operation of the Replacement Fund provided in Part
Two of this supplemental indenture or through the application of moneys paid to
the Trustee pursuant to the provisions of sec. 5.05 of the Indenture) prior to
August 1, 2000. On and after August 1, 2000, the bonds of the 2025 Series B are
subject to redemption (otherwise than through the operation of the Replacement
Fund provided in Part Two of this supplemental indenture or through the
application of moneys paid to the Trustee pursuant to the provisions of sec.
5.05 of the Indenture) prior to maturity, at the option of the Company, as a
whole at any time or in part from time to time, in principal amounts equal to
$1,000 or any multiple thereof, upon prior notice as hereinafter provided, at
the redemption prices
<PAGE>
6
specified in the third paragraph of the reverse side of the form of bond set
forth in this supplemental indenture, together with interest accrued thereon to
the date fixed for redemption thereof.
The bonds of the 2025 Series B are also subject to redemption through the
operation of the Replacement Fund provided in Part Two of this supplemental
indenture or through the application of moneys paid to the Trustee pursuant to
the provisions of sec. 5.05 of the Indenture, at any time or from time to time
prior to maturity, upon prior notice as hereinafter provided, at the redemption
prices specified in the fourth paragraph of the reverse side of the form of bond
set forth in this supplemental indenture, together with interest accrued thereon
to the date fixed for redemption thereof.
All such redemption of bonds of the 2025 Series B shall be effected as
provided in Article 3 of the Indenture except that, in case a part only of the
bonds of the 2025 Series B is to be paid and redeemed, the particular bonds or
part thereof shall be selected by the Trustee in such manner as the Trustee in
its uncontrolled discretion shall determine to be fair and in any case where
several bonds are registered in the same name, the Trustee may treat the
aggregate principal amount so registered as if it were represented by one bond
and except that when bonds are redeemed in part only the notice given to any
particular holder need state only the principal amount of the bonds of that
holder which are to be redeemed and except that notice to the holders of bonds
to be redeemed shall be given by mailing to such holders a notice of such
redemption, first class mail postage prepaid, not later than the thirtieth day,
and not earlier than the sixtieth day, before the date fixed for redemption, at
their last addresses as they shall appear upon the bond register of the Company.
Any notice which is mailed in the manner herein provided shall be conclusively
presumed to have been duly given, whether or not the holder receives such
notice; and failure duly to give such notice by mail, or any defect in such
notice, to the holder of any bond designated for redemption as a whole or in
part shall not affect the validity of the proceedings for the redemption of any
other bond. No publication of notice of such redemption shall be required.
SECTION 5. The aggregate principal amount of the bonds of the 2025 Series
B shall be unlimited.
SECTION 6. The place or places of payment (as to principal and premium, if
any, and interest), redemption, transfer, exchange and registration of the bonds
of the 2025 Series B shall be the office or offices or the agency or agencies of
the Company in the Borough of Manhattan, The City of New York, designated from
time to time by the Board of Directors of the Company.
<PAGE>
7
SECTION 7. The form of the bonds of the 2025 Series B and the certificate
of the Trustee to be endorsed on the bonds, respectively, shall be substantially
as follows:
[FORM OF BOND OF THE 2025 SERIES B]
[FACE SIDE OF BOND]
DUKE POWER COMPANY
FIRST AND REFUNDING MORTGAGE BOND,
7 1/2% Series B Due 2025
No. $
DUKE POWER COMPANY, a North Carolina corporation (hereinafter called the
"Company"), for value received, hereby promises to pay to or
registered assigns, the principal sum of Dollars on August 1, 2025,
in any coin or currency of the United States of America which at the time of
payment shall be legal tender for the payment of public and private debts, at
the office or agency of the Company in the Borough of Manhattan, The City of New
York, and to pay interest thereon at said office or agency from the interest
payment date next preceding the date hereof to which interest on outstanding
bonds of this series has been paid (unless the date hereof is prior to February
1, 1996, in which case from August 1, 1995, and unless the date hereof is a
January date subsequent to January 15, or a July date subsequent to July 15, in
which case from the next succeeding February 1 or August 1, as the case may be),
at the rate of seven and one-half per cent per annum, in like coin or currency,
semi-annually on February 1 and August 1 in each year until the principal hereof
shall become due and payable. Such interest payments shall be made by check
mailed to the person in whose name this bond is registered at the close of
business on the 15th day of January or July preceding each semi-annual interest
payment date, as the case may be (subject to certain exceptions provided in the
Indenture hereinafter mentioned), at his last address as it shall appear upon
the bond register of the Company.
The provisions of this bond are continued on the reverse hereof and such
continued provisions shall for all purposes have the same effect as though fully
set forth in this place.
This bond shall not become or be valid or obligatory for any purpose until
the Trustee shall have signed the form of certificate endorsed hereon.
<PAGE>
8
IN WITNESS WHEREOF, the Company has caused this instrument to be signed in
its name by its President or one of its Vice Presidents, manually or by
facsimile signature, and its corporate seal to be hereto affixed, or a facsimile
thereof to be hereon engraved, lithographed or printed, and to be attested by
the manual or facsimile signature of its Secretary or one of its Assistant
Secretaries.
Dated:
DUKE POWER COMPANY
By: ..........................................
President
Attest:
..............................................
Secretary
[FORM OF TRUSTEE'S CERTIFICATE FOR
BOND OF THE 2025 SERIES B]
This bond is one of the bonds, of the series designated therein, described
in the within-mentioned Indenture.
CHEMICAL BANK, Trustee
By: ..........................................
Authorized Officer
<PAGE>
9
[REVERSE SIDE OF BOND]
This bond is one of the bonds of a series, designated specially as First
and Refunding Mortgage Bonds, 7 1/2% Series B Due 2025, of an authorized issue
of bonds of the Company, without limit as to aggregate principal amount,
designated generally as First and Refunding Mortgage Bonds, all issued and to be
issued under and equally and ratably secured by an indenture dated as of
December 1, 1927, duly executed by Duke Power Company, a New Jersey corporation
(hereinafter called the "New Jersey Company"), to Guaranty Trust Company of New
York (now Morgan Guaranty Trust Company of New York), as Trustee (Chemical Bank,
successor Trustee), as supplemented and modified by indentures supplemental
thereto, including supplemental indentures dated as of September 1, 1947,
February 1, 1949, February 1, 1960, June 15, 1964 (under which the Company
succeeded to and was substituted for the New Jersey Company), April 1, 1967,
February 1, 1968, February 15, 1987, October 1, 1987, March 1, 1990, May 15,
1990, March 1, 1991, July 1, 1991, December 1, 1991, March 1, 1992, June 1,
1992, July 1, 1992, September 1, 1992, February 1, 1993, March 1, 1993, April 1,
1993, May 1, 1993, June 1, 1993, July 1, 1993, August 1, 1993, August 20, 1993,
May 1, 1994, November 1, 1994 and August 1, 1995, the latter providing for said
series (said indenture as so supplemented and modified being hereinafter
referred to as the "Indenture"), to which Indenture reference is made for a
description of the property mortgaged, the nature and extent of the security,
the rights of the holders of the bonds in respect thereof, the terms and
conditions upon which the bonds are secured and the restrictions subject to
which additional bonds secured thereby may be issued. To the extent permitted
by, and as provided in, the Indenture, modifications or alterations of the
Indenture, or of any indenture supplemental thereto, and of the rights and
obligations of the Company and of the holders of the bonds, may be made with the
consent of the Company by the affirmative vote, or with the written consent, of
the holders of not less than 66 2/3% in principal amount of the bonds then
outstanding, and by the affirmative vote, or with the written consent, of the
holders of not less than 66 2/3% in principal amount of the bonds of any series
then outstanding and affected by such modification or alteration, in case one or
more but less than all of the series of bonds then outstanding under the
Indenture are so affected, evidenced, in each case, as provided in the
Indenture; provided that any supplemental indenture may be modified in
accordance with the provisions contained therein for its modification; and
provided, further, that no such modification or alteration shall be made
<PAGE>
10
which will affect the terms of payment of the principal of, or interest or
premium on, this bond, or the right of any bondholder to institute suit for the
enforcement of any such payment on or after the respective due dates expressed
in this bond, or reduce the percentage required for the taking of any such
action. Any such affirmative vote of, or written consent given by, any holder of
this bond is binding upon all subsequent holders hereof as provided in the
Indenture.
In case an event of default as defined in the Indenture shall occur, the
principal of all the bonds outstanding thereunder may become or be declared due
and payable, at the time, in the manner and with the effect provided in the
Indenture.
The bonds of this series are not subject to redemption (otherwise than for
the Replacement Fund hereinafter mentioned or upon application of certain moneys
included in the trust estate) prior to August 1, 2000. On and after August 1,
2000, the bonds of this series are subject to redemption (otherwise than for the
Replacement Fund hereinafter mentioned or upon application of certain moneys
included in the trust estate) prior to maturity, at the option of the Company,
as a whole at any time or in part from time to time, at the following redemption
prices (expressed as percentages of their principal amounts), in each case
together with accrued interest to the date fixed for redemption:
If redeemed during the twelve-month period beginning August 1:
<TABLE>
<CAPTION>
REDEMPTION
YEAR PRICE
- --------------------- ----------
<S> <C>
2000................. 103.355 %
2001................. 103.131
2002................. 102.907
2003................. 102.684
2004................. 102.460
2005................. 102.236
2006................. 102.013
2007................. 101.789
2008................. 101.566
2009................. 101.342
2010................. 101.118
2011................. 100.895
2012................. 100.671
2013................. 100.447
2014................. 100.224
2015................. 100.000
2016................. 100.000
2017................. 100.000
2018................. 100.000
2019................. 100.000
2020................. 100.000
2021................. 100.000
2022................. 100.000
2023................. 100.000
2024................. 100.000
</TABLE>
<PAGE>
11
The bonds of this series are also subject to redemption for the Replacement
Fund for bonds of this series provided for in the supplemental indenture dated
as of August 1, 1995, providing for this series, or upon application of certain
moneys included in the trust estate, at any time or from time to time prior to
maturity, at the following redemption prices (expressed as percentages of their
principal amounts), in each case together with accrued interest to the date
fixed for redemption:
If redeemed during the twelve-month period beginning August 1:
<TABLE>
<CAPTION>
REDEMPTION
YEAR PRICE
- --------------------- ----------
<S> <C>
1995................. 100.000 %
1996................. 100.000
1997................. 100.000
1998................. 100.000
1999................. 100.000
2000................. 100.000
2001................. 100.000
2002................. 100.000
2003................. 100.000
2004................. 100.000
2005................. 100.000
2006................. 100.000
2007................. 100.000
2008................. 100.000
2009................. 100.000
2010................. 100.000
2011................. 100.000
2012................. 100.000
2013................. 100.000
2014................. 100.000
2015................. 100.000
2016................. 100.000
2017................. 100.000
2018................. 100.000
2019................. 100.000
2020................. 100.000
2021................. 100.000
2022................. 100.000
2023................. 100.000
2024................. 100.000
</TABLE>
Redemption is in every case to be effected at the office or agency of the
Company in the Borough of Manhattan, The City of New York, upon at least thirty
days' prior notice, given by mail as more fully provided in the Indenture.
If this bond or any portion hereof ($1,000 or a multiple thereof) is called
for redemption and payment is duly provided, this bond or such portion thereof
shall cease to bear interest from and after the date fixed for such redemption.
This bond is transferable, as provided in the Indenture, by the registered
owner hereof in person or by duly authorized attorney, at the office or agency
of the Company in the Borough of Manhattan, The City of New York, upon surrender
and cancellation of this bond, and thereupon a new bond of the same series and
of like aggregate principal amount will be
<PAGE>
12
issued to the transferee in exchange herefor as provided in the Indenture; or
the registered owner of this bond, at his option, may surrender the same for
cancellation at said office or agency of the Company and receive in exchange
herefor the same aggregate principal amount of bonds of the same series of
authorized denominations; all subject to the terms of the Indenture but without
payment of any charges other than a sum sufficient to reimburse the Company for
any stamp taxes or other governmental charges incident thereto.
This bond is a corporate obligation only and no recourse whatsoever, either
directly or through the Company or any trustee, receiver, assignee or any other
person, shall be had for the payment of the principal of or premium, if any, or
interest on this bond, or for the enforcement of any claim based hereon, or
otherwise in respect hereof or of the Indenture, against any promoter,
subscriber to the capital stock, incorporator, or any past, present or future
stockholder, officer or director of the Company as such, or of any successor or
predecessor corporation, whether by virtue of any constitutional provision,
statute or rule of law, or by the enforcement of any assessment, penalty,
subscription or otherwise, any and all such liability of promoters, subscribers,
incorporators, stockholders, officers and directors being waived and released by
each successive holder hereof by the acceptance of this bond, and as a part of
the consideration for the issue hereof, and being likewise waived and released
by the terms of the Indenture.
[END OF BOND FORM]
PART TWO.
REPLACEMENT FUND.
SECTION 1. So long as any of the bonds of the 2025 Series B are
outstanding, the Company will continue to maintain the Replacement Fund set
forth in, and in accordance with the applicable terms and conditions now
contained in, Part Two of the supplemental indenture dated as of February 1,
1949, and the covenants on the part of the Company contained in such Part Two
shall continue and remain in full force and effect, whether or not bonds of the
1979 Series are outstanding and to the same extent as though the words "or any
bonds of the 2025 Series B" were inserted after the word "Series" appearing in
the second line of Section 1 and the second line of Section 4 of said Part Two
of said supplemental indenture dated as of February 1, 1949.
<PAGE>
13
SECTION 2. If at any time (a) bonds of the 2025 Series B are outstanding
and (b) no bonds of the 1997 Series, of the 2021 Series, of the Medium-Term
Notes Series, of the 2021 Series B, of the 2004 Series, of the 2022 Series, of
the 2000 Series, of the 2000 Series B, of the 2005 Series, of the 2003 Series B,
of the 2023 Series, of the 2008 Series, of the 2003 Series C, of the 2004 Series
B, of the 2001 Series, of the 2033 Series, of the 2023 Series B, of the 2025
Series, of the 2024 Series or of the 1999 Series B are outstanding and (c) cash
which shall have been deposited with the Trustee pursuant to such Replacement
Fund shall not within five years from the date of deposit thereof have been paid
out, or used or set aside by the Trustee for the payment, purchase or redemption
of bonds, pursuant to such Replacement Fund, such cash shall, if in excess of
fifty thousand dollars ($50,000), be applied to the redemption of bonds of the
2025 Series B in an aggregate principal amount sufficient to exhaust as nearly
as possible the full amount of such cash. Anything in Section 5 of Part Two of
the aforesaid supplemental indenture dated as of February 1, 1949, in Section 3
of Part Two of the supplemental indentures dated as of April 1, 1967, March 1,
1991, December 1, 1991, June 1, 1992, July 1, 1992, September 1, 1992, February
1, 1993, May 1, 1993, June 1, 1993, July 1, 1993, August 1, 1993, August 20,
1993, May 1, 1994 and November 1, 1994, in Section 3 of Part Three of the
supplemental indenture dated as of March 1, 1990, in Section 4 of Part Three of
the supplemental indenture dated as of March 1, 1992 and in Section 5 of Part
Four of the supplemental indenture dated as of March 1, 1993 to the contrary
notwithstanding, no cash shall be paid over to the Company thereunder if at the
time any bonds of the 2025 Series B are then outstanding, and such cash shall in
such event be applied as in this Part Two set forth.
SECTION 3. Whenever all of the bonds of the 2025 Series B, the 1997
Series, the 2021 Series, the Medium-Term Notes Series, the 2021 Series B, the
2004 Series, the 2022 Series, the 2000 Series, the 2000 Series B, the 2005
Series, the 2003 Series B, the 2023 Series, the 2008 Series, the 2003 Series C,
the 2004 Series B, the 2001 Series, the 2033 Series, the 2023 Series B, the 2025
Series, the 2024 Series and the 1999 Series B shall have been paid, purchased or
redeemed, the Trustee shall, upon application of the Company, pay to or upon the
order of the Company all cash theretofore deposited with the Trustee pursuant to
the provisions of the Replacement Fund and not previously disposed of pursuant
to the provisions of the Replacement Fund, and shall deliver to the Company any
bonds which shall theretofore have been deposited with the Trustee pursuant to
the provisions
<PAGE>
14
of the Replacement Fund or paid, purchased or redeemed pursuant to the
provisions of the Replacement Fund.
PART THREE.
ADDITIONAL COVENANTS OF THE COMPANY.
SECTION 1. Whether or not the covenants on the part of the Company
contained in Part Three of the supplemental indenture dated as of February 1,
1949 are modified with the consent of the holders of bonds of the 1997 Series,
the 1987 Pollution Control Series A, the 1987 Pollution Control Series B, the
1987 Pollution Control Series C, the 1990 Pollution Control Series, the 2021
Series, the 2027 City of Greensboro Series, the Medium-Term Notes Series, the
2021 Series B, the 2004 Series, the 2022 Series, the 2000 Series, the 2000
Series B, the 2005 Series, the 2003 Series B, the 2023 Series, the 2008 Series,
the 2003 Series C, the 1993 Pollution Control Series, the 2004 Series B, the
2001 Series, the 2033 Series, the 2023 Series B, the 2025 Series, the 2024
Series or the 1999 Series B and whether or not the bonds of the 1997 Series, the
1987 Pollution Control Series A, the 1987 Pollution Control Series B, the 1987
Pollution Control Series C, the 1990 Pollution Control Series, the 2021 Series,
the 2027 City of Greensboro Series, the Medium-Term Notes Series, the 2021
Series B, the 2004 Series, the 2022 Series, the 2000 Series, the 2000 Series B,
the 2005 Series, the 2003 Series B, the 2023 Series, the 2008 Series, the 2003
Series C, the 1993 Pollution Control Series, the 2004 Series B, the 2001 Series,
the 2033 Series, the 2023 Series B, the 2025 Series, the 2024 Series or the 1999
Series B are outstanding, such covenants on the part of the Company contained in
said Part Three shall continue and remain in full force and effect so long as
any of the bonds of the 2025 Series B are outstanding and to the same extent as
though the words "or so long as any bonds of the 2025 Series B are outstanding"
were inserted after the words "so long as any of the bonds of the 1979 Series or
any bonds of the 2.65% Series are outstanding" wherever such words appear in
said Part Three of the supplemental indenture dated as of February 1, 1949.
SECTION 2. Whether or not the second sentence of paragraph (a) of
sec. 2.08 of the original indenture (making certain provisions for the
definition of the term "net amount" applicable while bonds of the 2.65% Series
were outstanding and which was originally set forth in Section 4 of Article One
of the supplemental indenture dated as of September 1, 1947 and which is
corrected and clarified by Section 2 of Part Four of the supplemental
<PAGE>
15
indenture dated as of February 1, 1968) is modified with the consent of the
holders of bonds of the 1997 Series, the 1987 Pollution Control Series A, the
1987 Pollution Control Series B, the 1987 Pollution Control Series C, the 1990
Pollution Control Series, the 2021 Series, the 2027 City of Greensboro Series,
the Medium-Term Notes Series, the 2021 Series B, the 2004 Series, the 2022
Series, the 2000 Series, the 2000 Series B, the 2005 Series, the 2003 Series B,
the 2023 Series, the 2008 Series, the 2003 Series C, the 1993 Pollution Control
Series, the 2004 Series B, the 2001 Series, the 2033 Series, the 2023 Series B,
the 2025 Series, the 2024 Series or the 1999 Series B and whether or not bonds
of the 1997 Series, the 1987 Pollution Control Series A, the 1987 Pollution
Control Series B, the 1987 Pollution Control Series C, the 1990 Pollution
Control Series, the 2021 Series, the 2027 City of Greensboro Series, the
Medium-Term Notes Series, the 2021 Series B, the 2004 Series, the 2022 Series,
the 2000 Series, the 2000 Series B, the 2005 Series, the 2003 Series B, the 2023
Series, the 2008 Series, the 2003 Series C, the 1993 Pollution Control Series,
the 2004 Series B, the 2001 Series, the 2033 Series, the 2023 Series B, the 2025
Series, the 2024 Series or the 1999 Series B are outstanding, said sentence
shall continue and remain in full force and effect so long as any bonds of the
2025 Series B are outstanding, and with the same force and effect as though said
sentence had stated that such provisions were to be applicable so long as any of
the bonds of the 2025 Series B are outstanding.
PART FOUR.
MISCELLANEOUS.
SECTION 1. (a) For the purposes of sec. 2.10 of the Indenture and for the
purposes of any modification of the provisions of the Replacement Fund referred
to in Part Two of this supplemental indenture, the covenants and provisions on
the part of the Company which are set forth or incorporated in Part Two of this
supplemental indenture shall be for the benefit only of the holders of the bonds
of the 2025 Series B. Such covenants and provisions shall remain in force and be
applicable only so long as any bonds of the 2025 Series B shall be outstanding,
and, subject to the provisions of paragraph (2) of subdivision (c) of sec. 10.01
of the Indenture, any such covenants and provisions may be modified with the
consent, in writing or by vote at a bondholders' meeting, of the holders of
sixty-six and two-thirds per cent (66 2/3%) of the principal amount of the bonds
of the 2025 Series B at the time outstanding and without the consent of the
holders of any other bonds
<PAGE>
16
then outstanding under the Indenture; provided that no such consent shall be
effective to waive any past default under such covenants and provisions, and its
consequences, unless the consent of the holders of at least a majority in
principal amount of all bonds then outstanding under the Indenture is obtained.
Such covenants shall be deemed to be additional covenants and none of them shall
affect or derogate from, or relieve the Company from, its obligation to comply
with any of the other covenants, conditions, requirements or provisions of the
Indenture or any other supplemental indenture.
(b) For the purposes of sec. 2.10 of the Indenture and for the purposes of
any modification of the provisions of Part Three of this supplemental indenture,
the covenants and provisions on the part of the Company which are set forth or
incorporated in said Part Three shall be for the benefit only of the holders of
the bonds of the 2025 Series B. Such covenants and provisions shall remain in
force and be applicable only so long as any bonds of the 2025 Series B shall be
outstanding, and, subject to the provisions of paragraph (2) of subdivision (c)
of sec. 10.01 of the Indenture, any such covenants and provisions may be
modified with the consent, in writing or by vote at a bondholders' meeting, of
the holders of sixty-six and two-thirds per cent (66 2/3%) of the principal
amount of the bonds of the 2025 Series B at the time outstanding and without the
consent of the holders of any other bonds then outstanding under the Indenture;
provided that no such consent shall be effective to waive any past default under
such covenants and provisions, and its consequences, unless the consent of the
holders of at least a majority in principal amount of all bonds then outstanding
under the Indenture is obtained. Such covenants shall be deemed to be additional
covenants and none of them shall affect or derogate from, or relieve the Company
from, its obligation to comply with any of the other covenants, conditions,
requirements or provisions of the Indenture or any other supplemental indenture.
SECTION 2. All terms contained in this supplemental indenture shall,
except as specifically provided herein or except as the context may otherwise
require, have the meanings given to such terms in the Indenture.
SECTION 3. In case any one or more of the provisions contained in this
supplemental indenture should be invalid, illegal or unenforceable in any
respect, such invalidity, illegality or unenforceability shall not affect any
other provision contained in this supplemental indenture, and, to the extent,
but only to the extent, that such provision is invalid, illegal or
<PAGE>
17
unenforceable, this supplemental indenture shall be construed as if such
provision had never been contained herein.
SECTION 4. The Trustee hereby accepts the trusts herein declared and
provided upon the terms and conditions in the Indenture set forth.
SECTION 5. This supplemental indenture may be executed in several
counterparts, each of which shall be an original, and all collectively but one
instrument.
<PAGE>
18
IN WITNESS WHEREOF, Duke Power Company, the party of the first part hereto,
has caused this supplemental indenture to be signed in its name by one of its
Vice Presidents and its corporate seal to be hereunto affixed, and the same to
be attested by one of its Assistant Secretaries, and Chemical Bank, the party of
the second part hereto, in token of its acceptance of the trust hereby created,
has caused this supplemental indenture to be signed in its name by one of its
Vice Presidents and its corporate seal to be hereunto affixed, and the same to
be attested by one of its Assistant Secretaries, all as of the day and year
first above written.
DUKE POWER COMPANY
By:......................................
RICHARD J. OSBORNE
Senior Vice President
ATTEST:
..............................................
ROBERT T. LUCAS III
Assistant Secretary
Signed, sealed, executed, acknowledged and
delivered by DUKE POWER COMPANY, in the
presence of:
..............................................
CHERYL ANN TERRELL
..............................................
SUE C. HARRINGTON
CHEMICAL BANK
By:......................................
P. J. GILKESON
Vice President
ATTEST:
..............................................
R. LORENZEN
Senior Trust Officer
Signed, sealed, executed, acknowledged and
delivered by CHEMICAL BANK, in the presence
of:
..............................................
P. KELLY
..............................................
B. SKIBA
<PAGE>
19
STATE OF NEW YORK
COUNTY OF NEW YORK SS.:
Personally appeared before me P. KELLY and made oath that she saw P. J.
GILKESON, a Vice President, and R. LORENZEN, a Senior Trust Officer,
respectively, of CHEMICAL BANK, sign, attest and affix hereto the corporate seal
of said Chemical Bank, and, as the act and deed of said corporation, deliver the
within written and foregoing deed, and that she, with B. SKIBA, witnessed the
execution thereof.
..............................................
P. KELLY
Sworn and subscribed before me
this 17th day of August, 1995.
..............................................
ANNABELLE DELUCA
Notary Public, State of New York
No. 01DE 5013759
Qualified in Kings County
Certificate Filed in New York County
Commission Expires July 15, 1997.
STATE OF NEW YORK
COUNTY OF NEW YORK SS.:
I, ANNABELLE DELUCA, a Notary Public in and for the State and County
aforesaid, certify that R. LORENZEN personally came before me this day and
acknowledged that he is a Senior Trust Officer of CHEMICAL BANK, a New York
corporation, and that, by authority duly given and as the act of the
corporation, the foregoing instrument was signed in its name by one of its Vice
Presidents, sealed with its corporate seal, and attested by himself as one of
its Senior Trust Officers.
Witness my hand and official seal, this 17th day of August, 1995.
..............................................
ANNABELLE DELUCA
Notary Public, State of New York
No. 01DE 5013759
Qualified in Kings County
Certificate Filed in New York County
Commission Expires July 15, 1997.
<PAGE>
20
STATE OF NORTH CAROLINA
COUNTY OF MECKLENBURG SS.:
Personally appeared before me CHERYL ANN TERRELL and made oath that she saw
RICHARD J. OSBORNE, a Senior Vice President, and ROBERT T. LUCAS III, an
Assistant Secretary, respectively, of DUKE POWER COMPANY, sign, attest and affix
hereto the corporate seal of said Duke Power Company, and, as the act and deed
of said corporation, deliver the within written and foregoing deed, and that
she, with SUE C. HARRINGTON, witnessed the execution thereof.
..............................................
CHERYL ANN TERRELL
Sworn and subscribed before me
this 18th day of August, 1995.
..............................................
BRENDA M. ATCHLEY
Notary Public
Union County, N.C.
My Commission expires December 1, 1999.
STATE OF NORTH CAROLINA
COUNTY OF MECKLENBURG SS.:
I, SUE C. HARRINGTON, a Notary Public in and for the State and County
aforesaid, certify that ROBERT T. LUCAS III personally came before me this day
and acknowledged that he is an Assistant Secretary of DUKE POWER COMPANY, a
North Carolina corporation, and that, by authority duly given and as the act of
the corporation, the foregoing instrument was signed in its name by one of its
Senior Vice Presidents, sealed with its corporate seal, and attested by himself
as one of its Assistant Secretaries.
My commission expires October 3, 1996.
Witness my hand and official seal, this 18th day of August, 1995.
..............................................
SUE C. HARRINGTON
Notary Public
Mecklenburg County, N.C.
<PAGE>
EXHIBIT 12
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
1995 1994 1993 1992 1991
<S> <C> <C> <C> <C> <C>
Earnings Before Income Tax. . . . . . . . . . . . . . . . . $1,180,979 $1,035,895 $1,036,392 $ 812,053 $ 876,641
Fixed Charges . . . . . . . . . . . . . . . . . . . . . . . 299,633 278,117 281,428 326,575 310,030
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,480,612 $1,314,012 $1,317,820 $1,138,628 $1,186,671
Fixed Charges
Interest on long-term debt. . . . . . . . . . . . . . . . . 253,058 237,063 243,047 257,149 269,419
Other interest. . . . . . . . . . . . . . . . . . . . . . . 21,143 16,814 17,704 47,239 23,947
Amortization of debt discount, premium and expense. . . . . 16,239 16,340 13,300 8,497 5,243
Interest component of rentals . . . . . . . . . . . . . . . 9,193 7,900 7,377 13,690 11,421
Fixed Charges . . . . . . . . . . . . . . . . . . . . . . . $ 299,633 $ 278,117 $ 281,428 $ 326,575 $ 310,030
Ratio of Earnings to Fixed Charges. . . . . . . . . . . . . 4.94 4.72 4.68 3.49 3.83
</TABLE>
<PAGE>
EXHIBIT 23
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in Registration Statement
Nos. 33-19274, 33-50543, 33-50715 and 33-50617 of Duke Power Company on
Form S-3 and Registration Statement No. 2-72172 of Duke Power Company on
Form S-8 of our report dated February 9, 1996, appearing in this Form 10-K of
Duke Power Company filed with the Securities and Exchange Commission on March
12, 1996.
DELOITTE & TOUCHE LLP
Charlotte, North Carolina
March 12, 1996
<PAGE>
EXHIBIT 24(a)
DUKE POWER COMPANY
POWER OF ATTORNEY
FORM 10-K
Annual Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 1995
(Annual Report)
The undersigned DUKE POWER COMPANY, a North Carolina corporation and
certain of its officers and/or directors, do each hereby constitute and appoint
W. H. Grigg, Richard J. Osborne, Ellen T. Ruff, Jeffrey L. Boyer, and each of
them, to act as attorneys-in-fact for and in the respective names, places, and
stead of the undersigned, to execute, seal, sign, and file with the Securities
and Exchange Commission the Annual Report of said Duke Power Company on Form
10-K and any and all amendments thereto, hereby granting to said
attorneys-in-fact, and each of them, full power and authority to do and perform
all and every act and thing whatsoever requisite, necessary, or proper to be
done in and about the premises, as fully to all intents and purposes as the
undersigned, or any of them, might or could do if personally present, hereby
ratifying and approving the acts of said attorneys-in-fact.
Executed the 27th day of February, 1996.
DUKE POWER COMPANY
By W. H. Grigg
Chairman and Chief Executive Officer
(Corporate Seal)
ATTEST:
Robert T. Lucas III
Assistant Secretary
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
W. H. Grigg Chairman and Chief Executive Officer
W. H. Grigg (Principal Executive Officer and Director)
Richard J. Osborne Senior Vice President and Chief Financial
Richard J. Osborne Officer (Principal Financial Officer)
Jeffrey L. Boyer Controller (Principal Accounting Officer)
Jeffrey L. Boyer
G. Alex Bernhardt (Director)
G. Alex Bernhardt
Crandall C. Bowles (Director)
Crandall C. Bowles
Robert J. Brown (Director)
Robert J. Brown
William A. Coley (Director)
William A. Coley
Steve C. Griffith, Jr. (Director)
Steve C. Griffith, Jr.
(Director)
Paul H. Henson
George Dean Johnson, Jr. (Director)
George Dean Johnson, Jr.
(Director)
James V. Johnson
W. W. Johnson (Director)
W. W. Johnson
Max Lennon (Director)
Max Lennon
James G. Martin (Director)
James G. Martin
Buck Mickel (Director)
Buck Mickel
<PAGE>
Richard B. Priory (Director)
Richard B. Priory
Russell M. Robinson, II (Director)
Russell M. Robinson, II
</TABLE>
<PAGE>
EXHIBIT 24(b)
CERTIFIED COPY OF A RESOLUTION FROM THE MINUTES OF A REGULAR MEETING OF THE
BOARD OF DIRECTORS OF DUKE POWER COMPANY HELD ON FEBRUARY 27, 1996
Mr. Grigg then referred to the Company's Form 10-K Annual Report for
the year ended December 31, 1995. He presented to the meeting a preliminary copy
of the Form 10-K, indicating that it would be in order to approve such document
subject to such changes as may be deemed necessary or advisable. Dr. Lennon then
advised the Audit Committee had reviewed the Form 10-K and found it to be in
order and recommended its approval. Upon motion duly made and seconded, it was
RESOLVED, That the Form 10-K Annual Report, as presented to the
meeting, with such changes therein as may be deemed necessary or advisable by
the officers of the Company be and hereby is in all respects approved; and
FURTHER RESOLVED, That the Power of Attorney as presented to the
meeting and executed by all the Directors present be and hereby is approved in
form and content for purposes of filing the Form 10-K Annual Report with the
Securities and Exchange Commission.
***********************
I, Ellen T. Ruff, Secretary of Duke Power Company, do hereby certify
that the above is a full, true and complete extract from the Minutes of the
regular meeting of the Board of Directors of Duke Power Company held on February
27, 1996, at which meeting a quorum was present; as taken from and compared with
the original Minutes of said meeting.
IN WITNESS WHEREOF, I have hereunto set my hand and affixed the
Corporate Seal of said Duke Power Company this 28th day of February, 1996.
Ellen T. Ruff
Secretary
[SEAL]
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM
THE CONSOLIDATED STATEMENTS OF INCOME, CONSOLIDATED STATEMENTS OF
CASH FLOWS, CONSOLIDATED BALANCE SHEETS AND CONSOLIDATED STATEMENTS
OF RETAINED EARNINGS FOR THE 12 MONTHS ENDED 12/31/95 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>
<CIK> 0000030371
<NAME> DUKE POWER COMPANY
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 9360533
<OTHER-PROPERTY-AND-INVEST> 956647
<TOTAL-CURRENT-ASSETS> 1176154
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<TOTAL-ASSETS> 13358484
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<RETAINED-EARNINGS> 2858275
<TOTAL-COMMON-STOCKHOLDERS-EQ> 4785184
234000
450000
<LONG-TERM-DEBT-NET> 3711405
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<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 12071
0
<CAPITAL-LEASE-OBLIGATIONS> 6278
<LEASES-CURRENT> 1198
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<GROSS-OPERATING-REVENUE> 4676684
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<TOTAL-OPERATING-EXPENSES> 3794074
<OPERATING-INCOME-LOSS> 1349051
<OTHER-INCOME-NET> 121246
<INCOME-BEFORE-INTEREST-EXPEN> 1003856
<TOTAL-INTEREST-EXPENSE> 289318
<NET-INCOME> 714538
48903
<EARNINGS-AVAILABLE-FOR-COMM> 665635
<COMMON-STOCK-DIVIDENDS> 409716
<TOTAL-INTEREST-ON-BONDS> 242699
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<EPS-PRIMARY> 3.25
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</TABLE>
