DUKE POWER CO /NC/, 10-K, 1994-03-31

DUKE POWER CO /NC/
10-K, 1994-03-31
ELECTRIC SERVICES

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<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, 1993
( ) 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 (IRS EMPLOYER
INCORPORATION OR ORGANIZATION) 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>
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
<S> <C>
Common Stock, without par value New York Stock Exchange
Preferred Stock A, par value $25
7.72%, 1992 Series New York Stock Exchange
6.375% 1993 Series New York Stock Exchange
</TABLE>

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
TITLE OF CLASS
Preferred Stock, par value $100
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. (X)
<TABLE>
<S> <C>
Estimated aggregate market value of the voting stock held by nonaffiliates of the registrant at
March 29, 1994................................................................................ $ 7,375,999,091
Number of shares of Common Stock, without par value, outstanding at March 29, 1994.............. 204,859,339
</TABLE>

DOCUMENTS INCORPORATED BY REFERENCE:
The registrant is incorporating herein by reference certain sections of its
proxy statement relating to the 1994 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, 1993
TABLE OF CONTENTS
<TABLE>
<CAPTION>
ITEM PAGE
<C> <S> <C>
PART I.
1. Business.................................................................... 1
Executive Officers of the Company........................................... 14
2. Properties.................................................................. 15
3. Legal Proceedings........................................................... 15
4. Submission of Matters to a Vote of Security Holders......................... 15
<CAPTION>
PART II.
<C> <S> <C>
5. Market for the Registrant's Common Equity and Related Stockholder Matters... 15
6. Selected Financial Data..................................................... 16
7. Management's Discussion and Analysis of Results of Operations and Financial
Condition................................................................. 17
8. Financial Statements and Supplementary Data................................. 22
9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure................................................................ 45
<CAPTION>
PART III.
<C> <S> <C>
10. Directors and Executive Officers of the Registrant.......................... 45
11. Executive Compensation...................................................... 45
12. Security Ownership of Certain Beneficial Owners and Management.............. 45
13. Certain Relationships and Related Transactions.............................. 45
<CAPTION>
PART IV.
<C> <S> <C>
14. Exhibits, Consolidated Financial Statement Schedules, and Reports on Form
8-K....................................................................... 45
Signatures.................................................................. 47
Exhibit Index............................................................... 48
</TABLE>

<PAGE>
DUKE POWER COMPANY
PART I.
ITEM 1. BUSINESS.
Duke Power Company (the Company) is 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. Its service area, approximately
two-thirds of which lies in North Carolina, covers about 20,000 square miles
with an estimated population of 4.8 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. During 1993, the
Company's electric revenues amounted to approximately $4.3 billion, of which
about 70 percent was derived from North Carolina and about 30 percent from South
Carolina. The Company ranks sixth in the United States among investor-owned
utilities in kilowatt-hour sales. Its executive offices are located in the Power
Building, 422 South Church Street, Charlotte, North Carolina 28242-0001
(Telephone No. 704-594-0887). THE STATISTICS PRESENTED HEREIN DO NOT INCLUDE
INFORMATION RELATING TO THE COMPANY'S UTILITY SUBSIDIARY, NANTAHALA POWER AND
LIGHT COMPANY, UNLESS OTHERWISE INDICATED. (SEE "ENERGY REQUIREMENTS AND
CAPABILITY.")
SERVICE AREA
The Company supplies electric service directly to approximately 1.7 million
residential, commercial and industrial customers in more than 200 cities, towns
and unincorporated communities in North Carolina and South Carolina. Electricity
is sold at wholesale to nine incorporated municipalities and to several private
utilities. In addition, in 1993 approximately 9% of total sales were made
through contractual arrangements 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.")
The Company's service area is undergoing increasingly diversified
industrial development. The textile, manufacture of machinery and equipment,
chemical and chemical related industries are of major significance to the
economy of the area. Other industrial activity includes the paper and allied
products, rubber and plastic products and various other light and heavy
manufacturing and service businesses. The largest industry served by the Company
is the textile industry, which accounted for approximately $488 million of the
Company's revenues for 1993, representing 11 percent of electric revenues and 40
percent of electric industrial revenues.
ENERGY REQUIREMENTS AND CAPABILITY
The following table sets forth the Company's generating capability at
December 31, 1993, its sources of electric energy for 1993, and certain
information presently projected for 1994:
<TABLE>
<CAPTION>
GENERATING CAPABILITY -- KW(A) GENERATION -- KWH
PROJECTED (MILLIONS)(D)
ACTUAL DECEMBER 31, ACTUAL
SOURCE DECEMBER 31, 1993 1994 1993
<S> <C> <C> <C>
Coal................................................ 7,510,000 7,656,000 34,097
Nuclear (b)......................................... 7,054,000 7,054,000 48,211
Hydro and other..................................... 3,281,000(c) 3,281,000(c) 1,625
Total (b).................................... 17,845,000 17,991,000 83,933
Less: Other Catawba Joint Owners' share............. 13,821
Plus: Purchases from Other Catawba Joint Owners..... 8,810
Purchased power and net interchange................. 1,750
Total........................................ 80,672
</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) Nuclear capability and related generation for 1993 and projected for 1994
give no effect to the joint ownership of the Catawba Nuclear Station. (See
"Joint Ownership of Generating Facilities.")
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(c) Includes Bad Creek and Jocassee pumped storage hydroelectric stations at
licensed generating capabilities of 1,065,000 KW and 610,000 KW,
respectively.
(d) Excludes firm purchases. (See "Energy Management and Future Power Needs.")
Nantahala Power and Light Company (NP&L), which operates 11 hydroelectric
stations and buys supplemental power to provide service to its 51,000 mostly
residential customers located in five counties in western North Carolina,
operates as a separate subsidiary of the Company. The Company is supplying
supplemental power to NP&L under the terms of an interconnect 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 agreement.
According to industry statistics published in 1993, 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 ranked first,
second and sixth most efficient in the nation in 1992. The Company's nuclear
system continued its tradition of operating efficiency, operating at 78 percent
of capacity for the year, in comparison with the industry's most current average
capacity factor of 71 percent for 1992.
The Company normally experiences seasonal peak loads in summer and winter
which are relatively in balance. The Company currently forecasts a 2.1 percent
compound annual growth in peak load through 2008. This amount is not reduced by
those future demand-side management program contributions considered resources
for meeting peak demand (See "Energy Management and Future Power Needs"). The
1992-1993 winter peak load of 13,314,000 KW occurred on February 19, 1993. On
July 29, 1993, the Company experienced its summer peak load of 15,720,000 KW
during unusually hot weather. A new all-time peak load of 16,070,000 KW occurred
on January 19, 1994 during extremely cold weather.
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 the respective states. 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.
Rate requests filed by the Company in its most recent general rate case in
1991 with the NCUC, PSCSC and FERC were principally designed to reflect the
Company's investment in the Bad Creek Hydroelectric Station. Rate orders issued
by the NCUC and PSCSC in November, 1991 recognized costs of the Bad Creek
Hydroelectric Station, including an amortization of costs deferred between
commercial operation and the rate order, which the Company had requested. The
Company's wholesale customers challenged its proposed rate increase and in 1991
FERC issued an order that accepted the Company's proposed rates for filing. A
negotiated settlement with these customers, which provided for an increase in
wholesale rates consistent with the increase in retail rates, was approved by
FERC and became effective in April 1992 (See "Management's Discussion and
Analysis of Results of Operations and Financial Condition, Liquidity and
Resources -- RATE MATTERS").
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.
The North Carolina Supreme Court, on April 22, 1992, remanded for the
second time the Company's 1986 rate order to the NCUC. In its ruling, the Court
held that the record from the 1986 proceedings failed to support the rate of
return of 13.2 percent on common equity authorized by the NCUC after the initial
decision of the Court remanding the 1986 rate order. The NCUC issued a final
order dated October 26, 1992, authorizing a 12.8 percent return on common equity
for the period October 31, 1986 through November 11, 1991, that resulted in a
refund to North Carolina retail customers in 1992 of approximately $95 million,
including interest.
FUEL COST ADJUSTMENT PROCEDURES. The Company has procedures in all three
of its regulatory jurisdictions to adjust rates for fluctuations in fuel
expense. The NCUC ordered the Company to follow these procedures in its
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August 1986 order, which was effective for periods beginning January 1, 1986.
The prospective adjustment in rates of past over- or under-recovery of fuel
costs was challenged in the North Carolina courts. North Carolina adopted
legislation assuring the legality of such adjustments, which contains a sunset
provision effective June 30, 1997.
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 20 to 25 percent of its
anticipated peak load requirements through 1996.
Demand-side management programs are a part of meeting the Company's future
power needs. These programs benefit the Company and its customers by providing
for load control through interruptible control features, shifting usage to
off-peak periods, increasing usage during off-peak periods, and by promoting
energy efficiency. In return for participation in demand-side management
programs, customers may be eligible to receive various incentives which help to
reduce their electric bills. Demand-side management programs such as Industrial
Interruptible Service and Residential Load Control can be used to manage
capacity availability problems. Energy-efficiency programs such as
high-efficiency chillers, high-efficiency heat pumps and high-efficiency air
conditioners are other examples of current demand-side management programs. 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. As additional demand-side costs are incurred, the Company ultimately
expects recovery of associated costs, which are currently being deferred,
through rates. The annual costs deferred, including the return, were
approximately $26 million in 1993 and $18 million in 1992.
The Company continues to engage in a comprehensive energy management
program as part of its Integrated Resource Plan. 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. In January 1993, the PSCSC
issued an order approving the Company's 1992 Integrated Resource Plan as
reasonable, and approving a "shared savings" proposal for accomplishments made
in the Company's demand-side management programs. In June 1993, the NCUC
approved the 1992 plan, including the shared savings mechanism. The Company's
current plan reduces supply side requirements in excess of 1,900 megawatts by
the year 2000 due to the Company's effective use of demand side options.
The purchase of capacity and energy is also an integral part of meeting
future power needs. The Company currently has under contract 500 megawatts of
capacity from other generators of electricity.
The Company's construction program and the estimated construction costs set
forth below are subject to continuing review and are revised from time to time
in light of changes in load forecasts, the Company's financial condition
(including cash flow, earnings and levels of rates), changing regulatory and
environmental standards (See "Regulation -- ENVIRONMENTAL MATTERS") and other
factors.
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Projected construction and nuclear fuel costs, excluding costs related to
portions of the Catawba Nuclear Station owned by the Other Catawba Joint Owners,
for each of 1994, 1995 and 1996 and for the three-year period 1994-1996, as now
scheduled, are as follows (in millions of dollars):
<TABLE>
<CAPTION>
TYPE OF FACILITIES 1994 1995 1996 TOTAL
<S> <C> <C> <C> <C>
Generation............................. $475 $436 $243 $1,154
Transmission........................... 44 49 55 148
Distribution........................... 200 211 233 644
Other.................................. 120 120 82 322
Total........................ $839 $816 $613 $2,268
Nuclear Fuel........................... $143 $123 $128 $ 394
</TABLE>

The Company's procedures for estimating construction costs (which include
allowance for funds used during construction) utilize, among other things, past
construction experience, current construction costs and allowances for
inflation.
The Company is building a combustion turbine facility in Lincoln County,
North Carolina to provide capacity at periods of peak demand. The Lincoln
Combustion Turbine Station will consist of 16 combustion turbines with a total
generating capacity of 1,184 megawatts. The estimated total cost of the project
is approximately $500 million. Current plans are for ten units to begin
commercial operation by the end of 1995 and the remaining six to begin
commercial operation before the end of 1996. 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. The
issuance of the final air permit for the facility has been appealed. Legal
proceedings with regard to the appeal are ongoing. The Company believes the
permit will be upheld.
The Company has nearly completed a Plant Modernization Program (PMP) to
improve the efficiency and reliability of 15 older coal-fired generating units.
These units, once modernized, will help the Company meet anticipated future
demand. The cost of this program is estimated to average approximately $200-$300
per installed KW, a fraction of the cost of building new plants. As of December
31, 1993, eleven coal-fired units with a nameplate generating capability of
1,241,000 KW had been returned to the system. It is anticipated that three
additional coal-fired generating units with nameplate generating capability of
160,000 KW will be returned to the system during 1994. The Company expects the
final unit remaining in the PMP after 1994, which unit has 40,000 KW of
nameplate generating capability, to be returned to the system 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.
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.
The Other Catawba Joint Owners and the Company are involved in various
proceedings related to the Catawba joint ownership contractual agreements. The
basic contention in each proceeding is 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
(See Note 3, "Notes to Consolidated Financial Statements"). The Company and two
of the four Other Catawba Joint Owners have entered into a proposed settlement
agreement
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which, if approved by the regulators, will resolve all issues in contention in
such proceedings between the Company and these owners. The Company recorded a
liability as an increase to Other current liabilities on its Consolidated
Balance Sheets of approximately $105 million in 1993 to reflect this proposed
settlement. In addition, future estimated obligations in connection with the
settlement are reflected in estimates of purchased capacity obligations in Note
3, "Notes to Consolidated Financial Statements". As the Company expects the
costs associated with this settlement will be recovered as part of the purchased
capacity levelization, the Company has included approximately $105 million as an
increase to Purchased capacity costs on its Consolidated Balance Sheets.
Therefore, the Company believes the ultimate resolution of these matters should
not have a material adverse effect on the results of operations or financial
position of the Company.
Although the two Other Catawba Joint Owners, who are not parties to the
above settlement, have not fully quantified the dollars associated with their
claims in the presently outstanding proceedings, information associated with
these proceedings indicates that the amount in contention could be as high as
$110 million, through December 31, 1993. Arbitration hearings were held in 1992
involving substantially all of the disputed amounts, and a decision interpreting
the language of the agreements on certain of these matters was issued on October
1, 1993. Further proceedings will be required to determine the amounts
associated with this decision as it relates to these owners, some of which may
involve refunds. However, the Company expects the costs associated with this
decision will be included in and recovered as part of the purchased capacity
levelization consistent with prior orders of the retail regulatory commissions.
Therefore, the Company believes the ultimate resolution of 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 and coal for the
generation of electric energy. The Company's reliance on oil and gas is minimal.
Information regarding the utilization of sources of power and cost of fuels
is set forth in the following table:
<TABLE>
<CAPTION>
COST OF FUEL PER NET KWH
GENERATION BY SOURCE GENERATED (MILLS)
<S> <C> <C> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31 YEAR ENDED DECEMBER 31
<CAPTION>
1993 1992 1991 1993 1992 1991
<S> <C> <C> <C> <C> <C> <C>
Coal............................................... 40.6% 36.7% 34.2% 16.06 16.49 17.04
Nuclear............................................ 57.5 61.0 63.8 5.41 5.41 5.66
Oil and Gas........................................ -- -- -- -- -- --
All Fuels (cost based on weighted average)......... 98.1 97.7 98.0 9.85 9.58 9.64
Hydroelectric*..................................... 1.9 2.3 2.0
100.0% 100.0% 100.0%
</TABLE>

* Generating figures are net of that output required to replenish pumped storage
units during off-peak periods.
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 and price renegotiation provisions, have expiration dates ranging
from 1995 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. However, due
to the Clean Air Act Amendments of 1990, fuel premiums may be required as
contracts are renewed. 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 short-term requirements 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
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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 1994 1995 2006
McGuire......................... 1997 1994 1995 1999
Catawba......................... 1997 1994 1995 1999
</TABLE>

Uranium material requirements will be met through various supplier
contracts, with uranium material produced primarily in the U.S., Canada and
Australia. 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. Short-term requirements have been and will be
fulfilled with uranium spot market purchases.
The Company purchased uranium material during 1993 at an average price of
approximately $28 per pound. The Company's material nuclear supply contracts
generally contain FORCE MAJEURE provisions.
The Nuclear Waste Policy Act of 1982 requires that the Department of Energy
(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 $525 million
through 1993. In November 1989, the DOE released a report which indicated that
it expects that a facility for spent fuel disposal will not be available until
the year 2010. The DOE stated further that it planned an initiative to establish
a monitored retrievable 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 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 (PUHCA), 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 1993, the Company's
construction costs for environmental protection totaled approximately $18
million, while the on-going environmental operation costs were approximately $20
million. The Company's 1994 -- 1996 construction program includes costs for
environmental protection which are estimated to be approximately $101 million,
including $22.3 million in 1994, $41.8 million in 1995 and $36.9 million in
1996. These costs include expenditures to begin compliance 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. Therefore, the Company may have to revise
the estimates in response to developments in these and other areas.
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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
(otherwise known as the "Clean Water Act") require permits for facilities that
discharge into waters, to ensure compliance with its provisions. The Company
holds numerous such permits, and such permits are reissued periodically. The
Federal Water Pollution Control Act is scheduled for reauthorization by Congress
in 1994. 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.
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). In 1993, Duke as a PRP, resolved
litigation at a Superfund site in West Virginia, and is currently participating
in a PRP group with regard to a Superfund site in Concord, North Carolina.
Additionally, the Company is a DE MINIMUS contributor at two sites in
Pennsylvania. The Company is also a PRP at contamination sites in Charlotte,
North Carolina and Lenoir, North Carolina, which will likely be remediated in
accordance with state acts which are similar to CERCLA. 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. Other contamination sites relate to the Company's operation
of manufactured gas plant (MGP) sites prior to the early 1950s, some of which
are still owned by the Company and some of which are now owned by third parties.
The Company is participating in a state-sponsored program which will result in
the investigation and, where appropriate, remediation of MGP sites. 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 is scheduled for reauthorization by Congress in 1994. 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.
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.
The steam generators at the McGuire and Catawba Nuclear Stations have
experienced stress corrosion cracking in their tubes. Stress corrosion cracking
is a phenomenon that typically occurs in tight U-bends, at tube support plates,
and where tubes are attached to the tube sheets. Stress corrosion cracking has
been identified as a problem in steam generators of certain designs, including
those at the McGuire and Catawba Stations. The Company believes that the stress
corrosion cracking is caused by defective design, workmanship and materials used
by the manufacturer of the steam generators. Both primary side and secondary
side cracking and corrosion have been observed in the steam generators at the
McGuire and Catawba Stations. In addition, recent inspections at McGuire Units 1
and 2 have revealed a different type of secondary side stress corrosion cracking
in the free-span area of the steam generator tubes located on the "cold-leg"
side of those Units (cold-leg free-span cracking). The Company conducts tests at
each refueling outage to determine the extent of stress corrosion cracking
during the preceding fuel cycle.
The steam generators at Catawba Unit 2 have certain design differences from
those at Catawba Unit 1 or either McGuire Unit, but it is too early in the life
of Catawba Unit 2 to determine the extent to which stress corrosion cracking
will be a problem.
7

<PAGE>
Although the Company has taken steps to mitigate the effects of stress
corrosion cracking in the McGuire and Catawba steam generator tubes, including
examining the steam generator tubes at each refueling outage, tube plugging,
tube sleeving, more stringent water chemistry control, shot peening, and tight
U-bend heat treatment, further stress corrosion cracking in the McGuire Units 1
and 2 and Catawba Unit 1 steam generators appears likely. Potential consequences
of future stress corrosion cracking include extensive tube plugging and
sleeving, additional water chemistry control, additional inspections and testing
resulting in longer outages, mid-cycle outages, reduction in plant output, and
requests for license amendments. The Company has compared the cost of continued
repair of the steam generators with the cost of early steam generator
replacement and has determined that for McGuire Units 1 and 2 and Catawba Unit
1, the most cost-effective alternative is to replace the steam generators as
soon as it is feasible to do so.
The Company has begun planning for the replacement of steam generators and
has set the following schedule to begin the process: McGuire Unit 1 -- 1995;
Catawba Unit 1 -- 1996; McGuire Unit 2 -- 1997. The order of replacement is
subject to change based on performance of the existing steam generators and on
the overall performance of the three units. The Company has signed an agreement
with Babcock & Wilcox International to purchase 12 replacement steam generators
for the McGuire and Catawba Stations. Each unit's steam generator replacement is
expected to take approximately four months and cost approximately $170 million,
excluding the cost of replacement power and without consideration of
reimbursement of applicable costs by the Other Catawba Joint Owners of Catawba
Unit 1. Stress corrosion problems are excluded under the nuclear insurance
policies. The Company anticipates that the replacement of the steam generators
should not have a material adverse effect on the Company's results of
operations or financial position. Because Catawba Unit 2 has not shown the
degree of stress corrosion cracking which has occurred in McGuire Units 1 and
2 and Catawba Unit 1, the Catawba Unit 2 steam generators have not been
scheduled for replacement.
The Company in connection with its McGuire and Catawba stations and on
behalf of the Other Catawba Joint Owners commenced a legal action on March 22,
1990, in the United States District Court for the District of South Carolina
(Charleston Division) seeking damages from Westinghouse Electric Corporation
(Westinghouse) for supplying to the McGuire and Catawba Stations steam
generators that were alleged to be defective in design, workmanship and
materials, and that will require replacement well short of their stated design
life. In the action, the Company sought a judgment against Westinghouse for
damages of approximately $600 million, including the cost of necessary remedial
measures, the cost of replacement of steam generators and payment for
replacement power during the outages to accomplish replacement. In addition to
these damages, the Company sought punitive or treble damages and attorneys'
fees. The lawsuit was settled on March 17, 1994. (See "Subsequent Events.")
NUCLEAR DECOMMISSIONING COSTS. Estimated site-specific nuclear
decommissioning costs, including the cost of decommissioning plant components
not subject to radioactive contamination, total approximately $955 million
stated in 1990 dollars. This amount includes the Company's 12.5 percent
ownership in the Catawba Nuclear Station. The Other Catawba Joint Owners are
liable for providing decommissioning related to their ownership interest in the
Catawba Nuclear Station. Both the NCUC and the PSCSC have granted the Company
recovery of the estimated site-specific 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 Nuclear Regulatory Commission (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 1993, the Company expensed approximately $52.5
million which was contributed to the external funds and accrued an additional $5
million to the internal reserve. The balance of the external funds as of
December 31, 1993, was $118.5 million. The balance of the internal reserve as of
December 31, 1993, was $200 million and is reflected in Accumulated depreciation
and amortization on the Consolidated Balance Sheets. Management's opinion is
that the estimated site-specific decommissioning costs being recovered through
rates, when coupled with assumed after-tax fund earnings of 4.5 percent to 5.5
percent, are currently sufficient to provide for the cost of decommissioning
based on Company's current decommissioning schedule.
8

<PAGE>
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 $8.3 million during 1993 related to
its ownership interest in nuclear plants. The Company has reflected the
remaining liability and regulatory asset of approximately $117 million in the
Consolidated Balance Sheets.
NUCLEAR INSURANCE. For a discussion of the Company's nuclear insurance
coverage, see "Notes to Consolidated Financial Statements, Note
13 -- 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 804,940 KW, 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 769,500 KW, 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 1,065,000 KW.
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 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 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 has far-reaching implications for the Company
by moving utilities toward a more competitive environment. The Act reformed
certain provisions of the Public Utility Holding Company Act of 1935 (PUHCA) and
removed certain regulatory barriers. For example, the Act 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 registration under PUHCA as an
electric utility holding company. The Act requires transmission of power for
third parties to wholesale customers, provided that the reliability of service
to the utility's local customer base is protected and the local customer base
does not subsidize the third-party service. Although the Act does not require
transmission access to retail customers, states can authorize such transmission
access to and for retail electric customers.
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 price of
electricity, utilities might be forced to reduce their assets to reflect market
basis if such basis is less than cost. Discontinuation of cost-based regulation
could also require some utilities to write off their regulatory assets.
Management cannot predict the potential impact, if
9

<PAGE>
any, of these competitive forces on the future financial position and results of
operations of the Company. However, the Company is continuing to position itself
to effectively meet these challenges by maintaining prices that are regionally
and nationally competitive.
NON-UTILITY ACTIVITIES
The Company is engaged in a variety of non-utility operations, including
real estate development and forest management, marketing of electrical
appliances, management of passive financial investments, developing and
investing in electric generation and transmission facilities outside the
Company's service area and providing engineering and technical services. Most of
the Company's non-utility operations are organized in separate subsidiaries.
Subsidiary and diversified operations contributed $22 million after tax to
corporate earnings in 1993.
A major part of the future growth in the electric power market is
anticipated to be outside the traditional regulated framework and, to a large
extent, outside the United States. The Company, through its subsidiaries, is
participating in these international opportunities and continues participating
in domestic opportunities to provide additional value to its shareholders.
Internationally, the Company is seeking opportunities to provide engineering
consulting services, construction, operation and maintenance of generating
facilities, and ownership of transmission and generating facilities. Although
these opportunities are concentrated in areas that utilize the Company's
expertise, they present different and greater risks than the Company's core
business. The Company considers only opportunities in which the expected return
is commensurate with the risks, and makes efforts to mitigate such risks.
In March 1993, Duke Energy Group (DEG) invested $25 million in convertible
preferred stock of J. Makowski & Company (Makowski), a developer of natural
gas-fired electric projects, and is providing $10.2 million in credit support
for a Makowski project. Additionally, DEG has one seat on the Board of Directors
of Makowski.
In June 1993, after a competitive bidding process, the Argentine government
awarded the right to buy 65 percent of the stock of Compania de Transporte de
Energia Electrica en Alta Tension S. A. (Transener) to a consortium led by DEG.
Transener is Argentina's primary transmission company. It employs about 1,100
persons, and has 6,867 kilometers of 500 kilovolt lines, 284 kilometers of 220
kilovolt lines, and 27 substations. The consortium assumed ownership and
operation of the system on July 16, 1993.
Another consortium, also led by DEG, was awarded the majority ownership and
operation of Hidroelectrica Piedra del Aguila S.A. on November 29, 1993.
Hidroelectrica Piedra del Aguila S.A. owns a hydroelectric facility located in
southwestern Argentina. When fully operational in 1995, the facility will have a
capacity of 1,400 megawatts. The consortium assumed ownership of 59 percent of
the stock of Hidroelectrica Piedra del Aguila S.A., and took over operation of
the hydroelectric complex on December 29, 1993.
EMPLOYEES
At December 31, 1993, the Company employed 18,274 full-time persons, which
includes 789 full-time employees of subsidiaries and affiliates. About 2,000
electrical operating employees are represented by the International Brotherhood
of Electrical Workers (IBEW). The Company reached a new labor agreement with the
IBEW, effective October 1, 1993, for a one year term.
The Company has been engaged in a concentrated effort to more efficiently
and effectively utilize its resources through better work practices. During the
first quarter of 1993, the Company offered a Limited Period Separation
Opportunity Program (LPSO) which gave employees the option of leaving the
Company for a lump sum severance payment and, for qualifying employees, enhanced
retirement benefits. On March 15, 1994, the Company announced plans to offer
Enhanced Voluntary Separation (EVS), a severance package, for employees who
choose to leave the Company voluntarily during the second quarter of 1994.
Implementing programs such as LPSO, EVS and other efficiency practices has
resulted in continued workforce reduction and in streamlined workflows. The
number of full-time employees has decreased to the present level from 19,945 at
year-end 1990. The 1990 amount included 496 employees of subsidiaries and
affiliates.
10

<PAGE>
SUBSEQUENT EVENTS
On January 25, 1994, the Board of Directors selected William H. Grigg, Vice
Chairman of the Board, to succeed William S. Lee as Chairman of the Board,
President and Chief Executive Officer, effective at the Annual Meeting of
Shareholders to be held on April 28, 1994. Mr. Lee will serve the Company as a
consultant after that date until his retirement following his 65th birthday in
June 1994.
On March 2, 1994, the Duke Endowment announced its intention to diversify
its investment portfolio by selling up to 16 million shares of its Duke Power
Common Stock. A registration statement was filed with the Securities and
Exchange Commission on that day and underwriting agreements were entered into
on March 29, 1994 relating to the sale of 14 million of such shares, with
over-allotment options of up to 2 million shares. The Duke Endowment will retain
approximately 10 million shares after the sale (assuming the over-allotment
options are exercised), and has announced that it has no present intention to
dispose of any additional shares of Common Stock.
On March 17, 1994, the Company, together with the Other Catawba Joint
Owners, settled the lawsuit initiated by the Company on March 22, 1990 against
Westinghouse Electric Corporation seeking damages for supplying to the McGuire
and Catawba Nuclear Stations steam generators that were alleged to be defective
in design, workmanship and materials and that would require replacement well
short of their stated design life. While the terms of the settlement may not be
disclosed pursuant to court order, the Company believes the litigation was
settled on terms that provided satisfactory consideration to the Company. Such
settlement will not have a material effect on the Company's results of
operations or financial position. (See "Regulation -- Nuclear Facilities" and
"Management's Discussion and Analysis of Results of Operations and Financial
Condition, Current Issues -- Stress Corrosion Cracking.")
11
<PAGE>
(graphic--full page map showing the Duke Power Service Area)

<PAGE>
DUKE POWER COMPANY
OPERATING STATISTICS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
1993 1992 1991 1990 1989
<S> <C> <C> <C> <C> <C>
SOURCES OF ELECTRIC ENERGY
Millions of kilowatt-hours:
Generated -- net output:
Coal.................................... 34,097 28,999 26,455 27,262 26,175
Nuclear (a)............................. 48,211 48,238 49,328 44,649 47,773
Hydro (b)............................... 1,582 1,834 1,545 1,879 1,520
Oil and gas............................. 43 5 7 53 27
Total generation...................... 83,933 79,076 77,335 73,843 75,495
Purchased power and net interchange (c)... 1,750 1,403 587 1,531 1,158
Total output.......................... 85,683 80,479 77,922 75,374 76,653
Less: Other Catawba Joint Owners' share... 13,821 14,313 12,280 11,735 12,566
Plus: Purchases from Other Catawba Joint
Owners.................................. 8,810 9,466 8,525 8,658 9,809
Total sources of energy............... 80,672 75,632 74,167 72,297 73,896
Line loss and company usage............... (4,614) (4,590) (4,280) (4,222) (4,522)
Total kilowatt-hour sales (d)........... 76,058 71,042 69,887 68,075 69,374
AVERAGE COST PER TON OF COAL BURNED............. $ 42.21 $ 43.47 $ 45.21 $ 45.49 $ 45.13
ELECTRIC ENERGY SALES
Millions of kilowatt-hours:
Residential............................... 19,465 17,789 17,918 17,221 16,895
General service........................... 16,904 15,818 15,586 15,032 14,206
Industrial
Textile................................. 11,954 11,685 11,315 11,130 11,443
Other................................... 16,244 15,356 14,955 14,764 14,491
Other energy and wholesale (c)(e)......... 11,337 10,360 10,132 10,468 11,969
Total kilowatt-hour sales billed.......... 75,904 71,008 69,906 68,615 69,004
Unbilled kilowatt-hour sales............ 154 34 (19) (540) 370
Total kilowatt-hour sales (d)........... 76,058 71,042 69,887 68,075 69,374
ELECTRIC REVENUE
Thousands of dollars:
Residential............................... $1,424,173 $1,312,227 $1,272,322 $1,216,945 $1,198,705
General service........................... 1,014,124 964,853 921,337 886,480 851,422
Industrial
Textile................................. 487,576 482,172 475,191 476,493 493,933
Other................................... 726,399 696,413 668,765 654,551 653,830
Other energy and wholesale (c)(e)......... 476,862 460,849 441,777 391,803 449,545
Other electric revenues................... 152,742 44,970 37,568 78,859 45,520
Total electric revenues (d)........... $4,281,876 $3,961,484 $3,816,960 $3,705,131 $3,692,955
NUMBER OF CUSTOMERS -- END OF YEAR
Residential............................... 1,460,876 1,439,845 1,415,605 1,391,336 1,362,118
General service (f)....................... 232,272 227,675 222,917 224,642 216,960
Industrial
Textile................................. 1,396 1,390 1,385 1,398 1,408
Other................................... 7,338 7,314 7,255 7,325 7,310
Other energy and wholesale (c)............ 7,957 7,773 7,605 7,405 7,249
Total customers....................... 1,709,839 1,683,997 1,654,767 1,632,106 1,595,045
RESIDENTIAL CUSTOMER STATISTICS
Average number for year................... 1,455,609 1,431,403 1,409,775 1,383,799 1,356,088
Average annual use -- KWH................ 13,372 12,427 12,710 12,444 12,459
Average annual billing.................... $ 978.40 $ 916.74 $ 902.50 $ 879.42 $ 883.94
AVERAGE ANNUAL BILLED REVENUE PER KWH
Residential............................... 7.32(cents) 7.38(cents) 7.10(cents) 7.07(cents) 7.09(cents)
General service........................... 6.00 6.10 5.91 5.90 5.99
Industrial................................ 4.31 4.36 4.35 4.37 4.43
Other energy and wholesale (c)(e)......... 4.21 4.45 4.36 3.74 3.76
</TABLE>

(a) Includes 100% of Catawba generation.
(b) 1991 includes KWH of the Bad Creek Hydroelectric Station prior to commercial
operation.
(c) Kilowatt-hour sales, Electric revenues and Net interchange and purchased
power for the years 1989 and 1990 include a reclassification for certain
power transactions previously classified as Net interchange and purchased
power prior to a 1990 FERC order.
(d) Does not reflect operating statistics, kilowatt-hour sales and revenues of
Nantahala Power and Light Company.
(e) Includes sales to Nantahala Power and Light Company.
(f) 1991 restated to eliminate certain duplicate customers.
13

<PAGE>
EXECUTIVE OFFICERS OF THE COMPANY
<TABLE>
<CAPTION>
SERVICE IN
SUCH
CAPACITY
NAME POSITION SINCE AGE*
<S> <C> <C> <C> <C>
William S. Lee**................ Chairman of the Board, President and Chief Executive Officer 1982 64
William H. Grigg**.............. Vice Chairman of the Board 1991 61
William A. Coley**.............. Executive Vice President, Customer Group 1991 50
Steve C. Griffith, Jr.**........ Executive Vice President and General Counsel 1991 60
Richard B. Priory**............. Executive Vice President, Power Generation Group 1991 47
Richard J. Osborne.............. Vice President and Chief Financial Officer 1991 42
David L. Hauser................. Controller (Chief Accounting Officer) 1987 42
</TABLE>

OTHER OFFICERS
<TABLE>
<S> <C> <C> <C> <C>
Donald H. Denton, Jr............ Senior Vice President, Chief Planning Officer
Michael S. Tuckman.............. Senior Vice President, Nuclear Generation Department
James R. Bavis.................. Vice President, Human Resources
Sue A. Becht.................... Treasurer
Sharon A. Decker................ Vice President, Customer Services
Excell O. Ferrell, III.......... Vice President, Northern Region
William L. Foust................ President, Duke Merchandising
Ronald L. Gibson................ Vice President, Marketing and Customer Planning
James E. Grogan................. Vice President, Generation Services Department
James W. Hampton................ Vice President, Oconee Nuclear Site
Donald E. Hatley................ Vice President, Public Affairs
Jim R. Hicks.................... Vice President, Information Technology Services
J. William Hillhouse, Jr........ Vice President, Charlotte Area
James D. Hinton................. Vice President, Power Delivery
John P. Holland................. Vice President, Winston-Salem Area
F. Alfred Jenkins............... Vice President, Hickory Area
Robert S. Lilien................ Vice President and Tax Counsel
John F. Lomax................... Vice President, Southern Region
David H. Maner.................. Vice President, Greensboro Area
Maurice D. McIntosh............. Vice President, Fossil & Hydro Generation Department
Ted C. McMeekin................. Vice President, McGuire Nuclear Site
Barbara B. Orr.................. Vice President, Greenville Area
David L. Rehn................... Vice President, Catawba Nuclear Site
William F. Reinke............... Vice President, System Planning & Operating
William T. Robertson, Jr........ Vice President, Procurement, Services and Materials
Christopher C. Rolfe............ Vice President, Corporate Performance
Ellen T. Ruff................... Secretary and Deputy General Counsel
Ruth G. Shaw.................... Vice President, Corporate Communications
William R. Stimart.............. Vice President, Rates and Regulatory Affairs
Fred E. West, Jr................ Vice President, Central Region
Virginia M. Britton............. Assistant Controller
Carolyn R. Duncan............... Assistant Secretary
S. L. Love...................... Assistant Treasurer
Phyllis T. Simpson.............. Assistant Secretary
</TABLE>

* As of February 1, 1994.
**Member of the Management Committee.
14

<PAGE>
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.
All of the above executive officers have held responsible positions with
the Company for the past five years.
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.
The map on page 12 shows the location of the Company's service area and
generating stations.
Reference is made to Schedule V -- Property, Plant and Equipment for
information concerning the Company's investment in utility plant. 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 Management and Future Power Needs".
ITEM 3. LEGAL PROCEEDINGS.
Reference is made to "Notes to Consolidated Financial Statements, Note
13 -- Commitments and Contingencies", "Business -- Regulation -- NUCLEAR
FACILITIES" and "Subsequent Events".
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 1993.
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, 1993, there were approximately 127,688 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 RANGE
DIVIDENDS
COMMON STOCK PER SHARE HIGH LOW
<S> <C> <C> <C>
1993 by Quarter
Fourth.................................................. $0.47 $ 44 $ 39
Third................................................... 0.47 44 7/8 39 7/8
Second.................................................. 0.45 41 3/8 37 1/8
First................................................... 0.45 39 7/8 35 3/8
1992 by Quarter
Fourth.................................................. $0.45 $ 37 1/2 $ 34 5/8
Third................................................... 0.45 36 1/2 34 1/8
Second.................................................. 0.43 34 5/8 32
First................................................... 0.43 35 31 3/8
</TABLE>

<PAGE>
ITEM 6.
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
1993 1992 1991 1990
<S> <C> <C> <C> <C>
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(thousands)
Electric revenues (a)..................... $ 4,281,876 $ 3,961,484 $ 3,816,960 $ 3,705,131
Electric expenses (a)..................... 3,467,811 3,236,789 3,110,137 3,062,348
Electric operating income............... 814,065 724,695 706,823 642,783
Other income.............................. 71,269 85,007 150,905 146,740
Income before interest deductions....... 885,334 809,702 857,728 789,523
Interest deductions....................... 258,919 301,619 274,105 251,335
Net income................................ 626,415 508,083 583,623 538,188
Dividends on preferred and preference
stock................................. 52,429 56,407 54,683 52,616
Earnings for common stock................. $ 573,986 $ 451,676 $ 528,940 $ 485,572
COMMON STOCK DATA (b)
Shares of common stock
-- year-end (thousands)................ 204,859 204,859 204,699 202,584
-- average (thousands)................. 204,859 204,819 203,431 202,570
Per share of common stock
Earnings................................ $ 2.80 $ 2.21 $ 2.60 $ 2.40
Dividends............................... $ 1.84 $ 1.76 $ 1.68 $ 1.60
Book value -- year-end.................. $ 21.17 $ 20.26 $ 19.86 $ 18.84
Market price -- high-low................ $44 7/8-35 3/8 $37 1/2-31 3/8 $ 35-26 3/4 $32 3/8-25 1/2
-- year-end................. $ 42 3/8 $ 36 1/8 $ 35 $ 30 5/8
BALANCE SHEET DATA (thousands)
Total assets.............................. $12,193,107 $10,950,387 $10,470,615 $10,083,507
Long-term debt............................ $ 3,285,397 $ 3,288,111 $ 3,159,575 $ 3,102,746
Preferred stock with sinking fund
requirements............................ $ 281,000 $ 279,519 $ 228,650 $ 239,800
<CAPTION>
1989
<S> <C>
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(thousands)
Electric revenues (a)..................... $ 3,692,955
Electric expenses (a)..................... 2,988,355
Electric operating income............... 704,600
Other income.............................. 101,826
Income before interest deductions....... 806,426
Interest deductions....................... 234,815
Net income................................ 571,611
Dividends on preferred and preference
stock................................. 52,477
Earnings for common stock................. $ 519,134
COMMON STOCK DATA (b)
Shares of common stock
-- year-end (thousands)................ 202,563
-- average (thousands)................. 202,554
Per share of common stock
Earnings................................ $ 2.56
Dividends............................... $ 1.52
Book value -- year-end.................. $ 18.05
Market price -- high-low................ $ 28 1/4-21 3/8
-- year-end................. $ 28 1/16
BALANCE SHEET DATA (thousands)
Total assets.............................. $ 9,542,398
Long-term debt............................ $ 2,822,442
Preferred stock with sinking fund
requirements............................ $ 247,825
</TABLE>

(a) Electric revenues, Electric expenses, Kilowatt-hour sales and Net
interchange and purchased power for the years 1989 and 1990 include a
reclassification for certain power transactions previously classified as Net
interchange and purchased power prior to a 1990 FERC order.
(b) All common stock data reflects the two-for-one split of common stock on
September 28, 1990.
16

<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 27 percent from $2.21 in 1992 to $2.80 in 1993.
The increase was primarily due to higher kilowatt-hour sales and a one-time
charge taken in 1992 related to a rate refund to North Carolina retail
customers of $.32 per share. (For additional information on the refund, see
Liquidity and Resources "Rate Matters," page 18.) The increase was partially
offset by higher operating and maintenance expenses, additional charitable
contributions to the Duke Power Company Foundation and an increase in the
federal income tax rate caused by the Omnibus Budget Reconciliation Act of
1993. Higher general taxes also decreased earnings.

Earnings per share increased from $2.60 in 1991 to $2.80 in 1993, indicating
an average annual growth rate of 4 percent. Total Company earned return on
average common equity was 13.6 percent in 1993 compared to 11.1 percent in
1992 and 13.5 percent in 1991.

The Company continued its practice of increasing the common stock dividend
annually. Common dividends per share increased from $1.68 in 1991 to $1.84 in
1993, rising at an average annual rate of 5 percent. Indicated annual
dividends per share increased to $1.88.

Revenue and Sales
Revenues increased at an average annual rate of 6 percent from 1991 to 1993,
primarily because of increased overall kilowatt-hour sales and the November
1991 rate increases.

Kilowatt-hour sales for 1993 increased 7 percent compared to 1992. Sales to
residential customers increased by 9 percent reflecting colder winter weather
and a hotter-than-normal summer. General service customer kilowatt-hour sales
increased by 7 percent as a result of both continued economic growth and
weather trends cited above. Sales to other-industrial customers and textile
customers increased by 6 percent and 2 percent, respectively, as a result of
the continued economic growth in the Company's service area.

Operating Expenses
From 1992 to 1993, non-fuel operating and maintenance expenses rose 4 percent.
Administrative and general expenses increased partly because of increased
pension expenses to reflect more conservative investment return assumptions
and one-time costs associated with a voluntary separation option offered
during the first quarter of 1993. A winter storm during the first quarter of
1993 also increased non-fuel operating and maintenance expenses. These
increases from 1992 to 1993 were partially offset by lower nuclear and fossil
maintenance expenses resulting from lower outage costs.

Non-fuel operating and maintenance expenses increased at an average annual
rate of 5 percent from 1991 to 1993. Administrative and general expenses
increased over this period because of the implementation of a new accounting
standard in January 1992 that reflects accrual basis accounting for certain
postretirement health care and life insurance benefits, in addition to the
reasons cited in the preceding paragraph. Operating and maintenance expenses
for fossil and hydro plants also increased from 1991 to 1993. Fossil increases
were caused by bringing refurbished units back on-line, and hydro increases
were the result of the completion of the Bad Creek Hydroelectric Station in
late 1991.

Net interchange and purchased power decreased at an average annual rate of 1
percent from 1991 to 1993. A slight decline in the amount of purchased power
from the other Catawba joint owners as recognized on the income statement was
substantially offset by increased purchases from other utilities. (For
additional information on the Catawba purchase power agreements, see Note 3 to
the Consolidated Financial Statements.)

Fuel expense increased at an average annual rate of 6 percent from 1991 to
1993. The increase was due primarily to higher system production requirements
that were satisfied by increased fossil generation. A continued decline of
fuel prices over this period helped to offset the overall increase in fuel
expenses.

From 1991 to 1993, depreciation and amortization expense increased at an
average annual rate of 6 percent primarily because of the completion of the
Bad Creek Hydroelectric Station in 1991 and added investment in distribution
property.

Other Income and Interest Deductions
Allowance for funds used during construction (AFUDC) represented 5 percent of
earnings for common stock in 1993 compared to 13 percent in 1991. The decrease
is primarily the result of the completion of the Bad Creek Hydroelectric
Station in 1991. AFUDC is expected to represent less than 10 percent of total
earnings during the next three years.

The carrying charge, net of associated taxes, on the purchased capacity
levelization deferral related to the joint ownership of the Catawba Nuclear
Station represented 6 percent of total earnings in 1993, compared to 6 percent
in 1992 and 5 percent in 1991. This carrying charge and the related tax
benefits are included in Other, net and Income taxes -- other, net,
respectively. The growth in this carrying charge is due to the increasing
cumulative impact of the Company's funding of purchased power costs which
current rates are expected to collect in future periods. The Company recovers
the accumulated balance, including the carrying charge, when the declining
purchased capacity payments drop below the levelized revenues. (For additional
information on purchased capacity levelization, see Capital Needs "Purchased
Capacity Levelization," page 19.)

Interest on long-term debt decreased at an average annual rate of 3 percent
from 1991 to 1993. The decrease is due to the Company's refinancing of higher
cost debt beginning in late 1991 and continuing throughout 1993. From 1992 to
1993, Other interest decreased as a result of the one-time impact in 1992 of
approximately $27 million in interest paid to North Carolina retail customers
due to a rate refund.

Income provided by diversified activities and the Company's subsidiaries was
$22.0 million in 1993 compared to $25.7 million in 1992 and $23.6 million in
1991. The activities of Crescent Resources, Inc., the Company's real estate
development and forest management subsidiary, generated the majority of
subsidiary and non-electric earnings. Other components include subsidiary
investment income, fees for engineering services, construction and operation
of generation and transmission

<PAGE>

facilities outside the Company's service area,
water operations and merchandising.

Liquidity and Resources
Rate Matters
During 1991, the Company filed in both the North Carolina and South Carolina
retail jurisdictions its only requests for general rate increases since 1986.
The rate increases were primarily needed to recover costs associated with the
construction of the Bad Creek Hydroelectric Station. In North Carolina, the
Company requested a 9.22 percent rate increase and was granted a 4.15 percent
increase, which resulted in additional annual revenues of $100.1 million. In
South Carolina, a 7.29 percent increase was requested and a 3.0 percent rate
increase was granted, resulting in additional annual revenues of $30.2
million.

Also in 1991, the Company filed a request for a wholesale rate increase with
the Federal Energy Regulatory Commission (FERC). A negotiated settlement
between the Company and the wholesale customers was approved by the FERC on
March 31, 1992. The approved agreement, effective April 1, 1992, provided for
a 3.3 percent rate increase, resulting in $2.1 million in additional annual
revenues.

The North Carolina Supreme Court on April 22, 1992, remanded for the second
time the Company's 1986 rate order to the North Carolina Utilities Commission
(NCUC). In this ruling, the Court held that the record from the 1986
proceedings failed to support the rate of return on common equity of 13.2
percent authorized by the NCUC after the initial decision of the Court
remanding the 1986 rate order. The NCUC issued a final order dated October 26,
1992, authorizing a 12.8 percent return on common equity for the period
October 31, 1986, through November 11, 1991. This order resulted in a 1992
refund to North Carolina retail customers of approximately $95 million,
including interest.

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 sales agreement.

Although the two other Catawba joint owners, who are not parties to the above
settlement, have not fully quantified the dollars associated with their claims
in the presently outstanding proceedings, information associated with these
proceedings indicates that the amount in contention could be as high as $110
million, through December 31, 1993. Arbitration hearings were held in 1992
involving substantially all the disputed amounts, and a decision interpreting
the language of the agreements on certain of these matters was issued on
October 1, 1993. Further proceedings will be required to determine the amounts
associated with this decision as it relates to these owners, some of which may
involve refunds. However, the Company expects the costs associated with this
decision will be included in and recovered as part of the purchased capacity
levelization consistent with prior orders of the retail regulatory
commissions. Therefore, the Company believes the ultimate resolution of 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. 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.

Cash From Operations
In 1993, net cash provided by operating activities accounted for 46 percent of
total cash from operating, financing and investing activities compared to 50
percent in 1992 and 77 percent in 1991. For 1993 and 1992, essentially all the
Company's capital needs, exclusive of refinancing activities, were met by cash
generated from operations.

Financing and Investing Activities
The Company's capital structure, including subsidiary capitalization, at year-
end 1993 was 52 percent common equity, 39 percent long-term debt and 9 percent
preferred stock. This structure is consistent with the Company's target to
maintain an "AA" credit rating. As of December 31, 1993, the Company's bonds
were rated "AA" by Fitch Investors Service, "Aa2" by Moody's Investors
Service, and "AA-" by Standard & Poor's Ratings Group and Duff & Phelps.

As a result of favorable market conditions, the Company continued refinancing
activities to retire higher cost debt and preferred stock. During 1993, the
Company obtained proceeds from the issuance of $1.5 billion in long-term debt
and $220 million in preferred stock, most of which were used to retire $1.4
billion of long-term debt and $216 million of preferred stock.

<PAGE>

In 1992, the Company issued $940 million in long-term debt. Most of these
proceeds, combined with the proceeds from bonds issued in late 1991, were used
to redeem $884 million of long-term debt. During 1992, the Company also issued
$284 million of preferred stock, most of which was used to redeem $229 million
of preferred stock.

Also on April 6, 1992, the Company redeemed all outstanding shares of the
Cumulative Preference Stock 6 3/4 percent Convertible Series AA at its par
value of $100 per share.

The Company's embedded cost of long-term debt for 1993 decreased to 8.01
percent compared to 8.39 percent in 1992 and 8.72 percent in 1991. The
embedded cost of preferred stock declined to 6.76 percent in 1993 from 7.05
percent in 1992 and 7.48 percent in 1991. These decreases are primarily the
result of the Company's refinancing activities. Downward trends in embedded
costs may level off because of fewer refinancing opportunities.

Fixed Charges Coverage
Fixed charges coverage using the SEC method increased to 4.68 times for 1993
compared to 3.48 and 3.85 times, respectively, in 1992 and 1991. Fixed charges
coverage, excluding AFUDC and the return on purchased capacity levelization,
was 4.40 times in 1993 compared to 3.27 in 1992 and 3.46 in 1991 and the
Company goal of 3.5 times. In 1992, the coverage under both methods was lower
because of the impact of the rate refund.

Capital Needs
Property Additions and Retirements
Additions to property and nuclear fuel of $676 million and retirements of $312
million resulted in an increase in gross plant of $364 million in 1993.

Since January 1, 1991, additions to property and nuclear fuel of $2.1 billion
and retirements of $780 million have resulted in an increase in gross plant of
$1.3 billion.

Construction Expenditures
Plant construction costs for generating facilities, including AFUDC, decreased
from $232 million in 1991 to $182 million in 1993. Completion of the Bad Creek
Hydroelectric Station in 1991 was a significant part of the decrease.
Construction costs for distribution plant, including AFUDC, decreased from
$275 million in 1991 to $240 million in 1993.

Projected construction and nuclear fuel costs, both including AFUDC, are $2.3
billion and $394 million, respectively, for 1994 through 1996. Total projected
construction costs include expenditures for the construction of the Lincoln
Combustion Turbine Station and replacement of certain steam generators at the
McGuire Nuclear Station and the Catawba Nuclear Station. (For additional
information on steam generator replacement, see Current Issues "Stress
Corrosion Cracking," page 21.) For 1994 through 1996, the Company anticipates
funding its projected construction and nuclear fuel costs through the internal
generation of funds and, to a lesser extent, through the issuance of
securities, primarily First and Refunding Mortgage Bonds.

Purchased Capacity Levelization
The rates established in the Company's retail jurisdictions permit the Company
to recover its investment in both units of the Catawba Nuclear Station and the
costs associated with contractual purchases of capacity from the other Catawba
joint owners. 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.

These rate treatments require the Company to fund portions of the purchased
power payment until these costs, including carrying charges, are recovered at
a later date. The Company recovers the accumulated costs and carrying charges
when the declining purchased capacity payments drop below the levelized
revenues. In the North Carolina and wholesale jurisdictions, purchased
capacity payments continue to exceed levelized revenues. In the South Carolina
jurisdiction, cumulative levelized revenues have exceeded purchased capacity
payments. Jurisdictional levelizations are intended to recover total costs,
including allowed 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
is composed 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 its integrated resource
planning process. The goal is to provide adequate and reliable electricity in
an environmentally responsible manner through cost-effective power management.

The Company is building a combustion turbine facility in Lincoln County, North
Carolina. The Lincoln Combustion Turbine Station will consist of 16 combustion
turbines with a total generating capacity of 1,184 megawatts. The estimated
total cost of the project is approximately $500 million. Current plans are for
ten units to begin commercial operation by the end of 1995 and the remaining
six to begin commercial operation before the end of 1996. The Lincoln facility
will provide capacity at periods of peak demand.

Demand-side management programs are a part of meeting the Company's future
power needs. These programs benefit the Company and its customers by providing
for load control through interruptible control features, shifting usage to
off-peak periods, increasing usage during off-peak periods, and by promoting
energy efficiency. In return for participation in demand-side management
programs, customers may be eligible to receive various incentives which help
to reduce their electric bills. Demand-side management programs such as
Industrial Interruptible Service and Residential Load Control can be used to
manage capacity availability problems. Energy-efficiency programs such as
high-efficiency chillers, high-efficiency heat pumps and high-efficiency air
conditioners are other examples of current demand-side management programs.
The November 1991 rate orders of the NCUC and The Public Service Commission of
South Carolina (PSCSC) provided for recovery

<PAGE>

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. As additional
demand-side costs are incurred, the Company ultimately expects recovery of
associated costs, which are currently being deferred, through rates. The
annual costs deferred, including the return, were approximately $26 million in
1993 and $18 million in 1992.

The purchase of capacity and energy is also an integral part of meeting future
power needs. The Company currently has under contract 500 megawatts of
capacity from other generators of electricity.

Current Issues
While the Company improved its financial performance in 1993 compared to 1992,
the ability to maintain and improve its current level of earnings will depend
on several factors. Future trends in the Company's earnings will depend on the
continued economic growth in the Piedmont Carolinas, the Company's ability to
contain costs, its ability to maintain competitive prices, the outcome of
various legislative and regulatory actions and the success of the Company's
diversified activities.

Resource Optimization. The Company has been engaged in a concentrated effort
to more efficiently and effectively use its resources through better work
practices. During the first quarter of 1993, the Company offered a Limited
Period Separation Opportunity program (LPSO) which gave employees the option
of leaving the Company for a lump sum severance payment and, for qualifying
employees, enhanced retirement benefits. Implementing programs such as LPSO
and other efficiency practices has resulted in a continued workforce reduction
and in streamlined workflows. The number of full-time employees has decreased
from 19,945 at year-end 1990 to 18,274 at year-end 1993. Included in these
amounts are 496 and 789 employees of subsidiaries and affiliates for 1990 and
1993, respectively.

Income Tax Accounting Change. In January 1993, the Company implemented a
standard as required by the Financial Accounting Standards Board (FASB) that
requires a liability approach for financial accounting and reporting for
income taxes. While classification of certain items on the Consolidated
Balance Sheets has changed, principally because certain items previously
reported net of tax are now being reported on a gross basis, there is no
material effect on the Company's results of operations.

Nuclear Decommissioning Costs. Estimated site-specific nuclear decommissioning
costs, including the cost of decommissioning plant components not subject to
radioactive contamination, total approximately $955 million stated in 1990
dollars. 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 liable for providing decommissioning related to their ownership interests
in the station. Both the NCUC and the PSCSC have granted the Company recovery
of the estimated site-specific 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 Nuclear Regulatory Commission (NRC) 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 1993, the Company expensed approximately
$52.5 million which was contributed to the external funds and accrued an
additional $5.0 million to the internal reserve. The balance of the external
funds as of December 31, 1993, was $118.5 million. The balance of the internal
reserve as of December 31, 1993, was $200.0 million and is reflected in
Accumulated depreciation and amortization on the Consolidated Balance Sheets.
Management's opinion is that the estimated site-specific decommissioning costs
being recovered through rates, when coupled with assumed after-tax fund
earnings of 4.5 percent to 5.5 percent, are currently sufficient to provide
for the cost of decommissioning based on the Company's current decommissioning
schedule.

Environmental Update. 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. The Company was an operator of
manufactured gas plants prior to the early 1950s. The Company is entering 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 two federal Superfund sites and two comparable state
sites. 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,
through efficient operations and by using nuclear generation. The sulfur
dioxide provisions of the Act allow utilities to choose among various
alternatives for compliance. The Company is currently developing a detailed

<PAGE>

compliance plan for Phase II requirements which must be filed with the
Environmental Protection Agency (EPA) by 1996. A preliminary strategy, which
allows for varying options, indicates that one-time costs associated with
bringing the Company into compliance with the Act could be as high as $1
billion, and that approximately $75 million in additional annual operating and
maintenance expenses will be incurred as well. These one-time costs could be
less depending on favorable developments in the emissions allowance market,
future regulatory and legislative actions, and advances in clean air
technology. All options within the preliminary strategy allow for full
compliance of Phase II requirements by the year 2000.

Stress Corrosion Cracking (SCC). Stress corrosion cracking has occurred in the
steam generators of Units 1 and 2 at the McGuire Nuclear Station and Unit 1 at
the Catawba Nuclear Station. The Company is of the opinion that the SCC is
caused by the defective design, workmanship and materials used by the
manufacturer of the steam generators. 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 will be a problem. Although the Company has taken steps to
mitigate the effects of SCC, the inherent potential for future SCC in the
Catawba and McGuire steam generators still exists. The Company has begun
planning for the replacement of steam generators and has set the following
schedule to begin the process: McGuire Unit 1 - 1995, Catawba Unit 1 - 1996,
McGuire Unit 2 - 1997. The Catawba Unit 2 steam generators have not been
scheduled for replacement. The order of replacement is subject to change based
on performance of the existing steam generators and on the overall performance
of the three units. The Company has signed an agreement with Babcock & Wilcox
International to purchase replacement steam generators. 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
without consideration of reimbursement of applicable costs by the other joint
owners of Catawba Unit 1. Stress corrosion problems are excluded under the
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--North Carolina Municipal
Power Agency Number 1, North Carolina Electric Membership Corporation,
Piedmont Municipal Power Agency and Saluda River Electric Cooperative, Inc.--
commenced a legal action on March 22, 1990. This action alleges that
Westinghouse Electric Corporation (Westinghouse), the supplier of the steam
generators, knew, or recklessly disregarded information in its possession,
that the steam generators supplied to McGuire and Catawba stations would be
susceptible to SCC and that Westinghouse deliberately concealed such
information from the Company. The Company is seeking a judgment against
Westinghouse for damages of approximately $600 million, including the cost of
necessary remedial measures, the cost of replacement steam generators and
payment for replacement power during the outages to accomplish the
replacement. In addition to these damages, the Company is seeking punitive or
treble damages and attorneys' fees. A trial date has been set for March 14,
1994.

Competition. The Energy Policy Act of 1992 has far-reaching implications for
the Company by moving utilities toward a more competitive environment. The Act
reformed certain provisions of the Public Utility Holding Company Act of 1935
(PUHCA) and removed certain regulatory barriers. For example, the Act 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 registration under PUHCA
as an electric utility holding company. The Act requires transmission of power
for third parties to wholesale customers, provided the reliability of service
to the utility's local customer base is protected and the local customer base
does not subsidize the third-party service. Although the Act does not require
transmission access to retail customers, states can authorize such
transmission access to and for retail electric customers.

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 price of electricity,
utilities might be forced to reduce their assets to reflect their market basis
if such basis is less than cost. Discontinuance of cost-based regulation could
also require some utilities to write off their 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 is continuing to position itself to effectively meet these
challenges by maintaining prices that are regionally and nationally
competitive.

Subsidiary Activities. A major part of the future growth in the electric power
market is anticipated to be outside the traditional regulated framework and,
to a large extent, outside the United States. The Company, through its
subsidiaries, is participating in these international opportunities and
continues participating in domestic opportunities to provide additional value
to its shareholders. Internationally, the Company is seeking opportunities to
provide engineering consulting services, construction, operation and
maintenance of generation facilities, and ownership of transmission and
generation facilities. Although these opportunities are concentrated in areas
that utilize the Company's expertise, they present different and greater risks
than does the Company's core business. The Company considers only
opportunities in which the expected returns are commensurate with the risks
and makes efforts to mitigate such risks. At December 31, 1993, the Company
had equity investments of $84.5 million in international transmission and
generation facilities and $17.1 million in electric assets within the United
States, but outside its current service area. The Company is actively pursuing
additional international and domestic opportunities to capitalize on the
future potential growth of this market.
21

<PAGE>
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, 1993........................... 23
Consolidated Statements of Cash Flows for the Three Years Ended December 31, 1993....................... 24
Consolidated Balance Sheets -- December 31, 1993 and 1992............................................... 25
Consolidated Statements of Capitalization -- December 31, 1993 and 1992................................. 26
Consolidated Statements of Retained Earnings for the Three Years Ended December 31, 1993................ 26
Notes to Consolidated Financial Statements.............................................................. 27
Independent Auditors' Report................................................................................. 39
Responsibility for Financial Statements...................................................................... 39
Selected Quarterly Financial Data (Unaudited)................................................................ 40
Subsidiary Highlights (Unaudited)............................................................................ 41
Consolidated Financial Statement Schedules:
Schedule V -- Property, Plant and Equipment for the Three Years Ended December 31, 1993................. 42
Schedule VI -- Accumulated Depreciation and Amortization of Property, Plant and Equipment for the Three
Years Ended December 31, 1993.......................................................................... 43
Schedule VIII -- Valuation and Qualifying Accounts and Reserves for the Three Years Ended December 31,
1993................................................................................................... 44
Schedule X -- Supplementary Consolidated Income Statement Information for the Three Years Ended December
31, 1993............................................................................................... 44
</TABLE>

<PAGE>
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
Dollars in Thousands Year ended December 31, 1993 1992 1991
<S> <C> <C> <C>
ELECTRIC REVENUES (Notes 1 and 2).....................$4,281,876 $3,961,484 $3,816,960
ELECTRIC EXPENSES
Operation
Fuel used in electric generation (Note 1)...........732,246 659,593 657,725
Net interchange and purchased power (Note 3)........535,033 540,840 545,840
Wages, benefits and materials......................701,994 636,729 622,121
Maintenance of plant facilities........................375,457 403,162 354,679
Depreciation and amortization (Note 1).................488,441 491,339 431,624
General taxes..........................................231,680 215,493 204,688
Income taxes (Notes 1 and 4)...........................402,960 289,633 293,460
Total electric expenses...........................3,467,811 3,236,789 3,110,137
Electric operating income.........................814,065 724,695 706,823
OTHER INCOME (Notes 1, 4, 11 and 14)
Allowance for equity funds used during construction.....17,221 15,476 50,704
Other, net..............................................61,769 83,216 102,884
Income taxes -- other, net.............................(24,092) (27,475) (25,472)
Income taxes -- credit.................................16,371 13,790 22,789
Total other income...................................71,269 85,007 150,905
Income before interest deductions.................885,334 809,702 857,728
INTEREST DEDUCTIONS
Interest on long-term debt.............................256,347 265,646 274,662
Other interest..........................................12,431 41,736 18,834
Allowance for borrowed funds used
during construction (Notes 1 and 4)..................(9,859) (5,763) (19,391)
Total interest deductions..........................258,919 301,619 274,105
NET INCOME...............................................626,415 508,083 583,623
Dividends on preferred and preference stock.............52,429 56,407 54,683
EARNINGS FOR COMMON STOCK.............................$ 573,986 $ 451,676 $ 528,940
COMMON STOCK DATA (Note 6)
Average shares outstanding (thousands).................204,859 204,819 203,431
Earnings per share.......................................$2.80 $2.21 $2.60
Dividends per share..................................... $1.84 $1.76 $1.68
</TABLE>

SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
23

<PAGE>

CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Dollars in Thousands Year ended December 31, 1993 1992 1991
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income..........................................$ 626,415 $ 508,083 $ 583,623
Adjustments to reconcile net income to
net cash provided by operating activities:
Non-cash items
Depreciation and amortization (Note 1)............. 657,068 660,896 619,823
Deferred income taxes and investment tax credit,
net of amortization (Note 4)....................... 56,315 44,518 27,456
Allowance for equity funds used during
construction..................................... (17,221) (15,476) (50,704)
Purchased capacity levelization (Note 3)............ (20,049) (66,511) (70,605)
Other, net (Note 15)................................. 36,864 (16,258) (32,149)
(Increase) Decrease in
Accounts receivable............................. (36,948) 14,255 (45,412)
Inventory........................................ 29,150 (9,383) 6,866
Prepayments........................................ (452) (939) 181
Increase (Decrease) in
Accounts payable................................. (54,275) 69,739 44,265
Taxes accrued (Notes 1 and 4)..................... 26,583 4,514 11,739
Interest accrued and other liabilities
(Notes 1, 9 and 13)........................... 30,185 (22,825) 12,863
Total adjustments.................................. 707,220 662,530 524,323
Net cash provided by operating activities... 1,333,635 1,170,613 1,107,946
CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures........................... (543,563) (465,292) (572,705)
Investment in nuclear fuel.......................... (111,731) (122,565) (183,803)
External Funding for decommissioning (Note 16)....... (52,524) (61,246) --
Pre-funded pension cost (Note 12).................... (50,000) -- --
Net change in investment securities and joint
ventures (Notes 1, 11 and 15)..................... (12,379) (96,475) (35,807)
Net cash used in investing activities....... (770,197) (745,578) (792,315)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of
First and refunding mortgage bonds.............. 1,395,682 926,650 414,297
Preferred stock................................. 215,633 281,089 --
Pollution-control bonds........................... 76,265 -- --
Short-term notes payable, net (Note 5).......... (108,000) 40,000 (99,000)
Common stock................................... -- -- 48,014
Payments for the redemption of
First and refunding mortgage bonds............ (1,399,336) (1,013,218) (279,970)
Preferred stock............................... (224,295) (246,414) (9,650)
Pollution-control bonds........................ (79,310) -- --
Dividends paid.................................. (427,868) (417,443) (381,589)
Other (Note 15).................................. (5,926) 3,313 (5,662)
Net cash used in financing activities... (557,155) (426,023 (313,560)
Net increase (decrease) in cash..................... 6,283 (988) 2,071
Cash at beginning of year............................ 9,293 10,28 8,210
Cash at end of year............................... $ 15,576 $ 9,293 $ 10,281
</TABLE>

SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

24
<PAGE>

CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
Dollars in Thousands December 31, 1993 1992
<S> <C> <C>
ELECTRIC PLANT (at original cost --
Notes 1, 3, 9, 13, 15 and 16)
Electric plant in service.........................$12,573,012 $12,193,888
Less accumulated depreciation and amortization......4,431,460 4,197,505
Electric plant in service, net....................8,141,552 7,996,383
Nuclear fuel..........................................705,994 718,420
Less accumulated amortization.........................405,910 425,088
Nuclear fuel, net...................................300,084 293,332
Construction work in progress (including nuclear
fuel in process:
1993 -- $113,904; 1992 -- $148,945).................482,473 490,408
Total electric plant, net.......................8,924,109 8,780,123
OTHER PROPERTY AND INVESTMENTS
Other property -- at cost (less accumulated
depreciation:
1993 -- $90,191; 1992 -- $83,108) (Note 15).........311,241 295,098
Investments in joint ventures (Notes 11 and 15).......101,612 31,268
Other investments, at cost or less.....................90,301 127,632
Nuclear decommissioning trust funds (Notes 10,
15 and 16)....................................... 118,456 61,812
Pre-funded pension cost (Note 12)......................50,000 --
Total other property and investments..............671,610 515,810
CURRENT ASSETS
Cash (Notes 5 and 10)................................. 15,576 9,293
Short-term investments (Note 10)......................120,651 141,285
Receivables (less allowance for losses:
1993 -- $6,392; 1992 -- $5,207) (Note 1)............531,592 494,644
Inventory -- at average cost
Coal.................................................69,155 101,550
Other...............................................199,733 196,489
Prepayments............................................12,062 11,610
Total current assets..............................948,769 954,871
DEFERRED DEBITS (Notes 1, 3, 4, 13 and 15)
Purchased capacity costs..............................768,099 378,095
Debt expense..........................................197,963 115,436
Regulatory asset related to income taxes..............486,440 --
Regulatory asset related to DOE assessment fee........116,731 101,785
Other..................................................79,386 104,267
Total deferred debits.......................... 1,648,619 699,583
TOTAL ASSETS........................................$12,193,107 $10,950,387

<CAPTION>
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION (See Consolidated Statements of
Capitalization).................................... $ 8,404,131 $ 8,218,257
CURRENT LIABILITIES
Accounts payable........................................337,391 394,721
Taxes accrued (Note 1).................................. 82,824 36,885
Interest accrued.........................................68,868 68,078
Other (Note 13).........................................211,207 75,613
Total................................................700,290 575,297
Notes payable (Notes 5 and 10)...........................18,000 126,000
Current maturities of long-term debt and preferred
stock (Notes 9 and 15).................................91,898 9,434
Total current liabilities...........................810,188 710,731
ACCUMULATED DEFERRED INCOME TAXES (Notes 1 and 4).......2,207,708 1,369,677
DEFERRED CREDITS AND OTHER LIABILITIES
Investment tax credit (Notes 1 and 4)...................282,505 296,165
DOE assessment fee (Note 1).............................116,731 101,785
Nuclear decommissioning costs externally funded
(Notes 15 and 16).....................................118,456 61,812
Other...................................................253,388 191,960
Total deferred credits and other liabilities........771,080 651,722
COMMITMENTS AND CONTINGENCIES (Note 13)..................
TOTAL CAPITALIZATION AND LIABILITIES..................$12,193,107 $10,950,387
</TABLE>

SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
25

<PAGE>

CONSOLIDATED STATEMENTS OF CAPITALIZATION AND RETAINED EARNINGS

<TABLE>
<CAPTION>
Dollars in Thousands December 31 1993 1992
<S> <C> <C>
CAPITALIZATION
<S> <C> <C>
COMMON STOCK EQUITY (Notes 6 and 7)
Common stock, no par, 300,000,000 shares
authorized; 204,859,339 shares outstanding
for 1993 and 1992..............................$1,926,909 $1,926,909
Retained earnings................................2,410,825 2,223,718
Total common stock equity...................4,337,734 4,150,627
PREFERRED AND PREFERENCE STOCK WITHOUT SINKING
FUND REQUIREMENTS (Note 7)........................ 500,000 500,000
PREFERRED STOCK WITH SINKING FUND REQUIREMENTS
(Notes 8 and 10).................................. 281,000 279,519
LONG-TERM DEBT (Notes 9, 10 and 15)
Parent company long-term debt................... 3,199,032 3,202,437
Subsidiary long-term debt.......................... 86,365 85,674
Total consolidated long-term debt.......... 3,285,397 3,288,111
TOTAL CAPITALIZATION............................. $8,404,131 $8,218,257
</TABLE>

<TABLE>
<CAPTION>
Dollars in Thousands Year ended December 31, 1993 1992 1991
<S> <C> <C> <C>
RETAINED EARNINGS
<S> <C> <C> <C>
BALANCE -- Beginning of year........................ $2,223,718 $2,141,259 $1,953,779
ADD -- Net income.......................................626,415 508,083 583,623
Total........................................ 2,850,133 2,649,342 2,537,402
DEDUCT
Dividends
Common stock...................................... 376,937 360,475 341,801
Preferred and preference stock......................52,429 56,407 54,683
Capital stock transactions, net........................9,942 8,742 (341)
Total deductions.................................439,308 425,624 396,143
BALANCE -- End of year...............................$2,410,825 $2,223,718 $2,141,259
</TABLE>

SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
26
<PAGE>

Notes To Consolidated Financial Statements

Note 1. Summary of Significant Accounting Policies
A. Revenues

Revenues are recorded as service is rendered to customers. "Receivables"
on the Consolidated Balance Sheets include $175,726,000 and $167,610,000
as of December 31, 1993 and 1992, respectively, for service that has been
rendered but not yet billed to customers.

B. 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.

C. Allowance for Funds Used During Construction (AFUDC)

AFUDC represents the estimated debt and equity costs of capital funds that
are necessary to finance the construction of new facilities. AFUDC, a non-
cash item, is recognized as a cost of "Construction work in progress"
(CWIP), with offsetting credits to "Other income" and "Interest
deductions." 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 1993 AFUDC rate of 9.29 percent reflects "Allowance for borrowed
funds used during construction" calculated using a pre-tax cost of debt.
The rates for 1992 and 1991 of 8.07 percent and 8.86 percent have been
calculated using a net of tax cost of debt. Rates for all periods are
compounded semiannually. The change in calculation from a net of income
tax to a pre-tax basis is a result of the adoption of Statement of
Financial Accounting Standards No. 109 (SFAS 109). (See Note 4.)

D. Depreciation and Amortization

Provisions for depreciation are recorded using the straight-line method.
The year-end composite weighted-average depreciation rates were 3.47
percent for 1993 and 3.48 percent for 1992 and 1991. Effective with the
implementation of new retail rates in November 1991, all coal-fired
generating units are depreciated at a rate of 2.57 percent and all nuclear
units are depreciated at a rate of 4.70 percent, of which 1.61 percent is
for decommissioning. (See Note 16.)
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 $8,338,000 during 1993
related to its ownership interest in nuclear plants. The Company has
reflected the remaining liability and regulatory asset of $116,731,000 in
the Consolidated Balance Sheets.

E. Subsidiaries

The Company's consolidated financial statements reflect consolidation of
all of its wholly-owned subsidiaries. Intercompany transactions have been
eliminated in consolidation. (See Note 11 and "Subsidiary Highlights,"
page 41.)

F. Income Taxes

The Company implemented SFAS 109, "Accounting for Income Taxes," effective
January 1, 1993. (See Note 4.)
The Company and its subsidiaries file a consolidated federal income tax
return. Income taxes have been allocated to each company based on its
separate company taxable income or loss.
Income taxes are allocated to non-electric operations under "Other
income" and to electric operating expense. The "Income taxes - credit"
classified under "Other income" results from tax deductions of interest
costs relating primarily to deferred purchased capacity costs and CWIP.
Deferred income taxes have been provided for temporary differences
between book and tax income, principally resulting from accelerated tax
depreciation and levelization of purchased power costs. Investment tax
credits have been deferred and are being amortized over the estimated
useful lives of the related properties.
27
<PAGE>

G. Unamortized Debt Premium, Discount and Expense

Expenses incurred in connection with the issuance of presently outstanding
long-term debt, and premiums and discounts
relating to such debt, are being amortized over the terms of the
respective issues. Also, any expenses or call premiums associated with
refinancing higher-cost debt obligations are being amortized over the
lives of the new issues of long-term debt.

H. Fuel Cost Adjustment Procedures

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 the Company to adjust rates for past over- or
under-recovery of fuel costs. Therefore, the Company reflects in revenues
the difference between actual fuel costs incurred and fuel costs recovered
through rates.
The North Carolina legislature ratified a bill in July 1987 assuring
the legality of such adjustments in rates. In 1991, the statute was
extended through June 30, 1997.

I. Consolidated Statements of Cash Flows

For purposes of the Consolidated Statements of Cash Flows,
the Company's 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 $352,697,000, $215,465,000 and
$245,945,000 for years ended December 31, 1993, 1992 and 1991,
respectively.
Interest paid, net of amount capitalized, was $244,829,000,
$298,455,000 and $269,330,000 for the years ended December 31, 1993, 1992
and 1991, respectively.

Note 2. Rate Matters

The North Carolina Utilities Commission (NCUC) and The Public Service
Commission of South Carolina (PSCSC) must approve rates for retail sales
within their respective states. The Federal Energy Regulatory Commission
(FERC) must approve the Company's rates for sales to wholesale customers.
Sales to the other joint owners of the Catawba Nuclear Station, which
represent a substantial majority of the Company's wholesale revenues, are
set through contractual agreements. (See Note 3.)
During 1991, the Company filed in both the North Carolina and the South
Carolina retail jurisdictions its only requests for general rate increases
since 1986. The rate increase requested by the Company in North Carolina
was 9.22 percent; a 4.15 percent increase was granted resulting in $100.1
million in additional annual revenues. In South Carolina, a rate increase
of 7.29 percent was requested; a 3.0 percent increase was granted
resulting in $30.2 million in additional annual revenues. These increases
were requested primarily to recover costs associated with the Bad Creek
Hydroelectric Station.
In 1991, the Company filed a request with the FERC seeking a 7.47
percent rate increase for its wholesale customers, who represent
approximately 2 percent of the Company's total revenues. A negotiated
settlement between the Company and the wholesale customers was approved by
the FERC on March 31, 1992. The approved agreement, effective April 1,
1992, provided for a 3.3 percent rate increase, resulting in $2.1 million
in additional annual revenues.
The North Carolina Supreme Court on April 22, 1992, remanded for the
second time the Company's 1986 rate order to the NCUC. In this ruling, the
Court held that the record from the 1986 proceedings failed to support the
rate of return of 13.2 percent on common equity authorized by the NCUC
after the initial decision of the Court remanding the 1986 rate order. The
NCUC issued a final order dated October 26, 1992, authorizing a 12.8
percent return on common equity for the period October 31, 1986, through
November 11, 1991, that resulted in a refund to North Carolina retail
customers in 1992 of approximately $95 million, including interest.
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 sales agreement.

Note 3. Joint Ownership of Generating Facilities

The Company has 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
<S> <C>
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%
</TABLE>

Each participant has provided its own financing for its ownership interest
in the plant.
The Company retains a 12.5 percent ownership interest in the Catawba
Nuclear Station. As of December 31, 1993, $498,930,000 of Electric plant
in service and Nuclear fuel
28
<PAGE>

represents the Company's investment in Units 1 and 2. Accumulated
depreciation and amortization of $152,698,000 associated with Catawba had
been recorded as of year-end. The Company's share of operating costs of
Catawba are included in the corresponding electric expenses 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
agreements were effective beginning with the commercial operation of each
unit. Unit 1 and Unit 2 began commercial operation in June 1985 and in
August 1986, respectively. Such agreements were established for 15 years
for NCMPA and PMPA and 10 years for NCEMC and Saluda River.
Energy cost payments are based on variable operating costs, a function
of the generation output. Capacity payments are based on the fixed costs
of the plant. The estimated purchased capacity obligations through 1998
are $392,000,000 for 1994, $293,000,000 for 1995, $55,000,000 for 1996,
$44,000,000 for 1997 and $32,000,000 for 1998. Payment obligations include
the terms of a proposed settlement agreement between the Company and two
of the four joint owners of the Catawba Nuclear Station which was executed
in January 1994 and is subject to regulatory approval. (See Note 13.)
Effective in its November 1991 rate order, the North Carolina Utilities
Commission (NCUC) 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 new NCUC rate order changed the
levelized basis to a 15-year period ending 2001 for all of the other joint
owners compared to the previous 15-year levelization period for NCMPA and
PMPA and 10-year levelization period for NCEMC and Saluda River. The
Public Service Commission of South Carolina (PSCSC), 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. The new
PSCSC rate order retained the levelized basis of a 7 1/2-year period for
PMPA and NCMPA; for NCEMC and Saluda River, the new levelized basis
reflects the projected purchased capacity payments for the twelve-month
period ended October 1992. The Federal Energy Regulatory Commission
granted the Company recovery on a levelized basis of the capital costs and
fixed operating and maintenance costs of capacity purchased from the other
joint owners over their contractual purchased power buyback periods. As
currently provided in rates in all jurisdictions, the Company recovers the
costs of purchased energy and a portion of purchased capacity. The portion
of costs not currently recovered through rates is being accumulated, and
the Company is recording a carrying charge on the accumulated balance.
The Company recovers the accumulated balance including the carrying charge
when the capacity payments drop below the levelized revenues. In the North
Carolina and wholesale jurisdictions, purchased capacity payments
continue to exceed levelized revenues. In the South Carolina jurisdiction,
cumulative levelized revenues have exceeded purchased capacity payments.
Jurisdictional levelizations are intended to recover total costs,
including allowed returns, and are subject to adjustments, including final
true-ups.
For the years ended December 31, 1993, 1992 and 1991, the Company
recorded purchased capacity and energy costs from the other joint owners
of $547,900,000, $514,300,000 and $536,500,000, respectively. These
amounts, adjusted for the cost 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, 1993 and 1992,
$768,099,000 pre-tax and $378,095,000 net of income tax, respectively,
associated with the costs of capacity purchased but not reflected in
current rates had been accumulated in the Consolidated Balance Sheets as
"Purchased capacity costs." Accumulated deferred income taxes associated
with "Purchased capacity costs" were $254,789,000 as of December 31, 1993.
As of December 31, 1992, deferred income taxes reduced "Purchased capacity
costs" on the Consolidated Balance Sheet by $265,255,000. The change in
presentation from a net of tax to pre-tax basis is a result of the
adoption of SFAS 109. (See Note 4.)

Note 4. Income Tax Expense

The Company implemented Statement of Financial Accounting Standards No.
109 (SFAS 109), "Accounting for Income Taxes," effective January 1, 1993.
No prior periods have been restated.
SFAS 109 requires a liability approach for financial accounting and
reporting of income taxes. While classification of certain items on the
Consolidated Balance Sheets has changed, principally because of certain
items previously reported net of tax now being reported on a gross basis,
there is no material effect on the Company's results of operations. As a
result of implementing SFAS 109, the December 1993 Consolidated Balance
Sheet reflects an increase of $778 million in both Total assets and
Accumulated deferred income taxes (ADIT). The increase was primarily
because of a change in presentation from a net of tax to pre-tax basis
which resulted in an increase in "Purchased capacity costs" of $255
million and in the creation of the "Regulatory asset related to income
taxes" of $486 million. Effective January 1, 1993, "Allowance for borrowed
funds used during construction" on the Consolidated Statement of Income
reflects a pre-tax cost of debt.
Accumulated deferred income taxes after implementation of SFAS 109
consist primarily of the following temporary differences (dollars in
thousands):
29
<PAGE>

December 31, 1993
<S> <C> <C>
Excess tax over book depreciation at historical tax rates $1,289,205
Regulatory liability related to adjusting deferred taxes
to the current statutory tax rate (124,952)*
Net excess tax over book depreciation $1,164,253
Regulatory asset related to restating to a pre-tax basis 611,392*
Deferred Catawba purchased capacity costs 254,789
Book versus tax basis difference 110,594
Loss on bond redemptions 74,438
Other (7,758)
Total deferred income taxes $2,207,708
</TABLE>

* The net regulatory asset related to income taxes is $486,440,000.

Total deferred income tax liability was $2,701,374,000 as of December 31,
1993. Total deferred income tax asset was $493,666,000 as of December 31,
1993.

Income tax expense consisted of the following (dollars in thousands):

1993 1992 1991
<S> <C> <C> <C>
Income taxes related to electric expenses
Current income taxes
Federal $278,279 $215,726 $232,121
State 60,948 47,116 54,335
339,227 262,842 286,456
Deferred taxes, net
Excess tax over book depreciation 60,760 86,046 60,976
Loss on bond redemptions 33,016 9,950 1,995
Pre-funded pension cost 19,751 -- --
Amortization of canceled construction
costs (17,890) (23,959) (23,959)
Deferred Catawba purchased capacity costs 2,841 7,271 8,163
Property taxes (5,806) (15,499) (11,987)
Other (17,682) (25,756) (16,977)
74,990 38,053 18,211
Investment tax credit
Deferred -- -- 2,273
Amortization of deferrals (credit) (11,257) (11,262) (13,480)
(11,257) (11,262) (11,207)
Total income taxes related to electric
expenses 402,960 289,633 293,460
Income taxes related to other income
Income taxes - return on deferred Catawba
purchased capacity costs 20,702 18,845 20,675
Income taxes - other, net 3,390 8,630 4,797
Income taxes - (credit) (16,371) (13,790) (22,789)
Total income taxes related to other income 7,721 13,685 2,683
Total income tax expense $410,681 $303,318 $296,143
</TABLE>

Total current income taxes were $354,366,000 for 1993, $258,800,000 for
1992 and $268,686,000 for 1991. Of these amounts, state income taxes were
$61,237,000 for 1993, $44,149,000 for 1992 and $48,671,000 for 1991.
Total deferred income taxes were $67,572,000 for 1993, $55,780,000 for
1992 and $38,664,000 for 1991. Of these amounts, deferred state income
taxes were $14,279,000 for 1993, $13,786,000 for 1992 and $10,833,000 for
1991.
30
<PAGE>

Income taxes differ from amounts computed by applying the statutory tax
rate to pre-tax income as follows (dollars in thousands):

<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Income taxes on pre-tax income at the
statutory federal rate of 35% - 1993;
34% - 1992 and 1991 $362,984 $275,876 $299,120
Increase (reduction) in tax resulting from:
Allowance for funds used during construction
(AFUDC) (6,027) (7,221) (23,832)
Amortization of electric investment tax
credit deferrals (11,257) (11,262) (13,480)
AFUDC in book depreciation/amortization 25,694 25,114 25,923
Deferred income tax flowback at rates
higher than statutory (9,091) (21,685) (22,561)
State income taxes, net of federal
income tax benefits 49,292 37,878 39,345
Other items, net (914) 4,618 (8,372)
Total income tax expense (see above) $410,681 $303,318 $296,143
</TABLE>

On August 10, 1993, President Clinton signed the Omnibus Budget
Reconciliation Act of 1993 which includes an increase in the federal
corporate income tax rate from 34% to 35%, retroactive to January 1, 1993.
Accordingly, the Company's income tax expense reflects an increase of
approximately $10 million for 1993.

Note 5. Short-Term Borrowings and Compensating-Balance Arrangements

To support short-term obligations, the Company had credit facilities of
$324,980,000, $329,385,000 and $340,385,000 as of December 31, 1993, 1992
and 1991, with 29, 49 and 52 commercial banks, respectively. Included in
these facilities is a three-year, $300,000,000 revolving credit agreement
with the balance in separate, annually-renewable lines of credit. These
facilities are on a fee or compensating-balance basis. No short-term debt
resulting from these credit facilities was outstanding as of December 31,
1993, 1992 and 1991.
Cash balances maintained at the banks on deposit were $12,988,000 and
$7,243,000 as of December 31, 1993 and 1992, respectively. 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 $49,000 and
$509,000 as of December 31, 1993 and 1992, 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):

December 31, 1993 December 31, 1992 December 31, 1991
<S> <C> <C> <C>
Amount outstanding at end of period -
average rate of 3.27% as of December 31,
1993, 3.57% as of December 31, 1992
and 4.65% as of December 31, 1991 $ 18,000 $126,000 $ 86,000
Maximum amount outstanding during the period $ 178,000 $219,000 $285,500
Average amount outstanding during the period $ 35,187 $ 48,851 $ 92,090
Weighted-average interest rate for the period -
computed on a daily basis 3.17% 4.02% 6.47%
</TABLE>

Note 6. Common Stock and Retained Earnings

Common Stock
Effective April 1, 1991, the Company began issuing common stock in lieu of
purchasing shares on the open market for its various stock purchase plans.
The Company discontinued issuances of common stock, effective December 1,
1991, and resumed open market purchases to satisfy the requirements of the
various stock purchase plans. Except as discussed earlier, open market
purchases were used to satisfy the requirements of the Company's various
stock plans from 1991 through 1993.
During 1991 and through April 6, 1992, the Company issued common stock
to satisfy the conversion rights of preference stock. (See Note 7.)
As of December 31, 1993, a total of 7,004,659 shares was reserved for
issuance to stock plans.

Retained Earnings
As of December 31, 1993, none of the Company's retained earnings were
restricted as to the declaration or payment of dividends.

31
<PAGE>

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, 1993 and 1992:

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>

On April 6, 1992, the Company redeemed all outstanding shares of the
Cumulative Preference Stock, 63/4% Convertible Series AA at its par value
of $100 per share.

In 1992 and 1991, shares of preference stock were converted into shares
of common stock as follows:

Year Preference Shares Common Shares
<S> <C> <C>
1992 19,060 159,386
1991 1,846 15,440
</TABLE>

Preferred and preference stock without sinking fund requirements as of
December 31, 1993 and 1992, were as follows (dollars in
thousands):

Rate/Series Year Shares
Issued Outstanding 1993 1992
<S> <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
8.20% G 1971 600,000 - 60,000
7.80% H 1972 600,000 - 60,000
8.28% K 1977 500,000 - 50,000
7.85% S 1992 600,000 60,000 60,000
7.00% W 1993 500,000 50,000 -
7.04% Y 1993 600,000 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 -
Adjustable Rate A 1986 500,000 50,000 50,000
Auction Series A 1990 750,000 75,000 75,000
$500,000 $500,000
</TABLE>

Note 8. Preferred Stock With Sinking Fund Requirements

The following shares of stock were authorized with or without sinking fund
requirements as of December 31, 1993 and 1992:

<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>

Preferred stock with sinking fund requirements as of December 31, 1993 and
1992, was as follows (dollars in thousands):

Year Shares
Rate/Series Issued Outstanding 1993 1992
<S> <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
7.875% P 1986 485,000 - 48,500
7.12% Q 1987 485,000 48,500 48,519
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 -

Less: Current sinking fund
requirements
7.875% P - (1,500)
7.12% Q (1,500) -
$281,000 $279,519
</TABLE>

The annual sinking fund requirements through 1998 are
$1,500,000 in 1994, 1995, 1996 and 1997 and $5,750,000 in 1998. Some
additional redemptions are permitted at the Company's option. The Company
reacquired 15,000 shares of 7.12% Series Q Preferred Stock in 1992 to
satisfy 1993 sinking fund requirements.
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.

32
<PAGE>

Note 9. Long-Term Debt

Long-term debt outstanding as of December 31, 1993 and 1992, was as
follows (dollars in thousands):

Series Year Due 1993 1992
<S> <C> <C> <C>
First and refunding mortgage bonds:
6.06%-6.23% 1994 $81,700 $81,700
6.47%-6.60% 1995 40,300 40,300
4 1/2% 1995 40,000 40,000
6.59% 1996 3,000 3,000
7 7/8% 1996 - 100,000
5 3/8% 1997 72,600 72,600
5 5/8% 1997 100,000 100,000
6 3/8% 1998 - 68,500
5.17% 1998 50,000 -
7% 1999 - 56,075
7.5% 1999 100,000 100,000
6 1/4% 1999 65,000 65,000
5.76% 1999 5,000 -
5.78% 1999 25,000 -
5.79% 1999 30,000 -
7% 2000 100,000 100,000
7% B 2000 100,000 100,000
7 1/2% 2001 - 97,900
7 3/8% B 2001 - 38,050
5 7/8% 2001 150,000 -
7 3/4% 2002 - 78,100
7 3/8% B 2002 - 67,900
6 5/8% B 2003 100,000 -
7 3/4% 2003 - 94,872
5 7/8% C 2003 75,000 -
6.125% 2003 75,000 -
8% 2004 75,000 75,000
6 1/4% B 2004 100,000 -
7.37%-7.41% 2004 100,000 100,000
7% 2005 200,000 200,000
8 1/8% 2007 - 119,500
6 3/8% 2008 125,000 -
9% 2016 - 175,000
8 1/2% 2017 - 150,000
9 5/8% 2020 46,982 200,000
10 1/8% B 2020 24,854 150,000
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 -
6 7/8% 2023 200,000 -
6 3/4% 2025 150,000 -
8.95% 2027 15,851 15,925
7% 2033 150,000 -
Pollution-Control bonds:
9 1/8% 2013 - 77,000
7.70% 2012 20,000 20,000
7.75% B 2017 10,000 10,000
7.50% 2017 25,000 25,000
2.55% 2014 40,000 -
2.60% 2014 - 40,000
5.80% 2014 77,000 -
Subtotal 3,172,287 3,061,422

Other long-term debt:
Capitalized leases 47,029 53,782
Other long-term debt 130,000 130,000
Unamortized debt discount
and premium, net (61,128) (35,940)
Current maturities of
long-term debt (89,156) (6,827)
Subtotal (a) 3,199,032 3,202,437
Subsidiary long-term debt:
Crescent Resources, Inc. (b) 54,149 53,207
Nantahala Power and Light (c) 33,458 33,574
Current maturities of long-term debt (1,242) (1,107)
Subtotal 86,365 85,674
Total consolidated long-term debt $3,285,397 $3,288,111
</TABLE>

(a) Substantially all the Company's electric plant was mortgaged as of
December 31, 1993.
(b) Substantial amounts of Crescent Resources, Inc.'s real estate
development projects, land and buildings are pledged as collateral.
(c) Nantahala Power and Light's loan agreements impose net worth
restrictions and limitations on disposal of assets and payment of cash
dividends.

As of December 31, 1993 and 1992, the Company had $40,000,000 in
pollution-control revenue bonds backed by an unused, two-year revolving
credit facility of $40,000,000 and $130,000,000 in commercial paper backed
by an unused, three-year $130,000,000 revolving credit facility. 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, 1993, Crescent Resources, Inc. had $52,064,000 in
mortgage loans which mature in 1997 and require monthly payments of
principal. Interest rates are variable and ranged from 4.21 percent to
5.08 percent as of December 31, 1993. Nantahala Power and Light had
$33,000,000 in senior notes maturing in 2011 and 2012 as of December 31,
1993. The two notes carry fixed interest rates of 9.21 percent and 7.45
percent and require prepayments beginning 1997 and 1998, respectively.

The annual maturities of consolidated long-term debt, including
capitalized lease principal payments through 1998, are $90,398,000 in
1994; $89,888,000 in 1995; $13,264,000 in 1996; $223,810,000 in 1997 and
$54,522,000 in 1998.
33
<PAGE>

Note 10. Fair Value of Financial Instruments

Estimated fair value amounts have been determined by the Company using
available market information and appropriate valuation methodologies.
Judgment is required in interpreting market data to develop the estimates
of fair value. Accordingly, the estimates determined as of December 31,
1993, are not necessarily indicative of the amounts that the Company could
realize in a current market exchange.

Cash, Short-term investments and Notes payable
The carrying amount approximates fair value because of the short maturity
of these instruments.

Long-term debt (excluding Capitalized leases) and Preferred stock with
sinking fund requirements
Fair value is based on market price estimates. As a result of substantial
refinancing activity in 1993 and 1992, the Company's book value of
consolidated long-term debt and preferred stock is not materially
different from fair market value as of December 31, 1993.

Nuclear decommissioning trust funds
External funds have been established, as required by the Nuclear
Regulatory Commission, as a mechanism to fund certain costs of nuclear
decommissioning. (See Note 16.) These nuclear decommissioning trust funds
are primarily invested in intermediate-term municipal bonds. As of
December 31, 1993, the Company's book value of its nuclear decommissioning
trust funds is not materially different from fair market value.

Note 11. Investment 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. Total assets of these joint ventures as of
December 31, 1993 and 1992, were $972 million and $433 million,
respectively. The Company's proportionate share of these assets was $241
million and $163 million, respectively. Total liabilities of these joint
ventures as of December 31, 1993 and 1992, were $413 million and $321
million, respectively. The Company's proportionate share of the
liabilities was $139 million and $132 million, respectively. Of the $413
million total liabilities outstanding at December 31, 1993, $290 million
represents non-recourse debt for which the Company bears no responsibility
in the event the joint venture defaults on the debt. The Company's portion
of net income from the joint ventures for the years ended December 31,
1993 and 1992, was $2,601,000 and ($1,179,000).

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 on years of
creditable service and the employee's average compensation based on the
highest compensation during a consecutive sixty-month period. Prior to
1992, benefits have been reduced by a Social Security adjustment for
employees age sixty-five and over and for early retirees with no
creditable service prior to September 1, 1980. During 1991, the Company
amended its plan for employees who retire after December 31, 1991. The
effect of this amendment was to reduce benefits by a Social Security
adjustment for all retirees. The plan was amended in 1992 to permit
participants with 30 years of creditable service to retire as early as age
51. The Company's policy is to fund pension costs as accrued. During 1993,
the Company made a one-time contribution of $50,000,000 to enhance the
funded position of the plan.

Net periodic pension cost for the years ended December 31, 1993, 1992 and
1991, include the following components (dollars in
thousands):

1993 1992 1991
<S> <C> <C> <C> <C> <C> <C>
Service cost benefit earned $39,514 $35,701 $37,286
during the year
Interest cost on projected 93,347 85,613 79,175
benefit obligation
Actual return on plan assets (117,898) (50,897) (127,978)
Amount deferred for recognition 35,652 (32,277) 52,574
Expected return on plan assets (82,246) (83,174) (75,404)
Net amortization 4,137 3,812 4,347
Net periodic pension cost $54,752 $41,952 $45,404
</TABLE>
34
<PAGE>

A reconciliation of the funded status of the plan to the amounts
recognized in the Consolidated Balance Sheets as of December 31, 1993 and
1992, is as follows (dollars in thousands):

1993 1992
<S> <C> <C>
Accumulated benefit obligation:
Vested benefits $(1,087,705) $(920,228)
Nonvested benefits (3,946) (2,915)
Accumulated benefit obligation $(1,091,651) $(923,143)
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 $1,137,992 $980,661
Projected benefit obligation (1,311,921) (1,132,410)
Unrecognized net experience loss 265,566 204,145
Unrecognized prior service cost reduction (42,705) (45,911)
Remaining unrecognized transitional obligation 1,068 1,202
Prepaid pension cost $50,000 $7,687
</TABLE>

In determining the projected benefit obligation, the weighted-average
assumed discount rate used was 7.50 percent in 1993 and 8.25 percent in
1992 and 1991. The assumed increase in future compensation level for
determining the projected benefit obligation is based on an age-related
basis. The weighted-average salary increase was 4.50 percent in 1993, 5.40
percent in 1992 and 5.65 percent in 1991. The expected long-term rate of
return on plan assets used in determining pension cost was 8.40 percent in
1993 and 9.25 percent in 1992 and 1991.
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, which maintains its own postretirement
benefit plans, currently provides certain health care and life insurance
benefits for retired employees. 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
$14,648,000 into these funding mechanisms in 1993 and $19,338,000 in 1992.
In 1992, the Company implemented a new accounting standard that
requires postretirement benefits to be recognized as earned by employees
rather than recognized as paid. Prior to 1992, the cost of retiree
benefits was recognized as the benefits were paid. Amounts paid by the
Company for 1991 amounted to $11,900,000.
35
<PAGE>

Net periodic postretirement benefit cost for the years ended December 31,
1993 and 1992, include the following components (dollars in thousands):

1993 1992
<S> <C> <C> <C> <C>
Service cost benefit earned during the year $4,974 $4,644
Interest cost on accumulated postretirement benefit
obligation 25,482 23,347
Actual return on plan assets (4,143) (2,953)
Amount deferred for recognition 334 1,061
Expected return on plan assets (3,809) (1,892)
Straight line - 20 year amortization of transition
obligation 13,479 13,479
Other amortization 278 160
Net periodic postretirement benefit cost $40,404 $39,738
</TABLE>

A reconciliation of the funded status of the plan to the amounts
recognized in the Consolidated Balance Sheets as of December 31,
1993 and 1992, is as follows (dollars in thousands):

1993 1992
<S> <C> <C> <C> <C>
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 $57,840 $41,634
Actives eligible to retire (21,810) (14,954)
Actives not eligible to retire (90,621) (74,900)
Retirees and surviving spouses (238,522) (213,018)
Accumulated postretirement benefit obligation (350,953) (302,872)
Unrecognized prior service cost 1,923 2,083
Unrecognized net experience (gain)/loss 29,127 (2,501)
Unrecognized transitional obligation 242,629 256,108
(Accrued) postretirement benefit cost $(19,434) $(5,548)
</TABLE>

In determining the accumulated postretirement benefit obligation (APBO),
the weighted-average assumed discount rate used was 7.50 percent in 1993
and 8.25 percent in 1992. The assumed increase in future compensation
level is determined on an age-related basis. The weighted-average salary
increase was 4.50 percent in 1993, 5.40 percent in 1992 and 5.65 percent
in 1991. The expected long-term rate of return on 401(h) assets used in
determining postretirement benefits cost was 8.40 percent in 1993 and 9.25
percent in 1992. For Retired Lives Reserve assets, 7.125 percent was used
in 1993 and 1992.
The assumed medical inflation rate was approximately 13 percent in
1993. 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 2002, which remains fixed
thereafter.
A 1.0 percent increase in the medical and dental trend rates produces a
6.25 percent ($1,903,213) 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 6.69 percent ($23,483,182) as of
December 31, 1993.

Note 13. Commitments and Contingencies
A. Construction Program

Projected construction and nuclear fuel costs, both including allowance
for funds used during construction, are $2.3 billion and $394 million,
respectively, for 1994 through 1996. The program is subject to periodic
review and revisions, and actual construction costs 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.

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 $9.4 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 $9.2 billion, which will be increased by $75.5
million as each additional commercial nuclear reactor is
36
<PAGE>

licensed, has been provided through a mandatory industry-wide excess
secondary insurance program of risk pooling. The $9.2 billion could also
be reduced by $75.5 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 $75.5 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 $75.5 million amount is subject to indexing for inflation. This amount
is further subject to a surcharge of 5 percent (which is included in the
above $9.4 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
$42 million. This amount represents 5 times the Company's annual premium
to NML.
The Company is also a member of Nuclear Electric Insurance Limited
(NEIL) and purchases $1.4 billion of insurance through NEIL's excess
property, decontamination and decommissioning liability insurance program.
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 $46 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 has also purchased an
additional $400 million of excess property damage insurance for its Oconee
and McGuire plants and $800 million for its Catawba plant through a pool
of stock and mutual insurance companies.
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 67 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 other joint owners of the Catawba Nuclear Station and the Company are
involved in various proceedings related to the Catawba joint ownership
contractual agreements. The basic contention in each proceeding is 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.) The Company and two of the four joint owners
have entered into a proposed settlement agreement which, if approved by
the regulators, will resolve all issues in contention in such proceedings
between the Company and these owners. The Company recorded a liability as
an increase to Other current liabilities on its Consolidated Balance
Sheets of approximately $105 million in 1993 to reflect this proposed
settlement. In addition, future estimated obligations in connection with
the settlement are reflected in estimates of purchased capacity
obligations in Note 3. As the Company expects the costs associated with
this settlement will be recovered as part of the purchased capacity
levelization, the Company has included approximately $105 million as an
increase to Purchased capacity costs on its Consolidated Balance Sheets.
Therefore, the Company believes the ultimate resolution of these matters
should not have a material adverse effect on the results of operations or
financial position of the Company.
Although the two other Catawba joint owners, who are not parties to the
above settlement, have not fully quantified the dollars associated with
their claims in the presently outstanding proceedings, information
associated with these proceedings indicates that the amount in contention
could be as high as $110 million through December 31, 1993. Arbitration
hearings were held in 1992 involving substantially all the disputed
amounts, and a decision interpreting the language of the agreements on
certain of these matters was issued on October 1, 1993. Further
proceedings will be required to determine the amounts associated with this
decision as it relates to these owners, some of which may involve refunds.
However, the Company expects the costs associated with this decision will
be included in and recovered as part of the purchased capacity
levelization consistent with prior orders of the retail regulatory
commissions. Therefore, the Company believes the ultimate resolution of
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. 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.
37
<PAGE>

Note 14. Other Income

For the years ended December 31, 1993, 1992 and 1991, the Company reported
carrying charges on purchased capacity levelization deferral related to
the joint ownership of the Catawba Nuclear Station of $32,180,000,
$28,820,000 and $28,765,000 (net of taxes), respectively, as components of
"Other, net" and "Income taxes - other, net"on the Consolidated Statements
of Income. (For additional information on purchased capacity levelization,
see Note 3.)
Also included in "Other, net" and "Income taxes - other, net" on the
Consolidated Statements of Income is income provided by diversified
activities and the Company's subsidiaries of $21,996,000, $25,728,000 and
$23,587,000 (net of taxes) for years ended December 31, 1993, 1992 and
1991, respectively. The activities of Crescent Resources, Inc., the
Company's real estate development and forest management subsidiary,
generated the majority of subsidiary and non-electric earnings. Other
components include subsidiary investment income, fees for engineering
services, construction and operation of generation and transmission
facilities outside the Company's current service area, water operations
and merchandising.
For the year ended December 31, 1991, the Company recorded a net of tax
carrying charge of $36,765,000 on costs incurred on the Bad Creek
Hydroelectric Station after commercial operation but prior to recovery of
costs through rates. This carrying charge is a component of "Other, net"
in the Consolidated Statements of Income.

Note 15. Reclassification

In the Consolidated Statements of Cash Flows, Consolidated Balance Sheets
and the Consolidated Statements of Capitalization, certain prior-year
information has been reclassified to conform with 1993 classifications.

Note 16. Nuclear Decommissioning Costs

Estimated site-specific nuclear decommissioning costs, including the cost
of decommissioning plant components not subject to radioactive
contamination, total approximately $955 million stated in 1990 dollars.
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
liable for providing decommissioning related to their ownership interests
in the station. Both the NCUC and the PSCSC have granted the Company
recovery of the estimated site-specific 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 Nuclear Regulatory Commission (NRC) 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 1993,
the Company expensed approximately $52.5 million which was contributed to
the external funds and accrued an additional $5.0 million to the internal
reserve. The balance of the external funds as of December 31, 1993, was
$118.5 million. The balance of the internal reserve as of December 31,
1993, was $200.0 million and is reflected in Accumulated depreciation and
amortization on the Consolidated Balance Sheets. Management's opinion is
that the estimated site-specific decommissioning costs being recovered
through rates, when coupled with assumed after-tax fund earnings of 4.5
percent to 5.5 percent, are currently sufficient to provide for the cost
of decommissioning based on the Company's current decommissioning
schedule.
38
<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 on page 22. Our audits also
included the consolidated financial statement schedules listed in the
accompanying index on page 22. These financial statements and consolidated
financial statement schedules are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
financial statements and consolidated financial statement schedules
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, 1993 and 1992, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1993 in
conformity with generally accepted accounting principles. Also, in our
opinion, such consolidated financial statement schedules, when considered
in relation to the basic consolidated financial statements taken as a
whole, present fairly in all material respects
the information set forth therein.

As discussed in Note 4 to the consolidated financial statements, in 1993,
the Company changed its method of accounting for income taxes to conform
with Statement of Financial Accounting Standards No. 109.

DELOITTE & TOUCHE
Deloitte & Touche
Charlotte, North Carolina
February 11, 1994

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. 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.

DAVID L. HAUSER
David L. Hauser
Controller

39
<PAGE>
SELECTED 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>
1993 by quarter
Electric Revenues........................................ $1,007,783 $987,218 $1,289,994 $996,881 $4,281,876
Electric Operating Income................................ 188,522 169,111 283,411 173,021 814,065
Net Income............................................... 141,684 122,470 241,409 120,852 626,415
Earnings Per Share....................................... $0.63 $0.53 $1.12 $0.52 $2.80
1992 by quarter
Electric Revenues........................................ $981,330 $899,319 $1,139,525 $941,310 $3,961,484
Electric Operating Income................................ 161,726 148,888 248,081 166,000 724,695
Net Income............................................... 106,365 86,938 190,519 124,261 508,083
Earnings Per Share....................................... $0.45 $0.36 $0.85 $0.55 $2.21
</TABLE>

Generally, quarterly earnings fluctuate with seasonal weather conditions, timing
of rate changes and maintenance of electric generating units, especially nuclear
units.
40
<PAGE>
SUBSIDIARY HIGHLIGHTS
The earnings contribution of the Company's diversified activities and
subsidiaries was $22.0 million in 1993, $25.7 million in 1992 and $23.6 million
in 1991. (a)(b) Highlights of selected subsidiaries are presented below.
(dollars in thousands)
ELECTRIC POWER SUPPLY
Nantahala Power and Light Company provides service to a five-county area in the
western North Carolina mountains by its operation of 11 hydroelectric stations
and purchases of supplemental power.
<TABLE>
<CAPTION>

1993 1992 1991
<S> <C> <C> <C>
Assets net of
liabilities................................ $ 47,679 $ 42,910 $ 39,384
Net
income...... ............................. $ 4,261 $ 3,526 $ 2,721
Number of employees
(c).......................................... 194 191 194
</TABLE>

FUNDS MANAGEMENT
Church Street Capital Corp. (CSCC) manages investment of funds for the Company
and is the parent company of several subsidiaries. CSCC has no full-time
employees.
<TABLE>
<CAPTION>

1993 1992 1991
<S> <C> <C> <C>
Short-term investments and marketable
securities............................... $ 155,871 $ 173,347 $ 120,303
Investment income (after tax)............... $ 3,548 $ 5,404 $ 6,397
</TABLE>

Highlights of CSCC's subsidiaries are presented below:
REAL ESTATE MANAGEMENT, LAND DEVELOPMENT
Crescent Resources, Inc. is engaged in forest management, real estate
development, and sales and leasing.
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Asset net of
liabilities................................ $133,034 $ 110,949 $ 88,046
Net income (a)............................... $ 16,327 $ 16,613 $ 9,661
Number of employees (c)...................... 77 73 69
</TABLE>

ENGINEERING, CONSTRUCTION, TECHNICAL SERVICES AND POWER DEVELOPMENT
Engineering, construction, technical services and power development
opportunities are pursued nationally and internationally.
Duke Engineering & Services, Inc. markets engineering, construction, quality
assurance, consulting and other engineering-related services for utility
facilities other than coal-fired plants.
Duke/Fluor Daniel, a joint venture with Fluor Daniel, Inc., provides design,
construction, operation and maintenance support primarily for coal-fired
generating plants.
Duke Energy Group, parent of Duke Energy Corp., structures, finances and
manages investments in electric generation and transmission facilities.
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Assets net of
liabilities.................................. $127,708 $ 36,687 $ 13,480
Net
income....................................... $ 40 $ 33 $ 1,512
Number of employees (c)....................... 518 495 364
</TABLE>

(a) 1991 EXCLUDES THE CUMULATIVE EFFECT OF AN ACCOUNTING CHANGE OF $6,727,000,
AFTER TAX.
(b) THE EARNINGS CONTRIBUTION OF THE COMPANY'S SUBSIDIARIES AND NON-ELECTRIC
OPERATIONS INCLUDES ELIMINATION OF INTERCOMPANY PROFIT OF $509,000 AND
$1,211,000, AFTER TAX, IN 1993 AND 1992, RESPECTIVELY.
(c) FULL-TIME EMPLOYEES.
41

<PAGE>
DUKE POWER COMPANY
SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
BALANCE BALANCE
BEGINNING ADD END
DESCRIPTION OF YEAR ADDITIONS RETIREMENTS (DEDUCT) OF YEAR
<S> <C> <C> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1993
Electric Plant in Service -- At Original Cost
Production.................................... $ 6,407,161 $ 166,112 $ 66,413 $ 13,903 $ 6,520,763
Transmission.................................. 1,331,668 48,836 8,684 (3,696) 1,368,124
Distribution.................................. 3,519,235 246,482 51,188 3,133 3,717,662
General....................................... 871,711 65,411 19,561 (1,461) 916,100
Miscellaneous................................. 64,113 (925) 24 (12,801) 50,363
Nuclear Fuel.................................. 718,420 158,796 171,222 -- 705,994
Total electric plant in service............. 12,912,308 684,712 317,092 (922) 13,279,006
Construction Work in Progress................... 490,408 (7,935) -- -- 482,473
Other Property -- At Cost
Water plant................................... 35,655 1,554 68 -- 37,141
Transit plant................................. -- -- -- -- --
Total other property........................ 35,655 1,554 68 -- 37,141
Total plant............................... $13,438,371 $ 678,331 $ 317,160 $ (922) $13,798,620
FOR THE YEAR ENDED DECEMBER 31, 1992
Electric Plant in Service -- At Original
Cost
Production.................................... $ 6,228,232 $ 121,364 $ 2,521 $ 60,086 $ 6,407,161
Transmission.................................. 1,300,021 34,235 2,114 (474) 1,331,668
Distribution.................................. 3,335,893 236,777 53,227 (208) 3,519,235
General....................................... 894,685 53,114 25,046 (51,042) 871,711
Miscellaneous................................. 71,380 221 174 (7,314) 64,113
Nuclear Fuel.................................. 2,004,441 264,506 1,448,742 (101,785) 718,420
Total electric plant in service............. 13,834,652 710,217 1,531,824 (100,737) 12,912,308
Construction Work in Progress................... 501,942 (11,534) -- -- 490,408
Other Property -- At Cost
Water plant................................... 35,009 830 227 43 35,655
Transit plant................................. 1,499 -- 1,499 -- --
Total other property........................ 36,508 830 1,726 43 35,655
Total plant............................... $14,373,102 $ 699,513 $1,533,550 $(100,694) $13,438,371
FOR THE YEAR ENDED DECEMBER 31, 1991
Electric Plant in Service -- At Original
Cost
Production.................................... $ 4,965,205 $ 1,229,905 $ 7,356 $ 40,478 $ 6,228,232
Transmission.................................. 1,223,152 80,809 2,627 (1,313) 1,300,021
Distribution.................................. 3,079,886 283,097 27,681 591 3,335,893
General....................................... 844,706 98,575 47,163 (1,433) 894,685
Miscellaneous................................. 111,972 (2,229) 201 (38,162) 71,380
Nuclear Fuel.................................. 1,870,975 133,466 -- -- 2,004,441
Total electric plant in service............. 12,095,896 1,823,623 85,028 161 13,834,652
Construction Work in Progress................... 1,521,391 (1,019,449) -- -- 501,942
Other Property -- At Cost
Water plant................................... 33,886 1,312 189 -- 35,009
Transit plant................................. 2,782 -- 1,283 -- 1,499
Total other property........................ 36,668 1,312 1,472 -- 36,508
Total plant............................... $13,653,955 $ 805,486 $ 86,500 $ 161 $14,373,102
</TABLE>

<PAGE>
DUKE POWER COMPANY
SCHEDULE VI -- ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY,
PLANT AND EQUIPMENT
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
CLEARING OTHER
BALANCE AND CHANGES BALANCE
BEGINNING OTHER ADD END OF
DESCRIPTION OF YEAR DEPRECIATION ACCOUNTS RETIREMENTS (DEDUCT) YEAR
<S> <C> <C> <C> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1993
Accumulated Depreciation of Electric Plant
Production.................................. $2,328,319 $232,937 $ -- $ 72,453 $(49,675) $2,439,128
Transmission................................ 561,068 33,527 -- 6,703 3,843 591,735
Distribution................................ 1,053,408 129,665 -- 47,387 (4,097 ) 1,131,589
General..................................... 242,694 25,375 4,830 14,194 (2,595 ) 256,110
Miscellaneous............................... 5,537 -- 359 -- -- 5,896
4,191,026 421,504 5,189 140,737 (52,524 ) 4,424,458
Accumulated Amortization of Limited Term
Plant....................................... 6,479 -- 511 (11 ) -- 7,001
Accumulated Amortization of Nuclear Fuel...... 425,088 -- 152,045 171,222 -- 405,911
4,622,593 421,504 157,745 311,948 (52,524 ) 4,837,370
Accumulated Depreciation of Water Plant....... 8,586 710 -- 63 -- 9,233
Total Accumulated Depreciation............ $4,631,179 $422,214 $157,745 $ 312,011 $(52,524) $4,846,603
FOR THE YEAR ENDED DECEMBER 31, 1992
Accumulated Depreciation of Electric Plant
Production.................................. $2,119,391 $226,137 $ -- $ 11,572 $(5,637 ) $2,328,319
Transmission................................ 531,332 33,213 -- 3,208 (269 ) 561,068
Distribution................................ 979,805 122,311 -- 49,127 419 1,053,408
General..................................... 229,400 26,612 4,758 18,929 853 242,694
Miscellaneous............................... 49,850 -- 357 -- (44,670 ) 5,537
3,909,778 408,273 5,115 82,836 (49,304 ) 4,191,026
Accumulated Amortization of Limited Term
Plant....................................... 5,983 -- 687 4 (187 ) 6,479
Accumulated Amortization of Nuclear Fuel...... 1,722,192 -- 151,638 1,448,742 -- 425,088
5,637,953 408,273 157,440 1,531,582 (49,491 ) 4,622,593
Accumulated Depreciation of Water Plant....... 8,094 691 -- 221 22 8,586
Accumulated Depreciation of Transit Plant..... 1,420 2 -- 1,449 27 --
Total Accumulated Depreciation.............. $5,647,467 $408,966 $157,440 $1,533,252 $(49,442) $4,631,179
FOR THE YEAR ENDED DECEMBER 31, 1991
Accumulated Depreciation of Electric Plant
Production.................................. $1,902,284 $198,372 $ -- $ 13,054 $31,789 $2,119,391
Transmission................................ 500,555 34,589 -- 2,901 (911 ) 531,332
Distribution................................ 896,226 109,461 -- 26,787 905 979,805
General..................................... 221,691 30,920 13,393 35,269 (1,335 ) 229,400
Miscellaneous............................... 88,258 -- 352 -- (38,760 ) 49,850
3,609,014 373,342 13,745 78,011 (8,312 ) 3,909,778
Accumulated Amortization of Limited Term
Plant....................................... 5,108 -- 497 -- 378 5,983
Accumulated Amortization of Nuclear Fuel...... 1,552,977 -- 169,215 -- -- 1,722,192
5,167,099 373,342 183,457 78,011 (7,934 ) 5,637,953
Accumulated Depreciation of Water Plant....... 7,578 682 -- 166 -- 8,094
Accumulated Depreciation of Transit Plant..... 2,662 41 -- 1,283 -- 1,420
Total Accumulated Depreciation.............. $5,177,339 $374,065 $183,457 $ 79,460 $(7,934 ) $5,647,467
</TABLE>

<PAGE>
DUKE POWER COMPANY
SCHEDULE VIII -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
BALANCE BALANCE
BEGINNING END OF
DESCRIPTION OF YEAR YEAR
<S> <C> <C>
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
FOR THE YEAR ENDED DECEMBER 31, 1992
Reserves Related to Assets on Balance Sheet............................................... $25,592 $ 10,730
Other Reserves
Operating Reserves (1)............................................................... $67,577 $ 78,103
FOR THE YEAR ENDED DECEMBER 31, 1991
Reserves Related to Assets on Balance Sheet............................................... $43,712 $ 25,592
Other Reserves
Operating Reserves (1)............................................................... $59,527 $ 67,577
</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.
SCHEDULE X -- SUPPLEMENTARY CONSOLIDATED INCOME STATEMENT INFORMATION
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
<S> <C> <C> <C>
1993 1992 1991
<CAPTION>
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Taxes, other than payroll and income taxes
Real and personal property................................................. $ 88,725 $ 82,327 $ 68,117
State and city franchise................................................... 91,494 84,033 89,307
Other...................................................................... 11,669 11,663 12,531
Total................................................................. $191,888 $178,023 $169,955
</TABLE>

<PAGE>
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" and "Information Regarding the
Board of Directors" in the proxy statement of the Company relating to its 1994
annual meeting of shareholders, which is being incorporated herein by reference.
Information concerning the executive officers of the Company is set forth
under 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 1994 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 sections entitled "Voting
Securities Outstanding" and "Election of Directors" in the proxy statement of
the Company relating to its 1994 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 section entitled "Election of
Directors" in the proxy statement of the Company relating to its 1994 annual
meeting of shareholders, which is 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
Consolidated Financial Statement Schedules included in Part II of this annual
report are as follows:
<TABLE>
<S> <C>
Consolidated Financial Statements
Consolidated Statements of Income for the Three Years Ended December 31, 1993
Consolidated Statements of Cash Flows for the Three Years Ended December 31, 1993
Consolidated Balance Sheets -- December 31, 1993 and 1992
Consolidated Statements of Capitalization -- December 31, 1993 & 1992
Consolidated Statements of Retained Earnings for the Three Years
Ended December 31, 1993
Notes to Consolidated Financial Statements
Selected Quarterly Financial Data (Unaudited)
Consolidated Financial Statement Schedules
Schedule V -- Property, Plant and Equipment for the Three Years Ended
December 31, 1993
Schedule VI -- Accumulated Depreciation and Amortization of Property,
Plant and Equipment for the Three Years Ended December 31, 1993
Schedule VIII -- Valuation and Qualifying Accounts and Reserves
for the Three Years Ended December 31, 1993
Schedule X -- Supplementary Consolidated Income Statement Information
for the Three Years Ended December 31, 1993
</TABLE>

<PAGE>
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 1993.
(c) Exhibits -- See Exhibit Index on page 48.
46

<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 29TH DAY OF MARCH, 1994.
DUKE POWER COMPANY
(REGISTRANT)
By: W. S. LEE
CHAIRMAN OF THE BOARD AND PRESIDENT
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
<C> <C> <S>
W. S. LEE Chairman of the
Board and President
(Principal Executive
Officer) March 29, 1994
RICHARD J. OSBORNE Vice President and Chief
Financial Officer (Principal
Financial Officer) March 29, 1994
DAVID L. HAUSER Controller (Principal
Accounting Officer) March 29, 1994
ROBERT L. ALBRIGHT
G. ALEX BERNHARDT
CRANDALL C. BOWLES
W. A. COLEY
JOE T. FORD
STEVE C. GRIFFITH, JR.
W. H. GRIGG
PAUL H. HENSON
GEORGE R. HERBERT A Majority of the Directors March 29, 1994
JAMES V. JOHNSON
W. W. JOHNSON
W. S. LEE
MAX LENNON
BUCK MICKEL
REECE A. OVERCASH, JR.
R. B. PRIORY
</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
47

<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 (filed with Form S-3, No. 33-50584, effective August
11, 1992, as Exhibit 3(g)).
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-3 -- Supplemental Indenture, dated as of July 1, 1935, supplementing said Mortgage (filed with
Form S-1, File No. 2-7224, effective October 15, 1947, as Exhibit 7(c)).
4-B-4 -- Supplemental Indenture, dated as of December 1, 1935, supplementing said Mortgage (filed
with Form S-1, File No. 2-7224, effective October 15, 1947, as Exhibit 7(d)).
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-12 -- Supplemental Indenture, dated as of April 1, 1951 supplementing said Mortgage (filed with
Form S-1, File No. 2-8877, effective April 6, 1951, as Exhibit 7(l)).
4-B-13 -- Supplemental Indenture, dated as of September 1, 1953 supplementing said Mortgage (filed
with Form S-1, File No. 2-10401, effective August 21, 1953, as Exhibit 4-B-13).
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-15 -- Supplemental Indenture, dated as of January 1, 1955 supplementing said Mortgage (filed
with Form S-9, File No. 2-11297, effective December 30, 1954, as Exhibit
2-B-15).
4-B-16 -- Supplemental Indenture, dated as of May 1, 1956 supplementing said Mortgage (filed with
Form S-9, File No. 2-12402 effective April 26, 1956, as Exhibit 2-B-16).
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-19 -- Supplemental Indenture, dated as of February 1, 1962 supplementing said Mortgage (filed
with Form S-9, File No. 2-20577, effective August 16, 1962, as Exhibit 2-B-20).
4-B-20 -- Supplemental Indenture, dated as of August 1, 1962 supplementing said Mortgage (filed
with Form S-1, File No. 2-25367, effective August 23, 1966, as Exhibit 4-B-19).
</TABLE>
48

<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NUMBER
<S> <C> <C>
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-22 -- Supplemental Indenture, dated as of February 1, 1965, supplementing said Mortgage (filed
with Form S-1, File No. 2-25367, effective August 23, 1966, as Exhibit 4-B-21).
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-25 -- Supplemental Indenture, dated as of February 1, 1969, supplementing said Mortgage (filed
with Form S-7, File No. 2-34289, effective August 27, 1969, as Exhibit 2-B-27).
4-B-26 -- Supplemental Indenture, dated as of September 1, 1969, supplementing said Mortgage (filed
with Form S-7, File No. 2-36095, effective February 16, 1970, as Exhibit
2-B-39).
4-B-27 -- Supplemental Indenture, dated as of March 1, 1970, supplementing said Mortgage (filed
with Form S-7, File No. 2-37953, effective July 28, 1970, as Exhibit 2-B-42).
4-B-28 -- Supplemental Indenture, dated as of August 1, 1970, supplementing said Mortgage (filed
with Form S-7, File No. 2-39451, effective March 4, 1971, as Exhibit 2-B-28).
4-B-29 -- Supplemental Indenture, dated as of March 1, 1971, supplementing said Mortgage (filed
with Form S-7, File No. 2-42404, effective December 7, 1971, as Exhibit
2-B-29).
4-B-30 -- Supplemental Indenture, dated as of December 1, 1971, supplementing said Mortgage (filed
with Form S-7, File No. 2-43122, effective March 7, 1972, as Exhibit 2-B-30).
4-B-31 -- Supplemental Indenture, dated as of April 1, 1972, supplementing said Mortgage (filed
with Form S-7 File No. 2-46208, effective November 20, 1972, as Exhibit 2-B-31).
4-B-32 -- Supplemental Indenture, dated as of December 1, 1972, supplementing said Mortgage (filed
with Form S-7, File No. 2-48058, effective June 5, 1973, as Exhibit 2-B-32).
4-B-33 -- Supplemental Indenture, dated as of June 1, 1973, supplementing said Mortgage (filed with
Form S-7, File No. 2-49333, effective November 5, 1973, as Exhibit 2-B-33).
4-B-34 -- Supplemental Indenture, dated as of November 1, 1973, supplementing said Mortgage (filed
with Form S-7, File No. 2-50493, effective April 25, 1974, as Exhibit 2-B-34).
4-B-35 -- Supplemental Indenture, dated as of May 1, 1974, supplementing said Mortgage (filed with
Form S-7, File No. 2-52669, effective February 11, 1975, as Exhibit 2-B-35).
4-B-36 -- Supplemental Indenture, dated as of February 1, 1975, supplementing said Mortgage (filed
with Form S-7, File No. 2-57118, effective October 5, 1976, as Exhibit 2-B-36).
4-B-37 -- Supplemental Indenture, dated as of July 1, 1975, supplementing said Mortgage (filed with
Form S-7, File No. 2-57118, effective October 5, 1976, as Exhibit 2-B-37).
4-B-38 -- Supplemental Indenture, dated as of October 1, 1976, supplementing said Mortgage (filed
with Form S-7, File No. 2-59494, effective August 10, 1977, as Exhibit 2-B-38).
4-B-39 -- Supplemental Indenture, dated as of Sepember 1, 1977, supplementing said Mortgage (filed
with Form S-7, File No. 2-61995, effective July 26, 1978, as Exhibit 2-B-39).
4-B-40 -- Supplemental Indenture, dated as of August 1, 1978, supplementing said Mortgage (filed
with Form S-7, File No. 2-64541, effective June 7, 1979, as Exhibit 2-B-40).
4-B-41 -- Supplemental Indenture, dated as of June 1, 1979, supplementing said Mortgage (filed with
Form S-7, File No. 2-65371, effective October 2, 1979, as Exhibit 2-B-41).
4-B-42 -- Supplemental Indenture, dated as of October 1, 1979, supplementing said Mortgage (filed
with Form S-7, File No. 2-66659, effective March 12, 1980, as Exhibit 2-B-42).
4-B-43 -- Supplemental Indenture, dated as of March 1, 1980, supplementing said Mortgage (filed
with Form S-16, File No.2-68571, effective August 19, 1980, as Exhibit 2-B-43).
4-B-44 -- Supplemental Indenture, dated as of August 1, 1980, supplementing said Mortgage (filed
with Form S-16, File No. 2-75951, effective February 23, 1982, as Exhibit
2-B-44).
4-B-45 -- Supplemental Indenture, dated as of March 1, 1982, supplementing said Mortgage (filed
with Form S-16, File No. 2-75951, effective February 23, 1982, as Exhibit
2-B-45).
4-B-46 -- Supplemental Indenture, dated as of September 1, 1982, supplementing said Mortgage (filed
with Form S-3, File No. 2-78882, effective August 30, 1982, as Exhibit 4-B-46).
</TABLE>
49

<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NUMBER
<S> <C> <C>
4-B-47 -- Supplemental Indenture, dated as of May 1, 1983, supplementing said Mortgage (filed with
Form S-3, File No. 2-95931, effective April 1, 1985, as Exhibit 4-B-47).
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-50 -- Supplemental Indenture, dated as of March 1, 1985, supplementing said Mortgage (filed
with Form S-3, File No. 2-95931, effective April 1, 1985, as Exhibit 4-B-50).
4-B-51 -- Supplemental Indenture, dated as of December 1, 1985, supplementing said Mortgage (filed
with Form S-3, File No. 33-5163, effective May 2, 1986, as Exhibit 4-B-51).
4-B-52 -- Supplemental Indenture, dated as of April 1, 1986, supplementing said Mortgage (filed
with Form S-3, File No. 33-5163, effective May 2, 1986, as Exhibit 4-B-52).
4-B-53 -- Supplemental Indenture, dated as of May 1, 1986, supplementing said Mortgage (filed with
Form 10-K for the year ended December 31, 1986, File No. 1-4928, as Exhibit
4-B-53).
4-B-54 -- Supplemental Indenture, dated as of June 1, 1986, supplementing said Mortgage (filed with
Form 10-K for the year ended December 31, 1986, File No. 1-4928, as Exhibit
4-B-54).
4-B-55 -- Supplemental Indenture, dated as of February 1, 1987, supplementing said Mortgage (filed
with Form 10-K for the year ended December 31, 1986, File No. 1-4928, as Exhibit 4-B-55).
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-57 -- Supplemental Indenture, dated as of March 1, 1987, supplementing said Mortgage (filed
with Form 10-K for the year ended December 31, 1986, File No. 1-4928, as Exhibit 4-B-57).
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-59 -- Supplemental Indenture, dated as of February 1, 1990, supplementing said Mortgage (filed
with Form 10-K for the year ended December 31, 1989, File No. 1-4928, as Exhibit 4-B-59).
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-61 -- Supplemental Indenture, dated as of May 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-61).
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).
</TABLE>
50

<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NUMBER
<S> <C> <C>
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).
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(dagger) -- Employees' Stock Ownership Plan.
*10-F -- Employee Incentive Plan.
*10-G -- 1993 Executive Long-Term Incentive Plan.
10-H(dagger) -- Supplemental Security Plan.
10-I(dagger) -- Stock Purchase-Savings Program for Employees.
10-J(dagger) -- Employees' Retirement Plan.
10-K(dagger) -- Supplemental Retirement Plan.
10-L(dagger) -- Compensation Deferral Plan.
10-M(dagger) -- Compensation Deferral Plan for Outside Directors.
10-N(dagger) -- Retirement Plan for Outside Directors.
10-O(dagger) -- Supplementary Defined Contribution Plan for Employees.
10-P(dagger) -- Directors' Charitable Giving Program.
10-Q(dagger) -- Vacation Banking Plan.
10-R(dagger) -- Estate Conservation Plan.
10-S(dagger) -- Supplemental Insurance Plan.
10-T(dagger) -- Group Life Insurance Plan.
10-U(dagger) -- Stock Ownership Plan for Nonemployee Directors.
* 11 -- Computation of Fully Diluted Earnings Per Share (Unaudited).
* 12 -- Compution of Ratio of Earnings to Fixed Charges.
* 23 -- Consent of Independent Auditors.
</TABLE>
51

<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NUMBER
<S> <C> <C>
* 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.
</TABLE>

(dagger) Compensatory plan or arrangement required to be filed as an exhibit,
and filed with Form 10-K for the year ended December 31, 1992, File No.
1-4928, under the same exhibit number as listed herein.
52

<PAGE>
1993 Employee Incentive Plan Summary

Annual Incentive Plan

Financial threshold which must be achieved for awards to be paid
Return on Equity

Eligibility: All regular full- and part-time Duke Power employees
who have been working at least 90 days.
Measures: ROE
Unit objectives

Award Opportunity as a percentage of salary:

Minimum Target Maximum
Points for Achievement of Unit 1.0 2.0 3.6
Objectives
X

ROE Multiplier .8 1.0 1.2

Total Award Opportunity .8% 2.0% 4.32%

Paid out in cash.

Incentive awards are not included in benefits calculations.

<PAGE>

1993 EXECUTIVE LONG-TERM INCENTIVE PLAN

(bullet) Three-year performance plan with three performance measures
(bullet) Return on Equity
(bullet) Total Electric Operation and Maintenance Cost Per
Kilowatt Hour Delivered
(bullet) Capital Expenditures Per Customers Equivalent

(bullet) Financial threshold which must be achieved for awards to be paid
(bullet) Return on Equity

(bullet) Plan covers approximately 100 senior managers

(bullet) Awards to be phased in over 3-year period (2nd year of phase-in)
(bullet) Annual performance periods during phase in

(bullet) Eligible percentage of base salary at target performance level
(bullet) Chief Executive Officer: 23%
(bullet) Management Committee: 20%
(bullet) Officer Team: 17%
(bullet) Management Council Group 2: 7%

(bullet) Payouts and Deferrals
(bullet) 50% of awards distributable in cash
(bullet) can receive as cash at end of performance period
(bullet) can specify the end of deferral period
(bullet) can defer until retirement or termination
(bullet) 50% of award subject to mandatory deferral as performance
units
(bullet) can receive as cash at end of 3-year mandatory
deferral period
(bullet) can defer as performance units until retirement or
termination

(bullet) Performance units adjustable for change in stock price and dividends

(bullet) Irrevocable elections are made prior to beginning of performance period

(bullet) Incentive awards are not included in benefits calculations

<PAGE>
EXHIBIT 11
DUKE POWER COMPANY
COMPUTATION OF FULLY DILUTED EARNINGS PER SHARE -- (UNAUDITED)
This calculation is submitted in accordance with Regulation S-K under the
Securities Exchange Act of 1934, although not required by footnote 2 to
paragraph 14 of Opinion No. 15 of the Accounting Principles Board because it
results in dilution of less than 3%.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
<S> <C> <C> <C>
1993 1992 1991
<CAPTION>
(DOLLARS IN THOUSANDS EXCEPT PER
SHARE FIGURES)
<S> <C> <C> <C>
Fully Diluted:
Earnings applicable to common stock (1)................................. $573,986 $451,676 $528,940
Add: Dividends on Preference Stock, 6 3/4% Convertible Series AA........ -- -- 140
Earnings as adjusted for computation...................................... $573,986 $451,676 $529,080
Average common shares outstanding -- twelve months (thousands)(1)....... 204,859 204,819 203,431
Add: Common shares required for conversion of Preference Stock, 6 3/4%
Convertible Series AA, $100 par, 500,000 shares authorized (no shares
outstanding as of December 31, 1992 & 1993)(2)....................... -- -- 169
Common shares as adjusted for computation (thousands)..................... 204,859 204,819 203,600
Fully diluted earnings per share........................................ $ 2.80 $ 2.21 $ 2.60
</TABLE>

(1) These figures agree with the related amounts in the Consolidated Statements
of Income.
(2) All shares were converted in April 1992. The conversion price used to
convert the Preference Stock, 6 3/4% Convertible Series AA, into shares of
common stock was $11.95.

EXHIBIT 12
DUKE POWER COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
<S> <C> <C> <C> <C> <C>
1993 1992 1991 1990 1989
Earnings Before Income Taxes.................... $1,037,096 $ 811,401 $ 879,766 $ 790,546 $ 867,641
Fixed Charges................................... 281,821 327,308 308,862 297,116 266,497
Total....................................... $1,318,917 $1,138,709 $1,188,628 $1,087,662 $1,134,138
Fixed Charges
Interest on long-term debt.................... 243,047 257,149 269,419 255,334 232,510
Other interest................................ 18,098 47,972 22,780 24,306 18,203
Amortization of debt discount, premium and
expense..................................... 13,300 8,497 5,242 4,998 4,677
Interest component of rentals................. 7,376 13,690 11,421 12,478 11,107
Fixed Charges............................... $ 281,821 $ 327,308 $ 308,862 $ 297,116 $ 266,497
Ratio of Earnings to Fixed Charges............ 4.68 3.48 3.85 3.66 4.26
</TABLE>
<PAGE>

<PAGE>
EXHIBIT 23
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in Registration Statement Nos.
33-59926, 33-60314, 33-19274, 33-50543, 33-50715, 33-50617 and 33-52479 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 11, 1994, appearing in this
Form 10-K of Duke Power Company for the year ended December 31, 1993.
DELOITTE & TOUCHE
DELOITTE & TOUCHE
Charlotte, North Carolina
March 29, 1994
<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, 1993

(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. S. Lee, Richard J. Osborne, Ellen T. Ruff, David L. Hauser, 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 22nd day of February, 1994.

DUKE POWER COMPANY

By W.S. Lee
-----------------------------
Chairman and President

(Corporate Seal)

ATTEST:

Carolyn R. Duncan
- - --------------------------
Assistant Secretary

<PAGE>

W.S. Lee Chairman and President (Principal
- - -------------------------- Executive Officer and Director)
W.S. Lee

Richard J. Osborne Vice President and Chief Financial
- - -------------------------- Officer (Principal Financial Officer)
Richard J. Osborne

David L. Hauser Controller (Principal Accounting
- - -------------------------- Officer)
David L. Hauser

Robert L. Albright (Director)
- - --------------------------
Robert L. Albright

G. Alex Bernhardt (Director)
- - --------------------------
G. Alex Bernhardt

Crandall C. Bowles (Director)
- - --------------------------
Crandall C. Bowles

William A. Coley (Director)
- - --------------------------
William A. Coley

Joe T. Ford (Director)
- - --------------------------
Joe T. Ford

Steve C. Griffith, Jr. (Director)
- - --------------------------
Steve C. Griffith, Jr.

W.H. Grigg (Director)
- - --------------------------
W.H. Grigg

Paul H. Henson (Director)
- - --------------------------
Paul H. Henson

George R. Herbert (Director)
- - --------------------------
George R. Herbert

- - -------------------------- (Director)
George Dean Johnson, Jr.

James V. Johnson (Director)
- - --------------------------
James V. Johnson

W.W. Johnson (Director)
- - --------------------------
W.W. Johnson

Max Lennon (Director)
- - --------------------------
Max Lennon

Buck Mickel (Director)
- - --------------------------
Buck Mickel

Reece A. Overcash, Jr. (Director)
- - --------------------------
Reece A. Overcash, Jr.

Richard B. Priory (Director)
- - --------------------------
Richard B. Priory

EXHIBIT 24(b)

EXTRACT FROM THE MINUTES OF A MEETING
OF THE BOARD OF DIRECTORS OF DUKE POWER COMPANY
HELD ON FEBRUARY 22, 1994

Mr. Lee then referred to the Company's Form 10-K Annual
Report. 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. Herbert then advised that 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 foregoing is a full, true, and complete extract
from the minutes of the meeting of the Board of Directors of said
Company held on February 22, 1994, containing all resolutions
adopted with respect to the Form 10-K, at which meeting a quorum
was present.

IN WITNESS WHEREOF, I have hereunto set my hand and affixed
the corporate seal of said DUKE POWER COMPANY, this 29th day of
March, 1994.

Ellen T. Ruff
--------------------------
Secretary

{SEAL}

APPENDIX

On Page 12 there is a full-page map of the Duke Power Service Area, showing
the locations of the Company's region offices, steam electric stations,
hydroelectric stations, nuclear electric stations and Nantahala Power and
Light Company. Such page also includes a smaller inset map showing the Company's
service area, along with the service area of Nantahala Power and Light
Company, superimposed over an outline map of the states of North Carolina
and South Carolina.