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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, 1996 or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
[No Fee Required]
For the transition period from to
COMMISSION FILE NUMBER 1-4928
DUKE POWER COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
North Carolina 56-0205520
(STATE OR OTHER JURISDICTION OF INCORPORATION OR
ORGANIZATION) (I.R.S. EMPLOYER IDENTIFICATION NO.)
422 South Church Street, Charlotte, North Carolina 28242-0001
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
704-594-0887
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
Common Stock, without par value New York Stock Exchange, Inc.
Preferred Stock A, par value $25
7.72%, 1992 Series New York Stock Exchange, Inc.
6.375%, 1993 Series New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 5 3/8% Due 1997 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 5 7/8% Due 2001 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 5 7/8% Series C Due 2003 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 6 1/4% Series B Due 2004 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 6 3/8% Due 2008 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 6 5/8% Series B Due 2003 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 6 3/4% Due 2025 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 6 7/8% Series B Due 2023 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 7% Due 2000 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 7% Series B Due 2000 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 7% Due 2005 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 7% Due 2033 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 7 3/8% Due 2023 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 7 7/8% Due 2024 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 8% Series B Due 1999 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 8% Due 2004 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 8 3/8% Series B Due 2021 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 8 5/8% Due 2022 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 8 3/4% Due 2021 New York Stock Exchange, Inc.
First and Refunding Mortgage Bonds, 7 1/2% Series B Due 2025 New York Stock Exchange, Inc.
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]
Estimated aggregate market value of the voting stock held by nonaffiliates of the registrant at
February 28, 1997................................................................................... $8,436,965,632
Number of shares of Common Stock, without par value, outstanding at February 28, 1997................. 201,589,596
DOCUMENTS INCORPORATED BY REFERENCE:
The registrant is incorporating herein by reference certain sections of the
Joint Proxy Statement-Prospectus relating to the 1997 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
DUKE POWER COMPANY
FORM 10-K
ANNUAL REPORT TO
THE SECURITIES AND EXCHANGE COMMISSION
FOR THE YEAR ENDED DECEMBER 31, 1996
TABLE OF CONTENTS
ITEM PAGE
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
PART II.
5. Market for the Registrant's Common Equity and Related Stockholder Matters......................................... 16
6. Selected Financial Data........................................................................................... 17
7. Management's Discussion and Analysis of Results of Operations and Financial Condition............................. 18
8. Financial Statements and Supplementary Data....................................................................... 27
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.............................. 55
PART III.
10. Directors and Executive Officers of the Registrant................................................................ 55
11. Executive Compensation............................................................................................ 55
12. Security Ownership of Certain Beneficial Owners and Management.................................................... 55
13. Certain Relationships and Related Transactions.................................................................... 55
PART IV.
14. Exhibits, Consolidated Financial Statement Schedules, and Reports on Form 8-K..................................... 56
Signatures........................................................................................................ 57
Exhibit Index..................................................................................................... 58
"SAFE HARBOR" STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF
1995:
This report includes forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. Although the Company believes that
its expectations are based on reasonable assumptions, no assurance can be given
that actual results may not differ materially from those in the forward-looking
statements herein for reasons that include: state and federal legislative and
regulatory initiatives that increase competition, affect cost and investment
recovery and have an impact on rate structures; the impact of competition from
other energy suppliers; industrial, commercial and residential growth in the
Company's service territory; the results of financing efforts; the effect of the
Company's accounting policies; and growth in opportunities for the Company's
subsidiaries and diversified operations, in each case during the periods covered
by the foward-looking statements.
DUKE POWER COMPANY
PART I.
ITEM 1. BUSINESS.
Duke Power Company (the Company) is primarily engaged in the generation,
transmission, distribution and sale of electric energy in the central portion of
North Carolina and the western portion of South Carolina, comprising the area in
both states known as the Piedmont Carolinas. It is one of the nation's largest
investor-owned electric utilities.
The Company is also engaged in a variety of diversified operations, most of
which are organized in separate subsidiaries. The Company's subsidiaries and
diversified activities are in the Associated Enterprises Group (AEG). AEG
includes Church Street Capital Corp.; Crescent Resources, Inc.; Duke Energy
Group, Inc.; Duke Engineering & Services, Inc.; Duke/Fluor Daniel; Duke/Louis
Dreyfus, LLC; Duke Merchandising; DukeNet Communications, Inc.; Duke Water
Operations; and Nantahala Power and Light Company (NP&L). For additional
information on subsidiaries and diversified activities, see "Subsidiaries and
Diversified Activities," "Management's Discussion and Analysis of Results of
Operations and Financial Condition, Current Issues -- Subsidiaries and
Diversified Operations" and "Subsidiaries and Diversified Activities
Highlights."
On November 25, 1996, the Company and PanEnergy Corp announced a proposed
stock-for-stock transaction creating an integrated energy company. Upon
consummation of the merger, PanEnergy will be a wholly owned subsidiary of the
Company, and the Company's name will be changed to Duke Energy Corporation. The
transaction is expected to close by December 31, 1997, subject to approval of
the shareholders of both companies and all applicable regulatory approvals. The
shareholders of each company will vote on the proposed merger at their annual
meetings, which are scheduled for April 24, 1997 for both companies.
Applications for regulatory approval were filed with the North Carolina
Utilities Commission (NCUC) and The Public Service Commission of South Carolina
(PSCSC) on December 19, 1996, and with the Federal Energy Regulatory Commission
(FERC) on February 3, 1997. Regulatory proceedings are expected to be
successfully completed by year-end 1997. In connection with the transaction,
each share of PanEnergy common stock will be converted into 1.0444 shares of
common stock of the Company. The transaction will be accounted for as a pooling
of interests. Further details about the proposed acquisition are provided in the
Company's reports on Form 8-K, filed with the Securities and Exchange Commission
on December 9, 1996 and March 20, 1997, and in the Joint Proxy Statement-
Prospectus provided to shareholders in connection with the Company's annual
meeting. Unless otherwise indicated, all information presented in this Form
10-K relates to the Company only and does not take into account the proposed
merger with PanEnergy.
During 1996, the Company's operating revenues, including AEG, were $4.8
billion. The Company's executive offices are located in the Power Building, 422
South Church Street, Charlotte, North Carolina 28242-0001 (Telephone No.
704-594-0887).
SERVICE AREA
The Company's service area (excluding NP&L), approximately two-thirds of
which lies in North Carolina, covers about 20,000 square miles with an estimated
population of 5.1 million and includes a number of cities, of which the largest
are Charlotte, Greensboro, Winston-Salem and Durham in North Carolina and
Greenville and Spartanburg in South Carolina. The Company supplies electric
service directly to approximately 1.8 million residential, commercial and
industrial customers in more than 200 cities, towns and unincorporated
communities. Electricity is sold at wholesale to incorporated municipalities and
to several public and private utilities. In addition, sales are made through
contractual agreements to former wholesale municipal or cooperative customers of
the Company who had purchased portions of the Catawba Nuclear Station
(collectively, the "other Catawba joint owners") (See "Joint Ownership of
Generating Facilities"). NP&L services an additional 55,000 mostly residential
customers in five counties in western North Carolina.
The Company's service area is undergoing increasingly diversified
industrial development. The textile industry, machinery and equipment
manufacturing, and chemical and chemical-related industries are of major
significance to the economy of the area. Other industrial activities include
rubber and plastic products, paper and allied products, and various other light
and heavy manufacturing and service businesses. The largest industry served is
the textile industry, which accounted for approximately $459 million of the
Company's revenues for 1996, representing 10 percent of electric revenues and 37
percent of industrial revenues.
1
ENERGY REQUIREMENTS AND CAPABILITY
The following table sets forth the Company's generating capability as of
December 31, 1996, its sources of electric energy for 1996 and certain
information presently projected for 1997:
GENERATING CAPABILITY -- GENERATION -- MWH
MW(A)(B)(C) (THOUSANDS)(C)
ACTUAL PROJECTED ACTUAL
SOURCE DECEMBER 31, 1996 DECEMBER 31, 1997 1996
Coal........................................................... 7,699 7,699 40,649
Nuclear (d).................................................... 5,078 5,078 33,177
Hydro and other................................................ 4,469 4,469 1,518
Total..................................................... 17,246 17,246 75,344
Plus: Purchases from other Catawba joint owners................ 2,662
Purchased power and net interchange............................ 3,587
Total..................................................... 81,593
(a) The data relating to capability does not reflect the possible unavailability
or reduction of capability of facilities at any given time because of
scheduled maintenance, repair requirements or regulatory restrictions.
(b) Excludes firm purchases and sales. (See "Energy Management and Future Power
Needs.")
(c) Excludes NP&L.
(d) Nuclear capability and related generation for 1996 and related projections
for 1997 reflect the Company's 12.5% ownership share of the Catawba Nuclear
Station. (See "Joint Ownership of Generating Facilities.")
NP&L operates 11 hydroelectric stations with a total capacity of 100
megawatts and also purchases supplemental power. The Company supplies
supplemental power to NP&L under the terms of an interconnection agreement
approved by FERC.
The Company has a bulk power sales agreement with Carolina Power & Light
Company (CP&L) to provide CP&L 400 megawatts of capacity as well as associated
energy when needed for a six-year period which began July 1, 1993. Electric
rates in all regulatory jurisdictions were reduced by adjustment riders to
reflect capacity revenues received from this CP&L bulk power agreement.
The Company's steam-fossil generating system continued its tradition of
operating efficiently and achieved a combined availability of 86 percent for
1996. The Company's nuclear system operated at 74 percent of capacity for 1996,
which reflects the impact of the steam generator replacement outage at the
Catawba Nuclear Station (See "Regulation -- Nuclear Facilities") and the removal
from service of the Oconee Nuclear Station in October 1996 for inspection and
modification of the piping system after a steam line on the non-nuclear side of
the plant ruptured. Oconee Units 1, 2, and 3 returned to service in 1997 on
February 12, February 3, and March 14, respectively. The Company's system
nuclear capacity factor reflects the Company's 12.5% ownership share of the
Catawba Nuclear Station.
The Company normally experiences seasonal peak loads in summer and winter
which are relatively in balance. The Company currently forecasts a 1.8 percent
compound annual growth in peak load through 2011. The Company experienced an
all-time peak load of 15,542 MW on August 14, 1995 during exceptionally warm
summer weather. This peak load excludes the portion of the demand of the other
Catawba joint owners met by their retained ownership.
RATE MATTERS
The NCUC and the PSCSC must approve the Company's rates for retail sales
within their respective states. The FERC must approve the Company's rates for
sales to wholesale customers, including the contractual arrangements between the
Company and the other Catawba joint owners.
The most recent general rate increase requests in the Company's retail
jurisdictions were filed and approved in 1991. The Company also filed its most
recent general rate increase request within the FERC wholesale jurisdiction in
1991. A negotiated settlement between the Company and the wholesale customers
was approved by the FERC in 1992.
In its most recent general rate case, the NCUC authorized a jurisdictional
rate of return on common equity of 12.50 percent, and the PSCSC authorized a
jurisdictional rate of return on common equity of 12.25 percent.
2
The PSCSC, on May 7, 1996, ordered a rate reduction in the form of a
decrement rider of 0.432 cents per kilowatt-hour, or an average of approximately
8 percent, affecting South Carolina retail customers. South Carolina retail
sales represent approximately 30 percent of the Company's total retail sales.
The rate reduction was reflected on bills rendered on or after June 1, 1996.
This net decrement rider reflects an interim true-up decrement adjustment
associated with the levelization of Catawba Nuclear Station purchased capacity
costs and an interim true-up increment associated with amortization of the
demand-side management deferral account. The rate adjustment was made because,
in the South Carolina retail jurisdiction, cumulative levelized revenues
associated with the recovery of Catawba purchased capacity costs had exceeded
purchased capacity payments and accrual of deferred returns, and certain
demand-side costs had exceeded the level reflected in rates.
Certain of the Company's wholesale customers, excluding the other Catawba
joint owners, initiated proceedings in 1995 before the FERC concerning rate
matters. The Company and nine of its eleven wholesale customers entered into a
settlement in July 1996 which reduced the customers' rates by approximately 9
percent and renewed their contracts with the Company through the year 2000. Both
of the customers that did not enter into the settlement have signed agreements
to purchase energy from other suppliers beginning in 1997. The eleven wholesale
customers involved in this matter accounted for less than 2 percent of the
Company's overall electric revenues during 1996. The two customers that have
signed agreements with other suppliers accounted for less than 0.5 percent of
the Company's 1996 overall electric revenues.
During 1996, NP&L filed an application with and received approval from the
NCUC to increase its annual retail service revenues by $4.6 million.
FUEL AND PURCHASED POWER COST ADJUSTMENT PROCEDURES. Duke Power has
procedures in all three of its regulatory jurisdictions to adjust rates for
fluctuations in fuel expense. In the North Carolina retail jurisdiction, a
review of fuel costs in rates is required annually and during general rate case
proceedings. In 1996, the South Carolina General Assembly amended the Code of
Laws of South Carolina to provide for annual reviews of fuel costs. In the
wholesale jurisdiction, fuel costs are reviewed semiannually. All jurisdictions
allow Duke Power to adjust rates for past over- or under-recovery of fuel costs.
Therefore, Duke Power reflects in revenues the difference between actual fuel
costs incurred and fuel costs recovered through rates.
NP&L's wholesale rates are adjusted annually to reflect current costs.
Purchased power costs of NP&L are reviewed annually and during general rate case
proceedings by the NCUC. NP&L is allowed to adjust rates for past over- or
under-recovery of purchased power costs. Therefore, NP&L defers the difference
between actual purchased power costs incurred and those recovered through rates.
ENERGY MANAGEMENT AND FUTURE POWER NEEDS
The Company's strategy for meeting customers' present and future energy
needs consists of three components: supply-side resources, demand-side
resources, and purchased power resources. The Company uses a 20 percent planning
reserve margin as a baseline to meet contingencies such as forecast
uncertainties, unit outages, weather extremes, and historically long lead times
for new generation resources. With the increased flexibility from the purchased
power market offering short lead time resources and shortened lead times for new
generation construction, the Company expects to maintain an operating reserve
margin of approximately 17 percent of its anticipated peak load requirements
through 2001. The Company continues to engage in a comprehensive energy
management program as part of its Integrated Resource Plan (IRP). Integrated
resource planning is the process used by utilities to evaluate a variety of
resources. The goal is to provide adequate and reliable electricity in an
environmentally responsible manner through cost-effective power management. As
customers elect to procure generation from other suppliers, as two of the
Company's wholesale customers have indicated they will do beginning in 1997, the
Company will no longer be obligated to plan for the future generation needs of
those customers. The Company files an IRP with the NCUC and the PSCSC once every
three years. During each of the intervening years, the Company files a Short
Term Action Plan which updates the IRP for any changes in projections for the
next three years. The PSCSC issued an order on December 14, 1995 approving the
Company's 1995 IRP. On February 20, 1996, the NCUC issued a similar order.
Short-term action plans were filed with both the NCUC and the PSCSC in April
1996.
The Company has completed the construction of a combustion turbine facility
in Lincoln County, North Carolina, to provide capacity at periods of peak
demand. The station consists of sixteen combustion turbines with a total
generating capacity of 1,200 megawatts. During 1995, twelve units of the Lincoln
Combustion Turbine Station began commercial operation. The last four units began
commercial operation in the first quarter of 1996.
Demand-side management (DSM) programs benefit the Company and its customers
by providing cost-effective energy efficiency, providing for load control
through interruptible control features, shifting usage to off-peak periods and
increasing
3
strategic sales of electricity. The November 1991 rate orders of the NCUC and
the PSCSC provided for recovery in rates of a designated level of costs for DSM
programs and allowed the deferral for later recovery of certain DSM costs that
exceed the level reflected in rates, including a return on the deferred costs.
In 1993, the NCUC and the PSCSC issued orders approving "shared savings"
mechanisms for accomplishments achieved in the Company's DSM programs, and
deferral of such shared savings. The May 1996 rate rider in South Carolina
included an increment for DSM cost recovery. (See "Rate Matters.") The Company
ultimately expects recovery through rates of associated deferred costs, not to
exceed $75 million including deferred returns in the North Carolina retail
jurisdiction. The annual costs deferred, including the return, were
approximately $11 million in 1996 and $27 million in 1995. The total costs
deferred, including the return, are $67 million and $40 million in North
Carolina and South Carolina, respectively.
The purchase of capacity and energy is an integral part of meeting future
power needs. As of December 31, 1996, the Company had under contract 329 MW of
capacity from other generators of electricity, including 91 MW from qualifying
facilities. In 1995, the Company issued two requests for proposals (RFP) to
solicit both short-term and long-term competitive bids to provide future
electric generating capacity resources. After review of all bids, the Company
selected a short-term bid from PECO Energy Co. of Philadelphia. The agreement
gives the Company the option to purchase up to 250 megawatts of capacity during
the summer months of 1998 through 2001. Contract arrangements between the
parties were finalized on August 1, 1996. The long-term RFP was closed and no
bids were accepted.
CAPITAL REQUIREMENTS
Projected capital expenditures, excluding costs related to portions of the
Catawba Nuclear Station owned by the other Catawba joint owners, for the years
set forth below, as now scheduled, are as follows (in millions):
1997 1998 1999 2000 2001 TOTAL
Duke Power -- Electric
Generation............................................................. $223 $ 177 $185 $137 $ 142 $ 864
Transmission........................................................... 38 38 38 38 38 190
Distribution........................................................... 246 248 251 255 258 1,258
Other.................................................................. 66 59 67 66 58 316
Nuclear Fuel........................................................... 134 160 130 140 152 716
Total Duke Power -- Electric................................... 707 682 671 636 648 3,344
Associated Enterprises Group............................................. 218 318 290 306 382 1,514
Total Company............................................................ $925 $1,000 $961 $942 $1,030 $4,858
The Company's procedures for estimating capital expenditures for Duke
Power -- Electric (which include allowance for funds used during construction)
utilize, among other things, past construction experience, current construction
costs, allowances for inflation and the Company's business plan. These
projections are subject to periodic review and revisions. Actual construction
and nuclear fuel costs and capital expenditures incurred may vary from such
estimates. Cost variances for Duke Power -- Electric are due to various factors,
including revised load estimates, environmental matters and cost and
availability of capital. Projections of the AEG capital expenditures are subject
to periodic review and revision and may vary significantly as the business plans
of the AEG evolve to meet the opportunities presented by their markets.
JOINT OWNERSHIP OF GENERATING FACILITIES
The Company, through several transactions beginning in 1978, sold an 87.5%
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. (See Note 3, "Notes to
Consolidated Financial Statements.")
4
The Company and North Carolina Municipal Power Agency Number 1 (NCMPA) and
Piedmont Municipal Power Agency (PMPA), two of the four other joint owners of
the Catawba Nuclear Station, entered into a settlement in 1995 which resolved
outstanding issues related to how certain calculations affecting bills under the
Catawba joint ownership contractual agreements should be performed. The
settlement was approved by the NCUC on January 16, 1996, and the PSCSC on
January 23, 1996. As part of the settlement, the Company agreed to purchase
additional megawatts (MW) of Catawba capacity during the period 1996 through
1999 and remove certain restrictions related to sales of surplus energy by these
two joint owners. The additional capacity purchases are 215 MW in 1996, 165 MW
in 1997, 120 MW in 1998 and 100 MW in 1999. The Company expects to recover the
costs associated with this settlement as part of the purchased capacity
levelization, consistent with prior orders of the retail regulatory commissions.
Therefore, the Company believes these matters should not have a material adverse
effect on its results of operations or its financial position.
The Company and all four of the other joint owners of the Catawba Nuclear
Station entered into settlement agreements in 1994 which resolved all issues in
contention in arbitration proceedings related to the Catawba joint ownership
contractual agreements. The basic contention in each proceeding was that certain
calculations affecting bills under these agreements should be performed
differently. These items are covered by the agreements between the Company and
the other Catawba joint owners, which previously have been approved by the
Company's retail regulatory commissions. (For additional information on Catawba
joint ownership, see Note 3, "Notes to the Consolidated Financial Statements.")
In 1994, the Company settled its cumulative net obligation through 1993 of
approximately $205 million related to these settlement agreements. Billings for
1994 and later years conform to the settlement agreements, which were approved
by the Company's retail regulatory commissions. Because the Company expects the
costs associated with these settlements to be recovered as part of the purchased
capacity levelization, which has been approved by the Company's retail
regulatory commissions, the Company included approximately $205 million as an
increase to "Purchased capacity costs" on its Consolidated Balance Sheet in
1994. Therefore, the Company believes these matters should not have a material
adverse effect on its results of operations or its financial position.
FUEL SUPPLY
The Company presently relies principally on nuclear fuel and coal for the
generation of electric energy. The Company's reliance on oil and gas is minimal
even with the addition of the Lincoln Combustion Turbine Station, which is
designed to operate on either natural gas or oil.
Information regarding the utilization of sources of power and cost of fuels
is set forth in the following table:
COST OF FUEL PER NET
GENERATION BY SOURCE KWH GENERATED (CENTS)
YEAR ENDED DECEMBER 31 YEAR ENDED DECEMBER 31
1996 1995 1994 1996 1995 1994
Coal....................................................................... 54.0% 43.7% 46.9% 1.40 1.56 1.53
Nuclear (1)................................................................ 44.0 53.7 51.0 0.53 0.57 0.56
Oil and gas (2) (3)........................................................ .3 .3 -- 6.74 5.06 16.90
All fuels (cost based on weighted average) (1) (2)......................... 98.3 97.7 97.9 1.02 1.03 1.03
Hydroelectric (4).......................................................... 1.7 2.3 2.1
100.0% 100.0% 100.0%
(1) Statistics related to nuclear generation and all fuels reflect the Company's
12.5% ownership in the Catawba Nuclear Station.
(2) Statistics related to oil and gas generation and all fuels reflect
precommercial generation at the Lincoln Combustion Turbine Station in 1995
and 1996.
(3) Oil and gas cost statistics include amounts for light-off fuel at the
Company's coal-fired stations.
(4) Generating figures are net of that output required to replenish pumped
storage units during off-peak periods and do not include NP&L.
COAL. The Company obtains a large amount of its coal under long-term
supply contracts with mining operators utilizing both underground and surface
mining. The Company has on hand an adequate supply of coal. The Company's
long-term supply contracts, all of which have price adjustment provisions, have
expiration dates ranging from 1997 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
5
other coal suppliers for quantities and qualities of coal required. The coal
covered by the Company's long-term supply contracts is produced from mines
located in eastern Kentucky, southern West Virginia and southwestern Virginia.
The Company's requirements not met by long-term supply contracts have been and
will be fulfilled with spot market purchases. The average sulfur content of coal
being purchased by the Company is approximately 1 percent. Such coal satisfies
the current emission limitation for sulfur dioxide for existing facilities. (See
"Management's Discussion and Analysis of Results of Operations and Financial
Condition, Current Issues -- The Clean Air Act Amendments of 1990.")
NUCLEAR. Generally, the supply of fuel for nuclear generating units
involves the mining and milling of uranium ore to produce uranium concentrates,
the conversion of uranium concentrates to uranium hexafluoride, enrichment of
that gas and fabrication of the enriched uranium hexafluoride into usable fuel
assemblies. After a region (approximately one-third of the nuclear fuel
assemblies in the reactor at any time) of spent fuel is removed from a nuclear
reactor, it is placed in temporary storage for cooling in a spent fuel pool at
the nuclear station site. The Company has contracted for uranium materials and
services required to fuel the Oconee, McGuire and Catawba Nuclear Stations.
Based upon current projections, these contracts will meet the Company's
requirements through the following years:
URANIUM CONVERSION ENRICHMENT FABRICATION
NUCLEAR STATION MATERIAL SERVICE SERVICE SERVICE
Oconee............................................ 1997 1998 2000 2006
McGuire........................................... 1997 1998 2000 2009
Catawba........................................... 1997 1998 2000 2009
Uranium material requirements will be met through various supplier
contracts, with uranium material produced primarily in the U.S. and Canada. The
Company believes that it will be able to renew contracts as they expire or to
enter into similar contractual arrangements with other nuclear fuel materials
and services suppliers. Requirements not met by long-term supply contracts have
been and will be fulfilled with uranium spot market purchases.
The Department of Energy (DOE) requested Expressions of Interest (EOI) to
facilitate in the disposal of plutonium. The Company and Commonwealth Edison,
along with the other joint owners of the Catawba Nuclear Station, responded to
the EOI in early 1996. As this project is in its early developmental stage,
management cannot predict the outcome of this process. However, the Company
believes these matters should not have a material effect on the results of
operations or financial position of the Company.
The Nuclear Waste Policy Act of 1982 requires that the DOE begin disposing
of spent fuel no later than January 31, 1998. The Company has entered into the
required contracts with the DOE for the disposal of nuclear fuel and began
making payments in July 1983 for disposal costs of fuel currently being
utilized. These payments, combined with a one-time payment for disposal costs of
fuel consumed prior to April 7, 1983, have totaled about $540 million through
1996 related to the Company's ownership interest in nuclear plants. The DOE has
announced that the department anticipates a delay in accepting the waste
materials on the contract date of January 31, 1998. The Company has joined with
35 other utilities in a lawsuit attempting to force the DOE to meet its
obligations as called for in the contract. While it is uncertain what interim
storage will be provided by the DOE due to its inability to meet the contract
date, the Company has satisfactory plans in place to provide storage of spent
nuclear fuel if the DOE cannot accept it.
REGULATION
The Company is subject to the jurisdiction of the NCUC and the PSCSC which,
among other things, must approve the issuance of securities. The Company also is
subject, as to some phases of its business, to the jurisdiction of the FERC, the
Environmental Protection Agency (EPA) and state environmental agencies and to
the jurisdiction of the Nuclear Regulatory Commission (NRC) as to design,
construction and operation of its nuclear power facilities. The Company is
exempt from regulation as a holding company under the Public Utility Holding
Company Act of 1935 (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
6
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. In 1996, the Company's construction costs for environmental
protection totaled approximately $9 million, while the on-going environmental
operation costs were approximately $24 million. The Company's 1997-2001
construction program includes costs for environmental protection which are
estimated to be approximately $152 million, including $4.2 million in 1997,
$44.5 million in 1998, $55.5 million in 1999, $25.6 million in 2000 and $22.5
million in 2001. These costs include expenditures associated with the Clean Air
Act Amendments of 1990. However, governmental regulations establishing
environmental protection standards are continually evolving and have not, in
some cases, been fully established. These projections are subject to periodic
review and revisions. Actual construction costs and capital expenditures
incurred may vary from such estimates. Cost variances are due to various
factors, including cost and availability of capital.
AIR QUALITY. See "Management's Discussion and Analysis of Results of
Operations and Financial Condition, Current Issues -- The Clean Air Act
Amendments of 1990" for a discussion of the Company's plans for compliance with
federal clean air standards. The EPA has recently proposed revisions to two of
its air quality standards, one for ozone and the other for particulate matter.
These two proposals will not be final until the summer of 1997, and will likely
take years to implement fully. The rules as proposed would likely require
significant capital expenditures by electric utilities, particularly with
respect to coal-fired generation facilities, as well as by businesses in many
other industries. If promulgated without revision, it is expected that the rules
will be challenged in court, which could delay the effective implementation date
or could result in the rules being overturned altogether. Thus, it is too early
to estimate with accuracy the impact these rules could have on the Company.
Nevertheless, if implemented as proposed, the cost of compliance for the Company
could range from approximately $30 million to approximately $600 million over a
period currently estimated to be from 2002 through 2005.
WATER QUALITY. The Federal Water Pollution Control Act Amendments of 1987
(referred to herein as the "Clean Water Act") require permits for facilities
that discharge treated wastewater to the environment. The Company holds numerous
such permits, which are issued periodically. The issuance of such permits is
delegated by the EPA to state agencies in North and South Carolina. The Clean
Water Act has been scheduled for review and reauthorization by Congress since
1994, but no legislation has been enacted. Until Congress acts upon the
reauthorization, management will be unable to assess what effect, if any, such
reauthorization will have on the Company's operations.
OTHER ENVIRONMENTAL REGULATIONS. Contingencies associated with
environmental matters are principally related to possible obligations to remove
or mitigate the effects of contaminants resulting from the disposal of certain
substances.
The Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA), commonly known as "Superfund," can require any individual or entity
which may have owned or operated a disposal site, as well as transporters or
generators of hazardous wastes which were sent to such site, to share in
remediation costs for the site. Such parties are known as "potentially
responsible parties" (PRPs). Some sites are remediated pursuant to state acts
which are similar to CERCLA. The Company is currently participating in PRP
groups with regard to Superfund sites near Concord, North Carolina and Lenoir,
North Carolina. While the total cost of remediation at these federal and state
contamination sites may be substantial, the Company shares probable liability
with other PRPs, many of which have substantial assets. Management is of the
opinion that resolution of these matters will not have a material adverse effect
on the results of operations or financial position of the Company.
Other clean-up sites in which the Company is involved arise from the former
operation of manufactured gas plants (MGP), which were commonplace in the
Carolinas until the 1950s. Some such sites are still owned by the Company, and
others are now owned by third parties. In North Carolina, the Company is
participating in a state-sponsored program to investigate and, where
appropriate, remediate MGP sites. In South Carolina, the Company is in the
process of remediating an MGP site in Greenville. Management is of the opinion
that resolution of these matters will not have a material adverse effect on the
results of operations or financial position of the Company.
CERCLA has been scheduled for review and reauthorization by Congress since
1994, but no legislation has been enacted. Until CERCLA reform occurs,
management will be unable to assess what effect, if any, such reauthorization
will have on the Company's operations.
GENERAL. Over the past few decades, the issue of the possible health
effects of electric and magnetic fields has generated a number of generally
inconclusive studies, some public concern and litigation as well as legislative
action in some states regarding high voltage transmission lines. The impact of
this issue on the Company cannot presently be determined.
NUCLEAR FACILITIES. The Company's nuclear facilities are subject to
continuing regulation by the NRC.
7
Stress corrosion cracking (SCC) has occurred in the steam generators of
Units 1 and 2 at the McGuire Nuclear Station and Unit 1 at the Catawba Nuclear
Station. Catawba Unit 2, which has certain design differences and came into
service at a later date, has not yet shown the degree of SCC which has occurred
in McGuire Units 1 and 2 and Catawba Unit 1. It is, however, too early in the
life of Catawba Unit 2 to determine the extent to which SCC may be a problem.
Although the Company has taken steps to mitigate the effects of SCC, the
inherent potential for future SCC in the McGuire and Catawba steam generators
still exists. The Company planned for the replacement of steam generators at
three units that have experienced SCC and purchased the replacement steam
generators from Babcock & Wilcox International. Replacement of the steam
generators at Catawba Unit 1 was successfully completed at a lower cost than
projected on October 4, 1996, after a 115-day outage that included replacement
work and other maintenance. Steam generator replacement in both McGuire units is
scheduled for completion during 1997. The Catawba Unit 2 steam generators have
not been scheduled for replacement. Steam generator replacement at each McGuire
unit is expected to take approximately four months and cost approximately $170
million, excluding the cost of replacement power. Stress corrosion problems are
excluded under the Company's nuclear insurance policies.
The Company, in connection with its McGuire and Catawba stations and on
behalf of the other joint owners of the Catawba Station, began a legal action in
1990, alleging that Westinghouse Electric Corporation knowingly supplied to the
McGuire and Catawba stations steam generators that were defective in design,
workmanship and materials, requiring replacement well short of their stated
design life. The lawsuit was settled in 1994. While the court order does not
allow disclosure of the terms of the settlement, the Company believes the
litigation was settled on terms that provided satisfactory consideration to the
Company and will not have a material effect on the Company's results of
operations or financial position.
NUCLEAR DECOMMISSIONING COSTS. Estimated site-specific nuclear
decommissioning costs, including the cost of decommissioning plant components
not subject to radioactive contamination, total approximately $1.3 billion
stated in 1994 dollars based on decommissioning studies completed in 1994. This
amount includes the Company's 12.5% ownership in the Catawba Nuclear Station.
The other Catawba joint owners are responsible for decommissioning costs related
to their ownership interests in the station. Such estimates presume each unit
will be decommissioned as soon as possible following the end of its license
life. Although subject to extension, the current operating licenses for the
Company's nuclear units expire as follows: Oconee 1 and 2 -- 2013, Oconee
3 -- 2014; McGuire 1 -- 2021, McGuire 2 -- 2023; and Catawba 1 -- 2024, Catawba
2 -- 2026.
The 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 1996, the Company expensed approximately $56 million,
which was contributed to the external funds and accrued an additional $2 million
to the internal reserve. The balance of the external funds as of December 31,
1996, was $363 million. The balance of the internal reserve as of December 31,
1996, was $208 million and is reflected in accumulated depreciation and
amortization on the Consolidated Balance Sheets. Management's opinion is that
the decommissioning costs being recovered through rates, invested at assumed
after-tax earnings rates of 5.5 percent to 5.9 percent, are sufficient to
provide for the estimated cost of decommissioning.
A provision in the Energy Policy Act of 1992 established a fund for the
decontamination and decommissioning of the DOE's uranium enrichment plants.
Licensees are subject to an annual assessment for 15 years based on their pro
rata share of past enrichment services. The annual assessment is recorded as
fuel expense. The Company paid $9.5 million during 1996 and has paid $45.0
million cumulatively related to its ownership interest in nuclear plants. The
Company has reflected the remaining liability and regulatory asset of $94.7
million in the Consolidated Balance Sheet at December 31, 1996.
NUCLEAR INSURANCE. For a discussion of the Company's nuclear insurance
coverage, see "Note 13, Notes to Consolidated Financial Statements, Commitments
and Contingencies -- Nuclear Insurance."
HYDROELECTRIC LICENSES. The principal hydroelectric projects of the
Company are licensed by FERC under Part I of the Federal Power Act. Eleven
developments on the Catawba-Wateree River in North Carolina and South Carolina,
with a nameplate rating of approximately 805 MW, are licensed for a term
expiring in 2008. The Company also holds a license for the Keowee-Toxaway
Project for a term expiring in 2016, covering the Keowee Hydro Station and the
Jocassee Pumped Storage Station for a combined total of approximately 770 MW, on
the upper tributaries of the Savannah River in northwestern South Carolina.
Additionally, the Company is the licensee through 2027 for the Bad Creek
Hydroelectric Station which uses Lake Jocassee as its lower reservoir and has a
nameplate rating of 1,065 MW. The Company received new 40-year licenses in 1996
for two existing projects on the Broad River. The Company sold seven small
hydroelectric projects in 1996. NP&L holds licenses for 11 hydroelectric
projects with a nameplate rating of 100 MW with license terms expiring
2001-2006. The Federal
8
Power Act provides, among other things, that, upon the expiration of any license
issued thereunder, the United States may (a) grant a new license to the licensee
for the project, (b) take over the project upon payment to the licensee of its
"net investment" in the project (but not in excess of the fair value thereof)
plus severance damages, or (c) grant a license for the project to a new licensee
subject to payment to the former licensee of the amount specified in (b) above.
INTERCONNECTIONS
The Company has major interconnections and arrangements with its
neighboring utilities which it currently considers adequate for coordinated
planning, emergency assistance, exchange of capacity and energy, and reliability
of power supply.
COMPETITION
The Company currently is subject to competition in some areas from
government-owned power systems, municipally-owned electric systems, rural
electric cooperatives and, in certain instances, from other private utilities.
Statutes in North Carolina and South Carolina provide for the assignment by the
NCUC and the PSCSC, respectively, of all areas outside municipalities in such
states to power companies and rural electric cooperatives. Substantially all of
the territory comprising the Company's service area has been so assigned. The
remaining areas have been designated as unassigned and in such areas the Company
remains subject to competition. A decision of the North Carolina Supreme Court
limits, in some instances, the right of North Carolina municipalities to serve
customers outside their corporate limits. In South Carolina there continues to
be competition between municipalities and other electric suppliers outside the
corporate limits of the municipalities, subject, however, to the regulation of
the PSCSC. In addition, the Company is engaged in continuing competition with
various natural gas providers.
The Energy Policy Act of 1992 (EPACT) and the FERC's subsequent rulemaking
activities are major drivers toward a more competitive market for electric
generation. EPACT reformed provisions of PUHCA and Part II of the Federal Power
Act to remove certain barriers to competition for the supply of electricity. For
example, EPACT allows utilities to participate in the development of independent
electric generating plants in the United States for sales to wholesale
customers, as well as to contract for utility projects internationally, without
becoming subject to regulation under PUHCA as an electric utility holding
company. In addition, EPACT permits the FERC to order transmission access for
third parties to transmission facilities owned by another entity so that energy
suppliers can sell to wholesale customers wherever they are located. It does
not, however, permit the FERC to issue an order requiring transmission access to
retail customers.
The FERC, responsible in large measure for implementation of the EPACT, has
moved vigorously to implement its mandate, interpreting the statute broadly in
issuing orders for third-party transmission service and issuing a number of
rules of general applicability. On April 24, 1996, the FERC issued its Order
Numbers 888 and 889, which established the final form of transmission tariff to
provide comparable service to all users of a utility's transmission system.
Open-access transmission for wholesale customers as defined by the FERC's
final rules provides energy suppliers, including the Company, with opportunities
to sell and deliver capacity and energy at market-based prices. Engaging in such
transactions may result in improved utilization of the Company's existing
assets. In addition, such access provides another supply option through which
the Company can buy capacity and energy at attractive rates, influencing its
competitive price position. However, sales to existing wholesale customers of
the Company may continue to be impacted by open access either due to competitive
pressure on the wholesale price of electricity, or the potential loss of sales
as wholesale customers seek other options to meet their capacity and energy
requirements at market-based prices. (For additional information about sales to
wholesale customers, see "Liquidity and Resources -- Duke Power Company Rate
Matters," and Note 3, "Notes to Consolidated Financial Statements.") Wholesale
sales represented approximately 8.8 percent of the Company's total kilowatt-hour
sales in 1996. Supplemental sales to the other joint owners of the Catawba
Nuclear Station comprised the majority of such sales. Such supplemental sales
will continue to decline in 1997 as a result of the retention of larger portions
of ownership entitlement by the other joint owners. (For additional information
on Catawba joint ownership, see Note 3, "Notes to Consolidated Financial
Statements.")
In early 1995, prior to issuance of the FERC's Notice of Proposed
Rulemaking, the Company and certain of its affiliates filed three applications
with the FERC, all of which were designed to enable effective participation in
the competitive environment of the changing electric utility industry. Duke
Power filed an application for permission to sell at market-based rates up to
2,500 megawatts of capacity and energy from its own assets. Two of the Company's
affiliates, Duke Energy Marketing Corp. (DEMC) and Duke/Louis Dreyfus LLC
(D/LD), filed applications with the FERC to become power marketers. All of the
applications were supported by transmission tariffs which complied with then
applicable FERC standards and established the rates, terms and conditions for
transmission service to third parties on the Company's transmission system. Late
in 1995,
9
the FERC granted the applications of Duke, DEMC, and D/LD; accepted Duke's
transmission tariffs; and ordered a hearing on the rates to be charged for
service under those tariffs. On July 9, 1996, in compliance with the standards
and schedules set forth in Order Number 888, the Company filed a pro forma open
access transmission tariff complying with the requirements of the FERC's final
rules. Such a filing was required of all transmission-owning utilities subject
to the FERC's jurisdiction. The Company also filed on that date a proposed
settlement in the proceeding earlier ordered by the FERC. The proposed
settlement resolves all rate issues related to transmission services under
Duke's tariff and contains the rates agreed upon under the settlement. The
settlement and the July 9, 1996 tariff filing remain subject to final FERC
approval.
Competition for retail customers is not generally allowed in the Company's
service territory. However, there are discussions and events at the national
level and within certain states regarding retail competition which could result
in changes in the industry. Such changes, should they occur, could impact all
entities owning generation, including the other joint owners of the Catawba
Nuclear Station. The process of assessing changes to the regulatory structure is
just beginning in the Company's retail jurisdictions and has not progressed as
rapidly as in some other states. A bill was passed in the North
Carolina General Assembly to establish a group to study the issues
surrounding retail competition. The study group is to report the
results of its study to the 1999 General Assembly. While a bill has
been introduced to provide for retail competition in South
Carolina, the bill does not have the support of all interested
parties and in effect just begins the process of addressing the
relevant issues in that state. In addition, a bill has been recently
introduced in the South Carolina legislature to create an electric deregulation
study committee on retail competition. In addition, at the federal level,
several bills have been introduced in Congress, and it is likely that other
bills will be introduced in the future, that may cover many different issues,
including the following: repeal of PUHCA and certain provisions of the Public
Utility Regulatory Policies Act of 1978, retail competition, disaggregation
of electric utilities and the restructuring of the electric utility industry.
This activity is at an early stage, and no assessment of its impact, if any,
upon the Company can be made at this time. (See "Management's Discussion and
Analysis of Results of Operations and Financial Condition, Current
Issues -- Competition.")
Currently, the electric utility industry is predominantly regulated on a
basis designed to recover the cost of providing electric power to its retail and
wholesale customers. If cost-based regulation were to be discontinued in the
industry, for any reason, including competitive pressure on the cost-based
prices of electricity, profits could be reduced and utilities might be required
to reduce their asset balances to reflect a market basis less than cost.
Discontinuance of cost-based regulation would also require affected utilities to
write off their associated regulatory assets. The regulatory assets of the
Company are classified as "Deferred debits" on the Consolidated Balance Sheets.
Substantially all of the "Deferred debits" are regulatory assets. Management
cannot predict the potential impact, if any, of these competitive forces on the
Company's future financial position and results of operations. However, the
Company continues to position itself to effectively meet these challenges by
maintaining prices that are locally, regionally and nationally competitive.
In addition to the changing regulatory environment, another trend toward
increasing competition in the electric utility industry is the convergence of
markets for electricity and natural gas. The Company's management has noted the
emergence of a national market for energy products and services in which demands
for energy in the forms of electricity and gas are increasingly being met by
vendors who have the ability to supply both. The Company's proposed merger with
PanEnergy Corp is its primary strategic response to this trend. (See
"Management's Discussion and Analysis of Results of Operations and Financial
Condition, Current Issues -- Proposed Merger with PanEnergy Corp.")
SUBSIDIARIES AND DIVERSIFIED ACTIVITIES
The Company continues to aggressively pursue both domestic and
international diversified business opportunities that are synergistic with the
Company's core business to provide additional value to the Company's
shareholders. Among the Company's current industry pursuits are ownership of
electric power facilities, energy marketing, real estate, communications,
engineering consulting and various energy services. Although these opportunities
are primarily concentrated in areas that utilize the Company's expertise, they
present different and potentially greater risks than does the Company's core
business. The Company only pursues opportunities in which the expected returns
are commensurate with the risks and makes efforts to mitigate such risks. The
Company undertakes a continuous evaluation of the various lines of business it
may enter or exit, with the objective of enhancing shareholder value and
managing any associated risk. (See "Subsidiaries and Diversified Activities
Highlights.")
Major subsidiaries and diversified activities include the following:
CRESCENT RESOURCES, INC. (Crescent) provides high-quality residential and
commercial real estate development services in the Southeast in addition to
providing forest management activities focused on growing trees suitable for use
in the construction, furniture and paper industries. During 1996, Crescent sold
869 residential developed lots compared to 600 lots in 1995. At December 31,
1996, Crescent owned approximately 2.5 million square feet of office, retail and
warehouse space and had approximately 900,000 square feet of commercial
properties under construction. Additionally, Crescent had approximately 249,000
acres of land under its management at year end.
10
DUKE ENERGY GROUP, INC. (Duke Energy Group) develops, owns, manages and
operates energy facilities worldwide. Domestically, Duke Energy Group
concentrates on advanced fossil-fueled generation including pulverized coal,
circulating fluidized bed, coal gasification and natural gas technologies.
Internationally, Duke Energy Group pursues advanced coal-fueled, hydroelectric
and gas-fueled generation as well as transmission projects. Duke Energy Group
has equity interests in two U.S. electric generation facilities and six
international projects.
DUKE ENGINEERING & SERVICES, INC. (DE&S) provides engineering, project
management, quality assurance, construction management, operating and
maintenance and environmental services for utilities, industry and government
worldwide. During 1996, DE&S continued to expand primarily due to the
acquisition of the nuclear engineering, government services and power services
businesses of VECTRA Technologies, Inc. DE&S was awarded 984 contracts in 1996,
including a contract to manage and integrate spent nuclear fuel activities at
the Department of Energy's Hanford facility in Washington state. DE&S's domestic
and global presence is evident by its 23 U.S. business offices, 13 international
offices and projects underway in more than 50 countries.
NANTAHALA POWER AND LIGHT COMPANY (NP&L) is a franchised electric utility
which operates 11 hydroelectric plants with a total capacity of 100 megawatts.
NP&L has approximately 55,000 customers in western North Carolina. NP&L sold
1,085,000 MWH in 1996 compared with 949,000 MWH in 1995, excluding firm sales
and sales to Duke Power.
OTHER BUSINESS UNITS include Church Street Capital Corp., which provides
equity funding and credit enhancement services for its subsidiaries and manages
investment funds; Duke/Fluor Daniel, a joint venture with Fluor Daniel, Inc.,
which provides engineering, procurement, construction and operating and
maintenance services for fossil-fueled electric generating stations worldwide;
Duke/Louis Dreyfus, LLC, which markets electric power, natural gas and
energy-related services to utilities, municipalities and other large energy
users in North America; Duke Merchandising, which sells and services home
appliances, electronics and wireless communications devices; DukeNet
Communications, Inc., which develops and manages communications systems,
including fiber optic and wireless digital network services; and Duke Water
Operations, which provides franchised water service to customers in parts of
North and South Carolina.
EMPLOYEES
At December 31, 1996, the Company had 17,726 full-time employees, which
included 2,724 full-time employees of subsidiaries and diversified activities.
About 1,850 electrical operating employees are represented by the International
Brotherhood of Electrical Workers (IBEW). During the last quarter of 1996, the
Company and the IBEW were unable to reach a new labor agreement and, in December
1996, the Company unilaterally implemented its final offer for settlement.
The number of full-time employees has decreased to the 1996 year-end level
from 18,551 at year-end 1991. (See "Management's Discussion and Analysis of
Results of Operations and Financial Condition, Current Issues -- Resource
Optimization.")
SUBSEQUENT EVENTS
On March 18, 1997, the PSCSC unanimously voted in favor of the merger of
the Company and PanEnergy Corp and approved the issuance of securities for the
merger. Hearings were held in the PSCSC proceeding on March 6, 1997 and in the
NCUC proceeding on March 18, 1997. In connection with the hearings, the Company
entered into stipulations with the South Carolina Consumer Advocate and the
Public Staff of the NCUC. The stipulations contain certain conditions that,
among other things, are generally designed to ensure (i) that the rates of the
Company's retail electric and water customers will not be affected by any costs
of, or increased costs attributable to, the merger or by any commitments made by
the Company in other jurisdictions relating to the merger, (ii) that the
Company's future conduct of business with its subsidiaries and affiliates, and
its allocation of costs among the Company and its subsidiaries and affiliates,
do not lessen competition or adversely impact rates, (iii) that the Company will
not seek to increase its retail rates through the year 2000, except to reflect
substantial financial impacts of governmental action affecting the industry
generally, or a segment thereof, including the Company, or major expenditures
attributable to FORCE MAJEURE events, and (iv) that North Carolina's regulatory
jurisdiction will not be diminished by preemption, to the detriment of retail
customers, should the Company in the future engage in an action that causes it
to cease to be exempt from registration under PUHCA. Orders to be issued in both
the PSCSC and NCUC proceedings may contain some or all of the conditions set
forth in the stipulations.
11
(Picture Graphic of a Map of North and South Carolina
appears here)
12
DUKE POWER COMPANY
OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
1996 1995 1994 1993 1992
Sources of Electric Energy (a)
Millions of kilowatt-hours:
Generated -- net output:
Coal.............................................. 40,649 32,389 32,714 34,097 28,999
Nuclear (b)....................................... 33,177 39,836 35,587 34,390 33,925
Hydro............................................. 1,319 1,685 1,460 1,582 1,834
Oil and gas (c)................................... 199 255 35 43 5
Total generation............................. 75,344 74,165 69,796 70,112 64,763
Purchased power and net interchange............... 3,587 1,175 1,276 1,750 1,403
Total output................................. 78,931 75,340 71,072 71,862 66,166
Plus: Purchases from other Catawba joint owners... 2,662 6,070 9,046 8,810 9,466
Total sources of energy...................... 81,593 81,410 80,118 80,672 75,632
Line loss and company usage....................... 4,741 4,673 4,555 4,614 4,590
Total kilowatt-hour sales.................... 76,852 76,737 75,563 76,058 71,042
Average Cost Per Ton of Coal Burned.................... $ 36.89 $ 41.72 $ 40.68 $ 42.21 $ 43.47
Electric Energy Sales (a)
Millions of kilowatt-hours:
Residential....................................... 20,992 19,669 18,870 19,465 17,789
General service................................... 19,269 18,160 17,289 16,904 15,818
Industrial
Textile......................................... 11,599 12,151 12,285 11,954 11,685
Other........................................... 18,021 17,631 17,005 16,244 15,356
Other energy and wholesale (d).................... 7,028 8,330 10,274 11,337 10,360
Total kilowatt-hour sales billed............. 76,909 75,941 75,723 75,904 71,008
Unbilled kilowatt-hour sales............... (57) 796 (160) 154 34
Total kilowatt-hour sales.................. 76,852 76,737 75,563 76,058 71,042
Electric Revenue (a)
Thousands of dollars:
Residential....................................... $1,519,902 $1,441,362 $1,379,740 $1,424,173 $1,312,227
General service................................... 1,123,804 1,076,791 1,031,061 1,014,124 964,853
Industrial
Textile......................................... 458,844 494,066 498,190 487,576 482,172
Other........................................... 765,387 766,750 745,154 726,399 696,413
Other energy and wholesale (d).................... 379,755 461,367 540,256 476,862 460,849
Other electric revenue............................ 149,181 182,102 84,928 152,742 44,970
Total electric revenues...................... $4,396,873 $4,422,438 $4,279,329 $4,281,876 $3,961,484
Number of Customers -- end of year (a)
Residential....................................... 1,563,940 1,526,323 1,493,166 1,460,876 1,439,845
General service................................... 253,849 246,276 239,355 232,272 227,675
Industrial
Textile......................................... 1,327 1,390 1,422 1,396 1,390
Other........................................... 7,304 7,320 7,320 7,338 7,314
Other energy and wholesale........................ 8,660 8,470 8,187 7,957 7,773
Total customers.............................. 1,835,080 1,789,779 1,749,450 1,709,839 1,683,997
Residential Customer Statistics (a)
Average number for the year....................... 1,549,346 1,514,434 1,483,497 1,455,609 1,431,403
Average annual use -- KWH......................... 13,549 12,988 12,720 13,372 12,427
Average annual billing............................ $ 981.00 $ 951.75 $ 930.06 $ 978.40 $ 916.74
Average annual billed revenue per KWH (a)
Cents:
Residential....................................... 7.24 7.33 7.31 7.32 7.38
General service................................... 5.83 5.93 5.96 6.00 6.10
Industrial........................................ 4.13 4.23 4.24 4.31 4.36
Other energy and wholesale (d).................... 5.40 5.54 5.26 4.21 4.45
13
(a) Does not include operating statistics of NP&L.
(b) Includes 12.5% of Catawba generation.
(c) 1996 and 1995 include KWH of the Lincoln Combustion Turbine Station prior to
commercial operation.
(d) Includes sales to NP&L.
EXECUTIVE OFFICERS OF THE COMPANY
WILLIAM H. GRIGG, 64, Chairman of the Board and Chief Executive Officer.
Mr. Grigg served as Chairman of the Board, President and Chief Executive
Officer, effective April 28, 1994, until July 27, 1994 when he assumed his
present position. He served as Vice Chairman of the Board beginning in 1991, and
Executive Vice President, Customer Group, beginning in 1988.
STEVE C. GRIFFITH, JR., 63, Vice Chairman of the Board and General Counsel.
Mr. Griffith served as Executive Vice President and General Counsel from 1991
until he assumed his present position in July 1994. He served as Senior Vice
President and General Counsel from 1982 until 1991.
RICHARD B. PRIORY, 50, President and Chief Operating Officer. Mr. Priory
served as Executive Vice President, Power Generation Group, from 1991 until he
assumed his present position in July 1994. He was Senior Vice President,
Generation and Information Services, from 1988 to 1991.
WILLIAM A. COLEY, 53, President, Associated Enterprises Group. Mr. Coley
was named Senior Vice President, Power Delivery, in 1988; Senior Vice President,
Customer Group, in 1990; and Executive Vice President, Customer Group, in 1991.
He was named to his present position in July 1994.
RICHARD J. OSBORNE, 45, Senior Vice President and Chief Financial Officer.
Prior to assuming his current position in July 1994, Mr. Osborne served as Vice
President and Chief Financial Officer beginning in 1991 and Vice President,
Finance, from 1988 to 1991.
JEFFREY L. BOYER, 40, Controller. Mr. Boyer served as Director of Corporate
Accounting for more than five years prior to assuming his present position in
July 1994.
Executive officers are elected annually by the Board of Directors and serve
until the first meeting of the Board of Directors following the next annual
meeting of shareholders and until their successors are duly elected.
There are no family relationships between any of the executive officers nor
any arrangement or understanding between any executive officer and any other
person pursuant to which the officer was selected.
There have been no events under any bankruptcy act, no criminal proceedings
and no judgments or injunctions material to the evaluation of the ability and
integrity of any executive officer during the past five years.
14
ITEM 2. PROPERTIES.
At December 31, 1996, the Company, excluding its subsidiary NP&L, operated
three nuclear generating stations, eight coal-fired stations and twenty
hydroelectric stations, all of which are located in North Carolina or South
Carolina.
The following is a list of the major generating stations owned by the
Company at December 31, 1996:
FACILITY ENERGY SOURCE NET MW
Oconee Nuclear 2,538
McGuire Nuclear 2,258
Catawba (a) Nuclear 282
Belews Creek Coal 2,240
Marshall Coal 2,090
Allen Coal 1,140
Cliffside Coal 760
Others Coal 1,469
Bad Creek Hydroelectric 1,065
Jocassee Hydroelectric 610
Others Hydroelectric 1,010
Lincoln Oil and gas 1,200
Others Oil and gas 584
(a) Represents Duke's 12.5% ownership share in Catawba Nuclear Station.
In addition to the electric generating plants described above, the Company
owned, as of December 31, 1996, approximately 8,300 conductor miles of
transmission lines, including 600 conductor miles of 500 kilovolts, 1,400
conductor miles of 220 kilovolts, 3,400 conductor miles of 100 kilovolts, and
2,900 conductor miles of 13 to 66 kilovolts. The Company also owned
approximately 74,200 conductor miles of distribution lines, including 47,200
conductor miles of rural overhead lines, 14,700 conductor miles of urban
overhead lines, 6,900 conductor miles of rural underground lines and 5,400
conductor miles of urban underground lines. As of such date, the Company's
transmission and distribution systems comprised approximately 1,600 substations
with an installed transformer capacity of approximately 85,200,000 kVA.
NP&L's generation facilities consist of 11 hydroelectric plants with an
aggregate nameplate capacity of approximately 100 MW. Duke Power supplies all of
NP&L's supplemental power needs from Duke Power's Tuckaseegee Substation near
NP&L's Thorpe Plant. NP&L also has an interconnection of 161 kV with the
Tennessee Valley Authority (TVA) at Santeetlah, North Carolina. The transmission
backbone of the NP&L system is a 161 kV line from Duke's Tuckaseegee Substation
to the interconnection with TVA at Santeetlah, with NP&L substations at
Robbinsville, Nantahala Plant, Oak Grove, Webster and Thorpe Plant.
The map found at the end of Item 1 shows the locations of the Company's and
NP&L's service areas and generating stations.
Substantially all electric plant is mortgaged under the Indenture relating
to the First and Refunding Mortgage Bonds of the Company.
For additional information concerning the properties of the Company, see
"Business -- Energy Requirements and Capability."
ITEM 3. LEGAL PROCEEDINGS.
Reference is made to "Business -- Regulation," "Management's Discussion and
Analysis of Results of Operations and Financial Condition, Current
Issues -- Commitments and Contingencies" and "Note 13, Notes to Consolidated
Financial Statements, Commitments and Contingencies -- Other."
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 1996.
15
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, 1996, there were approximately 130,683 holders of shares of such
Common Stock. During 1996, the Company repurchased 3,269,743 shares of its
Common Stock, at a total cost of $159 million, through a stock repurchase
program. On January 28, 1997, the Board of Directors amended the program to
expressly limit the number of shares authorized for repurchase under the
program, from the initiation of the program through a date two years after the
consummation of the proposed merger with PanEnergy Corp, to an amount not to
exceed 15 million shares. (For additional information on the stock repurchase
program, see Note 6, "Notes to the Consolidated Financial Statements.")
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:
STOCK PRICE
DIVIDENDS RANGE
COMMON STOCK PER SHARE HIGH
1996 By Quarter
Fourth......................................................................................... $0.53 $ 49 1/8
Third.......................................................................................... 0.53 51 3/8
Second......................................................................................... 0.51 51 1/2
First.......................................................................................... 0.51 53
1995 By Quarter
Fourth......................................................................................... $0.51 $ 47 7/8
Third.......................................................................................... 0.51 43 3/4
Second......................................................................................... 0.49 42 3/4
First.......................................................................................... 0.49 40 3/4
STOCK PRICE
RANGE
COMMON STOCK LOW
1996 By Quarter
Fourth......................................................................................... $ 43 3/8
Third.......................................................................................... 45 3/4
Second......................................................................................... 45 3/4
First.......................................................................................... 46 7/8
1995 By Quarter
Fourth......................................................................................... $ 43 1/8
Third.......................................................................................... 40
Second......................................................................................... 38 1/4
First.......................................................................................... 37 3/8
16
ITEM 6.
SELECTED FINANCIAL DATA
1996 1995 1994 1993 1992
Condensed consolidated statements of income
(thousands)
Operating revenues............................. $ 4,757,974 $ 4,676,684 $ 4,488,913 $ 4,466,233 $ 4,122,503
Operating expenses............................. 3,395,771 3,327,633 3,309,087 3,258,422 3,087,422
Operating income............................... 1,362,203 1,349,051 1,179,826 1,207,811 1,035,081
Interest expense and other income.............. (156,546) (168,072) (143,931) (171,419) (223,028)
Income before income taxes..................... 1,205,657 1,180,979 1,035,895 1,036,392 812,053
Income taxes................................... 475,691 466,441 397,019 409,977 303,970
Net income..................................... 729,966 714,538 638,876 626,415 508,083
Dividends on preferred and preference stock.... 44,245 48,903 49,724 52,429 56,407
Earnings for common stock...................... $ 685,721 $ 665,635 $ 589,152 $ 573,986 $ 451,676
Common stock data
Shares of common stock
year-end (thousands)........................ 201,590 204,859 204,859 204,859 204,859
average (thousands)......................... 203,553 204,859 204,859 204,859 204,819
Per share of common stock
Earnings.................................... $ 3.37 $ 3.25 $ 2.88 $ 2.80 $ 2.21
Dividends................................... $ 2.08 $ 2.00 $ 1.92 $ 1.84 $ 1.76
Book value -- year-end...................... $ 24.25 $ 23.36 $ 22.13 $ 21.17 $ 20.26
Market price -- high-low.................... $ 53-43 3/8 $47 7/8-37 3/8 $ 43-32 7/8 $44 7/8-35 3/8 $37 1/2-31 3/8
-- year-end................... $ 46 1/4 $ 47 3/8 $ 38 1/8 $ 42 3/8 $ 36 1/8
Balance sheet data
(thousands)
Total assets................................... $13,469,690 $13,358,484 $12,862,228 $12,293,605 $11,012,795
Long-term debt................................. $ 3,538,114 $ 3,711,405 $ 3,567,122 $ 3,285,397 $ 3,288,111
Preferred stock with sinking fund
requirements................................ $ 234,000 $ 234,000 $ 279,500 $ 281,000 $ 279,519
17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION.
This Management's Discussion and Analysis presents the financial condition,
results of operations and certain forward-looking information about Duke Power
Company and its subsidiaries. On November 25, 1996, the Company and PanEnergy
Corp announced a proposed stock-for-stock merger. Unless otherwise indicated,
all information presented herein relates to Duke Power Company only and does not
take into account the proposed merger with PanEnergy. (For additional
information on the proposed merger, see "Current Issues -- Proposed Merger with
PanEnergy Corp.")
RESULTS OF OPERATIONS
EARNINGS AND DIVIDENDS. Earnings per share increased 4 percent from $3.25
in 1995 to $3.37 in 1996. The increase was primarily due to electric customer
growth.
Earnings per share increased from $2.88 in 1994 to $3.37 in 1996,
indicating an average annual growth rate of 8 percent. Total Company earned
return on average common equity was 14.2 percent in 1996 compared to 14.3
percent in 1995 and 13.3 percent in 1994.
The Company continued its practice of annually increasing the common stock
dividend. Common dividends per share increased at an average annual rate of 4
percent from $1.92 in 1994 to $2.08 in 1996. Indicated annual dividends per
share increased to $2.12.
REVENUES AND SALES. Operating revenues increased at an average annual rate
of 3 percent from 1994 to 1996, primarily because of growth in the residential
and general service customer classes and increased retail kilowatt-hour sales to
weather-sensitive customer classes. As discussed below, increased retail sales
were partially offset by decreased sales to wholesale customers. A South
Carolina retail rate reduction also decreased revenues in 1996. (For additional
information on the South Carolina rate reduction, see "Liquidity and
Resources -- Duke Power Company Rate Matters.") Revenues from subsidiaries and
diversified operations contributed $162 million to the increase in revenues over
the three-year period, primarily from increased engineering service fees and
developed lot and land sales.
Wholesale revenues declined in 1996 as a result of the retention of
significantly larger portions of ownership entitlement by the other joint owners
of the Catawba Nuclear Station. This increased retention reduces the joint
owners' supplemental requirements supplied by the Company. The effect on
earnings of such wholesale revenue declines is partially offset by declines in
purchased power costs from the other joint owners which are not subject to
levelization. (For additional information on Catawba joint ownership, see Note
3, "Notes to the Consolidated Financial Statements.")
Kilowatt-hour sales from Duke Power electric operations were flat from 1995
to 1996. Sales to residential, general service, and other industrial customers
increased by 7 percent, 6 percent and 2 percent, respectively, as a result of
colder winter weather and continued economic growth in Duke Power's service
area. However, sales to textile customers decreased 5 percent, due to a weaker
demand for textile goods. Wholesale sales decreased 16 percent primarily due to
a decrease of 24 percent in supplemental sales requirements to the other joint
owners of the Catawba Nuclear Station.
OPERATING EXPENSES. From 1995 to 1996, other operation and maintenance
expenses increased 7 percent. Increased activities of subsidiaries and
diversified operations contributed to this increase. Distribution maintenance
expenses also increased, primarily because of restoration costs associated with
a February ice storm and Hurricane Fran.
Other operation and maintenance expenses increased at an average annual
rate of 6 percent from 1994 to 1996. Increased activities of the subsidiaries
and diversified operations associated with engineering services contributed to
this increase.
Fuel expense increased at an average annual rate of 4 percent from 1994 to
1996. The increase was due primarily to higher system production requirements
and higher levels of fossil generation as a percentage of total generation.
These increases were partially offset by lower fossil fuel costs.
Net interchange and purchased power expenses decreased from $553 million in
1994 to $379 million in 1996, an average annual decrease of 17 percent. This
decrease was primarily the result of lower purchased power costs from the other
joint owners not subject to levelization as the other joint owners retained
significantly larger portions of their ownership entitlement, and lower
levelized costs as a result of the substantial completion of the recovery of
such costs from South Carolina customers.
18
From 1994 to 1996, depreciation and amortization expense increased at an
average annual rate of 3 percent, primarily due to increased depreciation
associated with additional investments. These investments were primarily
associated with distribution plant, including investment to support customer
growth, and the completion of the Lincoln Combustion Turbine Station. (For
additional information on the Lincoln Combustion Turbine Station, see "Capital
Needs -- Meeting Future Power Needs.")
INTEREST EXPENSE AND OTHER INCOME. Interest expense increased at an average
annual rate of 2 percent from 1994 to 1996, primarily due to long-term debt
financing activities in 1994.
Allowance for funds used during construction (AFUDC) and other deferred
returns, net of associated taxes, represented 11 percent of earnings for common
stock in 1996 compared to 13 percent in 1994. AFUDC and other deferred returns
are expected to be less than 11 percent of total earnings during the next three
years.
The deferred return, net of associated taxes, on the purchased capacity
levelization deferral related to the joint ownership of the Catawba Nuclear
Station represented 7 percent of earnings for common stock in 1996, 1995 and
1994. The cumulative deferred purchased capacity balance began to decline in
1996 and will continue to decline in 1997. (For additional information on
purchased capacity levelization, see "Capital Needs -- Purchased Capacity
Levelization.")
AFUDC, net of associated taxes, represented 3 percent of earnings for
common stock in 1996 compared to 5 percent in 1995 and 6 percent in 1994. The
changes were primarily the result of the construction and subsequent commercial
operation of the Lincoln Combustion Turbine Station as 12 units were brought
on-line in 1995 and the remaining 4 units were brought on-line during the first
quarter of 1996. (For additional information on the Lincoln Combustion Turbine
Station, see "Capital Needs -- Meeting Future Power Needs.")
LIQUIDITY AND RESOURCES
DUKE POWER COMPANY RATE MATTERS. Duke Power Company's most recent general
rate increase requests in the North Carolina and South Carolina retail
jurisdictions were filed and approved in 1991. Additionally, Duke Power has a
bulk power sales agreement with Carolina Power & Light Company (CP&L) to provide
CP&L 400 megawatts of capacity as well as associated energy when needed for a
six-year period which began July 1, 1993. Electric rates in all of Duke Power's
regulatory jurisdictions were reduced by adjustment riders to reflect capacity
revenues received from this CP&L bulk power sales agreement.
The Public Service Commission of South Carolina (PSCSC), on May 7, 1996,
ordered a rate reduction in the form of a decrement rider of 0.432 cents per
kilowatt-hour, or an average of approximately 8 percent, affecting South
Carolina retail customers. South Carolina retail sales represent approximately
30 percent of the Company's total retail sales. The rate reduction was reflected
on bills rendered on or after June 1, 1996. This net decrement rider reflects an
interim true-up decrement adjustment associated with the levelization of Catawba
Nuclear Station purchased capacity costs and an interim true-up increment
associated with amortization of the demand-side management deferral account. The
rate adjustment was made because, in the South Carolina retail jurisdiction,
cumulative levelized revenues associated with the recovery of Catawba purchased
capacity costs had exceeded purchased capacity payments and accrual of deferred
returns, and certain demand-side costs had exceeded the level reflected in
rates.
Certain of the Company's wholesale customers, excluding the other Catawba
joint owners, initiated proceedings in 1995 before the Federal Energy Regulatory
Commission (FERC) concerning rate matters. The Company and nine of its eleven
wholesale customers entered into a settlement in July 1996 which reduced the
customers' rates by approximately 9 percent and renewed their contracts with the
Company through the year 2000. Both of the customers that did not enter into the
settlement have signed agreements to purchase energy from other suppliers
beginning in 1997. The eleven wholesale customers involved in this matter
accounted for less than 2 percent of the Company's overall electric revenues
during 1996. The two customers that have signed agreements with other suppliers
accounted for less than 0.5 percent of the Company's 1996 overall electric
revenues. (For additional information about sales to wholesale customers, see
"Current Issues -- Competition.")
CATAWBA SETTLEMENTS. The Company and North Carolina Municipal Power Agency
Number 1 (NCMPA) and Piedmont Municipal Power Agency (PMPA), two of the four
other joint owners of the Catawba Nuclear Station, entered into a settlement in
1995 which resolved outstanding issues related to how certain calculations
affecting bills under the Catawba joint ownership contractual agreements should
be performed. The settlement was approved by the North Carolina Utilities
Commission (NCUC) on January 16, 1996, and the PSCSC on January 23, 1996. As
part of the settlement, the Company agreed to
19
purchase additional megawatts (MW) of Catawba capacity during the period 1996
through 1999 and remove certain restrictions related to sales of surplus energy
by these two joint owners. The additional capacity purchases are 215 MW in 1996,
165 MW in 1997, 120 MW in 1998 and 100 MW in 1999. The Company expects to
recover the costs associated with this settlement as part of the purchased
capacity levelization, consistent with prior orders of the retail regulatory
commissions. Therefore, the Company believes these matters should not have a
material adverse effect on its results of operations or its financial position.
The Company and all four of the other joint owners of the Catawba Nuclear
Station entered into settlement agreements in 1994 which resolved all issues in
contention in arbitration proceedings related to the Catawba joint ownership
contractual agreements. The basic contention in each proceeding was that certain
calculations affecting bills under these agreements should be performed
differently. These items are covered by the agreements between the Company and
the other Catawba joint owners, which previously have been approved by the
Company's retail regulatory commissions. (For additional information on Catawba
joint ownership, see Note 3, "Notes to the Consolidated Financial Statements.")
In 1994, the Company settled its cumulative net obligation through 1993 of
approximately $205 million related to these settlement agreements. Billings for
1994 and later years conform to the settlement agreements, which were approved
by the Company's retail regulatory commissions.
Because the Company expects the costs associated with these settlements to
be recovered as part of the purchased capacity levelization, which has been
approved by the Company's retail regulatory commissions, the Company included
approximately $205 million as an increase to "Purchased capacity costs" on its
Consolidated Balance Sheets in 1994. Therefore, the Company believes these
matters should not have a material adverse effect on its results of operations
or its financial position.
CASH FROM OPERATIONS. Consolidated net cash provided by operating
activities in 1996 accounted for 97 percent of total cash from operating,
financing and investing activities compared with 81 percent in 1995 and 67
percent in 1994. When 1996 stock repurchase activities are excluded, cash
generated from operating activities exceeded the Company's capital needs. (For
additional information on the stock repurchase program, see Note 6, "Notes to
the Consolidated Financial Statements.")
FINANCING AND INVESTING ACTIVITIES. The Company's consolidated capital
structure at year-end 1996, including subsidiary long-term debt, was 54 percent
common equity, 39 percent long-term debt and 7 percent preferred stock. This
structure is consistent with the Company's target to maintain a double-A credit
rating. As of December 31, 1996, Duke Power's bonds were rated "AA" by Fitch
Investors Service and Duff & Phelps, "Aa2" by Moody's Investors Service and
"AA-" by Standard & Poor's Group. As a result of the announcement of the
proposed merger with PanEnergy Corp, the Company has been placed on credit
review by the rating agencies. (For additional information on the proposed
merger, see "Current Issues -- Proposed Merger with PanEnergy Corp.")
The Company had total credit facilities of $694.9 million and $669.9
million as of December 31, 1996 and 1995, respectively. The Company had unused
credit facilities of $474.4 million and $440.6 million as of December 31, 1996
and 1995, respectively.
During July 1996, the Company began purchasing shares of its common stock.
The Company has repurchased approximately 3.3 million shares of common stock for
$159 million as of December 31, 1996. (For additional information on the stock
repurchase program, see Note 6, "Notes to the Consolidated Financial
Statements.") In 1995, the Company issued $178 million of long-term debt, of
which $72 million was used to retire higher cost long-term debt. The Company
also retired $96 million of preferred stock and $80 million of long-term debt in
1995. In 1994, the Company issued $407 million in debt, primarily First and
Refunding Mortgage Bonds.
The Company has authority to issue up to $1 billion aggregate principal
amount of debt securities under a shelf registration statement filed with the
Securities and Exchange Commission (SEC). Such debt securities may be issued as
First and Refunding Mortgage Bonds, Senior Notes, or Subordinated Debentures.
In order to obtain variable rate financing at an attractive cost, the
Company entered into interest rate swap agreements associated with the November
1994 issuance of $200 million aggregate principal amount of its First and
Refunding Mortgage Bonds 8% Series B due 1999 and the August 1995 issuance of
$100 million aggregate principal amount of its First and Refunding Mortgage
Bonds 7 1/2% Series B due 2025. The interest rate swaps are reset quarterly
based upon the three-month London Interbank Offered Rate (LIBOR). As a result of
the interest rate swap contracts, interest expense is recognized at the weighted
average rate for the year tied to the LIBOR rate. The weighted average rates at
December 31, 1996, 1995 and 1994 were 5.64%, 6.14% and 5.95%, respectively, for
the 8% Series B due 1999. The weighted average rates at December 31, 1996 and
1995 were 6.69% and 7.06%, respectively, for the 7 1/2% Series B due 2025.
20
Duke Energy Group, Inc. entered into a hedge transaction in 1995 to offset
currency fluctuations between the U.S. dollar and the Chilean peso associated
with expected equity contributions to an affiliate in 1995, 1996 and 1997. The
hedge transaction has a notional amount of approximately $4.4 million at
December 31, 1996. Duke Energy Group, Inc. records any realized gains or losses
associated with the hedge as an adjustment to investments in affiliates.
Duke/Louis Dreyfus (D/LD) enters into various derivative financial
instruments involving future settlement. These transactions include
exchange-traded futures and options and over-the-counter swaps and options for
commodities, primarily natural gas and electricity. D/LD's derivative financial
instruments are used for trading and marketing activities. These instruments are
accounted for at market value and the related unrealized gains and losses are
recognized in income. D/LD utilizes various risk management procedures to
monitor its exposure and minimize counterparty risk.
Duke Power's embedded cost of long-term debt, excluding debt of
subsidiaries, was 7.95 percent for 1996 compared to 7.94 percent in 1995 and
7.98 percent in 1994. The embedded cost of preferred stock was 6.99 percent in
1996 compared to 7.06 percent in 1995 and 6.99 percent in 1994. The increase in
the embedded cost of long-term debt from 1995 to 1996 is primarily the result of
maturing lower cost debt. The decrease in the embedded cost of preferred stock
from 1995 to 1996 reflects the impact of decreased adjustable dividend rates on
a certain series of preferred stock.
FIXED CHARGES COVERAGE. Consolidated fixed charges coverage using the SEC
method was 5.07 times for 1996 compared to 4.94 and 4.72 times for 1995 and
1994, respectively. The increase is primarily a result of higher earnings.
Consolidated fixed charges coverage, excluding AFUDC and other deferred returns,
was 4.69 times for 1996 compared with 4.52 for 1995 and 4.32 for 1994 and the
Company goal of 3.5 times. The increase in coverage is primarily the result of
higher earnings, excluding AFUDC and other deferred returns.
CAPITAL NEEDS
PROPERTY ADDITIONS AND RETIREMENTS. Additions to property and nuclear fuel
of $720 million and retirements of $396 million resulted in an increase in gross
plant of $324 million in 1996.
Since January 1, 1994, additions to property and nuclear fuel of $4 billion
and retirements of $2.5 billion have resulted in an increase in gross plant of
$1.5 billion.
CONSTRUCTION EXPENDITURES. Plant construction costs for generating
facilities supporting Duke Power electric operations, including AFUDC, decreased
from $309 million in 1994 to $164 million in 1996, primarily because of the
completion of the Lincoln Combustion Turbine Station. (For more information, see
"Capital Needs -- Meeting Future Power Needs.") Construction costs for
distribution plant, including AFUDC, increased from $203 million in 1994 to $227
million in 1996.
Projected construction and nuclear fuel costs for Duke Power's electric
operations, both including AFUDC, are $2.6 billion and $716 million,
respectively, for 1997 through 2001. These construction expenditures are
primarily for distribution and production-related activities representing $1.3
billion and $864 million, respectively. These projections are subject to
periodic reviews and revisions. Actual construction and nuclear fuel costs and
capital expenditures incurred may vary from such estimates. Cost variances are
due to various factors, including revised load estimates, environmental matters
and cost and availability of capital.
Projected capital expenditures of subsidiaries and diversified activities
are $1.5 billion for 1997 through 2001, of which a significant portion is real
estate and power project development. These projections are subject to periodic
reviews and revisions and may vary significantly as business plans evolve to
meet the opportunities presented by their markets.
For 1997 through 2001, the Company anticipates substantially funding its
projected construction and capital expenditures through the internal generation
of funds.
PURCHASED CAPACITY LEVELIZATION. The rates established in Duke Power's
electric retail jurisdictions permit recovery of its investment in both units of
the Catawba Nuclear Station and the costs associated with contractual purchases
of capacity from the other joint owners of the Catawba Nuclear Station. The
contracts relating to the sales of portions of the station obligate the Company
to purchase a declining amount of capacity from the other joint owners. In the
North Carolina retail jurisdiction, regulatory treatment of these contracts
provides revenue for recovery of the capital costs and the fixed operating and
maintenance costs of purchased capacity on a levelized basis. In the South
Carolina retail jurisdiction, revenues have been 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.
21
Such rate treatments require the Company to fund portions of the purchased
capacity payments until these costs, including returns, are recovered at a later
date. The Company recovers the accumulated costs and returns when the sum of the
declining purchased capacity payments and accrual of returns for the current
period drop below the levelized revenues. During 1996, in the North Carolina
retail jurisdiction and the wholesale jurisdiction regulated by the Federal
Energy Regulatory Commission (FERC), annual levelized revenues exceeded
purchased capacity payments and the accrual of deferred returns for the first
time. In the South Carolina retail jurisdiction, cumulative levelized revenues
have exceeded purchased capacity payments and accrual of deferred returns. The
PSCSC, on May 7, 1996, ordered a rate reduction in the form of a decrement rider
for an interim true-up adjustment. (For additional information on the South
Carolina rate reduction, see "Liquidity and Resources -- Duke Power Company Rate
Matters.") Jurisdictional levelizations are intended to recover total costs,
including returns, and are subject to adjustments, including final true-ups.
MEETING FUTURE POWER NEEDS. The Company's strategy for meeting customers'
present and future energy needs consists of three components: supply-side
resources, demand-side resources and purchased power resources. To assist in
determining the optimal combination of these three resources, the Company uses
an integrated resource planning process. The goal is to provide adequate and
reliable electricity in an environmentally responsible, cost-effective manner.
As customers elect to procure generation from other suppliers, as two of the
Company's wholesale customers have indicated they will do beginning in 1997, the
Company will no longer be obligated to plan for the future generation needs of
those customers.
The Company has completed the construction of a combustion turbine facility
in Lincoln County, North Carolina, to provide capacity at periods of peak
demand. The station consists of 16 combustion turbines with a total generating
capacity of 1,200 megawatts. During 1995, twelve units of the Lincoln Combustion
Turbine Station began commercial operation. The last four units began commercial
operation in the first quarter of 1996.
The purchase of capacity and energy is also an integral part of meeting
future power needs. As of January 1, 1997, the Company has 329 megawatts of firm
purchased capacity from other generators of electricity under contract,
including 91 megawatts from qualifying facilities.
In 1995, the Company issued two requests for proposals (RFP) to solicit
both short-term and long-term competitive bids to provide future electric
generating capacity resources. After review of all the bids, the Company
selected a short-term bid from PECO Energy Co. of Philadelphia. The agreement
gives the Company the option to purchase up to 250 megawatts of capacity during
the summer months of 1998 through 2001. Contract arrangements between the
parties were finalized on August 1, 1996. The long-term RFP was closed and no
bids were accepted.
Demand-side management programs benefit the Company and its customers by
providing cost-effective energy efficiency, providing for load control through
interruptible control features, shifting usage to off-peak periods and
increasing strategic sales of electricity. The November 1991 rate orders of the
NCUC and the PSCSC provided for recovery in rates of a designated level of costs
for demand-side management programs and allowed the deferral for later recovery
of certain demand-side management costs that exceed the level reflected in
rates, including a return on the deferred costs. The May 1996 rate rider in
South Carolina included an increment for demand-side management cost recovery.
(For additional information on the South Carolina rate rider, see "Liquidity and
Resources -- Duke Power Company Rate Matters.") The Company ultimately expects
recovery through rates of associated deferred costs, not to exceed $75 million
including deferred returns in the North Carolina retail jurisdiction. The annual
costs deferred, including the return, were approximately $9 million and $2
million in North Carolina and South Carolina, respectively, in 1996 and $16
million and $11 million in North Carolina and South Carolina, respectively, in
1995. As of December 31, 1996, the balance of deferred demand-side management
costs as presented on the Consolidated Balance Sheets in "Other deferred debits"
is $67 million and $40 million in North Carolina and South Carolina,
respectively.
CURRENT ISSUES
While the Company improved its financial performance in 1996 compared to
1995, its ability to maintain and improve its current level of earnings will
depend on several factors. As the electric industry becomes increasingly
competitive, the Company's ability to control costs will be an important factor
in maintaining a pricing structure that is both attractive to customers and
profitable to the Company. Wheeling of third-party energy to a retail customer
is not generally allowed in the Company's service territory. However, there are
discussions and events at the national level and within certain states regarding
retail competition which could result in changes in the industry. On April 24,
1996, the FERC issued its final rules on open-access transmission, providing
energy suppliers with opportunities to sell and deliver capacity and energy at
market-based prices. (For additional information on competition, see "Current
Issues -- Competition.") Management cannot predict the outcome of these matters
and their impact, if any, on the Company's financial position and results of
operation. The
22
Company is focusing on providing competitive prices to its industrial customers,
as well as to wholesale customers who have access to alternative sources of
energy. Other significant factors impacting the Company's future earnings levels
include continued economic growth in the Piedmont Carolinas, the success of the
Company's subsidiaries and diversified activities, and the outcome of various
legislative and regulatory actions.
PROPOSED MERGER WITH PANENERGY CORP. On November 25, 1996, the Company and
PanEnergy Corp announced a proposed stock-for-stock transaction creating an
integrated energy company. Upon consummation of the merger, PanEnergy will be a
wholly owned subsidiary of the Company, and the Company's name will be changed
to Duke Energy Corporation. The transaction is expected to close by December 31,
1997, subject to approval of the shareholders of both companies and all
applicable regulatory approvals. The shareholders of each company will vote on
the proposed merger at their annual meetings, which are scheduled for April 24,
1997 for both companies. Applications for regulatory approval were filed with
the NCUC and the PSCSC on December 19, 1996, and with the FERC on February 3,
1997. Regulatory proceedings are expected to be successfully completed by
year-end 1997. In connection with the transaction, each share of PanEnergy
common stock will be converted into 1.0444 shares of common stock of the
Company. The transaction will be accounted for as a pooling of interests.
Further details about the proposed acquisition are provided in the Company's
report on Form 8-K, filed with the Securities and Exchange Commission on
December 9, 1996, and in the Joint Proxy Statement-Prospectus provided to
shareholders in connection with the Company's annual meeting. Unless otherwise
indicated, all information presented herein relates to the Company only and does
not take into account the proposed merger with PanEnergy.
RESOURCE OPTIMIZATION. The Company has been engaged in a concentrated
effort to more efficiently and effectively use its resources through better work
practices. In 1995, the Company offered to certain employees an Enhanced Vested
Benefits program (EVB) which gave targeted employees, who left the Company, an
enhanced vested retirement package and the Company's standard severance pay
based on years of service. This program resulted in the elimination of
approximately 900 positions during 1996. During 1994, the Company offered an
Enhanced Voluntary Separation program (EVS) which gave most employees the option
of leaving the Company for a lump-sum payment and the Company's standard
severance pay based on years of service. This program resulted in the departure
of approximately 1,300 employees in 1994. Implementing various efficiency
practices has resulted in streamlined work flows and provided the opportunity
for work force reduction programs such as EVB and EVS.
FULL-TIME EMPLOYEES
1996 1991
Duke Power electric operations..................................................... 15,002 18,187
Subsidiaries and diversified businesses............................................ 2,724 364
Total............................................................................ 17,726 18,551
The increase in workforce of subsidiaries and diversified businesses is
commensurate with the growth in their business opportunities.
NUCLEAR DECOMMISSIONING COSTS. Estimated site-specific nuclear
decommissioning costs, including the cost of decommissioning plant components
not subject to radioactive contamination, total approximately $1.3 billion
stated in 1994 dollars based on decommissioning studies completed in 1994. This
amount includes the Company's 12.5 percent ownership in the Catawba Nuclear
Station. The other joint owners of the Catawba Nuclear Station are responsible
for decommissioning costs related to their ownership interests in the station.
Such estimates presume each unit will be decommissioned as soon as possible
following the end of its license life. Although subject to extension, the
current operating licenses for the Company's nuclear units expire as follows:
Oconee 1 and 2 -- 2013, Oconee 3 -- 2014; McGuire 1 -- 2021, McGuire 2 -- 2023;
and Catawba 1 -- 2024, Catawba 2 -- 2026.
In accordance with a 1988 Nuclear Regulatory Commission order, during 1996,
the Company expensed approximately $56 million which was contributed to the
external funds and accrued an additional $2 million to the internal reserve. The
balance of the external funds as of December 31, 1996, was $363 million. The
balance of the internal reserve as of December 31, 1996, was $208 million and is
reflected in accumulated depreciation and amortization on the Consolidated
Balance Sheets.
Both the NCUC and the PSCSC have granted the Company recovery of estimated
decommissioning costs through retail rates over the expected remaining service
periods of the Company's nuclear plants. Decommissioning costs being recovered
23
through rates, invested at assumed after-tax earnings rate of 5.5 percent to 5.9
percent, are sufficient to provide for the estimated cost of decommissioning.
As required under the Nuclear Waste Policy Act of 1982, the Company entered
into a contract with the U.S. Department of Energy (DOE) under which the DOE
agreed to dispose of the Company's spent nuclear fuel. The DOE has announced
that the department anticipates a delay in accepting the waste materials on the
contract date of January 31, 1998. The Company has joined with 35 other
utilities in a lawsuit attempting to force the DOE to meet its obligations as
called for in the contract. While it is uncertain what interim storage will be
provided by the DOE due to its inability to meet the contract date, the Company
has satisfactory plans in place to provide storage of spent nuclear fuel if the
DOE cannot accept it.
ENVIRONMENTAL ISSUES. The Company is subject to federal, state and local
regulations regarding air and water quality, hazardous and solid waste disposal,
and other environmental matters. The Company was an operator of manufactured gas
plants until the early 1950s. The Company has entered into a cooperative effort
with the State of North Carolina and other owners of certain former manufactured
gas plant sites to investigate and, where necessary, remediate these
contaminated sites. The State of South Carolina has expressed interest in
entering into a similar arrangement. The Company is considered by regulators to
be a potentially responsible party and may be subject to liability at four
federal Superfund 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, efficient
plant operations and by using nuclear generation. The sulfur dioxide provisions
of the Act allow utilities to choose among various alternatives for compliance.
To meet the Phase II requirements by 2000, the Company's current strategy
includes the use of lower sulfur coal, emission allowance purchases, low
nitrogen oxide burners and emission monitoring equipment. A one-time cost
associated with bringing the Company into compliance with the Act could range
from $94 million to $260 million. Additional operating expenses of approximately
$25 million will be incurred for fuel premiums and emission allowance purchases
each year after 2000. This strategy is contingent upon developments in the
emissions allowance market, lower sulfur coal premiums, future regulatory and
legislative actions, and advances in clean air technology.
STRESS CORROSION CRACKING. Stress corrosion cracking (SCC) has occurred in
the steam generators of Units 1 and 2 at the McGuire Nuclear Station and Unit 1
at the Catawba Nuclear Station. Catawba Unit 2, which has certain design
differences and came into service at a later date, has not yet shown the degree
of SCC which has occurred in McGuire Units 1 and 2 and Catawba Unit 1. It is,
however, too early in the life of Catawba Unit 2 to determine the extent to
which SCC may be a problem. Although the Company has taken steps to mitigate the
effects of SCC, the inherent potential for future SCC in the McGuire and Catawba
steam generators still exists. The Company planned for the replacement of steam
generators at three units that have experienced SCC and purchased the
replacement steam generators from Babcock & Wilcox International. Replacement of
the steam generators at Catawba Unit 1 was successfully completed at a lower
cost than projected on October 4, 1996, after a 115-day outage that included
replacement work and other maintenance. Steam generator replacement in both
McGuire units is scheduled for completion during 1997. The Catawba Unit 2 steam
generators have not been scheduled for replacement. Steam generator replacement
at each McGuire unit is expected to take approximately four months and cost
approximately $170 million, excluding the cost of replacement power. Stress
corrosion problems are excluded under the Company's nuclear insurance policies.
The Company, in connection with its McGuire and Catawba stations and on
behalf of the other joint owners of the Catawba Station, began a legal action in
1990, alleging that Westinghouse Electric Corporation knowingly supplied to the
McGuire and Catawba stations steam generators that were defective in design,
workmanship and materials, requiring replacement well short of their stated
design life. The lawsuit was settled in 1994. While the court order does not
allow disclosure of the terms of the settlement, the Company believes the
litigation was settled on terms that provided satisfactory consideration to the
Company and will not have a material effect on the Company's results of
operations or financial position.
COMPETITION. The Energy Policy Act of 1992 (EPACT) and the FERC's
subsequent rulemaking activities are major drivers towards a more competitive
market for electric generation. EPACT reformed provisions of the Public Utility
Holding Company Act of 1935 (PUHCA) and Part II of the Federal Power Act to
remove certain barriers to competition for the supply of electricity. For
example, EPACT allows utilities to participate in the development of independent
electric generating plants in the United States for sales to wholesale
customers, as well as to contract for utility projects internationally,
24
without becoming subject to regulation under PUHCA as an electric utility
holding company. In addition, EPACT permits the FERC to order transmission
access for third parties to transmission facilities owned by another entity so
that energy suppliers can sell to wholesale customers wherever they are located.
It does not, however, permit the FERC to issue an order requiring transmission
access to retail customers.
The FERC, responsible in large measure for implementation of the EPACT, has
moved vigorously to implement its mandate, interpreting the statute broadly in
issuing orders for third-party transmission service and issuing a number of
rules of general applicability. On April 24, 1996, the FERC issued its Order
Numbers 888 and 889, which established the final form of transmission tariff to
provide comparable service to all users of a utility's transmission system.
Open-access transmission for wholesale customers as defined by the FERC's
final rules provides energy suppliers, including the Company, with opportunities
to sell and deliver capacity and energy at market-based prices. Engaging in such
transactions may result in improved utilization of the Company's existing
assets. In addition, such access provides another supply option through which
the Company can buy capacity and energy at attractive rates, influencing its
competitive price position. However, sales to existing wholesale customers of
the Company may continue to be impacted by open access either due to competitive
pressure on the wholesale price of electricity, or the potential loss of sales
as wholesale customers seek other options to meet their capacity and energy
requirements at market-based prices. (For additional information about sales to
wholesale customers, see "Liquidity and Resources -- Duke Power Company Rate
Matters," and Note 3, "Notes to Consolidated Financial Statements.") Wholesale
sales represented approximately 8.8 percent of the Company's total kilowatt-hour
sales in 1996. Supplemental sales to the other joint owners of the Catawba
Nuclear Station comprised the majority of such sales. Such supplemental sales
will continue to decline in 1997 as a result of the retention of larger portions
of ownership entitlement by the other joint owners. (For additional information
on Catawba joint ownership, see Note 3, "Notes to the Consolidated Financial
Statements.")
In early 1995, prior to issuance of the FERC's Notice of Proposed
Rulemaking, the Company and certain of its affiliates filed three applications
with the FERC, all of which were designed to enable effective participation in
the competitive environment of the changing electric utility industry. Duke
Power filed an application for permission to sell at market-based rates up to
2,500 megawatts of capacity and energy from its own assets. Two of the Company's
affiliates, Duke Energy Marketing Corp. (DEMC) and Duke/Louis Dreyfus L.L.C.
(D/LD), filed applications with the FERC to become power marketers. All of the
applications were supported by transmission tariffs which complied with
then-applicable FERC standards and established the rates, terms and conditions
for transmission service to third parties on the Company's transmission system.
Late in 1995, the FERC granted the applications of Duke, DEMC, and D/LD;
accepted Duke's transmission tariffs; and ordered a hearing on the rates to be
charged for service under those tariffs. On July 9, 1996, in compliance with the
standards and schedules set forth in Order Number 888, the Company filed a pro
forma open access transmission tariff complying with the requirements of the
FERC's final rules. Such a filing was required of all transmission-owning
utilities subject to the FERC's jurisdiction. The Company also filed on that
date a proposed settlement in the proceeding earlier ordered by the FERC. The
proposed settlement resolves all rate issues related to transmission services
under Duke's tariff and contains the rates agreed upon under the settlement. The
settlement and the July 9, 1996 tariff filing remain subject to final FERC
approval.
Competition for retail customers is not generally allowed in the Company's
service territory. However, there are discussions and events at the national
level and within certain states, including North and South Carolina, regarding
retail competition which could result in changes in the industry. Such changes,
should they occur, could impact all entities owning generation, including the
other joint owners of the Catawba Nuclear Station.
Currently, the electric utility industry is predominantly regulated on a
basis designed to recover the cost of providing electric power to its retail and
wholesale customers. If cost-based regulation were to be discontinued in the
industry, for any reason, including competitive pressure on the cost-based
prices of electricity, profits could be reduced and utilities might be required
to reduce their asset balances to reflect a market basis less than cost.
Discontinuance of cost-based regulation would also require affected utilities to
write off their associated regulatory assets. The regulatory assets of the
Company are classified as "Deferred debits" on the Consolidated Balance Sheets.
Substantially all of the "Deferred debits" are regulatory assets. Management
cannot predict the potential impact, if any, of these competitive forces on the
Company's future financial position and results of operations. However, the
Company continues to position itself to effectively meet these challenges by
maintaining prices that are locally, regionally and nationally competitive.
COMMITMENTS AND CONTINGENCIES. The Company is involved in legal, tax and
regulatory proceedings before various courts, regulatory commissions and
governmental agencies regarding matters arising in the ordinary course of
business, some of which may involve substantial amounts. Where appropriate, the
Company has made accruals in accordance with Statement of Financial Accounting
Standards No. 5, "Accounting for Contingencies," in order to provide for such
matters. Management
25
is of the opinion that the final disposition of these proceedings will not have
a material adverse effect on the results of operations or the financial position
of the Company.
SUBSIDIARIES AND DIVERSIFIED OPERATIONS. The Company continues to
aggressively pursue both domestic and international diversified business
opportunities that are synergistic with the Company's core business to provide
additional value to the Company's shareholders. Among the Company's current
industry pursuits are ownership of electric power facilities, energy marketing,
real estate, communications, engineering consulting and various energy services.
Although these opportunities are primarily concentrated in areas that utilize
the Company's expertise, they present different and potentially greater risks
than does the Company's core business. The Company only pursues opportunities in
which the expected returns are commensurate with the risks and makes efforts to
mitigate such risks. The Company undertakes a continuous evaluation of the
various lines of business it may enter or exit, with the objective of enhancing
shareholder value and managing any associated risk.
Domestically, non-electric property of the Company's subsidiaries and
diversified activities was $404 million and $335 million at December 31, 1996
and 1995, respectively. The Company had equity investments in affiliates, which
own assets within the United States, of $82 million and $58 million at December
31, 1996 and 1995, respectively.
Internationally, the Company had equity investments in affiliates, which
own generation and transmission facilities, of $107 million and $105 million at
December 31, 1996 and 1995, respectively. Additionally, the Company, through its
non-regulated subsidiaries, had loaned $3 million and $23 million to certain of
these affiliates at December 31, 1996 and 1995, respectively.
The Company's subsidiaries and diversified activities contributed $51
million to net income in 1996 compared with $54 million in 1995 and $52 million
in 1994. From 1994 to 1996, increased developed lot and land sales, and
engineering services and construction fees generated additional income. These
increases were offset by personal communications services joint venture start-up
losses and a provision for an investment in a plant in Argentina.
26
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
DUKE POWER COMPANY
INDEX
PAGE
Consolidated Financial Statements:
Consolidated Statements of Income for the Three Years Ended December 31, 1996..................................... 28
Consolidated Statements of Retained Earnings for the Three Years Ended December 31, 1996.......................... 29
Consolidated Statements of Cash Flows for the Three Years Ended December 31, 1996................................. 30
Consolidated Balance Sheets -- December 31, 1996 and 1995......................................................... 31
Notes to Consolidated Financial Statements............................................................................. 32
Independent Auditors' Report........................................................................................... 48
Responsibility for Financial Statements................................................................................ 48
Selected Quarterly Financial Data (Unaudited).......................................................................... 49
Subsidiaries and Diversified Activities Highlights..................................................................... 50
Consolidated Financial Statement Schedule:
Schedule II -- Valuation and Qualifying Accounts and Reserves for the Three Years Ended
December 31, 1996............................................................................................... 54
27
CONSOLIDATED STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31,
1996 1995 1994
DOLLARS IN THOUSANDS
Operating Revenues (Notes 1, 2 and 11).............................................. $4,757,974 $4,676,684 $4,488,913
Operating Expenses
Fuel used in electric generation (Note 1)......................................... 758,498 744,226 705,019
Net interchange and purchased power (Notes 2 and 3)............................... 378,724 468,293 553,355
Other operation and maintenance................................................... 1,505,028 1,403,547 1,341,659
Depreciation and amortization (Note 1)............................................ 492,185 458,131 459,781
General taxes..................................................................... 261,336 253,436 249,273
Total operating expenses....................................................... 3,395,771 3,327,633 3,309,087
Operating Income.................................................................... 1,362,203 1,349,051 1,179,826
Interest Expense and Other Income (Note 1)
Interest expense.................................................................. (283,075) (289,318) (270,217)
Allowance for funds used during construction and other deferred returns........... 111,891 125,040 111,872
Other, net........................................................................ 14,638 (3,794) 14,414
Total interest expense and other income........................................ (156,546) (168,072) (143,931)
Income Before Income Taxes.......................................................... 1,205,657 1,180,979 1,035,895
Income Taxes (Notes 1 and 4)........................................................ 475,691 466,441 397,019
Net Income.......................................................................... 729,966 714,538 638,876
Dividends on preferred and preference stock....................................... 44,245 48,903 49,724
Earnings for Common Stock........................................................... $ 685,721 $ 665,635 $ 589,152
Common Stock Data (Note 6)
Average shares outstanding (thousands)............................................ 203,553 204,859 204,859
Earnings per share................................................................ $ 3.37 $ 3.25 $ 2.88
Dividends per share............................................................... $ 2.08 $ 2.00 $ 1.92
See notes to consolidated financial statements.
28
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
YEAR ENDED DECEMBER 31,
1996 1995 1994
DOLLARS IN THOUSANDS
Balance -- Beginning of year........................................................ $2,858,275 $2,605,920 $2,410,825
Add -- Net income................................................................... 729,966 714,538 638,876
Total........................................................................ 3,588,241 3,320,458 3,049,701
Deduct
Dividends
Common stock................................................................... 423,064 409,716 393,370
Preferred and preference stock................................................. 44,245 48,903 49,724
Capital stock transactions, net................................................... 128,358 3,564 687
Total deductions............................................................. 595,667 462,183 443,781
Balance -- End of year.............................................................. $2,992,574 $2,858,275 $2,605,920
See notes to consolidated financial statements.
29
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
1996 1995 1994
DOLLARS IN THOUSANDS
Cash Flows from Operating Activities
Net Income........................................................................ $ 729,966 $ 714,538 $ 638,876
Adjustments to reconcile net income to net cash provided by operating activities:
Non-cash items
Depreciation and amortization.................................................. 667,713 674,816 647,515
Deferred income taxes and investment tax credit amortization................... (27,641) 5,989 94,261
Allowance for equity funds used during construction............................ (15,824) (23,082) (27,411)
Purchased capacity levelization................................................ 73,473 (33,149) (268,925)
Other, net..................................................................... 47,384 76,029 22,460
(Increase) Decrease in
Accounts receivable.......................................................... (20,289) (136,838) 47,586
Inventory.................................................................... 40,476 (14,549) (28,568)
Prepayments.................................................................. (1,031) (7,178) (435)
Increase (Decrease) in
Accounts payable............................................................. 15,153 11,694 (52,506)
Taxes accrued................................................................ (19,750) 14,454 (51,641)
Interest accrued and other liabilities....................................... (6,966) 28,934 14,523
Total adjustments.............................................................. 752,698 597,120 396,859
Net cash provided by operating activities................................. 1,482,664 1,311,658 1,035,735
Cash Flows from Investing Activities
Construction expenditures and other property additions............................ (646,465) (713,299) (772,452)
Investment in nuclear fuel........................................................ (84,206) (76,603) (108,711)
External funding for decommissioning.............................................. (56,470) (56,470) (52,524)
Pre-funded pension cost........................................................... -- -- (30,000)
Investment in affiliates.......................................................... (25,708) (54,945) (6,718)
Net change in investment securities............................................... (25,887) 54,425 17,922
Net cash used in investing activities..................................... (838,736) (846,892) (952,483)
Cash Flows from Financing Activities
Proceeds from the issuance of
First and refunding mortgage bonds............................................. -- 173,839 343,824
Short-term notes payable, net.................................................. (49,750) 48,200 86,300
Construction loans and other................................................... 113,997 47,643 57,032
Payments for the redemption of
First and refunding mortgage bonds............................................. (3,097) (157,365) (81,781)
Common stock................................................................... (159,000) -- --
Construction loans and other................................................... (91,548) (9,416) (18,885)
Preferred stock................................................................ -- (100,516) (1,500)
Dividends paid.................................................................... (466,751) (458,018) (443,633)
Other............................................................................. 2,917 (1,153) (20,991)
Net cash used in financing activities..................................... (653,232) (456,786) (79,634)
Net increase (decrease) in cash..................................................... (9,304) 7,980 3,618
Cash at beginning of year........................................................... 45,410 37,430 33,812
Cash at End of Year................................................................. $ 36,106 $ 45,410 $ 37,430
See notes to consolidated financial statements.
30
CONSOLIDATED BALANCE SHEETS
YEAR ENDED DECEMBER 31,
1996 1995
Dollars in Thousands
ASSETS
Current Assets
Cash (Notes 5 and 10)............................................................................. $ 36,106 $ 45,410
Short-term investments (Notes 1 and 10)........................................................... 72,712 76,300
Receivables (less allowance for losses: 1996 -- $7,134; 1995 -- $6,352) (Note 1).................. 709,992 689,703
Inventory -- at average cost...................................................................... 301,365 341,841
Prepayments and other............................................................................. 23,931 22,900
Total current assets.......................................................................... 1,144,106 1,176,154
Investments and Other Assets
Investments in affiliates (Note 11)............................................................... 188,982 163,274
Other investments, at cost or less (Note 10)...................................................... 114,669 85,194
Nuclear decommissioning trust funds (Notes 10 and 14)............................................. 362,627 273,466
Pre-funded pension cost (Note 12)................................................................. 80,000 80,000
Total investments and other assets............................................................ 746,278 601,934
Property, Plant and Equipment (Notes 1, 3, 9, 13 and 14)
Electric plant in service (at original cost)
Production...................................................................................... 7,278,439 7,154,332
Transmission.................................................................................... 1,543,688 1,532,302
Distribution.................................................................................... 4,303,885 4,105,513
Other........................................................................................... 1,068,342 1,030,226
Electric plant in service..................................................................... 14,194,354 13,822,373
Less accumulated depreciation and amortization.................................................. 5,438,498 5,122,192
Electric plant in service, net................................................................ 8,755,856 8,700,181
Nuclear fuel.................................................................................... 604,813 731,691
Less accumulated amortization................................................................... 363,290 453,921
Nuclear fuel, net............................................................................. 241,523 277,770
Construction work in progress (including nuclear fuel in process: 1996 -- $27,546;
1995 -- $25,500)................................................................................ 388,999 382,582
Total electric plant, net..................................................................... 9,386,378 9,360,533
Other property -- at cost (less accumulated depreciation: 1996 -- $31,544; 1995 -- $29,956)....... 426,039 354,713
Total property, plant and equipment, net...................................................... 9,812,417 9,715,246
Deferred Debits (Notes 1, 3, 4 and 13)
Purchased capacity costs.......................................................................... 892,000 965,473
Debt expense...................................................................................... 169,842 180,930
Regulatory asset related to income taxes.......................................................... 488,936 490,676
Regulatory asset related to DOE assessment fee.................................................... 94,717 101,274
Other............................................................................................. 121,394 126,797
Total deferred debits......................................................................... 1,766,889 1,865,150
Total Assets........................................................................................ $13,469,690 $13,358,484
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable.................................................................................. $ 327,315 $ 343,692
Notes payable (Notes 5 and 10).................................................................... 105,550 155,300
Taxes accrued (Note 1)............................................................................ 973 34,884
Interest accrued.................................................................................. 64,589 73,675
Current maturities of long-term debt (Note 9)..................................................... 212,309 12,071
Other (Note 13)................................................................................... 152,233 149,555
Total current liabilities..................................................................... 862,969 769,177
Long-Term Debt (Notes 5, 9 and 10).................................................................. 3,538,114 3,711,405
Accumulated Deferred Income Taxes (Notes 1 and 4)................................................... 2,376,012 2,382,204
Deferred Credits and Other Liabilities
Investment tax credit (Notes 1 and 4)............................................................. 250,117 261,347
DOE assessment fee (Note 1)....................................................................... 94,717 101,274
Nuclear decommissioning costs externally funded (Note 14)......................................... 362,627 273,466
Other............................................................................................. 412,419 390,427
Total deferred credits and other liabilities.................................................. 1,119,880 1,026,514
Preferred and Preference Stock with Sinking Fund Requirements (Notes 8 and 10)...................... 234,000 234,000
Preferred and Preference Stock without Sinking Fund Requirements (Notes 7 and 10)................... 450,000 450,000
Commitments and Contingencies (Notes 11 and 13).....................................................
Common Stockholders' Equity (Note 6)
Common stock, no par, 300,000,000 shares authorized;
201,589,596 shares outstanding for 1996 and
204,859,339 shares outstanding for 1995....................................................... 1,896,141 1,926,909
Retained earnings................................................................................. 2,992,574 2,858,275
Total common stockholders' equity............................................................. 4,888,715 4,785,184
Total Liabilities and Stockholders' Equity.......................................................... $13,469,690 $13,358,484
See notes to consolidated financial statements.
31
DUKE POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. NATURE OF OPERATIONS
The Company is primarily engaged in the generation, transmission,
distribution and sale of electric energy in the central portion of North
Carolina and the western portion of South Carolina, comprising the area in both
states known as the Piedmont Carolinas. The Company is one of the nation's
largest investor-owned electric utilities.
The Company is also engaged in a variety of diversified operations, most of
which are organized in separate subsidiaries. The Company's subsidiaries and
diversified activities are in the Associated Enterprises Group (AEG). AEG
includes Church Street Capital Corp.; Crescent Resources, Inc.; Duke Energy
Group, Inc.; Duke Engineering & Services, Inc.; Duke/Fluor Daniel; Duke/Louis
Dreyfus, LLC; Duke Merchandising; DukeNet Communications, Inc.; Duke Water
Operations; and Nantahala Power and Light Company. Certain subsidiaries have
invested in both domestic and international affiliates. (See Note 11.)
The financial statements are prepared in conformity with generally accepted
accounting principles appropriate in the circumstances to reflect in all
material respects the substance of events and transactions which should be
included. In preparing these statements, management makes informed judgments and
estimates of the expected effects of events and transactions that are currently
being reported. However, actual results could differ from these estimates.
B. REVENUES
Electric revenues are recorded as service is rendered to customers.
"Receivables" on the Consolidated Balance Sheets include $205,656,000 and
$206,792,000 as of December 31, 1996 and 1995, respectively, for electric
service that has been rendered but not yet billed to customers by Duke Power,
and $4,294,000 as of December 31, 1996 for electric service that has been
rendered but not yet billed to customers by Nantahala Power and Light Company.
C. ADDITIONS TO ELECTRIC PLANT
The Company capitalizes all construction-related direct labor and materials
as well as indirect construction costs. Indirect costs include general
engineering, taxes and the cost of money (allowance for funds used during
construction). The cost of renewals and betterments of units of property is
capitalized.
The cost of repairs and replacements representing less than a unit of
property is charged to electric expenses. The original cost of property retired,
together with removal costs less salvage value, is charged to accumulated
depreciation.
D. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds
necessary to finance the construction of new regulated facilities. AFUDC, a
non-cash item, is recognized as a cost of "Construction work in progress," with
an offsetting credit to "Interest expense and other income." After construction
is completed, the Company is permitted to recover these construction costs,
including a fair return, through their inclusion in rate base and in the
provision for depreciation.
The AFUDC rates of 9.7, 9.3 and 9.6 percent for Duke Power for 1996, 1995
and 1994, respectively, include a component for debt cost on a pre-tax basis.
Rates for all periods are compounded semiannually.
E. OTHER DEFERRED RETURNS
Other deferred returns represent the estimated financing costs associated
with funding certain regulatory assets. These regulatory assets primarily arise
from the Company's funding of purchased capacity costs above levels collected in
rates. Other deferred returns are non-cash items. They are primarily recognized
as an addition to "Purchased capacity costs" and as an offsetting credit to
"Interest expense and other income."
F. DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT
Provisions for electric plant depreciation are recorded using the
straight-line method. The year-end composite weighted-average depreciation rates
were 3.44, 3.48 and 3.46 percent for 1996, 1995 and 1994, respectively.
32
DUKE POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES -- Continued
Amortization of nuclear fuel is included in "Fuel used in electric
generation" in the Consolidated Statements of Income. The amortization is
recorded using the units-of-production method.
Under provisions of the Nuclear Waste Policy Act of 1982, the Company has
entered into contracts with the Department of Energy (DOE) for the disposal of
spent nuclear fuel. Payments made to the DOE for disposal costs are based on
nuclear output and are included in "Fuel used in electric generation" in the
Consolidated Statements of Income.
A provision in the Energy Policy Act of 1992 established a fund for the
decontamination and decommissioning of the DOE's uranium enrichment plants.
Licensees are subject to an annual assessment for 15 years based on their pro
rata share of past enrichment services. The annual assessment is recorded as
fuel expense. The Company paid $9,472,000 during 1996 and has paid $45,022,000
cumulatively related to its ownership interest in nuclear plants. The Company
has reflected the remaining liability and regulatory asset of $94,717,000 in the
Consolidated Balance Sheet at December 31, 1996.
G. SUBSIDIARIES
The Company's consolidated financial statements reflect consolidation of
all of its majority-owned subsidiaries. Intercompany transactions have been
eliminated in consolidation.
H. INCOME TAXES
The Company and its subsidiaries file a consolidated federal income tax
return.
Deferred income taxes have been provided for temporary differences.
Temporary differences occur when events and transactions recognized for
financial reporting result in taxable or tax-deductible amounts in different
periods. Investment tax credits have been deferred and are being amortized over
the estimated useful lives of the related properties.
I. UNAMORTIZED DEBT PREMIUM, DISCOUNT AND EXPENSE
Expenses incurred in connection with the issuance of presently outstanding
long-term debt issued for regulated operations, and premiums and discounts
relating to such debt, are being amortized over the terms of the respective
issues. Also, any call premiums or unamortized expenses associated with
refinancing higher-cost debt obligations used to finance regulated assets and
operations are being amortized over the lives of the new issues of long-term
debt.
J. CONSOLIDATED STATEMENTS OF CASH FLOWS
For purposes of the Consolidated Statements of Cash Flows, the Company's
short-term investments in highly liquid debt instruments, with an original
maturity of three months or less, are included in cash flows from investing
activities and thus are not considered cash equivalents.
Total income taxes paid were $491,340,000, $441,440,000 and $372,416,000
for the years ended December 31, 1996, 1995 and 1994, respectively.
Interest paid, net of amounts capitalized, was $269,219,000, $258,698,000
and $236,696,000 for the years ended December 31, 1996, 1995 and 1994,
respectively.
K. COST-BASED REGULATION
As a regulated entity, the Company is subject to the provisions of SFAS No.
71, "Accounting for the Effects of Certain Types of Regulation." Accordingly,
the Company records certain assets and liabilities that result from the effects
of the ratemaking process that would not be recorded under generally accepted
accounting principles for non-regulated entities. Currently, the electric
utility industry is predominantly regulated on a basis designed to recover the
cost of providing electric power to its retail and wholesale customers. If
cost-based regulation were to be discontinued in the industry for any reason,
including competitive pressure on the cost-based prices of electricity, profits
could be reduced, and utilities might be required to reduce their asset balances
to reflect a market basis less than cost. Discontinuance of cost-based
regulation would also require affected utilities to write off their associated
regulatory assets. The regulatory assets of the Company are classified as
33
DUKE POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES -- Continued
"Deferred debits" on the Consolidated Balance Sheets. Substantially all of the
"Deferred debits" are regulatory assets. Management cannot predict the potential
impact, if any, of these competitive forces on the Company's future financial
position and results of operations. However, the Company continues to position
itself to effectively meet these challenges by maintaining prices that are
locally, regionally and nationally competitive.
NOTE 2. RATE MATTERS
DUKE POWER COMPANY
The North Carolina Utilities Commission (NCUC) and The Public Service
Commission of South Carolina (PSCSC) must approve rates for retail sales within
their respective states. The Federal Energy Regulatory Commission (FERC) must
approve Duke Power's rates for sales to wholesale customers. Sales to the other
joint owners of the Catawba Nuclear Station, which represent a substantial
majority of Duke Power's wholesale revenues, are set through contractual
agreements. (See Note 3.)
The most recent general rate increase requests in Duke Power's retail
jurisdictions were filed and approved in 1991. Duke Power also filed its most
recent general rate increase request within the FERC wholesale jurisdiction in
1991. A negotiated settlement between Duke Power and the wholesale customers was
approved by the FERC in 1992.
Fuel costs are reviewed semiannually in the wholesale jurisdiction and
annually in the South Carolina retail jurisdiction, with provisions for changing
such costs in base rates. In the North Carolina retail jurisdiction, a review of
fuel costs in rates is required annually and during general rate case
proceedings.
All jurisdictions allow Duke Power to adjust rates for past over- or
under-recovery of fuel costs. Therefore, Duke Power reflects in revenues the
difference between actual fuel costs incurred and fuel costs recovered through
rates.
The PSCSC, on May 7, 1996, ordered a rate reduction in the form of a
decrement rider of 0.432 cents per kilowatt-hour, or an average of approximately
8 percent, affecting South Carolina retail customers. South Carolina retail
sales represent approximately 30 percent of the Company's total retail sales.
The rate reduction was reflected on bills rendered on or after June 1, 1996.
This net decrement rider reflects an interim true-up decrement adjustment
associated with the levelization of Catawba Nuclear Station purchased capacity
costs and an interim true-up increment associated with amortization of the
demand-side management deferral account. The rate adjustment was made because,
in the South Carolina retail jurisdiction, cumulative levelized revenues
associated with the recovery of Catawba purchased capacity costs had exceeded
purchased capacity payments and accrual of deferred returns, and certain
demand-side costs had exceeded the level reflected in rates.
Certain of the Company's wholesale customers, excluding the other Catawba
joint owners, initiated proceedings in 1995 before the FERC concerning rate
matters. The Company and nine of its eleven wholesale customers entered into a
settlement in July 1996 which reduced the customers' rates by approximately 9
percent and renewed their contracts with the Company through the year 2000. Both
of the customers that did not enter into the settlement have signed agreements
to purchase energy from other suppliers beginning in 1997. The eleven wholesale
customers involved in this matter accounted for less than 2 percent of the
Company's overall electric revenues during 1996. The two customers that have
signed agreements with other suppliers accounted for less than 0.5 percent of
the Company's 1996 overall electric revenues.
NANTAHALA POWER AND LIGHT COMPANY
During 1996, Nantahala Power and Light Company (NP&L) filed an application
with and received approval from the NCUC to increase its annual retail service
revenues by $4.6 million. NP&L's wholesale rates are adjusted annually to
reflect current costs. Purchased power costs of NP&L are reviewed annually and
during general rate case proceedings by the NCUC. NP&L is allowed to adjust
rates for past over- or under-recovery of purchased power costs. Therefore, NP&L
defers the difference between actual purchased power costs incurred and those
recovered through rates.
34
DUKE POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE 3. JOINT OWNERSHIP OF GENERATING FACILITIES
The Company previously sold interests in both units of the Catawba Nuclear
Station. The other owners of portions of the Catawba Nuclear Station and
supplemental information regarding their ownership are as follows:
OWNERSHIP INTEREST
OWNER IN THE STATION
North Carolina Municipal Power Agency Number 1 (NCMPA)........................ 37.5%
North Carolina Electric Membership Corporation (NCEMC)........................ 28.125%
Piedmont Municipal Power Agency (PMPA)........................................ 12.5%
Saluda River Electric Cooperative, Inc. (Saluda River)........................ 9.375%
Each owner has provided its own financing for its ownership interest in the
station.
The Company retains a 12.5 percent ownership interest in the Catawba
Nuclear Station. As of December 31, 1996, $497,304,000 of "Electric plant in
service" and "Nuclear fuel" represents the Company's investment in Units 1 and
2. Accumulated depreciation and amortization of $192,057,000 associated with
Catawba has been recorded as of year-end. The Company's share of operating costs
of Catawba is included in the Consolidated Statements of Income.
In connection with the joint ownership, the Company has entered into
contractual agreements with the other joint owners to purchase declining
percentages of the generating capacity and energy from the plant. These
purchased power agreements were effective beginning with the commercial
operation of each unit. Unit 1 and Unit 2 began commercial operation in June
1985 and August 1986, respectively. The purchased power agreements were
established for 15 years for NCMPA and PMPA and 10 years for NCEMC and Saluda
River. While the purchased power agreements with NCMPA and PMPA extend for 15
years, a significant decrease in the percentage of capacity and energy the
Company is obligated to purchase occurs in the 11th calendar year of operation
for each unit. This significant decrease occurred in 1995 for Unit 1 and 1996
for Unit 2.
The agreements also provide for supplemental power sales by the Company to
the other joint owners. Such power sales are to satisfy capacity and energy
needs of the other joint owners beyond the capacity and energy which they retain
from Catawba or potentially acquire in the form of other resources. The
agreements further provide the other joint owners the ability to secure such
supplemental requirements outside of these contractual agreements following an
appropriate notice period. NCEMC and Saluda River have given appropriate notice
that they intend to acquire their supplemental capacity requirements outside of
these agreements effective January 1, 2001 and January 1, 2002, respectively,
thus relieving the Company of the obligation to serve this portion of load. As
the joint owners retain more capacity and energy from Catawba, or a third party,
supplemental power sales are expected to decline.
The agreements with each of the other joint owners include provisions that
the Company will provide generating reserves to backstand the other joint
owners' retained capacity in the Catawba plant at the system average cost of
installed capacity. Additionally, the agreements include certain reliability
exchanges designed to manage outage-related risks by exchanging energy
entitlements between the Catawba Nuclear Station and the McGuire Nuclear
Station, impacting the Company as well as all the other joint owners.
35
DUKE POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE 3. JOINT OWNERSHIP OF GENERATING FACILITIES -- Continued
Purchased energy cost payments are based on variable operating costs and
are a function of the generation output of Catawba. Purchased capacity payments
are based on the fixed costs of the plant and include the capital costs and
fixed operating and maintenance costs. Actual purchased capacity costs for 1996
and projected obligations for 1997 through 2001, including the impact of the
1995 settlement agreement with NCMPA and PMPA (See Note 13), are as follows
(dollars in thousands):
PURCHASED PURCHASED TOTAL
CAPACITY CAPACITY PURCHASED
YEAR CAPITAL COST FIXED O&M CAPACITY
1996 Actual........................................ $ 84,303 $40,499 $ 124,802
1997 Projected..................................... $ 67,030 $34,858 $ 101,888
1998 Projected..................................... $ 48,423 $26,388 $ 74,811
1999 Projected..................................... $ 35,337 $19,122 $ 54,459
2000 Projected..................................... $ 4,286 $ 2,470 $ 6,756
2001 Projected..................................... -- -- --
Effective in its November 1991 rate order, the North Carolina Utilities
Commission reaffirmed the Company's recovery, on a levelized basis, of the
capital costs and fixed operating and maintenance costs of capacity purchased
from the other joint owners. The Public Service Commission of South Carolina in
its November 1991 rate order reaffirmed the Company's recovery on a levelized
basis of the capital costs of capacity purchased from the other joint owners.
Levelization was reaffirmed through inclusion in rates approved in March 1992 by
the Federal Energy Regulatory Commission (FERC). The portion of purchased
capacity subject to levelization not currently recovered in rates is being
deferred, and the Company is recording a deferred return on the accumulated
balance. The Company recovers the accumulated balance, including the deferred
return, when the sum of the declining purchased capacity payments and accrual of
deferred returns for the current period drops below the levelized revenues.
Jurisdictional levelizations are intended to recover total costs, including
deferred returns, and are subject to adjustments, including final true-ups. The
Company recovers the costs of purchased energy and the non-levelized portion of
purchased capacity on a current basis.
The current levelized revenues approved in the Company's last general rate
proceedings are $211,423,000, $94,137,000 and $6,815,000 for North Carolina
retail, South Carolina retail and Other Wholesale (FERC), respectively.
Purchased power costs, subject to levelization, are deferred based on allocation
factors of approximately 62 percent, 26 percent and 2 percent for North Carolina
retail, South Carolina retail and Other Wholesale (FERC), respectively. The
PSCSC, on May 7, 1996, ordered a rate reduction in the form of a decrement rider
for an interim true-up adjustment. (See Note 2.) The Company also recovers an
allocated amount of purchased power costs in the pricing of supplemental sales
made to the other joint owners on a current basis.
During 1996, in the North Carolina retail and FERC wholesale jurisdictions,
annual levelized revenues exceeded purchased capacity payments and the accrual
of deferred returns for the first time. In the South Carolina retail
jurisdiction, cumulative levelized revenues have exceeded purchased capacity
payments and accrual of deferred returns.
For the years ended December 31, 1996, 1995 and 1994, the Company recorded
purchased capacity and energy costs from the other joint owners of $151,174,000,
$388,246,000 and $604,505,000, respectively. These amounts, after adjustments
for the costs of capacity purchased not reflected in current rates, are included
in "Net interchange and purchased power" in the Consolidated Statements of
Income. As of December 31, 1996 and 1995, $892,000,000 and $965,473,000,
respectively, associated with the cost of capacity purchased but not reflected
in current rates have been accumulated in the Consolidated Balance Sheets as
"Purchased capacity costs."
36
DUKE POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE 4. INCOME TAX EXPENSE
Accumulated deferred income taxes consist primarily of the following (dollars in
thousands):
DECEMBER 31, 1996 DECEMBER 31, 1995
Excess tax over book depreciation at historical tax rates............ $1,424,709 $1,387,925
Regulatory liability related to adjusting deferred taxes to the
current statutory tax rate......................................... (108,462)* (114,538)*
Net excess tax over book depreciation........................... $1,316,247 $1,273,387
Regulatory asset related to restating to a pre-tax basis............. 597,398* 605,214*
Deferred purchased capacity costs.................................... 345,089 374,112
Book versus tax basis differences.................................... 42,963 60,443
Loss on bond redemptions............................................. 63,962 68,135
Other................................................................ 10,353 913
Total deferred income taxes..................................... $2,376,012 $2,382,204
* The net regulatory asset related to income taxes is $488,936,000 for 1996 and
$490,676,000 for 1995.
Total deferred income tax liability was $2,932,260,000 as of December 31, 1996,
and $2,946,711,000 as of December 31, 1995. Total deferred income tax asset was
$556,248,000 as of December 31, 1996, and $564,507,000 as of December 31, 1995.
Income tax expense for the years ended December 31, 1996, 1995 and 1994
consisted of the following (dollars in thousands):
1996 1995 1994
Current income taxes
Federal........................................................ $413,429 $377,237 $249,968
State.......................................................... 89,903 83,215 52,790
Total current income taxes................................ 503,332 460,452 302,758
Deferred taxes, net
Federal........................................................ (16,706) 13,466 83,359
State.......................................................... 295 3,770 22,153
Total deferred taxes, net................................. (16,411) 17,236 105,512
Investment tax credit amortization............................... (11,230) (11,247) (11,251)
Total income tax expense.................................. $475,691 $466,441 $397,019
Income taxes differ from amounts computed by applying the statutory tax rate to
pre-tax income for the years ended December 31, 1996, 1995 and 1994 as follows
(dollars in thousands):
1996 1995 1994
Income taxes on pre-tax income at the statutory federal rate of 35%.......... $421,980 $413,343 $362,563
Increase (reduction) in tax resulting from:
Allowance for funds used during construction (AFUDC)....................... (5,538) (8,079) (9,594)
Amortization of investment tax credit deferrals............................ (11,230) (11,247) (11,251)
AFUDC in book depreciation/amortization.................................... 19,990 21,057 19,027
Deferred income tax flowback at rates higher than statutory................ (6,389) (5,675) (5,530)
State income taxes, net of federal income tax benefits..................... 58,242 56,210 47,872
Other items, net........................................................... (1,364) 832 (6,068)
Total income tax expense................................................ $475,691 $466,441 $397,019
37
DUKE POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE 5. SHORT-TERM BORROWINGS AND CREDIT FACILITIES
The following credit facilities were available to the Company at December 31,
1996 and 1995:
LINE OF CREDIT AT OUTSTANDING AT LINE OF CREDIT AT OUTSTANDING AT
TYPE OF FACILITY DECEMBER 31, 1996 DECEMBER 31, 1996 DECEMBER 31, 1995 DECEMBER 31, 1995
Annually renewable lines of credit.............. $ 64,900,000 $ 8,550,000 $ 64,900,000 $29,300,000
Two-year revolving facilities (a)............... 40,000,000 -- 40,000,000 --
Four-year revolving facilities (b).............. 235,000,000 42,000,000 210,000,000 30,043,000
Five-year revolving facilities (c).............. 355,000,000 -- 355,000,000 --
$ 694,900,000 $50,550,000 $ 669,900,000 $59,343,000
(a) The Company had $40,000,000 in pollution control bonds, included in
long-term debt, outstanding throughout 1996 and 1995 backed by these
facilities.
(b) The outstanding balances of $42,000,000 in 1996 and $30,043,000 in 1995 are
included in long-term debt.
(c) The Company had $130,000,000 in commercial paper, included in long-term
debt, outstanding throughout 1996 and 1995 backed by these facilities.
Cash balances maintained at the banks on deposit were $11,336,000 as of
December 31, 1996, and $17,120,000 as of December 31, 1995. Cash balances and
fees compensate banks for their services, even though the Company has no formal
compensating-balance arrangements. To compensate certain banks for credit
facilities, the Company maintained balances of $45,000 as of December 31, 1996
and 1995. 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):
TWELVE MONTHS ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31,
1996 1995 1994
Amount outstanding at end of period -- average rate of 6.05% as of December 31,
1996, 5.91% as of December 31, 1995, and 6.02% as of December 31, 1994.......... $105,550 $155,300 $107,100
Maximum amount outstanding during the period...................................... $176,450 $264,300 $143,400
Average amount outstanding during the period...................................... $ 56,343 $ 88,470 $ 24,161
Weighted-average interest rate for the period -- computed on a daily basis........ 5.33% 6.05% 4.58%
NOTE 6. COMMON STOCK AND RETAINED EARNINGS
COMMON STOCK
As of December 31, 1996, a total of 9,004,659 shares was reserved for issuance
for stock plans.
On February 27, 1996, the Board of Directors authorized the Company to
repurchase up to $1 billion of its common stock over the next five years. As of
December 31, 1996, approximately 3.3 million shares had been repurchased for
$159 million. On January 28, 1997, the Board of Directors amended the program to
expressly limit the number of shares authorized for repurchase under the
program, from the initiation of the program through a date two years after the
consummation of the proposed merger with PanEnergy Corp, to an amount not to
exceed 15 million shares. (See Note 13.)
RETAINED EARNINGS
As of December 31, 1996, substantially all of the Company's retained earnings
were unrestricted as to the declaration or payment of dividends.
38
DUKE POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
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, 1996 and 1995:
PAR VALUE SHARES
Preferred Stock.................................................. $ 100 12,500,000
Preferred Stock A................................................ $ 25 10,000,000
Preference Stock................................................. $ 100 1,500,000
As of December 31, 1996 and 1995, there were no shares of preference stock
outstanding. Preferred stock without sinking fund requirements as of December
31, 1996 and 1995, was as follows (dollars in thousands):
YEAR SHARES
RATE/SERIES ISSUED OUTSTANDING 1996 1995
4.50% C............................................................. 1964 350,000 $ 35,000 $ 35,000
5.72% D............................................................. 1966 350,000 35,000 35,000
6.72% E............................................................. 1968 350,000 35,000 35,000
7.85% S............................................................. 1992 600,000 60,000 60,000
7.00% W............................................................. 1993 500,000 50,000 50,000
7.04% Y............................................................. 1993 600,000 60,000 60,000
7.72% (Preferred Stock A)........................................... 1992 1,600,000 40,000 40,000
6.375% (Preferred Stock A).......................................... 1993 2,400,000 60,000 60,000
Auction Series A.................................................... 1990 750,000 75,000 75,000
Total.......................................................... $450,000 $450,000
NOTE 8. PREFERRED AND PREFERENCE STOCK WITH SINKING FUND REQUIREMENTS
The following shares of stock were authorized with or without sinking fund
requirements as of December 31, 1996 and 1995:
PAR VALUE SHARES
Preferred Stock.............................................................. $ 100 12,500,000
Preferred Stock A............................................................ $ 25 10,000,000
Preference Stock............................................................. $ 100 1,500,000
As of December 31, 1996 and 1995, there were no shares of preference stock
outstanding. Preferred stock with sinking fund requirements as of December 31,
1996 and 1995, was as follows (dollars in thousands):
YEAR SHARES
RATE/SERIES ISSUED OUTSTANDING 1996 1995
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
7.50% R............................................................. 1992 850,000 85,000 85,000
6.20% T............................................................. 1992 130,000 13,000 13,000
6.30% U............................................................. 1992 130,000 13,000 13,000
6.40% V............................................................. 1992 130,000 13,000 13,000
6.75% X............................................................. 1993 500,000 50,000 50,000
Total.......................................................... $234,000 $234,000
The annual sinking fund requirements through 2001 are $0 in 1997, $4,250,000 in
1998, $24,250,000 in 1999, $37,250,000 in 2000 and $37,250,000 in 2001. Some
additional redemptions are permitted at the Company's option.
The call provisions for the outstanding preferred stock specify various
redemption prices not exceeding 108 percent of par value, plus accumulated
dividends to the redemption date.
39
DUKE POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE 9. LONG-TERM DEBT
Long-term debt outstanding as of December 31, 1996 and 1995, was as follows
(dollars in thousands):
SERIES YEAR DUE 1996 1995
FIRST AND REFUNDING MORTGAGE BONDS:
6.59% 1996 $ -- $ 3,000
5 3/8% 1997 72,600 72,600
5 5/8% 1997 100,000 100,000
5.17% 1998 50,000 50,000
7.5% 1999 100,000 100,000
6 1/4% 1999 65,000 65,000
5.76% 1999 5,000 5,000
5.78% 1999 25,000 25,000
5.79% 1999 30,000 30,000
8% B 1999 200,000 200,000
7% 2000 100,000 100,000
7% B 2000 100,000 100,000
5 7/8% 2001 150,000 150,000
6 5/8% B 2003 100,000 100,000
5 7/8% C 2003 75,000 75,000
6.125% 2003 75,000 75,000
8% 2004 75,000 75,000
6 1/4% B 2004 100,000 100,000
7.37%-7.41% 2004 100,000 100,000
7% 2005 200,000 200,000
6 3/8% 2008 125,000 125,000
8 3/4% 2021 150,000 150,000
8 3/8% B 2021 150,000 150,000
8 5/8% 2022 100,000 100,000
7 3/8% 2023 200,000 200,000
6 7/8% B 2023 200,000 200,000
7 7/8% 2024 150,000 150,000
6 3/4% 2025 150,000 150,000
7 1/2% B 2025 100,000 100,000
8.27% 2025 21,000 21,000
8.27% 2025 50,000 50,000
8.28% 2025 2,000 2,000
8.30% 2025 5,000 5,000
8.95% 2027 15,584 15,681
7% 2033 150,000 150,000
SERIES YEAR DUE 1996 1995
POLLUTION CONTROL BONDS:
7.70% 2012 $ 20,000 $ 20,000
7.75% B 2017 10,000 10,000
7.50% 2017 25,000 25,000
3.58% 2014 40,000 40,000
5.80% 2014 77,000 77,000
Subtotal 3,463,184 3,466,281
OTHER LONG-TERM DEBT:
Capitalized leases 11,265 7,477
Other long-term debt 146,539 147,410
Unamortized debt
discount and premium,
net (56,995) (61,674)
Current maturities of
long-term debt (174,726) (4,295)
Subtotal (a) 3,389,267 3,555,199
SUBSIDIARY LONG-TERM DEBT:
Crescent Resources, Inc.
(b) 118,058 130,694
Nantahala Power and
Light 68,372 33,288
Current maturities of
long-term debt (37,583) (7,776)
Subtotal 148,847 156,206
Total long-term debt $3,538,114 $3,711,405
(a) Substantially all of Duke Power's electric plant was mortgaged as of
December 31, 1996.
(b) Substantial amounts of Crescent Resources, Inc.'s real estate development
projects, land and buildings are pledged as collateral.
40
DUKE POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE 9. LONG-TERM DEBT -- Continued
As of December 31, 1996 and 1995, the Company had $40,000,000 in pollution
control revenue bonds backed by an unused, two-year revolving credit facility of
$40,000,000. In addition, the Company had $130,000,000 in commercial paper
outstanding throughout 1996 and 1995 backed by unused five-year revolving credit
facilities. These facilities are on a fee basis. Both the $40,000,000 in
pollution control bonds and the $130,000,000 in commercial paper are included in
long-term debt.
As of December 31, 1996, Crescent Resources, Inc. had $45,428,000 in
mortgage loans which mature through 1999 and $30,630,000 in mortgage loans
maturing in 2000 or thereafter. Additionally, Crescent Resources, Inc. had
$42,000,000 outstanding at December 31, 1996, included in long-term debt on a
$75,000,000 four-year revolving credit facility. Interest rates are variable and
at December 31, 1996, ranged from 5.95 percent to 7.10 percent. As of December
31, 1996, Nantahala Power and Light Company had $68,000,000 in senior notes
maturing in 2011, 2012 and 2016. The notes carry fixed interest rates of 9.21
percent, 7.45 percent and 6.90 percent and require monthly payments of principal
beginning in 1997, 1998 and 2002, respectively.
The annual maturities of consolidated long-term debt, including capitalized
lease principal payments through 2001, are $212,309,000 in 1997; $62,759,000 in
1998; $444,840,000 in 1999; $248,271,000 in 2000; and $154,541,000 in 2001.
NOTE 10. FINANCIAL INSTRUMENTS
The carrying amounts of "Cash," "Short-term investments," and "Notes
payable" on the Consolidated Balance Sheets approximate fair value primarily
because of the short maturities of these instruments. "Other investments"
includes notes receivable issued at fixed rates with maturities up to 30 years
for which there are no quoted market prices. The majority of estimated fair
value amounts of long-term debt and preferred stock as disclosed below were
obtained from independent parties. Judgment is required in interpreting market
data to develop the estimates of fair value. Accordingly, the estimates
determined as of December 31, 1996 and 1995, are not necessarily indicative of
the amounts the Company could have realized in current market exchanges.
External funds have been established, as required by the Nuclear Regulatory
Commission, as a mechanism to fund certain costs of nuclear decommissioning.
(See Note 14.) Currently, these nuclear decommissioning trust funds are invested
in U.S. stocks, bonds and cash equivalents. "Nuclear decommissioning trust
funds" are presented on the Consolidated Balance Sheets at amounts that
approximate fair value.
The carrying amounts and estimated fair values of long-term debt and
preferred stock are as follows (dollars in thousands):
DECEMBER 31, 1996 DECEMBER 31, 1995
CARRYING AMOUNT FAIR VALUE CARRYING AMOUNT FAIR VALUE
Long-term debt............................................... $ 3,796,153 $3,773,000 $ 3,777,672 $3,879,000
Preferred stock.............................................. $ 684,000 $ 699,000 $ 684,000 $ 689,000
The Company has authority to issue up to $1 billion aggregate principal
amount of debt securities under a shelf registration statement filed with the
Securities and Exchange Commission (SEC). Such debt securities may be issued as
First and Refunding Mortgage Bonds, Senior Notes or Subordinated Debentures.
In order to obtain variable rate financing at an attractive cost, the
Company entered into interest rate swap agreements associated with the November
1994, issuance of $200 million aggregate principal amount of its First and
Refunding Mortgage Bonds, 8% Series B due 1999 and the August 1995, issuance of
$100 million aggregate principal amount of its First and Refunding Mortgage
Bonds, 7 1/2% Series B due 2025. The interest rate swaps are reset quarterly
based upon the three-month London Interbank Offered Rate (LIBOR). As a result of
the interest rate swap contracts, interest expense on the Consolidated
41
DUKE POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE 10. FINANCIAL INSTRUMENTS -- Continued
Statements of Income is recognized at the weighted average rate for the year
tied to the LIBOR rate. The weighted average rates are as follows (dollars in
thousands):
WEIGHTED AVERAGE RATE
SERIES YEAR DUE FACE VALUE 1996 1995 1994
8% Series B............................... 1999 $200,000 5.64% 6.14% 5.95%
7 1/2% Series B........................... 2025 $100,000 6.69% 7.06% --
Duke Energy Group, Inc. entered into a hedge transaction in 1995 to offset
currency fluctuations between the U.S. dollar and the Chilean peso associated
with expected equity contributions to an affiliate in 1995, 1996 and 1997. The
hedge transaction has a notional amount of approximately $4.4 million at
December 31, 1996. Duke Energy Group, Inc. records any realized gains or losses
associated with the hedge as an adjustment to investments in affiliates.
NOTE 11. INVESTMENTS IN AFFILIATES
Certain investments, where the Company's ownership in domestic and
international affiliates is 50 percent or less, are accounted for by the equity
method. These investments include ownership interests in various power
development projects; start-up personal communications services; marketing of
natural gas, electric power, and development of other energy services;
participation in various construction and support activities for fossil-fueled
generating plants; and real-estate development projects. The Company's
proportionate share of net income (loss) from these affiliates for the years
ended December 31, 1996, 1995 and 1994 was $(6,133,000), $9,237,000 and
$7,049,000, respectively. These amounts are reflected in "Operating revenues" on
the Consolidated Statements of Income.
A summary of assets and liabilities of these affiliates follows (dollars in
thousands):
DECEMBER 31, 1996 DECEMBER 31, 1995
COMPANY'S COMPANY'S
PROPORTIONATE PROPORTIONATE
TOTAL SHARE TOTAL SHARE
Assets of affiliates................................................ $1,979,418 $ 549,442 $1,445,600 $ 351,376
Liabilities of affiliates........................................... $1,041,207* $ 360,460 $ 615,452* $ 188,102
* The Company's exposure to these liabilities is mitigated through the use of
project or limited recourse financing by the affiliates and capitalization of
its subsidiaries investing in the affiliates.
In addition, the Company had outstanding loans to certain affiliates of
$2,900,000 and $23,170,000 at December 31, 1996 and 1995, respectively.
In the normal course of business, some of these affiliates enter into
contractual agreements to exchange natural gas, electric power, futures, swaps
and options; and construction contracts which contain certain schedule and
performance requirements. The affiliates use risk management procedures to
control their exposure associated with the contracts. Certain subsidiaries of
the Company have guaranteed performance of the affiliates under some of these
contracts. Management is of the opinion that these guarantees will not have any
material adverse effect on the results of operations or the financial position
of the Company.
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. Through December 31, 1996, the benefit was based upon an
age-related formula which took into account years of creditable service and the
employee's average compensation based upon the highest compensation during a
consecutive sixty-month period. The benefit was reduced by an adjustment which
is based upon the employee's social security wages. Normal retirement age under
the Plan was age 65; however, early retirement benefits were payable as early as
age 55 with 10
42
DUKE POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE 12. RETIREMENT BENEFITS -- Continued
years of creditable service or age 51 if the employee had at least 30 years of
creditable service. The Company's policy is to fund pension costs as accrued.
Effective January 1, 1997, the Plan was amended to be a Cash Balance Plan.
Under the Cash Balance Plan, records are maintained on an individual participant
basis with monthly credits based upon the participant's creditable compensation
multiplied times a percentage that ranges from 3 percent to 7 percent depending
upon the sum of the participant's age and years of service. An additional credit
of 4 percent applies to creditable compensation in excess of the social security
wage base. Additionally, monthly interest credits will be allocated based upon
the yield of 30-year U.S. Treasury Bonds, subject to a 4 percent minimum and a 9
percent maximum yield. Normal retirement age will remain age 65. Employees who
were participants in the Plan before January 1, 1997, remain eligible to receive
certain transitional benefits under the provisions of the previous plan. After
January 1, 1997, employees can receive early retirement benefits as early as age
55 with at least 5 years of vesting service.
Net periodic pension cost for the years ended December 31, 1996, 1995 and
1994, include the following components (dollars in thousands):
1996 1995 1994
Service cost benefit earned during the year.......... $ 49,636 $ 46,402 $ 43,098
Interest cost on projected benefit obligation........ 116,088 111,110 96,521
Actual return on plan assets......................... (180,463) (253,314) (6,138)
Amount deferred for recognition...................... 58,705 144,022 (86,995)
Expected return on plan assets....................... (121,758) (109,292) (93,133)
Net amortization..................................... 9,070 6,161 7,657
Net periodic pension cost....................... $ 53,036 $ 54,381 $ 54,143
A reconciliation of the funded status of the plan to the amounts recognized
in the Consolidated Balance Sheets as of December 31, 1996 and 1995, is as
follows (dollars in thousands):
1996 1995
Accumulated benefit obligation:
Vested benefits............................................................................ $(1,453,115) $(1,289,459)
Nonvested benefits......................................................................... (4,083) (6,216)
Accumulated benefit obligation........................................................ $(1,457,198) $(1,295,675)
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.............................................................................. $ 1,587,812 $ 1,424,148
Projected benefit obligation.................................................................... (1,663,375) (1,596,747)
Unrecognized net experience loss................................................................ 220,355 286,837
Unrecognized prior service cost reduction....................................................... (65,460) (35,039)
Remaining unrecognized transitional obligation.................................................. 668 801
Pre-funded pension cost.................................................................... $ 80,000 $ 80,000
Assumptions used in the Company's pension accounting include:
1996 1995 1994
Weighted-average discount rate............................................... 7.50% 7.50% 8.25%
Weighted-average salary increase............................................. 4.75% 4.75% 5.40%
Expected long-term rate of return on plan assets............................. 9.00% 9.00% 9.00%
During 1995, the Company offered to certain employees an Enhanced Vested
Benefits program (EVB). The Company recorded an additional one-time expense for
special termination benefits associated with EVB of approximately $42,196,000,
including $21,600,000 of additional retirement plan costs.
43
DUKE POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE 12. RETIREMENT BENEFITS -- Continued
B. POSTRETIREMENT BENEFITS
The Company and its operating subsidiaries, with the exception of Nantahala
Power and Light Company (NP&L), which maintained its own postretirement benefit
plans through December 1995, currently provide certain health care and life
insurance benefits for retired employees. NP&L employees who retired after
January 1, 1996, are covered by Duke Power Company's postretirement benefit
plan. Through December 31, 1996, employees became eligible for these benefits if
they retired at age 55 or greater with 10 years of service or if they retired as
early as age 51 with 30 years or more of service. Effective January 1, 1997,
employees who were participants in the Retirement Plan before January 1, 1997,
become eligible for certain transitional postretirement benefits under the
provisions of the previous plan. Employees who were not participants in the plan
before January 1, 1997, become eligible as early as age 55 with at least 10
years of vesting service. All 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 $15,200,000 into these funding mechanisms in
1996 and $23,000,000 in 1995.
Net periodic postretirement benefit cost for the years ended December 31,
1996, 1995 and 1994, include the following components (dollars in thousands):
1996 1995 1994
Service cost benefit earned during the year................... $ 6,388 $ 5,874 $ 5,415
Interest cost on accumulated postretirement benefit
obligation.................................................. 27,276 27,201 25,321
Actual return on plan assets.................................. (12,383) (14,726) (1,451)
Amount deferred for recognition............................... 2,988 7,260 (3,469)
Expected return on plan assets................................ (9,395) (7,466) (4,920)
Straight-line -- 20 year amortization of transitional
obligation.................................................. 13,515 13,293 13,293
Other amortization............................................ 1,566 555 366
Net periodic postretirement benefit cost.................... $39,350 $39,457 $39,475
A reconciliation of the funded status of the plan to the amounts recognized
in the Consolidated Balance Sheets as of December 31, 1996 and 1995, is as
follows (dollars in thousands):
1996 1995
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....................................... $ 127,594 $ 105,506
Actives eligible to retire.................................................. (39,567) (25,780)
Actives not eligible to retire.............................................. (118,103) (97,389)
Retirees and surviving spouses.............................................. (251,325) (253,688)
Accumulated postretirement benefit obligation (APBO)........................ (408,995) (376,857)
Unrecognized prior service cost............................................. 66,692 712
Unrecognized net experience (gain)/loss..................................... (3,772) 25,955
Unrecognized transitional obligation........................................ 177,338 212,695
(Accrued) postretirement benefit cost................................ $ (41,143) $ (31,989)
44
DUKE POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE 12. RETIREMENT BENEFITS -- Continued
Assumptions used in the Company's postretirement benefits accounting
include:
1996 1995 1994
Weighted-average discount rate....................................................................... 7.50% 7.50% 8.25%
Weighted-average salary increase..................................................................... 4.75% 4.75% 5.40%
Expected long-term rate of return on 401(h) assets................................................... 9.00% 9.00% 9.00%
Expected long-term rate of return on RLR assets...................................................... 6.50% 8.00% 6.50%
The assumed medical inflation rate was approximately 9.5 percent in 1996.
This rate decreases by 0.5 percent to 1.0 percent per year until a rate of 5.5
percent is achieved in the year 2001, which remains fixed thereafter.
A 1.0 percent increase in the medical and dental trend rates produces a 7.0
percent ($2,940,971) 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 7.8 percent ($31,462,000) as of December 31, 1996.
NOTE 13. COMMITMENTS AND CONTINGENCIES
A. CONSTRUCTION PROGRAM
Projected construction and nuclear fuel costs for Duke Power's electric
operations, both including allowance for funds used during construction, are
$2.6 billion and $716 million, respectively, for 1997 through 2001. These
projections are subject to periodic review and revisions. Actual construction
and nuclear fuel costs and capital expenditures incurred may vary from such
estimates. Cost variances are due to various factors, including revised load
estimates, environmental matters and cost and availability of capital.
Projected capital expenditures of subsidiaries and diversified activities
are $1.5 billion for 1997 through 2001. These projections are subject to
periodic review and revisions and may vary significantly as business plans
evolve to meet the opportunities presented by their markets.
B. NUCLEAR INSURANCE
The Company maintains nuclear insurance coverage in three areas: liability
coverage, property, decontamination and decommissioning coverage, and extended
accidental outage coverage to cover increased generating costs and/or
replacement power purchases. The Company is being reimbursed by the other joint
owners of the Catawba Nuclear Station for certain expenses associated with
nuclear insurance premiums paid by the Company.
Pursuant to the Price-Anderson Act, the Company is required to insure
against public liability claims resulting from nuclear incidents to the full
limit of liability of approximately $8.9 billion. The maximum required private
primary insurance of $200 million has been purchased along with a like amount to
cover certain worker tort claims. The remaining amount, currently $8.7 billion,
which will be increased by $79.3 million as each additional commercial nuclear
reactor is licensed, has been provided through a mandatory industry-wide excess
secondary insurance program of risk pooling. The $8.7 billion could also be
reduced by $79.3 million for certain nuclear reactors that are no longer
operational and may be exempted from the risk pooling insurance program. Under
this program, licensees could be assessed retrospective premiums to compensate
for damages in the event of a nuclear incident at any licensed facility in the
nation. If such an incident occurs and public liability damages exceed primary
insurances, licensees may be assessed up to $79.3 million for each of their
licensed reactors, payable at a rate not to exceed $10 million a year per
licensed reactor for each incident. The $79.3 million amount is subject to
indexing for inflation and may be subject to state premium taxes. The $79.3
million includes a surcharge of 5 percent (which is also included in the above
$8.7 billion figure) if funds are insufficient to pay claims and associated
costs. If retrospective premiums were to be assessed, the other joint owners of
the Catawba Nuclear Station are obligated to assume their pro rata share of such
assessment.
The Company is a member of Nuclear Mutual Limited (NML), which provides
$500 million in primary property damage coverage for each of the Company's
nuclear facilities. If NML's losses ever exceed its reserves, the Company will
be liable, on a pro rata basis, for additional assessments of up to $34 million.
This amount represents 5 times the Company's
45
DUKE POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE 13. COMMITMENTS AND CONTINGENCIES -- Continued
annual premium to NML. The other joint owners of Catawba are obligated to assume
their pro rata share of any liability for retrospective premiums and other
premium assessments resulting from the NML policies applicable to Catawba.
The Company is also a member of Nuclear Electric Insurance Limited (NEIL)
and purchases insurance through NEIL's excess property, decontamination and
decommissioning liability insurance program. NEIL provides excess insurance
coverage of $2.25 billion for the Catawba Nuclear Station and $1.5 billion for
each of the Oconee and McGuire Nuclear Stations. If losses ever exceed the
accumulated funds available to NEIL for the excess property, decontamination and
decommissioning liability program, the Company will be liable, on a pro rata
basis, for additional assessments of up to $40 million. This amount is limited
to 5 times the Company's annual premium to NEIL for excess property,
decontamination and decommissioning liability insurance. The other joint owners
of Catawba are obligated to assume their pro rata share of any liability for
retrospective premiums and other premium assessments resulting from the NEIL
policies applicable to Catawba.
The Company participates in a NEIL program that provides insurance for the
increased cost of generation and/or purchased power resulting from an accidental
outage of a nuclear unit. Each unit of the 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. The Oconee Nuclear Station units are insured
for up to approximately $2.7 million, under like terms. Coverages continue at
100 percent for 52 weeks and 80 percent for the next 104 weeks. If NEIL's losses
for this program ever exceed its reserves, the Company will be liable, on a pro
rata basis, for additional assessments of up to $27 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. PROPOSED MERGER WITH PANENERGY CORP
On November 25, 1996, the Company and PanEnergy Corp announced a proposed
stock-for-stock transaction creating an integrated energy company. Upon
consummation of the merger, PanEnergy will be a wholly owned subsidiary of the
Company, and the Company's name will be changed to Duke Energy Corporation. The
transaction is expected to close by December 31, 1997, subject to approval of
the shareholders of both companies and all applicable regulatory approvals. The
shareholders of each company will vote on the proposed merger at their annual
meetings, which are scheduled for April 24, 1997 for both companies.
Applications for regulatory approval were filed with the NCUC and the PSCSC on
December 19, 1996 and the FERC on February 3, 1997. Regulatory proceedings are
expected to be successfully completed by year-end 1997. In connection with the
transaction, each share of PanEnergy common stock will be converted into 1.0444
shares of common stock of the Company. The transaction will be accounted for as
a pooling of interests. Further details about the proposed acquisition are
provided in the Company's report on Form 8-K, filed with the Securities and
Exchange Commission on December 9, 1996, and in the Joint Proxy
Statement-Prospectus provided to shareholders in connection with the Company's
annual meeting. Unless otherwise indicated, all information presented herein
relates to the Company only and does not take into account the proposed merger
with PanEnergy.
D. OTHER
The Company and North Carolina Municipal Power Agency Number 1 and Piedmont
Municipal Power Agency, two of the four other joint owners of the Catawba
Nuclear Station, entered into a settlement in September 1995 which resolved
outstanding issues related to how certain calculations affecting bills under the
Catawba joint ownership contractual agreements should be performed. The
settlement was approved by the North Carolina Utilities Commission on January
16, 1996 and The Public Service Commission of South Carolina on January 23,
1996. As part of the settlement, the Company agreed to purchase additional
megawatts (MW) of Catawba capacity during the period 1996 through 1999 and
remove certain restrictions related to sales of surplus energy by these two
joint owners. The additional capacity purchases are 215 MW in 1996, 165 MW in
1997, 120 MW in 1998 and 100 MW in 1999. The Company expects to recover the
costs associated with this settlement as part of the purchased capacity
levelization, consistent with prior orders of the retail regulatory commissions.
Therefore, the Company believes these matters should not have a material adverse
effect on the results of operations or the financial position of the Company.
46
DUKE POWER COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED
NOTE 13. COMMITMENTS AND CONTINGENCIES -- Continued
The Company and all four of the other joint owners of the Catawba Nuclear
Station entered into settlement agreements in 1994 which resolved all issues in
contention in arbitration proceedings related to the Catawba joint ownership
contractual agreements. The basic contention in each proceeding was that certain
calculations affecting bills under these agreements should be performed
differently. These items are covered by the agreements between the Company and
the other Catawba joint owners which have been previously approved by the
Company's retail regulatory commissions. (See Note 3.) In 1994, the Company
settled its cumulative net obligation through 1993 of approximately $205 million
related to these settlement agreements. Billings for 1994 and later years will
conform to the settlement agreements, which have been approved by the Company's
retail regulatory commissions. Because the Company expects the costs associated
with these settlements to be recovered as part of the purchased capacity
levelization, which has been approved by the Company's retail regulatory
commissions, the Company included approximately $205 million as an increase to
"Purchased capacity costs" on its Consolidated Balance Sheets in 1994.
Therefore, the Company believes these matters should not have a material adverse
effect on the results of operations or financial position of the Company.
The Company is also involved in legal, tax and regulatory proceedings
before various courts, regulatory commissions and governmental agencies
regarding matters arising in the ordinary course of business, some of which
involve substantial amounts. Where appropriate, the Company has made accruals in
accordance with Statement of Financial Accounting Standards No. 5, "Accounting
for Contingencies," in order to provide for such matters. Management is of the
opinion that the final disposition of these proceedings will not have a material
adverse effect on the results of operations or financial position of the
Company.
NOTE 14. NUCLEAR DECOMMISSIONING COSTS
Estimated site-specific nuclear decommissioning costs, including the cost
of decommissioning plant components not subject to radioactive contamination,
total approximately $1.3 billion stated in 1994 dollars based on decommissioning
studies completed in 1994. This amount includes the Company's 12.5 percent
ownership in the Catawba Nuclear Station. The other joint owners of the Catawba
Nuclear Station are responsible for decommissioning costs related to their
ownership interests in the station. Both the North Carolina Utilities Commission
and the Public Service Commission of South Carolina have granted the Company
recovery of estimated decommissioning costs through retail rates over the
expected remaining service periods of the Company's nuclear plants. Such
estimates presume each unit will be decommissioned as soon as possible following
the end of their license life. Although subject to extension, the current
operating licenses for the Company's nuclear units expire as follows: Oconee 1
and 2 -- 2013, Oconee 3 -- 2014; McGuire 1 -- 2021, McGuire 2 -- 2023; and
Catawba 1 -- 2024, Catawba 2 -- 2026.
In accordance with a 1988 Nuclear Regulatory Commission order, during 1996,
the Company expensed approximately $56,470,000 which was contributed to the
external funds for decommissioning costs and accrued an additional $1,618,000 to
the internal reserve. Nuclear units are depreciated at a rate of 4.70 percent,
of which 1.61 percent is for decommissioning. The balance of the external funds
as of December 31, 1996, was $362,627,000. The balance of the internal reserve
as of December 31, 1996, was $207,774,000 and is reflected in accumulated
depreciation and amortization on the Consolidated Balance Sheets. Management's
opinion is that the decommissioning costs being recovered through rates, when
coupled with assumed after-tax fund earnings of 5.5 percent to 5.9 percent, are
currently sufficient to provide for the cost of decommissioning.
47
INDEPENDENT AUDITORS' REPORT
DUKE POWER COMPANY:
We have audited the consolidated financial statements of Duke Power
Company and subsidiaries (the Company) listed in the accompanying index for
Item 8. Our audits also included the consolidated financial statement schedule
listed in the accompanying index. These financial statements and consolidated
financial statement schedule are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements and consolidated financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company at December 31,
1996 and 1995, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 1996 in conformity with
generally accepted accounting principles. Also, in our opinion, such
consolidated financial statement schedule, when considered in relation to the
basic consolidated financial statements taken as a whole, presents fairly in
all material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Charlotte, North Carolina
February 7, 1997
RESPONSIBILITY FOR FINANCIAL STATEMENTS
The financial statements of Duke Power Company are prepared by management,
which is responsible for their integrity and objectivity. The statements are
prepared in conformity with generally accepted accounting principles appropriate
in the circumstances to reflect in all material respects the substance of events
and transactions which should be included. The other information in the annual
report is consistent with the financial statements. In preparing these
statements, management makes informed judgments and estimates of the expected
effects of events and transactions that are currently being reported.
The Company's system of internal accounting control is designed to provide
reasonable assurance that assets are safeguarded and transactions are executed
according to management's authorization. Internal accounting controls also
provide reasonable assurance that transactions are recorded properly, so that
financial statements can be prepared according to generally accepted accounting
principles. In addition, the Company's accounting controls provide reasonable
assurance that errors or irregularities which could be material to the financial
statements are prevented or are detected by employees within a timely period as
they perform their assigned functions. The Company's accounting controls are
continually reviewed for effectiveness. In addition, written policies, standards
and procedures, and a strong internal audit program augment the Company's
accounting controls.
The Board of Directors pursues its oversight role for the financial
statements through the audit committee, which is composed entirely of directors
who are not employees of the Company. The audit committee meets with management
and internal auditors periodically to review the work of each group and to
monitor each group's discharge of its responsibilities. The audit committee also
meets periodically with the Company's independent auditors, Deloitte & Touche
LLP. The independent auditors have free access to the audit committee and the
Board of Directors to discuss internal accounting control, auditing and
financial reporting matters without the presence of management.
JEFFREY L. BOYER
CONTROLLER
48
QUARTERLY FINANCIAL DATA
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER TOTAL
DOLLARS IN THOUSANDS (EXCEPT PER-SHARE DATA)
1996 BY QUARTER
Operating revenues................................... $1,162,077 $1,119,731 $1,292,426 $1,183,740 $4,757,974
Operating income..................................... $ 357,412 $ 301,231 $ 470,706 $ 232,854 $1,362,203
Net income........................................... $ 191,304 $ 157,382 $ 264,987 $ 116,293 $ 729,966
Earnings per share................................... $ 0.88 $ 0.71 $ 1.25 $ 0.53 $ 3.37
1995 BY QUARTER
Operating revenues................................... $1,111,065 $1,052,403 $1,379,978 $1,133,238 $4,676,684
Operating income..................................... $ 369,414 $ 263,876 $ 504,507 $ 211,254 $1,349,051
Net income........................................... $ 201,276 $ 137,523 $ 285,200 $ 90,539 $ 714,538
Earnings per share................................... $ 0.92 $ 0.61 $ 1.33 $ 0.39 $ 3.25
Generally, quarterly earnings fluctuate with seasonal weather conditions
and maintenance of electric generating units, especially nuclear units.
49
SUBSIDIARIES AND DIVERSIFIED ACTIVITIES HIGHLIGHTS
The Company has organized all its subsidiaries and diversified activities
into the Associated Enterprises Group (AEG). AEG includes the following:
(Bullet) CHURCH STREET CAPITAL CORP. (CSCC) serves as the parent
company and provides equity funding and credit enhancement
services for the Company's non-electric operating
subsidiaries. CSCC and one of its wholly-owned subsidiaries
manage investment funds, highlights of which are as follows
(dollars in thousands):
SHORT-TERM INVESTMENTS AND MARKETABLE SECURITIES
1996 1995 1994
$72,712 $76,300 $170,642
INVESTMENT INCOME (AFTER TAX)
1996 1995 1994
$772 $4,783 $7,562
(Bullet) CRESCENT RESOURCES, INC. provides real estate management,
forestry operation and high-quality commercial and
residential real estate development services in the
Southeast.
(Bullet) DUKE ENERGY GROUP, INC. develops, owns, manages and operates
energy facilities worldwide.
(Bullet) DUKE ENGINEERING & SERVICES, INC. provides engineering,
project management, quality assurances, construction
management, operating and maintenance and environmental
services for utilities, industry and government worldwide.
(Bullet) DUKE/FLUOR DANIEL provides engineering, procurement,
construction and operating and maintenance services for
fossil-fueled electric generating stations worldwide.
(Bullet) DUKE/LOUIS DREYFUS, LLC markets electric power, natural gas
and energy-related services to utilities, municipalities and
other large energy users in North America.
(Bullet) DUKE MERCHANDISING sells and services home appliances,
electronics and wireless communications devices.
(Bullet) DUKENET COMMUNICATIONS, INC. develops and manages
communications systems, including fiber optic and wireless
digital network services.
(Bullet) DUKE WATER OPERATIONS provides franchised water service to
customers in parts of North and South Carolina.
(Bullet) NANTAHALA POWER AND LIGHT COMPANY is a franchised electricity
provider serving a five-county area in western North
Carolina.
50
The following tables set forth operating results, financial position, cash
flows and other information with respect to the Company's subsidiaries and
diversified activities for the periods and as of the dates specified:
OPERATING RESULTS
YEAR ENDED DECEMBER 31,
1996 1995 1994
DOLLARS IN THOUSANDS
OPERATING REVENUES
Crescent Resources, Inc................................................................ $113,759 $ 85,361 $ 64,724
Duke Energy Group, Inc................................................................. 13,095 10,017 9,478
Duke Engineering & Services, Inc. (a).................................................. 157,209 64,880 41,670
Nantahala Power and Light Company...................................................... 67,668 62,510 68,595
All Other Business Units (b)........................................................... 63,463 76,457 68,262
Total Associated Enterprises Group................................................ $415,194 $299,225 $252,729
OPERATING INCOME
Crescent Resources, Inc................................................................ $ 87,708 $ 63,973 $ 46,236
Duke Energy Group, Inc. (c)............................................................ (11,795) (1,422) (1,035)
Duke Engineering & Services, Inc. (a).................................................. 12,924 5,941 2,681
Nantahala Power and Light Company...................................................... 14,677 9,262 12,224
All Other Business Units (b)........................................................... (5,204) 14,466 12,825
Total Associated Enterprises Group................................................ $ 98,310 $ 92,220 $ 72,931
NET INCOME
Crescent Resources, Inc................................................................ $ 49,600 $ 35,500 $ 26,525
Duke Energy Group, Inc. (c)(d)......................................................... (7,377) 170 5,749
Duke Engineering & Services, Inc. (a).................................................. 7,896 3,701 1,675
Nantahala Power and Light Company...................................................... 6,265 4,037 6,169
All Other Business Units (b)........................................................... (5,106) 10,849 11,918
Total Associated Enterprises Group................................................ $ 51,278 $ 54,257 $ 52,036
FINANCIAL POSITION
DECEMBER 31,
1996 1995 1994
DOLLARS IN THOUSANDS
TOTAL ASSETS
Crescent Resources, Inc.............................................................. $ 446,307 $381,073 $294,175
Duke Energy Group, Inc............................................................... 131,210 149,391 110,656
Duke Engineering & Services, Inc. (a)................................................ 115,457 44,090 18,412
Nantahala Power and Light Company.................................................... 167,008 144,069 125,883
All Other Business Units (b)......................................................... 312,007 239,684 261,018
Total Associated Enterprises Group.............................................. $1,171,989 $958,307 $810,144
TOTAL LIABILITIES
Crescent Resources, Inc.............................................................. $ 201,809 $185,996 $134,574
Duke Energy Group, Inc............................................................... 6,204 9,783 4,672
Duke Engineering & Services, Inc. (a)................................................ 36,540 10,969 5,992
Nantahala Power and Light Company.................................................... 105,787 86,691 72,542
All Other Business Units (b)......................................................... 37,994 32,529 16,320
Total Associated Enterprises Group.............................................. $ 388,334 $325,968 $234,100
51
CASH FLOWS
YEAR ENDED DECEMBER 31,
1996 1995 1994
DOLLARS IN THOUSANDS
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES
Crescent Resources, Inc................................................................ $ 90,154 $ 40,144 $ 37,691
Duke Energy Group, Inc................................................................. (8,763) (3,521) (6,614)
Duke Engineering & Services, Inc. (a).................................................. 297 4,921 2,252
Nantahala Power and Light Company...................................................... 9,448 8,419 12,817
All Other Business Units (b)........................................................... 5,026 (3,152) 8,337
Total Associated Enterprises Group................................................ $ 96,162 $ 46,811 $ 54,483
CASH PROVIDED BY INVESTING ACTIVITIES
Crescent Resources, Inc. (e)........................................................... $ 37,786 $ 5,910 $ 2,524
Duke Energy Group, Inc. (f)............................................................ 27,046 14,253 40,740
Duke Engineering & Services, Inc. (a).................................................. -- -- --
Nantahala Power and Light Company...................................................... -- -- --
All Other Business Units (g)........................................................... 4,951 97,793 5,100
Total Associated Enterprises Group................................................ $ 69,783 $117,956 $ 48,364
CASH USED IN INVESTING ACTIVITIES
Crescent Resources, Inc................................................................ $115,371 $ 84,603 $ 78,689
Duke Energy Group, Inc................................................................. 14,029 44,776 19,575
Duke Engineering & Services, Inc. (a)(h)............................................... 40,890 996 1,090
Nantahala Power and Light Company...................................................... 21,166 23,944 23,989
All Other Business Units (i)........................................................... 46,161 65,772 17,410
Total Associated Enterprises Group................................................ $237,617 $220,091 $140,753
CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (J)
Crescent Resources, Inc................................................................ $(12,497) $ 38,521 $ 37,589
Duke Energy Group, Inc. (k)............................................................ -- -- --
Duke Engineering & Services, Inc. (a)(l)............................................... 375 997 --
Nantahala Power and Light Company...................................................... 11,659 15,536 10,896
All Other Business Units (m)........................................................... 69,463 4,305 (6,993)
Total Associated Enterprises Group................................................ $ 69,000 $ 59,359 $ 41,492
OTHER INFORMATION
DECEMBER 31,
1996 1995 1994
FULL-TIME EMPLOYEES AT YEAR-END
Crescent Resources, Inc............................................................................ 118 94 89
Duke Energy Group, Inc............................................................................. 52 43 35
Duke Engineering & Services, Inc. (a).............................................................. 1,834 551 275
Nantahala Power and Light Company.................................................................. 193 182 184
All Other Business Units........................................................................... 527 485 428
Total Associated Enterprises Group............................................................ 2,724 1,355 1,011
(a) Excludes operations and financial position of an affiliate, Duke/Fluor
Daniel, which is included in All Other Business Units amounts.
(b) All Other Business Units amounts include Associated Enterprises Group
intercompany eliminations.
(c) 1996 includes a provision for an investment in a power plant in Argentina.
(d) 1994 includes a gain from the sale of preferred stock.
(e) 1996 includes proceeds from sale of office building.
52
(f) 1996 includes proceeds from repayment of a loan by an affiliate. (See Note
11.) 1994 includes proceeds from the sale of preferred stock and debt
securities.
(g) 1996 and 1995 include the net change in short-term investments for the
period of $3,588,000 and $56,392,000, respectively. Also, 1995 includes
proceeds from the sale of a dividend capture program.
(h) 1996 includes amounts paid relating to acquisition activities.
(i) 1994 includes the net change in short-term investments for the period of
$12,060,000.
(j) Excludes capital infusion and return of capital transactions between
parent, Church Street Capital Corp., and its subsidiaries.
(k) 1996 and 1994 exclude net return of capital to parent, Church Street
Capital Corp., of $4,724,000 and $12,100,000, respectively. 1995 excludes
net capital infusions from Church Street Capital Corp. of $33,455,000.
(l) 1996 excludes net capital infusions from parent, Church Street Capital
Corp., of $35,900,000.
(m) 1996 includes capital infusion from Duke Power to Church Street Capital
Corp. of $65,000,000.
53
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
BALANCE BALANCE
BEGINNING END OF
DESCRIPTION OF YEAR YEAR
(DOLLARS IN
THOUSANDS)
FOR THE YEAR ENDED DECEMBER 31, 1996
Reserves Related to Assets on Balance Sheet........................................................... $ 7,774 $ 8,562
Other Reserves
Operating Reserves (1).............................................................................. 176,098 178,583
FOR THE YEAR ENDED DECEMBER 31, 1995
Reserves Related to Assets on Balance Sheet........................................................... 8,059 7,774
Other Reserves
Operating Reserves (1).............................................................................. 154,722 176,098
FOR THE YEAR ENDED DECEMBER 31, 1994
Reserves Related to Assets on Balance Sheet........................................................... 10,353 8,059
Other Reserves
Operating Reserves (1).............................................................................. 107,477 154,722
(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.
54
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
No events necessary to be disclosed by the Company under this item have
occurred.
PART III.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Information for this item concerning directors of the Company is set forth
in the sections entitled "Election of Directors," "Information Regarding the
Board of Directors" and "Common Stock Ownership of Certain Beneficial Owners and
Management" under "The Duke Meeting -- Additional Matters" in the Joint Proxy
Statement-Prospectus relating to the Company's 1997 annual meeting of
shareholders, which are being incorporated herein by reference.
Information concerning the executive officers of the Company is set forth
in the section entitled "Executive Officers of the Company" in this annual
report.
ITEM 11. EXECUTIVE COMPENSATION.
Information for this item is set forth in the sections entitled "Executive
Compensation" and "Directors' Fees" under "The Duke Meeting -- Additional
Matters", and "Interests of Certain Persons in the Merger -- Duke Employment
Agreements" under "The Merger" in the Joint Proxy Statement-Prospectus relating
to the Company's 1997 annual meeting of shareholders, which are being
incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Information for this item is set forth in the section entitled "Common
Stock Ownership of Certain Beneficial Owners and Management" under "The Duke
Meeting -- Additional Matters" in the Joint Proxy Statement-Prospectus relating
to the Company's 1997 annual meeting of shareholders, which is being
incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information for this item is set forth in the sections entitled
"Information Regarding the Board of Directors" and "Common Stock Ownership of
Certain Beneficial Owners and Management" under "The Duke Meeting -- Additional
Matters" in the Joint Proxy Statement-Prospectus relating to the Company's 1997
annual meeting of shareholders, which are being incorporated herein by
reference.
55
PART IV.
ITEM 14. EXHIBITS, CONSOLIDATED FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K.
(a) Consolidated Financial Statements, Supplemental Financial Data and
Supplemental Schedules included in Part II of this annual report are as follows:
Consolidated Financial Statements
Consolidated Statements of Income for the Three Years Ended December 31,
1996
Consolidated Statements of Retained Earnings for the Three Years Ended
December 31, 1996
Consolidated Statements of Cash Flows for the Three Years Ended December
31, 1996
Consolidated Balance Sheets -- December 31, 1996 and 1995
Notes to Consolidated Financial Statements
Selected Quarterly Financial Data (unaudited)
Consolidated Financial Statement Schedule
Schedule II -- Valuation and Qualifying Accounts and Reserves for the
Three Years Ended December 31, 1996
All other schedules are omitted because of the absence of the conditions
under which they are required or because the required information is
included in the financial statements or notes thereto.
(b) Reports on Form 8-K
A Report on Form 8-K was filed by the Company on December 9, 1996,
in which it reported in Item 5 thereof the execution of an Agreement and
Plan of Merger dated as of November 24, 1996, by and between the
Company, Duke Transaction Corporation and PanEnergy Corp.
(c) Exhibits -- See Exhibit Index immediately following signature page.
56
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 24th day of March, 1997.
DUKE POWER COMPANY
(Registrant)
By: W. H. GRIGG
CHAIRMAN OF THE BOARD
AND CHIEF EXECUTIVE OFFICER
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
SIGNATURE TITLE DATE
W. H. GRIGG Chairman of the Board and Chief Executive March 24, 1997
Officer (Principal Executive Officer)
RICHARD J. OSBORNE Senior Vice President and Chief Financial March 24, 1997
Officer (Principal Financial Officer)
JEFFREY L. BOYER Controller (Principal Accounting Officer) March 24, 1997
G. ALEX BERNHARDT
ROBERT J. BROWN
W. A. COLEY
STEVE C. GRIFFITH, JR. (Buzzard wing appears here)
W. H. GRIGG
GEORGE DEAN JOHNSON, JR. A majority of the Directors March 24, 1997
W. W. JOHNSON
MAX LENNON
JAMES G. MARTIN
BUCK MICKEL
R. B. PRIORY
RUSSELL M. ROBINSON, II
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
57
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.
EXHIBIT
NUMBER
2 --Agreement and Plan of Merger, dated as of November 24, 1996, as amended and restated as of March 10, 1997,
among registrant, Duke Transaction Corporation and PanEnergy Corp (filed with Form 8-K dated March 20, 1997,
File No. 1-4928, as Exhibit 2(a)).
3-A --Restated Articles of Incorporation of registrant, dated 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 10-K for the year ended December 31, 1995, File No.
1-4928, as Exhibit 3-C).
4-B-1 --First and Refunding Mortgage from registrant to Guaranty Trust Company of New York, Trustee, dated as of
December 1, 1927 (filed with Form S-1, File No. 2-7224, effective October 15, 1947, as Exhibit 7(a)).
4-B-2 --Supplemental Indenture, dated as of March 12, 1930, supplementing said Mortgage (filed with Form S-1, File
No. 2-7224, effective October 15, 1947, as Exhibit 7(b)).
4-B-5 --Supplemental Indenture, dated as of September 1, 1936, supplementing said Mortgage (filed with
Form S-1, File No. 2-7224, effective October 15, 1947, as Exhibit 7(e)).
4-B-6 --Supplemental Indenture, dated as of January 1, 1941, supplementing said Mortgage (filed with Form S-1, File
No. 2-7224, effective October 15, 1947, as Exhibit 7(f)).
4-B-7 --Supplemental Indenture, dated as of April 1, 1944, supplementing said Mortgage (filed with Form S-1, File
No. 2-7224, effective October 15, 1947, as Exhibit 7(g)).
4-B-8 --Supplemental Indenture, dated as of September 1, 1947, supplementing said Mortgage (filed with
Form S-1, File No. 2-7224, effective October 15, 1947, as Exhibit 7(h)).
4-B-9 --Supplemental Indenture, dated as of September 8, 1947, supplementing said Mortgage (filed with
Form S-1, File No. 2-10401, effective August 21, 1953, as Exhibit 4-B-9).
4-B-10 --Supplemental Indenture, dated as of February 1, 1949, supplementing said Mortgage (filed with Form S-1, File
No. 2-7808, effective February 3, 1949, as Exhibit 7(j)).
4-B-11 --Supplemental Indenture, dated as of March 1, 1949, supplementing said Mortgage (filed with Form S-1, File
No. 2-8877, effective April 6, 1951, as Exhibit 7(k)).
4-B-14 --Supplemental Indenture, dated as of October 1, 1954, supplementing said Mortgage (filed with Form S-9, File
No. 2-11297, effective December 30, 1954, as Exhibit 2-B-14).
4-B-17 --Supplemental Indenture, dated as of January 1, 1960, supplementing said Mortgage (filed with Form 10,
effective June 29, 1961, as Exhibit 3-B-18).
4-B-18 --Supplemental Indenture, dated as of February 1, 1960, supplementing said Mortgage (filed with Form 10,
effective June 29, 1961, as Exhibit 3-B-19).
4-B-21 --Supplemental Indenture, dated as of June 15, 1964, supplementing said Mortgage (filed with Form S-1, File
No. 2-25367, effective August 3, 1966, as Exhibit 4-B-20).
4-B-23 --Supplemental Indenture, dated as of April 1, 1967, supplementing said Mortgage (filed with Form S-9, File
No. 2-28023, effective February 15, 1968, as Exhibit 2-B-25).
4-B-24 --Supplemental Indenture, dated as of February 1, 1968, supplementing said Mortgage (filed with Form S-9, File
No. 2-31304, effective January 21, 1969, as Exhibit 2-B-26).
4-B-48 --Supplemental Indenture, dated as of September 1, 1983, supplementing said Mortgage (filed with Form
S-3, File No. 2-95931, effective April 1, 1985, as Exhibit 4-B-48).
4-B-49 --Supplemental Indenture, dated as of September 1, 1984, supplementing said Mortgage (filed with Form
S-3, File No. 2-95931, effective April 1, 1985, as Exhibit 4-B-49).
4-B-56 --Supplemental Indenture, dated as of February 15, 1987, supplementing said Mortgage (filed with Form
10-K for the year ended December 31, 1986, File No. 1-4928, as Exhibit 4-B-56).
4-B-58 --Supplemental Indenture, dated as of October 1, 1987, supplementing said Mortgage (filed with Form 10-K for
the year ended December 31, 1987, File No. 1-4928, as Exhibit 4-B-58).
4-B-60 --Supplemental Indenture, dated as of March 1, 1990, supplementing said Mortgage (filed with Form 10-K for the
year ended December 31, 1990, File No. 1-4928, as Exhibit 4-B-60).
58
EXHIBIT
NUMBER
4-B-62 --Supplemental Indenture, dated as of May 15, 1990, supplementing said Mortgage (filed with Form 10-K for the
year ended December 31, 1990, File No. 1-4928, as Exhibit 4-B-62).
4-B-63 --Supplemental Indenture, dated as of March 1, 1991, supplementing said Mortgage (filed with Form 10-K for the
year ended December 31, 1990, File No. 1-4928, as Exhibit 4-B-63).
4-B-64 --Supplemental Indenture, dated as of July 1, 1991, supplementing said Mortgage (filed with Form S-3, File No.
33-45501, effective February 13, 1992, as Exhibit 4-B-64).
4-B-65 --Supplemental Indenture, dated as of December 1, 1991, supplementing said Mortgage (filed with
Form S-3, File No. 33-45501, effective February 13, 1992, as Exhibit 4-B-65).
4-B-66 --Supplemental Indenture, dated as of March 1, 1992, supplementing said Mortgage (filed with Form 10-K for the
year ended December 31, 1991, File No. 1-4928, as Exhibit 4-B-66).
4-B-67 --Supplemental Indenture, dated as of June 1, 1992, supplementing said Mortgage (filed with Form S-3, File No.
33-50592, effective August 11, 1992, as Exhibit 4-B-67).
4-B-68 --Supplemental Indenture, dated as of July 1, 1992, supplementing said Mortgage (filed with Form S-3, File No.
33-50592, effective August 11, 1992, as Exhibit 4-B-68).
4-B-69 --Supplemental Indenture, dated as of September 1, 1992, supplementing said Mortgage (filed with
Form S-3, File No. 33-53308, effective November 24, 1992, as Exhibit 4-B-69).
4-B-70 --Supplemental Indenture, dated as of February 1, 1993, supplementing said Mortgage (filed with
Form 10-K for the year ended December 31, 1992, File No. 1-4928, as Exhibit 4-B-70).
4-B-71 --Supplemental Indenture, dated as of March 1, 1993, supplementing said Mortgage (filed with Form S-3, File
No. 33-59448, effective March 17, 1993, as Exhibit 4-B-71).
4-B-72 --Supplemental Indenture, dated as of April 1, 1993, supplementing said Mortgage (filed with Form S-3, File
No. 33-50543, effective October 20, 1993, as Exhibit 4-B-72).
4-B-73 --Supplemental Indenture, dated as of May 1, 1993, supplementing said Mortgage (filed with Form S-3, File No.
33-50543, effective October 20, 1993, as Exhibit 4-B-73).
4-B-74 --Supplemental Indenture, dated as of June 1, 1993, supplementing said Mortgage (filed with Form S-3, File No.
33-50543, effective October 20, 1993, as Exhibit 4-B-74).
4-B-75 --Supplemental Indenture, dated as of July 1, 1993, supplementing said Mortgage (filed with Form S-3, File No.
33-50543, effective October 20, 1993, as Exhibit 4-B-75).
4-B-76 --Supplemental Indenture, dated as of August 1, 1993, supplementing said Mortgage (filed with Form S-3, File
No. 33-50543, effective October 20, 1993, as Exhibit 4-B-76).
4-B-77 --Supplemental Indenture, dated as of August 20, 1993, supplementing said Mortgage (filed with Form S-3, File
No. 33-50543, effective October 20, 1993, as Exhibit 4-B-77).
4-B-78 --Supplemental Indenture, dated as of May 1, 1994, supplementing said Mortgage (filed with Form 10-K for the
year ended December 31, 1994, File No. 1-4928, as Exhibit 4-B-78).
4-B-79 --Supplemental Indenture, dated as of November 1, 1994, supplementing said Mortgage (filed with
Form 10-K for the year ended December 31, 1994, File No. 1-4928, as Exhibit 4-B-79).
4-B-80 --Supplemental Indenture, dated as of August 1, 1995, supplementing said Mortgage (filed with Form 10-K for
the year ended December 31, 1995, File No. 1-4928, as Exhibit 4-B-80).
4-C --Instrument of Resignation, Appointment and Acceptance among Duke Power Company, Morgan Guaranty Trust
Company of New York, as Trustee, and Chemical Bank, as Successor Trustee, dated as of August 30, 1994 (filed
with Form 10-K for the year ended December 31, 1994, File No. 1-4928, as Exhibit 4-C).
10-A --Agreement, dated March 6, 1978, between the registrant and the North Carolina Municipal Power Agency No. 1
(filed with Form 8-K for the month of March 1978, File No. 1-4928).
10-B --Agreement, dated August 1, 1980, between the registrant and Piedmont Municipal Power Agency (filed with Form
8-K for the month of August 1980, File No. 1-4928).
10-C --Agreement, dated October 14, 1980 between the registrant and North Carolina Electric Membership Corporation
(filed with Form 10-Q for the quarter ended September 30, 1980, File No. 1-4928).
10-D --Agreement, dated October 14, 1980 between the registrant and Saluda River Electric Cooperative, Inc. (filed
with Form 10-Q for the quarter ended September 30, 1980, File No. 1-4928).
10-E+ --Employees' Stock Ownership Plan.
10-F++ --Employee Incentive Plan.
10-G++ --1993 Executive Long-Term Incentive Plan.
10-H+ --Supplemental Security Plan.
10-I+ --Stock Purchase-Savings Program for Employees.
10-J+ --Employees' Retirement Plan.
10-K+ --Supplemental Retirement Plan.
59
EXHIBIT
NUMBER
10-L+ --Compensation Deferral Plan.
10-M+ --Compensation Deferral Plan for Outside Directors.
10-N+ --Retirement Plan for Outside Directors.
10-O+ --Supplementary Defined Contribution Plan for Employees.
10-P+ --Directors' Charitable Giving Program.
10-Q+ --Vacation Banking Plan.
10-R+ --Estate Conservation Plan.
10-S+ --Supplemental Insurance Plan.
10-T+ --Group Life Insurance Plan.
10-U+ --Stock Ownership Plan for Nonemployee Directors.
10-V+++ --Executive Short-Term Incentive Plan.
10-W+++ --Executive Long-Term Incentive Plan.
*10-X --Retirement Savings Plan.
*10-Y --Retirement Cash Balance Plan.
*10-Z --Executive Savings Plan.
*10-AA --Executive Cash Balance Plan.
*10-BB --Directors' Savings Plan.
*12 --Computation of Ratio of Earnings to Fixed Charges.
*23 --Consent of Independent Auditors.
*24(a) --Power of attorney authorizing Ellen T. Ruff and others to sign the annual report on behalf of the registrant
and certain of its directors and officers.
*24(b) --Certified copy of resolution of the Board of Directors of the registrant authorizing power of attorney.
*27 --Financial Data Schedule.
+ Compensatory plan or arrangement filed with Form 10-K for the year ended
December 31, 1992, File No. 1-4928, under the same exhibit number as listed
herein.
++ Compensatory plan or arrangement filed with Form 10-K for the year ended
December 31, 1993, File No. 1-4928, under the same exhibit number as listed
herein.
+++ Compensatory plan or arrangement filed with Form 10-K for the year ended
December 31, 1994, File No. 1-4928, under the same exhibit number as listed
herein.
60
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