-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, BBlgGx1mnxelt3c194Nj9bOMsJBeKksZyiao21kJLQ6Oyel4vbve82i32/8WEaWD Q8kR8RWEwcj5ShtySIALUg== 0000950168-96-000400.txt : 19960314 0000950168-96-000400.hdr.sgml : 19960314 ACCESSION NUMBER: 0000950168-96-000400 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19951231 FILED AS OF DATE: 19960312 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: DUKE POWER CO /NC/ CENTRAL INDEX KEY: 0000030371 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 560205520 STATE OF INCORPORATION: NC FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 001-04928 FILM NUMBER: 96533990 BUSINESS ADDRESS: STREET 1: 422 S CHURCH ST CITY: CHARLOTTE STATE: NC ZIP: 28242-0001 BUSINESS PHONE: 7045940887 MAIL ADDRESS: STREET 1: 422 S CHURCH ST CITY: CHARLOTTE STATE: NC ZIP: 28242 10-K405 1 DUKE POWER 10-K405 #41826.1 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) [x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED] For the fiscal year ended December 31, 1995 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] For the transition period from to Commission File Number 1-4928 DUKE POWER COMPANY (Exact name of registrant as specified in its charter) 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:
Title Of Each Class Name Of Each Exchange 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 March 8, 1996............................................................................. $9,850,948,807 Number of shares of Common Stock, without par value, outstanding at March 8, 1996.............. 204,859,339
Documents Incorporated By Reference: The registrant is incorporating herein by reference certain sections of its proxy statement relating to the 1996 annual meeting of shareholders to provide information required by the following parts of this annual report: Part III -- Item 10., Directors and Executive Officers of the Registrant -- Item 11., Executive Compensation -- Item 12., Security Ownership of Certain Beneficial Owners and Management -- Item 13., Certain Relationships and Related Transactions DUKE POWER COMPANY FORM 10-K ANNUAL REPORT TO THE SECURITIES AND EXCHANGE COMMISSION FOR THE YEAR ENDED DECEMBER 31, 1995 TABLE OF CONTENTS
Item Page PART I. 1 Business. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Executive Officers of the Company. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Submission of Matters to a Vote of Security Holders. . . . . . . . . . . . . . . . . . . . . . . . . . . PART II. 5 Market for the Registrant's Common Equity and Related Stockholder Matters. . . . . . . . . . . . . . . . 6 Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Management's Discussion and Analysis of Results of Operations and Financial Condition. . . . . . 8 Financial Statements and Supplementary Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. . . . . . . . . . . PART III. 10 Directors and Executive Officers of the Registrant. . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Executive Compensation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Security Ownership of Certain Beneficial Owners and Management. . . . . . . . . . . . . . . . . . . . . 13 Certain Relationships and Related Transactions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . PART IV. 14 Exhibits, Consolidated Financial Statement Schedules, and Reports on Form 8-K. . . . . . . . . . . . . Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exhibit Index. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
DUKE POWER COMPANY PART I. Item 1. Business. Duke Power Company (the Company) is primarily engaged in the generation, transmission, distribution and sale of electric energy in the central portion of North Carolina and the western portion of South Carolina, comprising the area in both states known as the Piedmont Carolinas. It is one of the nation's largest investor-owned electric utilities. The Company is also engaged in a variety of diversified operations, most of which are organized in separate subsidiaries. The Company's subsidiaries and diversified activities are in the Associated Enterprises Group (AEG). AEG includes Church Street Capital Corp.; Crescent Resources, Inc.; Duke Energy Group, Inc.; Duke Engineering & Services, Inc.; Duke/Fluor Daniel; Duke Merchandising; DukeNet Communications, Inc.; Duke Water Operations; and Nantahala Power and Light Company (NP&L). For additional information on subsidiaries and diversified activities, see "Subsidiaries and Diversified Activities", "Management's Discussion and Analysis of Results of Operations and Financial Condition, Current Issues -- Subsidiaries and Diversified Operations" and "Subsidiaries and Diversified Activities Highlights". During 1995, the Company's operating revenues, including AEG, were $4.7 billion. The Company's executive offices are located in the Power Building, 422 South Church Street, Charlotte, North Carolina 28242-0001 (Telephone No. 704-594-0887). Service Area The Company's service area (excluding NP&L), approximately two-thirds of which lies in North Carolina, covers about 20,000 square miles with an estimated population of 5.0 million and includes a number of cities, of which the largest are Charlotte, Greensboro, Winston-Salem and Durham in North Carolina and Greenville and Spartanburg in South Carolina. The Company supplies electric service directly to approximately 1.8 million residential, commercial and industrial customers in more than 200 cities, towns and unincorporated communities. Electricity is sold at wholesale to incorporated municipalities and to several public and private utilities. In addition, sales are made through contractual agreements to former wholesale municipal or cooperative customers of the Company who had purchased portions of the Catawba Nuclear Station (collectively, the "other Catawba joint owners") (See "Joint Ownership of Generating Facilities.") NP&L services an additional 53,000 mostly residential customers in five counties in western North Carolina. The Company's service area is undergoing increasingly diversified industrial development. The textile industry, machinery and equipment manufacturing, and chemical and chemical-related industries are of major significance to the economy of the area. Other industrial activities include rubber and plastic products, paper and allied products, and various other light and heavy manufacturing and service businesses. The largest industry served is the textile industry, which accounted for approximately $494 million of the Company's revenues for 1995, representing 11 percent of electric revenues and 39 percent of industrial revenues. Energy Requirements And Capability The following table sets forth the Company's generating capability as of December 31, 1995, its sources of electric energy for 1995 and certain information presently projected for 1996:
Source Generating Capability Generation MWH MW(a)(b)(c) (thousands)(c) Actual Projected Actual December 31, 1995 December 31, 1996 1995 Coal. . . . . . . . . . . . . . . . . . . . . . 7,699 7,699 32,389 Nuclear (d) . . . . . . . . . . . . . . . . . . 5,078 5,078 39,836 Hydro and other. . . . . . . . . . . . . . . . . 4,166 4,466(e) 1,940 Total . . . . . . . . . . . . . . . . . . . . . 16,943 17,243 74,165 Plus: Purchases from other Catawba joint owners . 6,070 Purchased power and net interchange . . . . . 1,175 Total . . . . . . . . . . . . . . . . . . 81,410
(a) The data relating to capability does not reflect the possible unavailability or reduction of capability of facilities at any given time because of scheduled maintenance, repair requirements or regulatory restrictions. (b) Excludes firm purchases and sales. (See "Energy Management and Future Power Needs.") (c) Excludes NP&L. (d) Nuclear capability and related generation for 1995 and related projections for 1996 reflect the Company's 12.5% ownership share of the Catawba Nuclear Station. (See "Joint Ownership of Generating Facilities".) (e) Includes four units of the Lincoln Combustion Turbine Station with generating capacity of 300 MW which were placed into commercial operation in early 1996. (See "Capital Requirements.") NP&L operates 11 hydroelectric stations with a total capacity of 100 megawatts and also purchases supplemental power. The Company supplies supplemental power to NP&L under the terms of an interconnection agreement approved by the Federal Energy Regulatory Commission (FERC). The Company has a bulk power sales agreement with Carolina Power & Light Company (CP&L) to provide CP&L 400 megawatts of capacity as well as associated energy when needed for a six-year period which began July 1, 1993. Electric rates in all regulatory jurisdictions were reduced by adjustment riders to reflect capacity revenues received from this CP&L bulk power agreement. According to 1994 industry statistics published in 1996, the Company ranked first in the nation in terms of efficiency of its steam-fossil generating system as measured by the conversion of fuel energy to electric energy. Published rankings indicate that individual units at Marshall Steam Station and Belews Creek Steam Station ranked first, third, fourth, fifth, eighth and tenth most efficient in the nation in 1994. The Company's nuclear system continued its tradition of operating efficiency, operating at 90 percent of capacity for 1995, in comparison with the industry's latest available average capacity factor of 74 percent for 1994. The Company's system nuclear capacity factor reflects the Company's 12.5% ownership share of the Catawba Nuclear Station. The Company normally experiences seasonal peak loads in summer and winter which are relatively in balance. The Company currently forecasts a 1.8 percent compound annual growth in peak load through 2010. An all-time peak load of 15,542 MW occurred on August 14, 1995 during exceptionally warm summer weather. This peak load excludes the portion of the demand of the other joint owners of the Catawba Nuclear Station met by their retained ownership. Rate Matters The North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (PSCSC) must approve the Company's rates for retail sales within their respective states. The FERC must approve the Company's rates for sales to wholesale customers, including the contractual arrangements between the Company and the other Catawba joint owners. The most recent general rate increase requests in the Company's retail jurisdictions were filed and approved in 1991. The Company also filed its most recent general rate increase request within the FERC wholesale jurisdiction in 1991. A negotiated settlement between the Company and the wholesale customers was approved by the FERC in 1992. In its most recent general rate case, the NCUC authorized a jurisdictional rate of return on common equity of 12.50 percent, and the PSCSC authorized a jurisdictional rate of return on common equity of 12.25 percent. During 1992, NP&L filed an application for a general rate increase with the NCUC. A general rate increase was approved in June 1993. Fuel And Purchased Power Cost Adjustment Procedures. Duke Power has procedures in all three of its regulatory jurisdictions to adjust rates for fluctuations in fuel expense. The North Carolina legislature enacted a statute in 1987 assuring the legality of adjustments of past over- and under-recovery of fuel costs in rates. The North Carolina legislature repealed the expiration provision of this statute in March 1995. In the North Carolina retail jurisdiction, a review of fuel costs in rates is required annually and during general rate case proceedings. Fuel costs are reviewed semiannually in the wholesale and South Carolina retail jurisdictions. All jurisdictions allow Duke Power to adjust rates for past over- or under-recovery of fuel costs. Therefore, Duke Power reflects in revenues the difference between actual fuel costs incurred and fuel costs recovered through rates. Purchased power costs of NP&L are reviewed annually and during general rate case proceedings by the NCUC. NP&L is allowed to adjust rates for past over- or under-recovery of purchased power costs. Therefore, NP&L defers the difference between actual purchased power costs incurred and those recovered through rates. Construction Work In Progress (CWIP). The NCUC is permitted in its discretion to include CWIP in rate base after giving consideration to the public interest and the Company's financial stability. The PSCSC may include CWIP in rate base in its discretion. Energy Management And Future Power Needs The Company's strategy for meeting customers' present and future energy needs is composed of three components: demand-side resources, purchased power resources and supply-side resources. By utilizing these resources, the Company expects to maintain a reserve margin of approximately 18 to 20 percent of its anticipated peak load requirements through 2000. The Company continues to engage in a comprehensive energy management program as part of its Integrated Resource Plan (IRP). Integrated resource planning is the process used by utilities to evaluate a variety of resources. The goal is to provide adequate and reliable electricity in an environmentally responsible manner through cost-effective power management. The Company files an IRP with the NCUC and the PSCSC once every three years. During each of the intervening years, the Company files a Short Term Action Plan which updates the IRP for any changes in projections for the next three years. The PSCSC issued an order on December 14, 1995 approving the Company's 1995 IRP. On February 20, 1996, the NCUC issued a similar order. Demand-side management (DSM) programs benefit the Company and its customers by promoting energy efficiency, providing for load control through interruptible control features, shifting usage to off-peak periods and increasing strategic sales of electricity. In return for participation in demand-side management programs, customers may be eligible to receive various incentives which help reduce their net investment in high-efficiency equipment or their electric bills. The November 1991 rate orders of the NCUC and the PSCSC provided for recovery in rates of a designated level of costs for DSM programs and allowed the deferral for later recovery of certain DSM costs that exceed the level reflected in rates, including a return on deferred costs. In 1993, the NCUC and the PSCSC issued orders approving "shared savings" mechanisms for accomplishments achieved in the Company's DSM programs, and deferral of such shared savings. The Company ultimately expects recovery through rates of associated deferred costs, not to exceed $75 million including deferred returns in the North Carolina retail jurisdiction. The annual costs deferred, including the return, were approximately $27 million in 1995 and $25 million in 1994. The total costs deferred, including the return, are $58 million and $38 million in North Carolina and South Carolina, respectively. The purchase of capacity and energy is an integral part of meeting future power needs. As of December 31, 1995, the Company had under contract 300 MW of capacity from other generators of electricity, including 62 MW from qualifying facilities. In 1995, the Company issued two requests for proposals (RFP) to solicit competitive bids for its future electric generating capacity resources. The short-term RFP could provide options for up to 675 megawatts of capacity with terms of 1 to 4 years. The long-term RFP solicits bids to provide up to 300 megawatts of purchased power to be available beginning in 1998 or 1999, for contract periods of between 5 and 20 years in duration. The Company has evaluated a total of 16 proposals received for both the short-term RFP and the long-term RFP and has begun negotiation with the bidders with the best proposals. Contracts are expected to be awarded in May 1996. Capital Requirements Projected capital expenditures, excluding costs related to portions of the Catawba Nuclear Station owned by the other Catawba joint owners, for the years set forth below, as now scheduled, are as follows (in millions):
1996 1997 1998 1999 2000 Total Duke Power - Electric Generation. . . . . . . . . . . . . $ 193 $ 210 $ 124 $ 115 $ 132 $ 774 Transmission. . . . . . . . . . . . 40 41 42 42 42 207 Distribution. . . . . . . . . . . . 199 198 199 200 201 997 Other. . . . . . . . . . . . . . . . 72 64 65 60 60 321 Nuclear Fuel. . . . . . . . . . . . 120 136 116 164 125 661 Total Duke Power - Electric. . . 624 649 546 581 560 2,960 Associated Enterprises Group. . . . . 226 194 178 206 219 1,023 Total Company. . . . . . . . . . . . . $ 850 $ 843 $ 724 $ 787 $ 779 $ 3,983
The Company's procedures for estimating capital expenditures for Duke Power - Electric (which include allowance for funds used during construction) utilize, among other things, past construction experience, current construction costs, allowances for inflation and the Company's business plan. These projections are subject to periodic review and revisions. Actual construction and nuclear fuel costs and capital expenditures incurred may vary from such estimates. Cost variances for Duke Power - Electric are due to various factors, including revised load estimates, environmental matters and cost and availability of capital. Projections of the AEG capital expenditures are subject to periodic review and revision and may vary significantly as the business plans of AEG evolve to meet the opportunity presented by its markets. The Company has substantially completed construction of a combustion turbine facility in Lincoln County, North Carolina to provide capacity at periods of peak demand. The Lincoln Combustion Turbine Station consists of 16 combustion turbines with a total generating capacity of 1,200 megawatts. The estimated total cost of the project is approximately $400 million. Twelve of the 16 units were placed into commercial operation in 1995, and as of March 1, 1996, the final four units were placed into commercial operation. During 1991, the NCUC granted the Certificate of Public Convenience and Necessity and the North Carolina Division of Environmental Management issued a final air permit for the facility. All appeals related to the issuance of the final air permit were resolved in 1995. Joint Ownership Of Generating Facilities In order to reduce its need for external financing, the Company, through several transactions beginning in 1978, sold an 87 1/2 percent undivided interest in the Catawba Nuclear Station to the other Catawba joint owners. These transactions contemplate that the Company will operate the facility, interconnect its transmission system, wheel a certain portion of the capacity and energy of such facility to the respective participants, provide back-up services for such capacity, buy for its own use (whether or not the facility is generating electricity) that portion of the capacity not then contractually required by the respective participants, and provide supplemental power as required by the purchasers to enable them to provide service on a firm basis. The transactions also include a reliability exchange between the Catawba Nuclear Station and the McGuire Nuclear Station of the Company, which provides for an exchange of 50 percent of each other Catawba joint owner's retained capacity from its ownership interest in the Catawba units for like amounts of capability and output from units of the McGuire Nuclear Station. The implementation of the reliability exchange has not had, nor does the Company anticipate that such implementation will have, a material effect on earnings. (See Note 3, "Notes to Consolidated Financial Statements.") The Company and North Carolina Municipal Power Agency Number 1 (NCMPA) and Piedmont Municipal Power Agency (PMPA), two of the four other joint owners of the Catawba Nuclear Station, entered into a settlement in September 1995 which resolved outstanding issues related to how certain calculations affecting bills under the Catawba joint ownership contractual agreements should be performed. The settlement was approved by the NCUC on January 16, 1996 and the PSCSC on January 23, 1996. As part of the settlement, the Company agreed to purchase additional megawatts (MW) of Catawba capacity during the period 1996 through 1999 and remove certain restrictions related to sales of surplus energy by these two joint owners. The additional capacity purchases are 215 MW in 1996, 165 MW in 1997, 120 MW in 1998 and 100 MW in 1999. The Company expects to recover the costs associated with this settlement as part of the purchased capacity levelization, consistent with prior orders of the retail regulatory commissions. Therefore, the Company believes these matters should not have a material adverse effect on the results of operations or financial position of the Company. The Company and all four of the other joint owners of the Catawba Nuclear Station entered into settlement agreements in 1994 which resolved all issues in contention in arbitration proceedings related to the Catawba joint ownership contractual agreements. The basic contention in each proceeding was that certain calculations affecting bills under these agreements should be performed differently. These items are covered by the agreements between the Company and the other Catawba joint owners which have been previously approved by the Company's retail regulatory commissions. (For additional information on Catawba joint ownership, see Note 3, "Notes to Consolidated Financial Statements.") In 1994, the Company settled its cumulative net obligation through 1993 of approximately $205 million related to these settlement agreements. Billings for 1994 and later years will conform to the settlement agreements, which have been approved by the Company's retail regulatory commissions. Because the Company expects the costs associated with these settlements to be recovered as part of the purchased capacity levelization, which has been approved by the Company's retail regulatory commissions, the Company included approximately $205 million as an increase to "Purchased capacity costs" on its Consolidated Balance Sheets in 1994. Therefore, the Company believes these matters should not have a material adverse effect on the results of operations or financial position of the Company. Fuel Supply The Company presently relies principally on nuclear fuel and coal for the generation of electric energy. The Company's reliance on oil and gas is minimal and will remain minimal even with the addition of the Lincoln Combustion Turbine Station, which is designed to operate on either natural gas or oil. Information regarding the utilization of sources of power and cost of fuels is set forth in the following table:
Generation by Source Cost of Fuel per Net KWH Generated (Cents) Year Ended December 31 Year Ended December 31 1995 1994 1993 1995 1994 1993 Coal. . . . . . . . . . . . . . . . . . . . . . . . . 43.7% 46.9% 48.6% 1.56 1.54 1.61 Nuclear (1) . . . . . . . . . . . . . . . . . . . . . 53.7% 51.0% 49.1% 0.57 0.56 0.53 Oil and gas . . . . . . . . . . . . . . . . . . . . . -- -- -- -- -- -- All Fuels (cost based on weighted average) (1) . . 97.4% 97.9% 97.7% 1.03 1.03 1.07 Hydroelectric (2) . . . . . . . . . . . . . . . . . . 2.6% 2.1% 2.3% 100.0% 100.0% 100.0%
(1) Statistics related to nuclear generation and all fuels reflect the Company's 12.5% ownership in the Catawba Nuclear Station. (2) Generating figures are net of that output required to replenish pumped storage units during off-peak periods and do not include NP&L. Coal. The Company obtains a large amount of its coal under long-term supply contracts with mining operators utilizing both underground and surface mining. The Company has on hand an adequate supply of coal. The Company's long-term supply contracts, all of which have price adjustment provisions, have expiration dates ranging from 1996 to 2003. The Company believes that it will be able to renew such contracts as they expire or to enter into similar contractual arrangements with other coal suppliers for quantities and qualities of coal required. The coal covered by the Company's long-term supply contracts is produced from mines located in eastern Kentucky, southern West Virginia and southwestern Virginia. The Company's requirements not met by long-term supply contracts have been and will be fulfilled with spot market purchases. The average sulfur content of coal being purchased by the Company is approximately 1 percent. Such coal satisfies the current emission limitation for sulfur dioxide for existing facilities. (See "Management's Discussion and Analysis of Results of Operations and Financial Condition, Current Issues -- The Clean Air Act Amendments of 1990.") Nuclear. Generally, the supply of fuel for nuclear generating units involves the mining and milling of uranium ore to produce uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, enrichment of that gas and fabrication of the enriched uranium hexafluoride into usable fuel assemblies. After a region (approximately one-third of the nuclear fuel assemblies in the reactor at any time) of spent fuel is removed from a nuclear reactor, it is placed in temporary storage for cooling in a spent fuel pool at the nuclear station site. The Company has contracted for uranium materials and services required to fuel the Oconee, McGuire and Catawba Nuclear Stations. Based upon current projections, these contracts will meet the Company's requirements through the following years:
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) recently requested Expressions of Interest (EOI) to facilitate in the disposal of plutonium. The Company and Commonwealth Edison, along with the other joint owners of the Catawba Nuclear Station, responded to the EOI in early 1996. As this project is in its early developmental stage, management cannot predict the outcome of this process. However, the Company believes these matters should not have a material effect on the results of operations or financial position of the Company. The Nuclear Waste Policy Act of 1982 requires that the DOE begin disposing of spent fuel no later than January 31, 1998. The Company has entered into the required contracts with the DOE for the disposal of nuclear fuel and began making payments in July 1983 for disposal costs of fuel currently being utilized. These payments, combined with a one-time payment for disposal costs of fuel consumed prior to April 7, 1983, have totaled about $510 million through 1995 related to the Company's ownership interest in nuclear plants. In December 1995, the DOE released a report which indicated that it expects a facility for spent fuel disposal will not be available until the year 2015. The DOE continues to pursue a centralized interim storage facility, with a target operation date of 1998, for earlier acceptance of spent fuel from utilities. The Company believes that it will be able to provide adequate on-system storage capacity until such time as the DOE begins receiving spent fuel. Regulation The Company is subject to the jurisdiction of the NCUC and the PSCSC which, among other things, must approve the issuance of securities. The Company also is subject, as to some phases of its business, to the jurisdiction of the FERC, the Environmental Protection Agency (EPA) and state environmental agencies and to the jurisdiction of the Nuclear Regulatory Commission (NRC) as to design, construction and operation of its nuclear power facilities. The Company is exempt from regulation as a holding company under the Public Utility Holding Company Act of 1935, except with respect to the acquisition of the securities of other public utilities. Environmental Matters. The Company is subject to federal, state, and local regulations with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. North Carolina has enacted a declaration of environmental policy requiring all state agencies to administer their responsibilities in accordance with such policy. The NCUC has adopted rules requiring consideration of environmental effects in determining whether certificates of public convenience and necessity will be granted for proposed generation facilities. South Carolina law also requires consideration by the PSCSC of environmental effects in determining whether certificates of public convenience and necessity will be granted for proposed major utility facilities, which include certain generation and transmission facilities. All of the Company's facilities which are currently under construction have been designed to comply with presently applicable environmental regulations. Such compliance has, however, increased the cost of electric service by requiring changes in the design and operation of existing facilities, as well as changes or delays in the design, construction and operation of new facilities. In 1995, the Company's construction costs for environmental protection totaled approximately $52 million, while the on-going environmental operation costs were approximately $25 million. The Company's 1996-2000 construction program includes costs for environmental protection which are estimated to be approximately $40 million, including $9.8 million in 1996, $4.1 million in 1997, $7.4 million in 1998, $9.7 million in 1999 and $9.4 million in 2000. These costs include expenditures associated with the Clean Air Act Amendments of 1990. However, governmental regulations establishing environmental protection standards are continually evolving and have not, in some cases, been fully established. These projections are subject to periodic review and revisions. Actual construction costs and capital expenditures incurred may vary from such estimates. Cost variances are due to various factors, including cost and availability of capital. AIR QUALITY. See "Management's Discussion and Analysis of Results of Operations and Financial Condition, Current Issues -- The Clean Air Act Amendments of 1990" for a discussion of the Company's plans for compliance with federal clean air standards. WATER QUALITY. The Federal Water Pollution Control Act Amendments of 1987 (referred to herein as the "Clean Water Act") require permits for facilities that discharge into waters. The Company holds numerous such permits, which are issued periodically. The issuance of such permits is delegated by the EPA to state agencies in North and South Carolina. The Clean Water Act has been scheduled for review and reauthorization by Congress since 1994, but no legislation has been enacted. Until Congress acts upon the reauthorization, management will be unable to assess what effect, if any, such reauthorization will have on the Company's operations. OTHER ENVIRONMENTAL REGULATIONS. Contingencies associated with environmental matters are principally related to possible obligations to remove or mitigate the effects on the environment resulting from the disposal of certain substances at contamination sites. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), commonly known as "Superfund", requires any individual or entity which may have owned or operated a contaminated site, as well as transporters or generators of hazardous wastes which were sent to such site, to assume joint and several responsibility for remediation of the site. Such parties are known as "potentially responsible parties" (PRPs). Some contamination sites are remediated pursuant to state acts which are similar to CERCLA. The Company has participated in site remediation activities in the past as a PRP at Superfund sites or similar state sites in the Charlotte area, near Chester, S.C., and in Pennsylvania and West Virginia. The Company's involvement in one Superfund site and one state site was resolved in early 1996. The Company is currently participating in PRP groups with regard to Superfund sites in Concord, North Carolina and Lenoir, North Carolina. While the total cost of remediation at these federal and state contamination sites may be substantial, the Company shares probable liability with other PRPs, many of which have substantial assets. Management is of the opinion that resolution of these matters will not have a material adverse effect on the results of operations or financial position of the Company. Other contamination sites in which the Company is involved arise from the operation of manufactured gas plant (MGP) sites, which were commonplace in the Carolinas until the 1950s. Some such sites are still owned by the Company, and others are now owned by third parties. In North Carolina, the Company is participating in a state-sponsored program to investigate and, where appropriate, remediate MGP sites. In South Carolina, the Company is in the process of remediating an MGP site in Greenville. Management is of the opinion that resolution of these matters will not have a material adverse effect on the results of operations or financial position of the Company. CERCLA has been scheduled for review and reauthorization by Congress since 1994, but has not been examined outside of the legislative committee structure. Until CERCLA reform occurs, management will be unable to assess what effect, if any, such reauthorization will have on the Company's operations. GENERAL. Over the past few decades, the issue of the possible health effects of electric and magnetic fields has generated a number of generally inconclusive studies, some public concern and litigation as well as legislative action in some states regarding high voltage transmission lines. The impact of this issue on the Company cannot presently be determined. Nuclear Facilities. The Company's nuclear facilities are subject to continuing regulation by the NRC. Stress corrosion cracking (SCC) has occurred in the steam generators of Units 1 and 2 at the McGuire Nuclear Station and Unit 1 at the Catawba Nuclear Station. Catawba Unit 2, which has certain design differences and came into service at a later date, has not yet shown the degree of SCC which has occurred in McGuire Units 1 and 2 and Catawba Unit 1. It is, however, too early in the life of Catawba Unit 2 to determine the extent to which SCC may be a problem. Although the Company has taken steps to mitigate the effects of SCC, the inherent potential for future SCC in the McGuire and Catawba steam generators still exists. The Company is planning for the replacement of steam generators at three units that have experienced SCC and has signed an agreement with Babcock & Wilcox International to purchase replacement steam generators. The current schedule for completion of the effort is as follows: Catawba Unit 1 -- 1996, McGuire Unit 1 -- 1997 and McGuire Unit 2 -- 1997. The order of replacement is subject to change based on operational and project circumstances. The Catawba Unit 2 steam generators have not been scheduled for replacement. Steam generator replacement at each unit is expected to take approximately four months and cost approximately $170 million per unit, excluding the cost of replacement power and the reimbursement of applicable costs by the other Catawba joint owners for Catawba Unit 1. The $170 million per unit cost estimate includes the cost of removal of steam generators being replaced. Stress corrosion problems are excluded under the Company's nuclear insurance policies. The Company, in connection with its McGuire and Catawba stations and on behalf of the other joint owners, began a legal action in 1990, alleging that Westinghouse Electric Corporation knowingly supplied to the McGuire and Catawba Stations steam generators that were defective in design, workmanship and materials, requiring replacement well short of their stated design life. The lawsuit was settled in 1994. While the court order does not allow disclosure of the terms of the settlement, the Company believes the litigation was settled on terms that provided satisfactory consideration to the Company and will not have a material effect on the results of operations or financial position of the Company. Nuclear Decommissioning Costs. Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $1.3 billion stated in 1994 dollars based on decommissioning studies completed in 1994. This amount includes the Company's 12.5 percent ownership in the Catawba Nuclear Station. The other joint owners of the Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. Both the NCUC and the PSCSC have granted the Company recovery of the estimated decommissioning costs through retail rates over the expected remaining service periods of the Company's nuclear plants. Such estimates presume that units will be decommissioned as soon as possible following the end of their license life. Although subject to extension, the current operating licenses for the Company's nuclear units expire as follows: Oconee 1 and 2 -- 2013, Oconee 3 -- 2014; McGuire 1 -- 2021, McGuire 2 -- 2023; and Catawba 1 -- 2024, Catawba 2 -- 2026. The NRC issued a rulemaking in 1988 which requires an external mechanism to fund the estimated cost to decommission certain components of a nuclear unit subject to radioactive contamination. In addition to the required external funding, the Company maintains an internal reserve to provide for decommissioning costs of plant components not subject to radioactive contamination. During 1995, the Company expensed approximately $56 million, which was contributed to the external funds and accrued an additional $1 million to the internal reserve. The balance of the external funds as of December 31, 1995, was $273 million. The balance of the internal reserve as of December 31, 1995, was $206 million and is reflected in accumulated depreciation and amortization on the Consolidated Balance Sheets. Management's opinion is that the decommissioning costs being recovered through rates, when coupled with assumed after-tax fund earnings of 5.5 percent to 5.9 percent, are currently sufficient to provide for the cost of decommissioning. A provision in the Energy Policy Act of 1992 established a fund for the decontamination and decommissioning of the DOE's uranium enrichment plants. Licensees are subject to an annual assessment for 15 years based on their pro rata share of past enrichment services. The annual assessment is recorded as fuel expense. The Company paid approximately $9.2 million during 1995 and $35.6 million cumulatively related to its ownership interest in nuclear plants. The Company has reflected the remaining liability and regulatory asset of approximately $101 million in the Consolidated Balance Sheets at December 31, 1995. Nuclear Insurance. For a discussion of the Company's nuclear insurance coverage, see "Note 13, Notes to Consolidated Financial Statements, Commitments and Contingencies -- Nuclear Insurance." Hydroelectric Licenses. The principal hydroelectric projects of the Company are licensed by FERC under Part I of the Federal Power Act. Eleven developments on the Catawba-Wateree River in North Carolina and South Carolina, with a nameplate rating of approximately 805 MW, are licensed for a term expiring in 2008. The Company also holds a license for the Keowee-Toxaway Project for a term expiring in 2016, covering the Keowee Hydro Station and the Jocassee Pumped Storage Station for a combined total of approximately 770 MW, on the upper tributaries of the Savannah River in northwestern South Carolina. Additionally, the Company is the licensee through 2027 for the Bad Creek Hydroelectric Station which uses Lake Jocassee as its lower reservoir and has a nameplate rating of 1,065 MW. NP&L holds licenses for 11 hydroelectric projects with a nameplate rating of 100 MW with license terms expiring 2001-2006. The Federal Power Act provides, among other things, that, upon the expiration of any license issued thereunder, the United States may (a) grant a new license to the licensee for the project, (b) take over the project upon payment to the licensee of its "net investment" in the project (but not in excess of the fair value thereof) plus severance damages, or (c) grant a license for the project to a new licensee subject to payment to the former licensee of the amount specified in (b) above. Interconnections The Company has major interconnections and arrangements with its neighboring utilities which it currently considers adequate for coordinated planning, emergency assistance, exchange of capacity and energy, and reliability of power supply. Competition The Company currently is subject to competition in some areas from government-owned power systems, municipally-owned electric systems, rural electric cooperatives and, in certain instances, from other private utilities. Statutes in North Carolina and South Carolina provide for the assignment by the NCUC and the PSCSC, respectively, of all areas outside municipalities in such states to power companies and rural electric cooperatives. Substantially all of the territory comprising the Company's service area has been so assigned. The remaining areas have been designated as unassigned and in such areas the Company remains subject to competition. A decision of the North Carolina Supreme Court limits, in some instances, the right of North Carolina municipalities to serve customers outside their corporate limits. In South Carolina there continues to be competition between municipalities and other electric suppliers outside the corporate limits of the municipalities, subject, however, to the regulation of the PSCSC. In addition, the Company is engaged in continuing competition with various natural gas providers. The Energy Policy Act of 1992 (EPACT) is a major driver towards a more competitive market for wholesale sales of power. EPACT reformed provisions of the Public Utility Holding Company Act of 1935 (PUHCA) and Part II of the Federal Power Act to remove certain barriers to competition for the supply of electricity. For example, EPACT allows utilities to develop independent electric generating plants in the United States for sales to wholesale customers, as well as to contract for utility projects internationally, without becoming subject to regulation under PUHCA as an electric utility holding company. In addition, EPACT permits the FERC to order transmission access for third parties to transmission facilities owned by another entity so that independent suppliers can sell at wholesale to customers wherever located. It does not, however, permit the FERC to issue an order requiring transmission access to retail customers. The FERC, responsible in large measure for implementation of the EPACT, has moved vigorously to implement its mandate, interpreting the statute broadly in issuing orders for third-party transmission service and issuing a number of rules of general applicability. The FERC, in late March of 1995, issued a Notice of Proposed Rulemaking (the "NOPR") in which it announced its intent to impose a final rule, applicable to all electric utilities subject to its jurisdiction, which will require all such utilities to adopt open-access transmission tariffs containing identical terms and conditions. The FERC should issue its final rule in 1996. Open transmission access for wholesale customers as contemplated by the FERC's NOPR would provide energy suppliers, including the Company, with opportunities to sell and deliver capacity and energy at market-based prices. Engaging in such transactions could result in improved utilization of the Company's existing assets. In addition, such access would provide another supply option through which the Company can buy capacity and energy at attractive rates, influencing its competitive price position. However, sales to existing wholesale customers of the Company could be impacted by open access as contemplated by the NOPR either due to competitive pressure on the wholesale price of electricity, or the potential loss of sales as wholesale customers seek other options to meet their capacity and energy requirements at market-based prices. Wholesale sales, excluding transactions with other utilities, represented approximately 6.7 percent of the Company's total kilowatt-hour sales in 1995. Supplemental sales to the other joint owners of the Catawba Nuclear Station comprised the majority of such sales. Such supplemental sales will be declining in 1996 as a result of the retention of significantly larger portions of ownership entitlement by the other joint owners. (For additional information on Catawba joint ownership, see Note 3 to the Consolidated Financial Statements.) In early 1995, prior to issuance of the FERC's NOPR, the Company and certain of its affiliates filed three applications with the FERC, all of which are designed to enable effective participation in the competitive environment of the changing electric utility industry. Duke Power filed an application for permission to sell at market-based rates up to 2,500 megawatts of capacity and energy from its own assets. Two of the Company's affiliates, Duke Energy Marketing Corporation (DEMC) and Duke/Louis Dreyfus L.L.C. (D/LD), filed applications with the FERC to become power marketers. All of the applications were supported by transmission tariffs which establish the rates, terms and conditions for transmission service to third parties on the Company's transmission system. Late in 1995, the FERC granted the applications of Duke, DEMC, and D/LD; accepted Duke's transmission tariffs; and ordered a hearing on the rates to be charged for service under those tariffs. The terms and conditions of service are subject to the outcome of the FERC's final rule, and the rates are subject to the outcome of hearings before the FERC. Wheeling of third party energy to a retail customer is not generally allowed in the Company's service territory. However, there are discussions and events at the national level and within certain states regarding retail competition which could result in changes in the industry. Currently, the electric utility industry is predominantly regulated on a basis designed to recover the cost of providing electric power to its retail and wholesale customers. If cost-based regulation were to be discontinued in the industry for any reason, including competitive pressure on the cost-based price of electricity, profits could be reduced and utilities might be required to reduce their recorded asset balances to reflect a market basis less than cost. Discontinuance of cost-based regulation would also require affected utilities to write off their associated regulatory assets. The regulatory assets of the Company are classified as "Deferred debits" on the Consolidated Balance Sheets. Substantially all of the "Deferred debits" are regulatory assets. Management cannot predict the potential impact, if any, of these competitive forces on the Company's future financial position and results of operations. However, the Company continues to position itself to effectively meet these challenges by maintaining prices that are locally, regionally and nationally competitive. Subsidiaries And Diversified Activities The Company continues to aggressively pursue both domestic and international diversified business opportunities that are synergistic with the Company's core business to provide additional value to the Company's shareholders. Although these opportunities are primarily concentrated in areas that utilize the Company's expertise, they present different and potentially greater risks than does the Company's core business. The Company only pursues opportunities in which the expected returns are commensurate with the risks and makes efforts to mitigate such risks. The Company undertakes a continuous evaluation of the various lines of business it may enter or exit, with the objectives of enhancing shareholder value and managing any associated risk. (See "Subsidiaries and Diversified Activities Highlights".) Major subsidiaries and diversified activities include the following: Crescent Resources, Inc. (Crescent) pursues both residential and commercial real estate development, in addition to providing forest management activities focused on growing trees suitable for use in the construction, furniture and paper industries. At December 31, 1995, Crescent owned approximately 2,398,000 square feet of office, retail and warehouse space and had approximately 400,000 square feet of commercial properties under construction. Additionally, Crescent had approximately 250,000 acres of land under its management at year end. Duke Energy Group, Inc. (Duke Energy) develops, owns and manages electric power facilities in the United States and abroad. Duke Energy also markets electric power and natural gas through a joint venture with Louis Dreyfus Electric Power. Domestically, Duke Energy concentrates on advanced fossil-fueled generation including pulverized coal, circulating fluidized bed, coal gasification and natural gas technologies. Internationally, Duke Energy pursues advanced coal-fueled, hydroelectric and gas-fueled generation as well as transmission projects. Duke Energy has equity interests in two U.S. electric generation facilities and four international projects. Nantahala Power and Light Company (NP&L) is a franchised electric utility which operates 11 hydroelectric plants with a total capacity of 100 megawatts. NP&L has approximately 53,000 customers in western North Carolina. NP&L sold 949,000 MWH in 1995 compared to 907,000 MWH in 1994, excluding sales to Duke Power. Other Business Units include Church Street Capital Corp., which manages investment funds and provides equity funding and credit enhancements for its subsidiaries; Duke Engineering & Services, Inc., which markets engineering, construction, quality assurance, consulting and other engineering-related services for facilities other than coal-fired generating plants, both nationally and internationally; Duke/Fluor Daniel, a joint venture with Fluor Daniel, Inc., which provides engineering, construction and support of operating and maintenance activities, primarily for coal-fired generating plants, both nationally and internationally; Duke Merchandising, which sells and services quality electric appliances and electronics; DukeNet Communications, Inc., which develops and manages communications systems; and Duke Water Operations, which provides franchised water services for Anderson, South Carolina and Rutherfordton, North Carolina. Employees At December 31, 1995, the Company had 17,121 full-time employees, which included 1,355 full-time employees of subsidiaries and diversified activities. About 1,950 electrical operating employees are represented by the International Brotherhood of Electrical Workers (IBEW). During the last quarter of 1995, the Company reached new labor agreements with the IBEW for one year terms. The number of full-time employees has decreased to the 1995 year-end level from 19,945 at year-end 1990. (See "Management's Discussion and Analysis of Results of Operations and Financial Condition, Current Issues -- Resource Optimization.") Subsequent Event The Company's Board of Directors has authorized the implementation of a program to repurchase up to $1 billion of the Company's Common Stock from time to time over the next five years. The repurchases will be made either on the open market (in accordance with applicable regulations) or through privately negotiated transactions. The Board's authorization provides flexibility for the Company's management to undertake the repurchase program at its discretion, and does not establish a target stock price or timetable for repurchases. The timing and amount of repurchases will be determined by cash available to the Company for such purpose and by the availability of alternative investment opportunities. (A Map of North Carolina and South Carolina appears here showing Duke Power's service area. The legend is as follows:) LEGEND (star)REGION OFFICE (circle) FOSSIL-FUELED STATION (triangle) HYDROELECTRIC STATION (square) NUCLEAR ELECTRIC STATION (open box) NANTAHALA POWER AND LIGHT DUKE POWER COMPANY OPERATING STATISTICS
Year ended December 31 1995 1994 1993 1992 1991 Sources of Electric Energy (d) Millions of kilowatt-hours: Generated--net output: Coal............................................. 32,389 32,714 34,097 28,999 26,455 Nuclear (a)...................................... 39,836 35,587 34,390 33,925 37,048 Hydro (b)........................................ 1,685 1,460 1,582 1,834 1,545 Oil and gas (c).................................. 255 35 43 5 7 Total generation.............................. 74,165 69,796 70,112 64,763 65,055 Purchased power and net interchange............... 1,175 1,276 1,750 1,403 587 Total output.................................. 75,340 71,072 71,862 66,166 65,642 Plus: Purchases from other Catawba joint owners... 6,070 9,046 8,810 9,466 8,525 Total sources of energy....................... 81,410 80,118 80,672 75,632 74,167 Line loss and company usage....................... 4,673 4,555 4,614 4,590 4,280 Total kilowatt-hour sales..................... 76,737 75,563 76,058 71,042 69,887 Average cost per ton of coal burned................... $ 41.72 $ 40.68 $ 42.21 $ 43.47 $ 45.21 Electric Energy Sales (d) Millions of kilowatt-hours: Residential....................................... 19,669 18,870 19,465 17,789 17,918 General service................................... 18,160 17,289 16,904 15,818 15,586 Industrial Textile......................................... 12,151 12,285 11,954 11,685 11,315 Other........................................... 17,631 17,005 16,244 15,356 14,955 Other energy and wholesale (e).................... 8,330 10,274 11,337 10,360 10,132 Total kilowatt-hour sales billed.............. 75,941 75,723 75,904 71,008 69,906 Unbilled kilowatt-hour sales...................... 796 (160) 154 34 (19) Total kilowatt-hour sales..................... 76,737 75,563 76,058 71,042 69,887 Electric Revenue (d) Thousands of dollars: Residential.......................................$1,441,362 $1,379,740 $1,424,173 $1,312,227 $1,272,322 General service................................... 1,076,791 1,031,061 1,014,124 964,853 921,337 Industrial Textile......................................... 494,066 498,190 487,576 482,172 475,191 Other........................................... 766,750 745,154 726,399 696,413 668,765 Other energy and wholesale (e).................... 461,367 540,256 476,862 460,849 441,777 Other electric revenue............................ 182,102 84,928 152,742 44,970 37,568 Total electric revenues.......................$4,422,438 $4,279,329 $4,281,876 $3,961,484 $3,816,960 Number of Customers--end of year (d) Residential....................................... 1,526,323 1,493,166 1,460,876 1,439,845 1,415,605 General service (f)............................... 246,276 239,355 232,272 227,675 222,917 Industrial Textile......................................... 1,390 1,422 1,396 1,390 1,385 Other........................................... 7,320 7,320 7,338 7,314 7,255 Other energy and wholesale........................ 8,470 8,187 7,957 7,773 7,605 Total customers............................... 1,789,779 1,749,450 1,709,839 1,683,997 1,654,767 Residential Customer Statistics (d) Average number for the year....................... 1,514,434 1,483,497 1,455,609 1,431,403 1,409,775 Average annual use--KWH........................... 12,988 12,720 13,372 12,427 12,710 Average annual billing............................$ 951.75 $ 930.06 $ 978.40 $ 916.74 $ 902.50 Average annual billed revenue per KWH (d) Cents: Residential....................................... 7.33 7.31 7.32 7.38 7.10 General service................................... 5.93 5.96 6.00 6.10 5.91 Industrial........................................ 4.23 4.24 4.31 4.36 4.35 Other energy and wholesale (e).................... 5.54 5.26 4.21 4.45 4.36
(a) Includes 12.5% of Catawba generation. (b) 1991 includes KWH of the Bad Creek Hydroelectric Station prior to commercial operation. (c) 1995 includes KWH of the Lincoln Combustion Turbine Station prior to commercial operation. (d) Does not include operating statistics of NP&L. (e) Includes sales to NP&L. (f) 1991 restated to eliminate certain duplicate customers. EXECUTIVE OFFICERS OF THE COMPANY WILLIAM H. GRIGG, 63, Chairman of the Board and Chief Executive Officer. Mr. Grigg served as Chairman of the Board, President and Chief Executive Officer, effective April 28, 1994, until July 27, 1994 when he assumed his present position. He served as Vice Chairman of the Board beginning in 1991, and Executive Vice President, Customer Group, beginning in 1988. STEVE C. GRIFFITH, JR., 62, Vice Chairman of the Board and General Counsel. Mr. Griffith served as Executive Vice President and General Counsel from 1991 until he assumed his present position in July 1994. He served as Senior Vice President and General Counsel from 1982 until 1991. RICHARD B. PRIORY, 49, President and Chief Operating Officer. Mr. Priory served as Executive Vice President, Power Generation Group, from 1991 until he assumed his present position in July 1994. He was Senior Vice President, Generation and Information Services, from 1988 to 1991. WILLIAM A. COLEY, 52, President, Associated Enterprises Group. Mr. Coley was named Senior Vice President, Power Delivery, in 1988; Senior Vice President, Customer Group, in 1990; and Executive Vice President, Customer Group, in 1991. He was named to his present position in July 1994. RICHARD J. OSBORNE, 44, Senior Vice President and Chief Financial Officer. Prior to assuming his current position in July 1994, Mr. Osborne served as Vice President and Chief Financial Officer beginning in 1991 and Vice President, Finance, from 1988 to 1991. JEFFREY L. BOYER, 39, Controller. Mr. Boyer served as Director of Corporate Accounting for more than five years prior to assuming his present position in July 1994. Executive officers are elected annually by the Board of Directors and serve until the first meeting of the Board of Directors following the next annual meeting of shareholders and until their successors are duly elected. There are no family relationships between any of the executive officers nor any arrangement or understanding between any executive officer and any other person pursuant to which the officer was selected. There have been no events under any bankruptcy act, no criminal proceedings and no judgments or injunctions material to the evaluation of the ability and integrity of any executive officer during the past five years. ITEM 2. Properties. At December 31, 1995, the Company operated three nuclear generating stations, eight coal-fired stations and twenty-seven hydroelectric stations, all of which are located in North Carolina or South Carolina. The following is a list of the major generating stations owned by the Company at December 31, 1995: FACILITY ENERGY SOURCE NET MW - -------------------------------------------------------- ---------------- Oconee Nuclear 2,538 McGuire Nuclear 2,258 Catawba(a) Nuclear 282 Belews Creek Coal 2,240 Marshall Coal 2,090 Allen Coal 1,140 Cliffside Coal 760 Others Coal 1,469 Bad Creek Hydroelectric 1,065 Jocassee Hydroelectric 610 Others Hydroelectric 1,007 Combustion turbines (b) Oil and gas 1,484 (a) Represents Duke's 12.5% ownership share in Catawba Nuclear Station. (b) Includes 900 MW of the Lincoln Combustion Turbine Station which were in commercial operation as of December 31, 1995. The Company has substantially completed the construction of the Lincoln Combustion Turbine Station, a 16-turbine facility designed to provide capacity at periods of peak demand. The station has a total generating capacity of 1,200 megawatts. Twelve of the 16 units were placed into commercial operation in 1995, and as of March 1, 1996, the final four units were placed into commercial operation. The facility is designed to operate on either natural gas or oil. In addition to the electric generating plants described above, the Company owned, as of December 31, 1995, approximately 8,300 conductor miles of transmission lines and approximately 73,500 conductor miles of distribution lines. As of such date, the Company's transmission and distribution systems comprised approximately 1,600 substations with an installed transformer capacity of approximately 84,200,000 kVA. NP&L's generation facilities consist of eleven hydroelectric plants with an aggregate nameplate capacity of approximately 100 MW. The transmission backbone of the system is a 161 kV line from Santeetlah to substations at Robbinsville, Nantahala Plant, Oak Grove, Webster and Thorpe Plant. The map found at the end of Item 1 shows the location of the Company's and NP&L's service area and generating stations. Substantially all electric plant is mortgaged under the Indenture relating to the First and Refunding Mortgage Bonds of the Company. For additional information concerning the properties of the Company, see "Business -- Energy Requirements and Capability." ITEM 3. Legal Proceedings. Reference is made to "Business -- Regulation", "Management's Discussion and Analysis of Results of Operations and Financial Condition, Current Issues -- Commitments and Contingencies" and "Note 13, Notes to Consolidated Financial Statements, Commitments and Contingencies -- Other". ITEM 4. Submission Of Matters To A Vote Of Security Holders. No matters were submitted to a vote of the Company's security holders during the last quarter of 1995. PART II. ITEM 5. Market For The Registrant's Common Equity And Related Stockholder Matters. The Common Stock of the Company is traded on the New York Stock Exchange. At December 31, 1995, there were approximately 129,265 holders of shares of such Common Stock. The following table sets forth for the periods indicated the dividends paid per share of Common Stock and the high and low sales prices of such shares reported by the New York Stock Exchange Composite Transactions:
Stock Price Dividends Range Per Common Stock Share High Low 1995 By Quarter Fourth. . . . . . . . . . . $0.51 $47 7/8 $43 1/8 Third . . . . . . . . . . . . 0.51 43 3/4 40 Second . . . . . . . . . . . 0.49 42 3/4 38 1/4 First . . . . . . . . . . . 0.49 40 3/4 37 3/8 1994 By Quarter Fourth. . . . . . . . . . . $0.49 $42 1/8 $38 Third . . . . . . . . . . . . 0.49 39 7/8 35 1/2 Second . . . . . . . . . . . 0.47 37 32 7/8 First . . . . . . . . . . . 0.47 43 35 3/4
ITEM 6. SELECTED FINANCIAL DATA
1995 1994 1993 1992 1991 Condensed consolidated statements of income (thousands) Operating revenues . . . . . . . . . . $ 4,676,684 $ 4,488,913 $ 4,466,233 $ 4,122,503 $ 3,962,605 Operating expenses . . . . . . . . . . 3,327,633 3,309,087 3,258,422 3,087,422 2,968,239 Operating income . . . . . . . . . . . 1,349,051 1,179,826 1,207,811 1,035,081 994,366 Interest expense and other income . . (168,072) (143,931) (171,419) (223,028) (117,725) Income before income taxes . . . . . . 1,180,979 1,035,895 1,036,392 812,053 876,641 Income taxes . . . . . . . . . . . . . 466,441 397,019 409,977 303,970 293,018 Net income . . . . . . . . . . . . . . 714,538 638,876 626,415 508,083 583,623 Dividends on preferred and preference stock . . . . . . . . . . . . . . 48,903 49,724 52,429 56,407 54,683 Earnings for common stock . . . . . . $ 665,635 $ 589,152 $ 573,986 $ 451,676 $ 528,940 Common stock data Shares of common stock year-end (thousands) . . . . . . . 204,859 204,859 204,859 204,859 204,699 average (thousands) . . . . . . . 204,859 204,859 204,859 204,819 203,431 Per share of common stock Earnings . . . . . . . . . . . . . $ 3.25 $ 2.88 $ 2.80 $ 2.21 $ 2.60 Dividends . . . . . . . . . . . . $ 2.00 $ 1.92 $ 1.84 $ 1.76 $ 1.68 Book value -- year-end . . . . . . $ 23.36 $ 22.13 $ 21.17 $ 20.26 $ 19.86 Market price -- high-low . . . . . $ 47 7/8 - 37 3/8 $ 43 - 32 7/8 $44 7/8 - 35 3/8 $37 1/2 - 31 3/8 $ 35 - 26 3/4 -- year-end . . . . . $ 47 3/8 $ 38 1/8 $ 42 3/8 $ 36 1/8 $ 35 Balance sheet data (thousands) Total assets. . . . . . . . . . . . . $ 13,358,484 $ 12,862,228 $ 12,293,605 $ 11,012,795 $ 10,617,552 Long-term debt . . . . . . . . . . . . $ 3,711,405 $ 3,567,122 $ 3,285,397 $ 3,288,111 $ 3,235,492 Preferred stock with sinking fund requirements . . . . . . . . . . . $ 234,000 $ 279,500 $ 281,000 $ 279,519 $ 228,650
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION. RESULTS OF OPERATIONS EARNINGS AND DIVIDENDS Earnings per share increased 13 percent from $2.88 in 1994 to $3.25 in 1995. The increase was primarily due to increased kilowatt-hour sales to weather sensitive classes. Earnings per share increased from $2.80 in 1993 to $3.25 in 1995, indicating an average annual growth rate of 8 percent. Total Company earned return on average common equity was 14.3 percent in 1995 compared to 13.3 percent in 1994 and 13.6 percent in 1993. The Company continued its practice of annually increasing the common stock dividend. Common dividends per share increased at an average annual rate of 4 percent from $1.84 in 1993 to $2.00 in 1995. Indicated annual dividends per share increased to $2.04. REVENUES AND SALES Operating revenues increased at an average annual rate of 2 percent from 1993 to 1995, primarily because of increased retail kilowatt-hour sales to weather sensitive classes and growth in the general service and industrial customer classes. As discussed below, increased retail sales were partially offset by decreased sales to wholesale customers. Revenues from subsidiaries and diversified operations contributed $73 million to the increase in revenues over the three-year period, primarily from increased developed lot and land sales and engineering services and construction fees. Wholesale revenues declined in 1995 and are expected to decline again in 1996 as a result of the retention of significantly larger portions of ownership entitlement by the other joint owners of the Catawba Nuclear Station. This increased retention reduces the joint owners' supplemental requirements supplied by the Company. The effect on earnings of such wholesale revenue declines is partially offset by declines in purchased power costs from the other joint owners which are not subject to levelization. (For additional information on Catawba joint ownership, see Note 3 to the Consolidated Financial Statements.) Kilowatt-hour sales from Duke Power electric operations increased 2 percent in 1995 compared to 1994. Sales to residential, general service and other industrial customers increased by 4 percent, 5 percent and 4 percent, respectively, as a result of warmer summer weather, cooler winter weather and continued economic growth in Duke Power's service area. However, sales to textile customers decreased 1 percent. Wholesale sales decreased 19 percent primarily due to a decrease of 36 percent in supplemental sales requirements to the other joint owners of the Catawba Nuclear Station. A new record peak demand of 15,542 megawatts was set in August 1995 during warmer than normal temperatures. OPERATING EXPENSES From 1994 to 1995, other operation and maintenance expenses increased 5 percent. Increased activities of the subsidiaries and diversified operations associated with both engineering services and other project development efforts contributed to this increase. Increases in distribution and transmission expenses were offset by reductions in nuclear and fossil outage costs. In 1995 and 1994, the Company had relatively constant costs associated with work force reduction programs and certain claims that are expected to be non-recurring in nature. Other operation and maintenance expenses increased at an average annual rate of 6 percent from 1993 to 1995. Costs associated with the enhanced vested retirement benefit program in 1995 as well as other non-recurring costs contributed to this increase in addition to increased activities of the subsidiaries and diversified operations associated with engineering services and other project development efforts. (For additional information on the vested retirement program, see Current Issues, "Resource Optimization.") Fuel expense increased at an average annual rate of 1 percent from 1993 to 1995. The increase was due primarily to higher system production requirements, offset by improved nuclear generation. Net interchange and purchased power expenses decreased from $535 million in 1993 to $468 million in 1995, an average annual decrease of 6 percent. This decrease was primarily the result of lower purchased power costs from the other joint owners not subject to levelization as the other joint owners retained significantly larger portions of their ownership entitlement. In 1996, net interchange and purchased power is expected to decrease again as purchased power costs from the other joint owners continue to decline. From 1993 to 1995, depreciation and amortization expense decreased at an average annual rate of 4 percent, primarily because the reduction in the amortization of property losses more than offset increased depreciation associated with additional investments. These investments were primarily associated with distribution plant, including investment to support customer growth, commercial operation of 12 units of the Lincoln Combustion Turbine Station, and fossil plant resulting from bringing refurbished units back on-line. (For additional information on the Lincoln Combustion Turbine Station, see Capital Needs, "Meeting Future Power Needs.") INTEREST EXPENSE AND OTHER INCOME Interest expense increased at an average annual rate of 3 percent from 1993 to 1995, primarily due to long-term debt financing activities in 1994. Allowance for funds used during construction (AFUDC) and other deferred returns, net of associated taxes, represented 13 percent of earnings for common stock in 1995 compared to 10 percent in 1993. AFUDC and other deferred returns are expected to be less than 11 percent of total earnings during the next three years. The deferred return, net of associated taxes, on the purchased capacity levelization deferral related to the joint ownership of the Catawba Nuclear Station represented 7 percent of earnings for common stock in 1995, compared to 7 percent in 1994 and 6 percent in 1993. The growth in this return is due to the increasing cumulative impact of the Company's funding of purchased power costs through 1995, which the Company expects to collect through current rates in future periods. The deferred purchased capacity balance is expected to begin to decline in 1996. (For additional information on purchased capacity levelization, see Capital Needs, "Purchased Capacity Levelization.") AFUDC, net of associated taxes, represented 5 percent of earnings for common stock in 1995 compared to 6 percent in 1994 and 4 percent in 1993. The changes were primarily the result of the construction and subsequent commercial operation of the Lincoln Combustion Turbine Station as 12 units were brought on-line at various times during 1995. (For additional information on the Lincoln Combustion Turbine Station, see Capital Needs, "Meeting Future Power Needs.") LIQUIDITY AND RESOURCES DUKE POWER COMPANY RATE MATTERS The Company's most recent general rate increase requests in the North Carolina and South Carolina retail jurisdictions were filed and approved in 1991. Additionally, Duke Power has a bulk power sales agreement with Carolina Power & Light Company (CP&L) to provide CP&L 400 megawatts of capacity as well as associated energy when needed for a six-year period which began July 1, 1993. Electric rates in all of Duke Power's regulatory jurisdictions were reduced by adjustment riders to reflect capacity revenues received from this CP&L bulk power sales agreement. CATAWBA SETTLEMENTS The Company and North Carolina Municipal Power Agency Number 1 (NCMPA) and Piedmont Municipal Power Agency (PMPA), two of the four other joint owners of the Catawba Nuclear Station, entered into a settlement in September 1995 which resolved outstanding issues related to how certain calculations affecting bills under the Catawba joint ownership contractual agreements should be performed. The settlement was approved by the North Carolina Utilities Commission (NCUC) on January 16, 1996 and the Public Service Commission of South Carolina (PSCSC) on January 23, 1996. As part of the settlement, the Company agreed to purchase additional megawatts (MW) of Catawba capacity during the period 1996 through 1999 and remove certain restrictions related to sales of surplus energy by these two joint owners. The additional capacity purchases are 215 MW in 1996, 165 MW in 1997, 120 MW in 1998 and 100 MW in 1999. The Company expects to recover the costs associated with this settlement as part of the purchased capacity levelization, consistent with prior orders of the retail regulatory commissions. Therefore, the Company believes these matters should not have a material adverse effect on the results of operations or the financial position of the Company. The Company and all four of the other joint owners of the Catawba Nuclear Station entered into settlement agreements in 1994 which resolved all issues in contention in arbitration proceedings related to the Catawba joint ownership contractual agreements. The basic contention in each proceeding was that certain calculations affecting bills under these agreements should be performed differently. These items are covered by the agreements between the Company and the other Catawba joint owners, which previously have been approved by the Company's retail regulatory commissions. (For additional information on Catawba joint ownership, see Note 3 to the Consolidated Financial Statements.) In 1994, the Company settled its cumulative net obligation through 1993 of approximately $205 million related to these settlement agreements. Billings for 1994 and later years will conform to the settlement agreements, which were approved by the Company's retail regulatory commissions. Because the Company expects the costs associated with these settlements to be recovered as part of the purchased capacity levelization, which has been approved by the Company's retail regulatory commissions, the Company included approximately $205 million as an increase to "Purchased capacity costs" on its Consolidated Balance Sheets in 1994. Therefore, the Company believes these matters should not have a material adverse effect on the results of operations or financial position of the Company. CASH FROM OPERATIONS Consolidated net cash provided by operating activities in 1995 accounted for 81 percent of total cash from operating, financing and investing activities compared with 67 percent in 1994 and 46 percent in 1993. When 1993 and 1995 refinancing activities are excluded, substantially all of the Company's capital needs were met by cash generated from operating activities. Refinancing activities were insignificant in 1994. FINANCING AND INVESTING ACTIVITIES The Company's consolidated capital structure at year-end 1995, including subsidiary long-term debt, was 52 percent common equity, 40 percent long-term debt and 8 percent preferred stock. This structure is consistent with the Company's target to maintain a double-A credit rating. As of December 31, 1995, Duke Power's bonds were rated "AA" by Fitch Investors Service, "Aa2" by Moody's Investors Service, and "AA-" by Standard & Poor's Group and Duff & Phelps. The Company had total credit facilities of $669.9 million and $440.0 million as of December 31, 1995 and 1994, respectively. The Company had unused credit facilities of $440.6 million and $259.9 million as of December 31, 1995 and 1994, respectively. In response to favorable market conditions in 1993, the Company issued $1.5 billion in long-term debt and $220 million in preferred stock, most of which was used to retire higher cost debt and preferred stock. In 1995, the Company issued $178 million of long-term debt, of which $72 million was used to retire higher cost long-term debt. The Company also retired $96 million of preferred stock and $80 million of long-term debt in 1995. Capital Structure Billions of dollars (Bar graph appears here with the following plot points:) 1990 1991 1992 1993 1994 1995 Long-term debt 40% 40% 40% 39% 40% 40% Preferred and preference stock 10% 9% 9% 9% 9% 8% Common equity 50% 51% 51% 52% 51% 52% Total Amount 7.7 8.0 8.2 8.4 8.9 9.2 In order to obtain variable rate financing at an attractive cost, the Company entered into interest rate swap agreements associated with the November 29, 1994 issuance of $200 million aggregate principal amount of its First and Refunding Mortgage Bonds 8% Series B due 1999 and the August 21, 1995 issuance of $100 million aggregate principal amount of its First and Refunding Mortgage Bonds 7 1/2% Series B due 2025. The interest rate swaps are reset quarterly based upon the three-month London Interbank Offered Rate (LIBOR). As a result of the interest rate swap contracts, interest expense is recognized at the weighted average rate for the year tied to the LIBOR rate. The weighted average rates at December 31, 1995 and 1994 were 6.14% and 5.95%, respectively, for the 8% Series B due 1999 and 7.06% in 1995 for the 7 1/2% Series B due 2025. The Company has also entered into a hedge transaction to offset currency fluctuations between the U.S. dollar and the Japanese yen associated with various steam generator purchase contracts. The hedge transaction with a notional amount of approximately $25 million at December 31, 1994, was fully liquidated by November 1995. The Company recorded any gains or losses associated with the hedge as an adjustment to the capitalized cost of the steam generators. Duke Energy Group, Inc. has entered into a hedge transaction to offset currency fluctuations between the U.S. dollar and the Chilean peso associated with expected equity contributions over the next two years to a joint venture. The hedge transaction had a notional amount of approximately $17 million at December 31, 1995. Duke Energy Group, Inc. records gains or losses associated with the hedge as an adjustment to investments in joint ventures. Duke Power's embedded cost of long-term debt, excluding debt of subsidiaries, was 7.94 percent for 1995 compared to 7.98 percent in 1994 and 8.01 percent in 1993. The embedded cost of preferred stock was 7.06 percent in 1995 compared to 6.99 percent in 1994 and 6.76 percent in 1993. The decreases in the embedded cost of long-term debt are primarily the result of the Company's refinancing activities and the resulting lower-cost debt. The increase in the embedded cost of preferred stock from 1993 to 1995 reflects the impact of increased adjustable dividend rates on a certain series of preferred stock and the retirement of preferred stock in 1995. FIXED CHARGES COVERAGE Consolidated fixed charges coverage using the SEC method increased to 4.94 times for 1995 compared to 4.72 and 4.68 times in 1994 and 1993, respectively. Coverage increased primarily because of higher earnings. Consolidated fixed charges coverage, excluding AFUDC and other deferred returns, was 4.52 times for 1995 compared with 4.32 in 1994 and 4.39 in 1993 and the Company goal of 3.5 times. Coverage was higher in 1995 than 1994 and 1993 as a result of increased earnings excluding AFUDC and other deferred returns. Fixed Charges Coverage Times (Graph appears here with the following plot points:)
1990 1991 1992 1993 1994 1995 SEC method 3.65 3.83 3.49 4.68 4.72 4.94 SEC method excluding AFUDC and other deferred returns 3.15 3.44 3.27 4.39 4.32 4.52
CAPITAL NEEDS PROPERTY ADDITIONS AND RETIREMENTS Additions to property and nuclear fuel of $794 million and retirements of $288 million resulted in an increase in gross plant of $506 million in 1995. Since January 1, 1993, additions to property and nuclear fuel of $2.4 billion and retirements of $864 million have resulted in an increase in gross plant of $1.5 billion. Duke Power Construction Costs* Millions of dollars (Graph appears here with the following plot points:)
1990 1991 1992 1993 1994 1995 Nuclear fuel 141.2 193.0 127.8 121.8 128.6 89.4 Construction 909.7 606.6 464.0 547.6 650.3 583.1 Total 1050.9 799.6 591.8 669.4 778.9 672.5
*Includes AFUDC and excludes NP&L and Duke Power's other subsidiaries. CONSTRUCTION EXPENDITURES Plant construction costs for generating facilities supporting Duke Power electric operations, including AFUDC, increased from $182 million in 1993 to $281 million in 1995, primarily because of construction of the Lincoln Combustion Turbine Station and the steam generator replacement project. (For more information, see Capital Needs, "Meeting Future Power Needs" and Current Issues, "Stress Corrosion Cracking.") Construction costs for distribution plant, including AFUDC, decreased from $240 million in 1993 to $221 million in 1995. Projected construction and nuclear fuel costs for Duke Power's electric operations, both including AFUDC, are $2.3 billion and $661 million, respectively, for 1996 through 2000. These construction expenditures are primarily for distribution and production related activities representing $997 million and $774 million, respectively. These projections are subject to periodic reviews and revisions. Actual construction and nuclear fuel costs and capital expenditures incurred may vary from such estimates. Cost variances are due to various factors, including revised load estimates, environmental matters and cost and availability of capital. Projected capital expenditures of subsidiaries and diversified activities are $1.0 billion for 1996 through 2000 of which a significant portion is for real estate development. These projections are subject to periodic review and revision and may vary significantly as the business plans of the Associated Enterprises Group evolve to meet the opportunity presented by its markets. For 1996 through 2000, the Company anticipates substantially funding its projected construction and capital expenditures through the internal generation of funds. PURCHASED CAPACITY LEVELIZATION The rates established in Duke Power's electric retail jurisdictions permit recovery of its investment in both units of the Catawba Nuclear Station and the costs associated with contractual purchases of capacity from the other joint owners of the Catawba Nuclear Station. The contracts relating to the sales of portions of the station obligate the Company to purchase a declining amount of capacity from the other joint owners. In the North Carolina retail jurisdiction, regulatory treatment of these contracts provides revenue for recovery of the capital costs and the fixed operating and maintenance costs of purchased capacity on a levelized basis. In the South Carolina retail jurisdiction, revenues are provided for the recovery of the capital costs of purchased capacity on a levelized basis, while current rates include recovery of fixed operating and maintenance expenses. Such rate treatments require the Company to fund portions of the purchased capacity payments until these costs, including returns, are recovered at a later date. The Company recovers the accumulated costs and returns when the sum of the declining purchased capacity payments and accrual of returns for the current period drop below the levelized revenues. In the North Carolina retail jurisdiction, and wholesale jurisdiction regulated by the Federal Energy Regulatory Commission (FERC), purchased capacity payments and the accrual of deferred returns continue to exceed levelized revenues. However, in 1996, the levelized revenues are expected to exceed the purchased capacity payments and accrual of deferred returns. In the South Carolina retail jurisdiction, cumulative levelized revenues have exceeded purchased capacity payments and accrual of deferred returns. Jurisdictional levelizations are intended to recover total costs, including returns, and are subject to adjustments, including final true-ups. MEETING FUTURE POWER NEEDS The Company's strategy for meeting customers' present and future energy needs consists of three components: supply-side resources, demand-side resources and purchased power resources. To assist in determining the optimal combination of these three resources, the Company uses an integrated resource planning process. The goal is to provide adequate and reliable electricity in an environmentally responsible, cost-effective manner. The Company is constructing a combustion turbine facility in Lincoln County, North Carolina. The Lincoln Combustion Turbine Station, designed to provide capacity at periods of peak demand, will consist of 16 combustion turbines with a total generating capacity of 1,200 megawatts. The estimated total cost of the project is approximately $400 million. Units 1 through 12 began commercial operation during 1995 and the remaining four units are scheduled to begin commercial operation in 1996. In 1995, the Company issued two requests for proposals (RFP) to solicit competitive bids for its future electric generating capacity resources. The short-term RFP could provide options for up to 675 megawatts of capacity with terms of 1 to 4 years. The long-term RFP solicits bids to provide up to 300 megawatts of purchased power to be available beginning in 1998 or 1999, for contract periods of between 5 and 20 years in duration. The Company has evaluated a total of 16 proposals received for both the short-term RFP and the long-term RFP and has begun negotiation with the bidders with the best proposals. Contracts are expected to be awarded in May 1996. The purchase of capacity and energy is also an integral part of meeting future power needs. As of January 1, 1996, the Company has 300 megawatts of firm purchased capacity from other generators of electricity under contract, including 62 megawatts from qualifying facilities. Demand-side management programs benefit the Company and its customers by promoting energy efficiency, providing for load control through interruptible control features, shifting usage to off-peak periods and increasing strategic sales of electricity. In return for participation in demand-side management programs, customers may be eligible to receive various incentives which help reduce their net investment in high-efficiency equipment or their electric bills. The November 1991 rate orders of the NCUC and the PSCSC provided for recovery in rates of a designated level of costs for demand-side management programs and allowed the deferral for later recovery of certain demand-side management costs that exceed the level reflected in rates, including a return on the deferred costs. The Company ultimately expects recovery through rates of associated deferred costs, not to exceed $75 million including deferred returns in the North Carolina retail jurisdiction. The annual costs deferred, including the return, were approximately $16 million and $11 million in North Carolina and South Carolina, respectively, in 1995 and $15 million and $10 million in North Carolina and South Carolina, respectively, in 1994. As of December 31, 1995, the balance of deferred demand-side management costs as presented on the Consolidated Balance Sheets in "Other deferred debits" is $58 million and $38 million in North Carolina and South Carolina, respectively. CURRENT ISSUES While the Company improved its financial performance in 1995 compared to 1994, its ability to maintain and improve its current level of earnings will depend on several factors. As the industry becomes increasingly competitive, the Company's ability to control costs will be an important factor in maintaining a pricing structure that is both attractive to customers and profitable to the Company. Wheeling of third party energy to a retail customer is not generally allowed in the Company's service territory. However, there are discussions and events at the national level and within certain states regarding retail competition which could result in changes in the industry. (For additional information on competition, see Current Issues, "Competition.") Management cannot predict the outcome of these matters and their impact, if any, on the Company's future financial position and results of operation. The Company is focusing on providing competitive prices to its industrial customers, as well as to wholesale customers who have access to alternative sources of energy. Other significant factors impacting the Company's future earnings levels include continued economic growth in the Piedmont Carolinas, the success of the Company's subsidiaries and diversified activities, and the outcomes of various legislative and regulatory actions. RESOURCE OPTIMIZATION. The Company has been engaged in a concentrated effort to more efficiently and effectively use its resources through better work practices. In 1995, the Company offered to certain employees an Enhanced Vested Benefits program (EVB) which gave targeted employees, who left the Company, an enhanced vested retirement package and the Company's standard severance pay based on years of service. This program will result in the departure of approximately 900 employees by the end of the first quarter of 1996. During 1994, the Company offered an Enhanced Voluntary Separation program (EVS) which gave most employees the option of leaving the Company for a lump-sum payment and the Company's standard severance pay based on years of service. This program resulted in the departure of approximately 1,300 employees in 1994. Implementing various efficiency practices has resulted in streamlined workflows and provided the opportunity for work force reduction programs such as EVB and EVS. The number of full-time employees has decreased from 19,945 at year-end 1990 to 17,121 at year-end 1995. NUCLEAR DECOMMISSIONING COSTS. Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $1.3 billion stated in 1994 dollars based on decommissioning studies completed in 1994. This amount includes the Company's 12.5 percent ownership in the Catawba Nuclear Station. The other joint owners of the Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. Such estimates presume each unit will be decommissioned as soon as possible following the end of its license life. Although subject to extension, the current operating licenses for the Company's nuclear units expire as follows: Oconee 1 and 2 - 2013, Oconee 3 - 2014; McGuire 1 - 2021, McGuire 2 - 2023; and Catawba 1 - 2024, Catawba 2 - 2026. The Nuclear Regulatory Commission issued a rule-making in 1988 which requires an external mechanism to fund the estimated cost to decommission certain components of a nuclear unit subject to radioactive contamination. In addition to the required external funding, the Company maintains an internal reserve to provide for decommissioning costs of plant components not subject to radioactive contamination. During 1995, the Company expensed approximately $56 million, which was contributed to the external funds, and accrued an additional $1 million to the internal reserve. The balance of the external funds as of December 31, 1995, was $273 million. The balance of the internal reserve as of December 31, 1995, was $206 million and is reflected in accumulated depreciation and amortization on the Consolidated Balance Sheets. Both the NCUC and the PSCSC have granted the Company recovery of estimated decommissioning costs through retail rates over the expected remaining service periods of the Company's nuclear plants. Management's opinion is that the decommissioning costs being recovered through rates, when coupled with assumed after-tax fund earnings of 5.5 percent to 5.9 percent, are currently sufficient to provide for the cost of decommissioning. ENVIRONMENTAL ISSUES. The Company is subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal, and other environmental matters. The Company was an operator of manufactured gas plants until the early 1950s. The Company has entered into a cooperative effort with the State of North Carolina and other owners of certain former manufactured gas plant sites to investigate and, where necessary, remediate these contaminated sites. The State of South Carolina has expressed interest in entering into a similar arrangement. The Company is considered by regulators to be a potentially responsible party and may be subject to liability at three federal Superfund sites and one comparable state site. While the cost of remediation of these sites may be substantial, the Company will share in any liability associated with remediation of contamination at such sites with other potentially responsible parties. Management is of the opinion that resolution of these matters will not have a material adverse effect on the results of operations or financial position of the Company. THE CLEAN AIR ACT AMENDMENTS OF 1990. The Clean Air Act Amendments of 1990 require a two-phase reduction by electric utilities in the aggregate annual emissions of sulfur dioxide and nitrogen oxide by the year 2000. The Company currently meets all requirements of Phase I. The Company supports the national objective of clean air in the most cost-effective manner and has already reduced emissions through the use of low-sulfur coal in its fossil plants, efficient plant operations and by using nuclear generation. The sulfur dioxide provisions of the Act allow utilities to choose among various alternatives for compliance. To meet the Phase II requirements by 2000, the Company's current strategy includes the use of lower sulfur coal, emission allowance purchases, low nitrogen oxide burners and emission monitoring equipment. A one-time cost associated with bringing the Company into compliance with the Act could range from $94 million to $320 million. Additional operating expenses of approximately $55 million will be incurred for fuel premiums and emission allowance purchases each year after 2000. This strategy is contingent upon developments in the emissions allowance market, lower sulfur coal fuel premiums, future regulatory and legislative actions, and advances in clean air technology. STRESS CORROSION CRACKING. Stress corrosion cracking (SCC) has occurred in the steam generators of Units 1 and 2 at the McGuire Nuclear Station and Unit 1 at the Catawba Nuclear Station. Catawba Unit 2, which has certain design differences and came into service at a later date, has not yet shown the degree of SCC which has occurred in McGuire Units 1 and 2 and Catawba Unit 1. It is, however, too early in the life of Catawba Unit 2 to determine the extent to which SCC may be a problem. Although the Company has taken steps to mitigate the effects of SCC, the inherent potential for future SCC in the McGuire and Catawba steam generators still exists. The Company is planning for the replacement of steam generators at three units that have experienced SCC and has signed an agreement with Babcock & Wilcox International to purchase replacement steam generators. The current schedule for completion of the effort is as follows: Catawba Unit 1 - 1996, McGuire Unit 1 - 1997 and McGuire Unit 2 - 1997. The order of replacement is subject to change based on operational and project circumstances. The Catawba Unit 2 steam generators have not been scheduled for replacement. Steam generator replacement at each unit is expected to take approximately four months and cost approximately $170 million, excluding the cost of replacement power and the reimbursement of applicable costs by the other joint owners of Catawba Unit 1. Stress corrosion problems are excluded under the Company's nuclear insurance policies. The Company, in connection with its McGuire and Catawba stations and on behalf of the other joint owners of the Catawba Station, began a legal action in 1990, alleging that Westinghouse Electric Corporation knowingly supplied to the McGuire and Catawba stations steam generators that were defective in design, workmanship, and materials, requiring replacement well short of their stated design life. The lawsuit was settled in 1994. While the court order does not allow disclosure of the terms of the settlement, the Company believes the litigation was settled on terms that provided satisfactory consideration to the Company and will not have a material effect on the Company's results of operations or financial position. COMPETITION. The Energy Policy Act of 1992 (EPACT) is a major driver towards a more competitive market for wholesale sales of power. EPACT reformed provisions of the Public Utility Holding Company Act of 1935 (PUHCA) and Part II of the Federal Power Act to remove certain barriers to competition for the supply of electricity. For example, EPACT allows utilities to develop independent electric generating plants in the United States for sales to wholesale customers, as well as to contract for utility projects internationally, without becoming subject to regulation under PUHCA as an electric utility holding company. In addition, EPACT permits the FERC to order transmission access for third parties to transmission facilities owned by another entity so that independent suppliers can sell at wholesale to customers wherever located. It does not, however, permit the FERC to issue an order requiring transmission access to retail customers. The FERC, responsible in large measure for implementation of the EPACT, has moved vigorously to implement its mandate, interpreting the statute broadly in issuing orders for third-party transmission service and issuing a number of rules of general applicability. The FERC in late March of 1995 issued a Notice of Proposed Rulemaking (the "NOPR") in which it announced its intent to impose a final rule, applicable to all electric utilities subject to its jurisdiction, which will require all such utilities to adopt open-access transmission tariffs containing identical terms and conditions. The FERC should issue its final rule in 1996. Open transmission access for wholesale customers as contemplated by the FERC's NOPR would provide energy suppliers, including the Company, with opportunities to sell and deliver capacity and energy at market-based prices. Engaging in such transactions could result in improved utilization of the Company's existing assets. In addition, such access would provide another supply option through which the Company can buy capacity and energy at attractive rates, influencing its competitive price position. However, sales to existing wholesale customers of the Company could be impacted by open access as contemplated by the NOPR either due to competitive pressure on the wholesale price of electricity, or the potential loss of sales as wholesale customers seek other options to meet their capacity and energy requirements at market-based prices. Wholesale sales, excluding transactions with other utilities, represented approximately 6.7 percent of the Company's total kilowatt-hour sales in 1995. Supplemental sales to the other joint owners of the Catawba Nuclear Station comprised the majority of such sales. Such supplemental sales will be declining in 1996 as a result of the retention of significantly larger portions of ownership entitlement by the other joint owners. (For additional information on Catawba joint ownership, see Note 3 to the Consolidated Financial Statements.) In early 1995, prior to issuance of the FERC's NOPR, the Company and certain of its affiliates filed three applications with the FERC, all of which are designed to enable effective participation in the competitive environment of the changing electric utility industry. Duke Power filed an application for permission to sell at market-based rates up to 2,500 megawatts of capacity and energy from its own assets. Two of the Company's affiliates, Duke Energy Marketing Corporation (DEMC) and Duke/Louis Dreyfus L.L.C. (D/LD), filed applications with the FERC to become power marketers. All of the applications were supported by transmission tariffs which establish the rates, terms and conditions for transmission service to third parties on the Company's transmission system. Late in 1995, the FERC granted the applications of Duke, DEMC, and D/LD; accepted Duke's transmission tariffs; and ordered a hearing on the rates to be charged for service under those tariffs. The terms and conditions of service are subject to the outcome of the FERC's final rule, and the rates are subject to the outcome of hearings before the FERC. Wheeling of third party energy to a retail customer is not generally allowed in the Company's service territory. However, there are discussions and events at the national level and within certain states regarding retail competition which could result in changes in the industry. Currently, the electric utility industry is predominantly regulated on a basis designed to recover the cost of providing electric power to its retail and wholesale customers. If cost-based regulation were to be discontinued in the industry for any reason, including competitive pressure on the cost-based prices of electricity, profits could be reduced and utilities might be required to reduce their asset balances to reflect a market basis less than cost. Discontinuance of cost-based regulation would also require affected utilities to write off their associated regulatory assets. The regulatory assets of the Company are classified as "Deferred debits" on the Consolidated Balance Sheets. Substantially all of the "Deferred debits" are regulatory assets. Management cannot predict the potential impact, if any, of these competitive forces on the Company's future financial position and results of operations. However, the Company continues to position itself to effectively meet these challenges by maintaining prices that are locally, regionally and nationally competitive. COMMITMENTS AND CONTINGENCIES. The Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business, some of which may involve substantial amounts. Where appropriate, the Company has made accruals in accordance with Statement of Financial Accounting Standards No. 5, "Accounting for Contingencies," in order to provide for such matters. Management is of the opinion that the final disposition of these proceedings will not have a material adverse effect on the results of operations or the financial position of the Company. SUBSIDIARIES AND DIVERSIFIED OPERATIONS. The Company continues to aggressively pursue both domestic and international diversified business opportunities that are synergistic with the Company's core business to provide additional value to the Company's shareholders. Among the Company's current industry pursuits are: ownership of electric power facilities, power marketing, real estate, communications, engineering consulting and various energy services. Although these opportunities are primarily concentrated in areas that utilize the Company's expertise, they present different and potentially greater risks than does the Company's core business. The Company only pursues opportunities in which the expected returns are commensurate with the risks and makes efforts to mitigate such risks. The Company undertakes a continuous evaluation of the various lines of business it may enter or exit, with the objectives of enhancing shareholder value and managing any associated risk. Domestically, non-electric property of the Company's subsidiaries and diversified activities was $335 million and $286 million at December 31, 1995 and 1994, respectively. The Company had equity investments in joint ventures, which own assets within the United States, of $58 million and $14 million at December 31, 1995 and 1994, respectively. Internationally, the Company had equity investments in joint ventures, which own generation and transmission facilities, of $105 million and $94 million at December 31, 1995 and 1994, respectively. Additionally, the Company, through its nonregulated subsidiaries, had loaned $23 million to certain of these joint ventures at December 31, 1995. The Company's subsidiaries and diversified activities contributed $54 million to net income in 1995 compared with $52 million in 1994 and $22 million in 1993. From 1993 to 1995, increased developed lot and land sales, and engineering services and construction fees generated additional income. These increases were offset by personal communications services joint venture losses in 1995. Additionally, a one-time gain on the sale of an investment in preferred stock of an independent power development company in 1994 contributed to the increase in diversified income from 1993 to 1994. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. DUKE POWER COMPANY INDEX
PAGE Consolidated Financial Statements: Consolidated Statements of Income for the Three Years Ended December 31, 1995. . . . . . . . . . . . . . . . Consolidated Statements of Retained Earnings for the Three Years Ended December 31, 1995. . . . . . . . . . Consolidated Statements of Cash Flows for the Three Years Ended December 31, 1995. . . . . . . . . . . . . . Consolidated Balance Sheets -- December 31, 1995 and 1994. . . . . . . . . . . . . . . . . . . . . . . . . . Notes to Consolidated Financial Statements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Independent Auditors' Report. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Responsibility for Financial Statements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selected Quarterly Financial Data (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Subsidiaries and Diversified Activities Highlights. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Financial Statement Schedule: Schedule II -- Valuation and Qualifying Accounts and Reserves for the Three Years Ended December 31, 1995. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CONSOLIDATED STATEMENTS OF INCOME
Dollars in Thousands Year ended December 31, 1995 1994 1993 OPERATING REVENUES (Notes 1, 2 and 11)............................................ $4,676,684 $4,488,913 $4,466,233 OPERATING EXPENSES Fuel used in electric generation (Note 1)...................................... 744,226 705,019 732,246 Net interchange and purchased power (Notes 2 and 3)............................ 468,293 553,355 535,125 Other operation and maintenance................................................ 1,403,547 1,341,659 1,254,028 Depreciation and amortization (Note 1)......................................... 458,131 459,781 496,971 General taxes.................................................................. 253,436 249,273 240,052 Total operating expenses.................................................... 3,327,633 3,309,087 3,258,422 OPERATING INCOME................................................................. 1,349,051 1,179,826 1,207,811 INTEREST EXPENSE AND OTHER INCOME (Note 1) Interest expense............................................................... (289,318) (270,217) (274,051) Allowance for funds used during construction and other deferred returns........ 125,040 111,872 82,600 Other, net..................................................................... (3,794) 14,414 20,032 Total interest expense and other income..................................... (168,072) (143,931) (171,419) INCOME BEFORE INCOME TAXES........................................................ 1,180,979 1,035,895 1,036,392 INCOME TAXES (Notes 1 and 4)...................................................... 466,441 397,019 409,977 NET INCOME........................................................................ 714,538 638,876 626,415 Dividends on preferred and preference stock.................................... 48,903 49,724 52,429 EARNINGS FOR COMMON STOCK......................................................... $ 665,635 $ 589,152 $ 573,986 COMMON STOCK DATA (Note 6) Average shares outstanding (thousands)......................................... 204,859 204,859 204,859 Earnings per share............................................................. $3.25 $2.88 $2.80 Dividends per share............................................................ $2.00 $1.92 $1.84
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Dollars in Thousands Year ended December 31, 1995 1994 1993 BALANCE --Beginning of year........................................................ $2,605,920 $2,410,825 $2,223,718 ADD -- Net income.................................................................. 714,538 638,876 626,415 Total.................................................................... 3,320,458 3,049,701 2,850,133 DEDUCT Dividends Common stock................................................................ 409,716 393,370 376,937 Preferred and preference stock.............................................. 48,903 49,724 52,429 Capital stock transactions, net................................................ 3,564 687 9,942 Total deductions......................................................... 462,183 443,781 439,308 BALANCE -- End of year............................................................. $2,858,275 $2,605,920 $2,410,825
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. CONSOLIDATED STATEMENTS OF CASH FLOWS
Dollars in Thousands Year ended December 31, 1995 1994 1993 CASH FLOWS FROM OPERATING ACTIVITIES Net Income..................................................................... $ 714,538 $ 638,876 $ 626,415 Adjustments to reconcile net income to net cash provided by operating activities: Non-cash items Depreciation and amortization............................................... 674,816 647,515 664,355 Deferred income taxes and investment tax credit amortization................ 5,989 94,261 62,897 Allowance for equity funds used during construction......................... (23,082) (27,411) (17,221) Purchased capacity levelization............................................. (33,149) (268,925) (20,049) Other, net.................................................................. 76,029 22,460 73,607 (Increase) Decrease in Accounts receivable...................................................... (136,838) 47,586 (37,131) Inventory................................................................ (14,549) (28,568) 24,904 Prepayments.............................................................. (7,178) (435) (2,396) Increase (Decrease) in Accounts payable......................................................... 11,694 (52,506) (28,184) Taxes accrued............................................................ 14,454 (51,641) 25,797 Interest accrued and other liabilities................................... 28,934 14,523 30,508 Total adjustments........................................................... 597,120 396,859 777,087 Net cash provided by operating activities............................. 1,311,658 1,035,735 1,403,502 CASH FLOWS FROM INVESTING ACTIVITIES Construction expenditures and other property additions......................... (713,299) (772,452) (599,759) Investment in nuclear fuel..................................................... (76,603) (108,711) (111,731) External funding for decommissioning........................................... (56,470) (52,524) (52,524) Pre-funded pension cost........................................................ -- (30,000) (50,000) Investment in joint ventures................................................... (54,945) (6,718) (70,345) Net change in investment securities............................................ 54,425 17,922 46,489 Net cash used in investing activities................................. (846,892) (952,483) (837,870) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from the issuance of First and refunding mortgage bonds.......................................... 173,839 343,824 1,395,682 Preferred stock............................................................. -- -- 215,633 Pollution control bonds..................................................... -- -- 76,265 Short-term notes payable, net............................................... 48,200 86,300 (105,200) Construction loans and other................................................ 47,643 57,032 13,280 Payments for the redemption of First and refunding mortgage bonds.......................................... (157,365) (81,781) (1,399,336) Preferred stock............................................................. (100,516) (1,500) (224,295) Pollution control bonds..................................................... -- -- (79,310) Construction loans and other................................................ (9,416) (18,885) (12,454) Dividends paid................................................................. (458,018) (443,633) (427,868) Other.......................................................................... (1,153) (20,991) (6,752) Net cash used in financing activities................................. (456,786) (79,634) (554,355) Net increase in cash.............................................................. 7,980 3,618 11,277 Cash at beginning of year......................................................... 37,430 33,812 22,535 CASH AT END OF YEAR............................................................... $ 45,410 $ 37,430 $ 33,812
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. CONSOLIDATED BALANCE SHEETS ASSETS
Dollars in Thousands December 31, 1995 1994 CURRENT ASSETS Cash (Notes 5 and 10)...................................................................... $ 45,410 $ 37,430 Short-term investments (Notes 1 and 10).................................................... 76,300 132,692 Receivables (less allowance for losses: 1995 - $6,352; 1994 - $6,637) (Note 1)............ 689,703 552,865 Inventory -- at average cost............................................................... 341,841 319,385 Prepayments and other...................................................................... 22,900 15,722 Total current assets................................................................. 1,176,154 1,058,094 INVESTMENTS AND OTHER ASSETS Investments in joint ventures (Note 11).................................................... 163,274 108,330 Other investments, at cost or less (Note 10)............................................... 85,194 83,226 Nuclear decommissioning trust funds (Notes 10 and 14)...................................... 273,466 172,390 Pre-funded pension cost (Note 12).......................................................... 80,000 80,000 Total investments and other assets................................................... 601,934 443,946 PROPERTY, PLANT AND EQUIPMENT (Notes 1, 3, 9, 13 and 14) Electric plant in service (at original cost) Production.............................................................................. 7,154,332 6,747,397 Transmission............................................................................ 1,532,302 1,439,435 Distribution............................................................................ 4,105,513 3,965,393 Other................................................................................... 1,030,226 1,020,192 Electric plant in service............................................................ 13,822,373 13,172,417 Less accumulated depreciation and amortization.......................................... 5,122,192 4,810,004 Electric plant in service, net....................................................... 8,700,181 8,362,413 Nuclear fuel............................................................................ 731,691 757,983 Less accumulated amortization........................................................... 453,921 415,560 Nuclear fuel, net.................................................................... 277,770 342,423 Construction work in progress (including nuclear fuel in process: 1995 - $25,500; 1994 - $52,273)......................................................... 382,582 558,730 Total electric plant, net............................................................ 9,360,533 9,263,566 Other property -- at cost (less accumulated depreciation: 1995 - $29,956; 1994 - $24,137)......................................................... 354,713 302,383 Total property, plant and equipment, net............................................. 9,715,246 9,565,949 DEFERRED DEBITS (Notes 1, 3, 4 and 13) Purchased capacity costs................................................................... 965,473 932,324 Debt expense............................................................................... 180,930 186,306 Regulatory asset related to income taxes................................................... 490,676 489,292 Regulatory asset related to DOE assessment fee............................................. 101,274 102,467 Other...................................................................................... 126,797 83,850 Total deferred debits................................................................ 1,865,150 1,794,239 TOTAL ASSETS.................................................................................. $ 13,358,484 $ 12,862,228
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. CONSOLIDATED BALANCE SHEETS LIABILITIES AND STOCKHOLDERS' EQUITY
Dollars in Thousands December 31, 1995 1994 CURRENT LIABILITIES Accounts payable..............................................................................$ 343,692 $ 343,688 Notes payable (Notes 5 and 10)................................................................ 155,300 107,100 Taxes accrued (Note 1)........................................................................ 34,884 29,999 Interest accrued.............................................................................. 73,675 72,157 Current maturities of long-term debt and preferred stock (Notes 8 and 9)...................... 12,071 93,759 Other (Note 13)............................................................................... 149,555 121,539 Total current liabilities............................................................... 769,177 768,242 LONG-TERM DEBT (Notes 5, 9 and 10)............................................................... 3,711,405 3,567,122 ACCUMULATED DEFERRED INCOME TAXES (Notes 1 and 4)................................................ 2,382,204 2,348,631 DEFERRED CREDITS AND OTHER LIABILITIES Investment tax credit (Notes 1 and 4)......................................................... 261,347 272,594 DOE assessment fee (Note 1)................................................................... 101,274 102,467 Nuclear decommissioning costs externally funded (Note 14)..................................... 273,466 172,390 Other......................................................................................... 390,427 318,453 Total deferred credits and other liabilities............................................ 1,026,514 865,904 PREFERRED AND PREFERENCE STOCK WITH SINKING FUND REQUIREMENTS (Notes 8 and 10)................... 234,000 279,500 PREFERRED AND PREFERENCE STOCK WITHOUT SINKING FUND REQUIREMENTS (Notes 7 and 10)................ 450,000 500,000 COMMITMENTS AND CONTINGENCIES (Note 13).......................................................... COMMON STOCKHOLDERS' EQUITY (Note 6) Common stock, no par, 300,000,000 shares authorized; 204,859,339 shares outstanding for 1995 and 1994........................................... 1,926,909 1,926,909 Retained earnings............................................................................. 2,858,275 2,605,920 Total common stockholders' equity....................................................... 4,785,184 4,532,829 TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.......................................................$ 13,358,484 $ 12,862,228
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. NATURE OF OPERATIONS The Company is primarily engaged in the generation, transmission, distribution and sale of electric energy in the central portion of North Carolina and the western portion of South Carolina, comprising the area in both states known as the Piedmont Carolinas. The Company is one of the nation's largest investor-owned electric utilities. The Company is also engaged in a variety of diversified operations, most of which are organized in separate subsidiaries. The Company's subsidiaries and diversified activities are in the Associated Enterprises Group (AEG). AEG includes Church Street Capital Corp.; Crescent Resources, Inc.; Duke Energy Group, Inc.; Duke Engineering & Services, Inc.; Duke/Fluor Daniel; Duke Merchandising; DukeNet Communications, Inc.; Duke Water Operations; and Nantahala Power and Light Company. Certain of these subsidiaries have invested in both domestic and international joint ventures. (See Note 11.) The financial statements are prepared in conformity with generally accepted accounting principles appropriate in the circumstances to reflect in all material respects the substance of events and transactions which should be included. In preparing these statements, management makes informed judgments and estimates of the expected effects of events and transactions that are currently being reported. B. REVENUES Electric revenues are recorded as service is rendered to customers. "Receivables" on the Consolidated Balance Sheets include $206,792,000 and $163,270,000 as of December 31, 1995 and 1994, respectively, for electric service that has been rendered but not yet billed to customers. C. ADDITIONS TO ELECTRIC PLANT The Company capitalizes all construction-related direct labor and materials as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of money (allowance for funds used during construction). The cost of renewals and betterments of units of property is capitalized. The cost of repairs and replacements representing less than a unit of property is charged to electric expenses. The original cost of property retired, together with removal costs less salvage value, is charged to accumulated depreciation. D. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC) AFUDC represents the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated facilities. AFUDC, a non-cash item, is recognized as a cost of "Construction work in progress," with an offsetting credit to "Interest expense and other income." After construction is completed, the Company is permitted to recover these construction costs, including a fair return, through their inclusion in rate base and in the provision for depreciation. The AFUDC rates of 9.3, 9.6 and 9.3 percent for Duke Power for 1995, 1994 and 1993, respectively, include a component for debt cost on a pre-tax basis. Rates for all periods are compounded semiannually. E. OTHER DEFERRED RETURNS Other deferred returns represent the estimated financing costs associated with funding certain regulatory assets. These regulatory assets primarily arise from the Company's funding of purchased capacity costs above levels collected in rates. Other deferred returns are non-cash items. They are primarily recognized as an addition to "Purchased capacity costs" and as an offsetting credit to "Interest expense and other income." F. DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT Provisions for electric plant depreciation are recorded using the straight-line method. The year-end composite weighted-average depreciation rates were 3.48, 3.46 and 3.47 percent for 1995, 1994 and 1993, respectively. Amortization of nuclear fuel is included in "Fuel used in electric generation" in the Consolidated Statements of Income. The amortization is recorded using the units-of-production method. Under provisions of the Nuclear Waste Policy Act of 1982, the Company has entered into contracts with the Department of Energy (DOE) for the disposal of spent nuclear fuel. Payments made to the DOE for disposal costs are based on nuclear output and are included in "Fuel used in electric generation" in the Consolidated Statements of Income. A provision in the Energy Policy Act of 1992 established a fund for the decontamination and decommissioning of the DOE's uranium enrichment plants. Licensees are subject to an annual assessment for 15 years based on their pro rata share of past enrichment services. The annual assessment is recorded as fuel expense. The Company paid $9,205,000 during 1995 and has paid $35,551,000 cumulatively related to its ownership interest in nuclear plants. The Company has reflected the remaining liability and regulatory asset of $101,274,000 in the Consolidated Balance Sheets at December 31, 1995. G. SUBSIDIARIES The Company's consolidated financial statements reflect consolidation of all of its majority-owned subsidiaries. Intercompany transactions have been eliminated in consolidation. H. INCOME TAXES The Company and its subsidiaries file a consolidated federal income tax return. Deferred income taxes have been provided for temporary differences. Temporary differences occur when events and transactions recognized for financial reporting result in taxable or tax-deductible amounts in future periods. Investment tax credits have been deferred and are being amortized over the estimated useful lives of the related properties. I. UNAMORTIZED DEBT PREMIUM, DISCOUNT AND EXPENSE Expenses incurred in connection with the issuance of presently outstanding long-term debt issued for regulated operations, and premiums and discounts relating to such debt, are being amortized over the terms of the respective issues. Also, any call premiums or unamortized expenses associated with refinancing higher-cost debt obligations used to finance regulated assets and operations are being amortized over the lives of the new issues of long-term debt. J. CONSOLIDATED STATEMENTS OF CASH FLOWS For purposes of the Consolidated Statements of Cash Flows, the Company's short-term investments in highly liquid debt instruments, with an original maturity of three months or less, are included in cash flows from investing activities and thus are not considered cash equivalents. Total income taxes paid were $441,440,000, $372,416,000 and $354,981,000 for the years ended December 31, 1995, 1994 and 1993, respectively. Interest paid, net of amounts capitalized, was $258,698,000, $236,696,000 and $249,659,000 for the years ended December 31, 1995, 1994 and 1993, respectively. K. COST-BASED REGULATION As a regulated entity, the Company is subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Accordingly, the Company records certain assets and liabilities that result from the effects of the ratemaking process that would not be recorded under generally accepted accounting principles for non-regulated entities. Currently, the electric utility industry is predominantly regulated on a basis designed to recover the cost of providing electric power to its retail and wholesale customers. If cost-based regulation were to be discontinued in the industry for any reason, including competitive pressure on the cost-based prices of electricity, profits could be reduced, and utilities might be required to reduce their asset balances to reflect a market basis less than cost. Discontinuance of cost-based regulation would also require the affected utilities to write off their associated regulatory assets. The regulatory assets of the Company are classified as "Deferred debits" on the Consolidated Balance Sheets. Substantially all of the "Deferred debits" are regulatory assets. Management cannot predict the potential impact, if any, of these competitive forces on the Company's future financial position and results of operations. However, the Company continues to position itself to effectively meet these challenges by maintaining prices that are locally, regionally and nationally competitive. NOTE 2. RATE MATTERS DUKE POWER COMPANY The North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina must approve rates for retail sales within their respective states. The Federal Energy Regulatory Commission (FERC) must approve Duke Power's rates for sales to wholesale customers. Sales to the other joint owners of the Catawba Nuclear Station, which represent a substantial majority of Duke Power's wholesale revenues, are set through contractual agreements. (See Note 3.) The most recent general rate increase requests in the Company's retail jurisdictions were filed and approved in 1991. The Company also filed its most recent general rate increase request within the FERC wholesale jurisdiction in 1991. A negotiated settlement between the Company and the wholesale customers was approved by the FERC in 1992. Fuel costs are reviewed semiannually in the wholesale and South Carolina retail jurisdictions, with provisions for changing such costs in base rates. In the North Carolina retail jurisdiction, a review of fuel costs in rates is required annually and during general rate case proceedings. All jurisdictions allow Duke Power to adjust rates for past over- or under-recovery of fuel costs. Therefore, Duke Power reflects in revenues the difference between actual fuel costs incurred and fuel costs recovered through rates. A bill ratified by the North Carolina legislature in 1987 to assure the legality of such adjustments in rates had its expiration provision repealed in March 1995. Duke Power has a bulk power sales agreement with Carolina Power & Light Company (CP&L) to provide CP&L 400 megawatts of capacity as well as associated energy when needed for a six-year period which began July 1, 1993. Electric rates in all regulatory jurisdictions were reduced by adjustment riders to reflect capacity revenues received from this CP&L bulk power sales agreement. NANTAHALA POWER AND LIGHT COMPANY During 1992, Nantahala Power and Light Company (NP&L) filed an application for a general rate increase with the NCUC. A general rate increase was approved in June 1993 which resulted in additional annual revenues of $4.3 million. Purchased power costs of NP&L are reviewed annually and during general rate case proceedings by the NCUC. NP&L is allowed to adjust rates for past over- or under-recovery of purchased power costs. Therefore, NP&L defers the difference between actual purchased power costs incurred and those recovered through rates. NOTE 3. JOINT OWNERSHIP OF GENERATING FACILITIES The Company previously sold interests in both units of the Catawba Nuclear Station. The other owners of portions of the Catawba Nuclear Station and supplemental information regarding their ownership are as follows: Ownership Interest Owner in the Station North Carolina Municipal Power Agency Number 1 (NCMPA) 37.5% North Carolina Electric Membership Corporation (NCEMC) 28.125% Piedmont Municipal Power Agency (PMPA) 12.5% Saluda River Electric Cooperative, Inc. (Saluda River) 9.375% Each owner has provided its own financing for its ownership interest in the station. The Company retains a 12.5 percent ownership interest in the Catawba Nuclear Station. As of December 31, 1995, $499,209,000 of "Electric plant in service" and "Nuclear fuel" represents the Company's investment in Units 1 and 2. Accumulated depreciation and amortization of $185,264,000 associated with Catawba has been recorded as of year-end. The Company's share of operating costs of Catawba is included in the Consolidated Statements of Income. In connection with the joint ownership, the Company has entered into contractual agreements with the other joint owners to purchase declining percentages of the generating capacity and energy from the plant. These purchased power agreements were effective beginning with the commercial operation of each unit. Unit 1 and Unit 2 began commercial operation in June 1985 and August 1986, respectively. The purchased power agreements were established for 15 years for NCMPA and PMPA and 10 years for NCEMC and Saluda River. While the purchased power agreements with NCMPA and PMPA extend for 15 years, a significant decrease in the percentage of capacity and energy the Company is obligated to purchase occurs in the 11th calendar year of operation for each unit. This significant decrease occurred in 1995 for Unit 1 and will occur in 1996 for Unit 2. Certain provisions in the agreements with NCEMC and Saluda River have moderated the rate of decrease in the percentage of capacity and energy that the Company is obligated to purchase until 1996 when the Company has no further obligation to purchase capacity and related energy. The agreements also provide for supplemental power sales by the Company to the other joint owners. Such power sales are to satisfy capacity and energy needs of the other joint owners beyond the capacity and energy which they retain from Catawba or potentially acquire in the form of other resources. As the joint owners retain more capacity and energy from Catawba, or a third party, supplemental power sales are expected to decline. The agreements with each of the other joint owners include provisions that the Company will provide generating reserves to backstand the other joint owners' retained capacity in the Catawba plant at the system average cost of installed capacity. Additionally, the agreements include certain reliability exchanges designed to manage outage-related risks by exchanging energy entitlements between the Catawba Nuclear Station and the McGuire Nuclear Station, impacting the Company as well as all the other joint owners. Purchased energy cost payments are based on variable operating costs and are a function of the generation output of Catawba. Purchased capacity payments are based on the fixed costs of the plant and include the capital costs and fixed operating and maintenance costs. Actual purchased capacity costs for 1995 and projected obligations for 1996 through 2000, including the impact of the 1995 settlement agreement with NCMPA and PMPA (See Note 13), are as follows (dollars in thousands): PURCHASED CAPACITY PURCHASED CAPACITY TOTAL PURCHASED YEAR CAPITAL COST FIXED O&M CAPACITY 1995 Actual $237,978 $83,358 $321,336 1996 Projected $ 83,870 $41,510 $125,380 1997 Projected $ 65,803 $35,042 $100,845 1998 Projected $ 47,609 $26,541 $ 74,150 1999 Projected $ 34,752 $19,646 $ 54,398 2000 Projected $ 4,217 $ 2,542 $ 6,759 Effective in its November 1991 rate order, the North Carolina Utilities Commission reaffirmed the Company's recovery, on a levelized basis, of the capital costs and fixed operating and maintenance costs of capacity purchased from the other joint owners. The Public Service Commission of South Carolina in its November 1991 rate order reaffirmed the Company's recovery on a levelized basis of the capital costs of capacity purchased from the other joint owners. Levelization was reaffirmed through inclusion in rates approved in March 1992 by the Federal Energy Regulatory Commission (FERC). The portion of purchased capacity subject to levelization not currently recovered in rates is being deferred, and the Company is recording a return on the accumulated balance. The Company recovers the accumulated balance, including the return, when the sum of the declining purchased capacity payments and accrual of returns for the current period drops below the levelized revenues. Jurisdictional levelizations are intended to recover total costs, including returns, and are subject to adjustments, including final true-ups. The Company recovers the costs of purchased energy and the non-levelized portion of purchased capacity on a current basis. The current levelized revenues approved in the Company's last general rate proceedings are $211,423,000, $94,137,000 and $6,815,000 for North Carolina retail, South Carolina retail and Other Wholesale (FERC), respectively. Purchased power costs, subject to levelization, are deferred based on allocation factors of approximately 62 percent, 26 percent and 2 percent for North Carolina retail, South Carolina retail and Other Wholesale (FERC), respectively. The Company also recovers an allocated amount of purchased power costs in the pricing of supplemental sales made to the other joint owners on a current basis. In 1995, in the North Carolina retail and FERC wholesale jurisdictions, purchased capacity payments and the accrual of deferred returns continued to exceed levelized revenues. However, in 1996, the levelized revenues are expected to exceed the purchased capacity payments and accrual of deferred returns. In the South Carolina retail jurisdiction, cumulative levelized revenues have exceeded purchased capacity payments and accrual of deferred returns. For the years ended December 31, 1995, 1994 and 1993, the Company recorded purchased capacity and energy costs from the other joint owners of $388,246,000, $604,505,000 and $547,899,000, respectively. These amounts, after adjustments for the costs of capacity purchased not reflected in current rates, are included in "Net interchange and purchased power" in the Consolidated Statements of Income. As of December 31, 1995 and 1994, $965,473,000 and $932,324,000, respectively, associated with the cost of capacity purchased but not reflected in current rates have been accumulated in the Consolidated Balance Sheets as "Purchased capacity costs." NOTE 4. INCOME TAX EXPENSE Accumulated deferred income taxes consist primarily of the following (dollars in thousands):
December 31, 1995 December 31, 1994 Excess tax over book depreciation at historical tax rates $ 1,387,925 $ 1,343,605 Regulatory liability related to adjusting deferred taxes to the current statutory tax rate .................... (114,538)* (120,422)* Net excess tax over book depreciation .............. $ 1,273,387 $ 1,223,183 Regulatory asset related to restating to a pre-tax basis 605,214* 609,714* Deferred Catawba purchased capacity costs ............... 374,112 361,018 Book versus tax basis difference ........................ 60,443 89,058 Loss on bond redemptions ................................ 68,135 70,067 Other ................................................... 913 (4,409) Total deferred income taxes ........................ $ 2,382,204 $ 2,348,631
* The net regulatory asset related to income taxes is $490,676,000 for 1995 and $489,292,000 for 1994. Total deferred income tax liability was $2,946,711,000 as of December 31, 1995, and $2,873,373,000 as of December 31, 1994. Total deferred income tax asset was $564,507,000 as of December 31, 1995, and $524,742,000 as of December 31, 1994. Income tax expense for the years ended December 31, 1995, 1994 and 1993 consisted of the following (dollars in thousands):
1995 1994 1993 Current income taxes Federal.................................................................... $377,237 $249,968 $283,930 State...................................................................... 83,215 52,790 63,150 Total current income taxes................................................ 460,452 302,758 347,080 Deferred taxes, net Federal.................................................................... 13,466 83,359 59,267 State...................................................................... 3,770 22,153 14,887 Total deferred taxes, net................................................. 17,236 105,512 74,154 Investment tax credit amortization........................................... (11,247) (11,251) (11,257) Total income tax expense.................................................. $466,441 $397,019 $409,977
Income taxes differ from amounts computed by applying the statutory tax rate to pre-tax income for the years ended December 31, 1995, 1994 and 1993 as follows (dollars in thousands):
1995 1994 1993 Income taxes on pre-tax income at the statutory federal rate of 35%....... $413,343 $362,563 $362,737 Increase (reduction) in tax resulting from: Allowance for funds used during construction (AFUDC).................... (8,079) (9,594) (6,027) Amortization of investment tax credit deferrals......................... (11,247) (11,251) (11,257) AFUDC in book depreciation/amortization................................. 21,057 19,027 25,694 Deferred income tax flowback at rates higher than statutory............. (5,675) (5,530) (9,091) State income taxes, net of federal income tax benefits.................. 56,210 47,872 51,289 Other items, net........................................................ 832 (6,068) (3,368) Total income tax expense......................................... $466,441 $397,019 $409,977
NOTE 5. SHORT-TERM BORROWINGS AND CREDIT FACILITIES The following credit facilities were available to the Company at December 31, 1995 and 1994, with 25 and 26 commercial banks, respectively:
Line of Credit at Outstanding at Line of Credit at Outstanding at Type of Facility December 31, 1995 December 31, 1995 December 31, 1994 December 31, 1994 Annually renewable lines of credit $ 64,900,000 $ 29,300,000 $ 44,980,000 $ 10,100,000 Two-year revolving facilities (a) 40,000,000 -- 40,000,000 -- Three-year revolving facilities (b) 355,000,000 -- 355,000,000 -- Four-year revolving facilities (c) 210,000,000 30,043,000 -- -- $669,900,000 $59,343,000 $439,980,000 $10,100,000
(a) The Company had $40,000,000 in pollution control bonds, included in long-term debt, outstanding throughout 1995 and 1994 backed by the unused portion of these facilities. (b) The Company had $130,000,000 in commercial paper, included in long-term debt, outstanding throughout 1995 and 1994 backed by the unused portion of these facilities. (c) The outstanding balance of $30,043,000 is included in long-term debt. Cash balances maintained at the banks on deposit were $17,120,000 as of December 31, 1995, and $13,214,000 as of December 31, 1994. Cash balances and fees compensate banks for their services, even though the Company has no formal compensating-balance arrangements. To compensate certain banks for credit facilities, the Company maintained balances of $45,000 and $49,000 as of December 31, 1995 and 1994, respectively. The Company retains the right of withdrawal with respect to the funds used for compensating-balance arrangements. A summary of short-term borrowings is as follows (dollars in thousands):
Twelve Months Ended December 31, 1995 December 31, 1994 December 31, 1993 Amount outstanding at end of period -- average rate of 5.91% as of December 31, 1995, 6.02% as of December 31, 1994, and 3.55% as of December 31, 1993............................. $ 155,300 $ 107,100 $ 20,800 Maximum amount outstanding during the period .................... $ 264,300 $ 143,400 $ 180,800 Average amount outstanding during the period .................... $ 88,470 $ 24,161 $ 35,366 Weighted-average interest rate for the period -- computed on a daily basis.............................................. 6.05% 4.58% 3.19%
NOTE 6. COMMON STOCK AND RETAINED EARNINGS Common Stock As of December 31, 1995, a total of 7,004,659 shares was reserved for issuance for stock plans. Retained Earnings As of December 31, 1995, substantially all of the Company's retained earnings were unrestricted as to the declaration or payment of dividends. NOTE 7. PREFERRED AND PREFERENCE STOCK WITHOUT SINKING FUND REQUIREMENTS The following shares of stock were authorized with or without sinking fund requirements as of December 31, 1995 and 1994:
Par Value Shares Preferred Stock $100 12,500,000 Preferred Stock A 25 10,000,000 Preference Stock 100 1,500,000
As of December 31, 1995 and 1994, there were no shares of preference stock outstanding. Preferred stock without sinking fund requirements as of December 31, 1995 and 1994, was as follows (dollars in thousands):
Year Shares Rate/Series Issued Outstanding 1995 1994 4.50% C ............................................................ 1964 350,000 $ 35,000 $ 35,000 5.72% D............................................................. 1966 350,000 35,000 35,000 6.72% E ............................................................ 1968 350,000 35,000 35,000 7.85% S ............................................................ 1992 600,000 60,000 60,000 7.00% W............................................................. 1993 500,000 50,000 50,000 7.04% Y............................................................. 1993 600,000 60,000 60,000 7.72% (Preferred Stock A)................................................ 1992 1,600,000 40,000 40,000 6.375% (Preferred Stock A)............................................... 1993 2,400,000 60,000 60,000 Adjustable Rate A........................................................ 1986 500,000 -- 50,000 Auction Series A......................................................... 1990 750,000 75,000 75,000 Total.............................................................. $450,000 $500,000
NOTE 8. PREFERRED AND PREFERENCE STOCK WITH SINKING FUND REQUIREMENTS The following shares of stock were authorized with or without sinking fund requirements as of December 31, 1995 and 1994: Par Value Shares Preferred Stock $100 12,500,000 Preferred Stock A 25 10,000,000 Preference Stock 100 1,500,000 As of December 31, 1995 and 1994, there were no shares of preference stock outstanding. Preferred stock with sinking fund requirements as of December 31, 1995 and 1994, was as follows (dollars in thousands):
Year Shares Rate/Series Issued Outstanding 1995 1994 5.95% B (Preferred Stock A) ........................................ 1992 800,000 $ 20,000 $ 20,000 6.10% C (Preferred Stock A) ........................................ 1992 800,000 20,000 20,000 6.20% D (Preferred Stock A) ........................................ 1992 800,000 20,000 20,000 7.12% Q............................................................. 1987 470,000 -- 47,000 7.50% R............................................................. 1992 850,000 85,000 85,000 6.20% T............................................................. 1992 130,000 13,000 13,000 6.30% U............................................................. 1992 130,000 13,000 13,000 6.40% V............................................................. 1992 130,000 13,000 13,000 6.75% X............................................................. 1993 500,000 50,000 50,000 Less: Current sinking fund requirements 7.12% Q.............................................................. -- (1,500) Total.............................................................. $234,000 $279,500
The annual sinking fund requirements through 2000 are $0 in 1996 and 1997, $4,250,000 in 1998, $24,250,000 in 1999 and $37,250,000 in 2000. Some additional redemptions are permitted at the Company's option. The call provisions for the outstanding preferred stock specify various redemption prices not exceeding 105 percent of par value, plus accumulated dividends to the redemption date. NOTE 9. LONG-TERM DEBT Long-term debt outstanding as of December 31, 1995 and 1994, was as follows (dollars in thousands):
Series Year Due 1995 1994 FIRST AND REFUNDING MORTGAGE BONDS: 6.47%-6.60% 1995 $ -- $ 40,300 4 1/2% 1995 -- 40,000 6.59% 1996 3,000 3,000 5 3/8% 1997 72,600 72,600 5 5/8% 1997 100,000 100,000 5.17% 1998 50,000 50,000 7.5% 1999 100,000 100,000 6 1/4% 1999 65,000 65,000 5.76% 1999 5,000 5,000 5.78% 1999 25,000 25,000 5.79% 1999 30,000 30,000 8% B 1999 200,000 200,000 7% 2000 100,000 100,000 7% B 2000 100,000 100,000 5 7/8% 2001 150,000 150,000 6 5/8% B 2003 100,000 100,000 5 7/8% C 2003 75,000 75,000 6.125% 2003 75,000 75,000 8% 2004 75,000 75,000 6 1/4% B 2004 100,000 100,000 7.37%-7.41% 2004 100,000 100,000 7% 2005 200,000 200,000 6 3/8% 2008 125,000 125,000 9 5/8% 2020 -- 46,982 10 1/8% B 2020 -- 24,854 8 3/4% 2021 150,000 150,000 8 3/8% B 2021 150,000 150,000 8 5/8% 2022 100,000 100,000 7 3/8% 2023 200,000 200,000 6 7/8% B 2023 200,000 200,000 7 7/8% 2024 150,000 150,000 6 3/4% 2025 150,000 150,000 7 1/2% B 2025 $ 100,000 $ -- 8.27% 2025 21,000 -- 8.27 % 2025 50,000 -- 8.28% 2025 2,000 -- 8.30% 2025 5,000 -- 8.95% 2027 15,681 15,769 7% 2033 150,000 150,000 POLLUTION CONTROL BONDS: 7.70% 2012 20,000 20,000 7.75% B 2017 10,000 10,000 7.50% 2017 25,000 25,000 3.76% 2014 40,000 40,000 5.80% 2014 77,000 77,000 Subtotal 3,466,281 3,440,505 OTHER LONG-TERM DEBT: Capitalized leases 7,477 26,039 Other long-term debt 147,410 130,000 Unamortized debt discount and premium, net (61,674) (62,918) Current maturities of long-term debt (4,295) (81,926) Subtotal (a) 3,555,199 3,451,700 SUBSIDIARY LONG-TERM DEBT: Crescent Resources, Inc. (b) 130,694 92,102 Nantahala Power and Light 33,288 33,653 Current maturities of long-term debt (7,776) (10,333) Subtotal 156,206 115,422 Total long-term debt $3,711,405 $3,567,122
(a) Substantially all of Duke Power's Electric Plant was mortgaged as of December 31, 1995. (b) Substantial amounts of Crescent Resources, Inc.'s Real Estate Development projects, land and buildings are pledged as collateral. As of December 31, 1995 and 1994, the Company had $40,000,000 in pollution control revenue bonds backed by an unused, two-year revolving credit facility of $40,000,000. In addition, the Company had $130,000,000 in commercial paper outstanding throughout 1995 and 1994 backed by unused three-year revolving credit facilities. These facilities are on a fee basis. Both the $40,000,000 in pollution control bonds and the $130,000,000 in commercial paper are included in long-term debt. As of December 31, 1995, Crescent Resources, Inc. had $65,526,000 in mortgage loans which mature through 2000 and $35,125,000 in mortgage loans maturing in 2001 or thereafter. Additionally, Crescent Resources, Inc. had $30,043,000 outstanding at December 31, 1995, included in long-term debt on a $50,000,000 four-year revolving credit facility. Interest rates are variable and at December 31, 1995, ranged from 5.50 percent to 7.10 percent. As of December 31, 1995, Nantahala Power and Light Company had $33,000,000 in senior notes maturing in 2011 and 2012. The two notes carry fixed interest rates of 9.21 percent and 7.45 percent and require monthly payments of principal beginning in 1997 and 1998, respectively. The annual maturities of consolidated long-term debt, including capitalized lease principal payments through 2000, are $12,071,000 in 1996; $215,476,000 in 1997; $63,097,000 in 1998; $473,326,000 in 1999; and $206,583,000 in 2000. NOTE 10. FINANCIAL INSTRUMENTS The carrying amounts of "Cash," "Short-term investments," and "Notes payable" on the Consolidated Balance Sheets approximate fair value primarily because of the short maturities of these instruments. "Other investments" substantially consist of notes receivable issued at fixed rates with maturities up to 30 years for which there are no quoted market prices. Due to the numerous outstanding notes, it was not practicable or cost beneficial for the Company to estimate the fair value of these instruments. The majority of estimated fair value amounts of long-term debt and preferred stock as disclosed below were obtained from independent parties. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 1995 and 1994, are not necessarily indicative of the amounts the Company could have realized in current market exchanges. External funds have been established, as required by the Nuclear Regulatory Commission, as a mechanism to fund certain costs of nuclear decommissioning. (See Note 14.) Currently, these nuclear decommissioning trust funds are invested in U.S. stocks, bonds and cash equivalents. "Nuclear decommissioning trust funds" are presented on the Consolidated Balance Sheets at amounts that approximate fair value. The carrying amounts and estimated fair values of long-term debt and preferred stocks are as follows (dollars in thousands):
December 31, 1995 December 31, 1994 Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt............................. $3,777,672 $3,879,000 $3,696,260 $3,392,000 Preferred stock............................ $ 684,000 $ 689,000 $ 781,000 $ 697,000
In order to obtain variable rate financing at an attractive cost, the Company entered into interest rate swap agreements associated with the November 29, 1994, issuance of $200 million aggregate principal amount of its First and Refunding Mortgage Bonds, 8% Series B due 1999 and the August 21, 1995, issuance of $100 million aggregate principal amount of its First and Refunding Mortgage Bonds, 7 1/2% Series B due 2025. The interest rate swaps are reset quarterly based upon the London Interbank Offered Rate (LIBOR). As a result of the interest rate swap contracts, interest expense on the Consolidated Statements of Income is recognized at the weighted average rate for the year tied to the LIBOR rate. The weighted average rates are as follows (dollars in thousands): Weighted Average Rate Series Year Due Face Value 1995 1994 8% Series B 1999 $200,000 6.14% 5.95% 7 1/2% Series B 2025 $100,000 7.06% -- The Company also entered into a hedge transaction to offset currency fluctuations between the U.S. dollar and the Japanese yen associated with various steam generator contracts. The hedge transaction, with a notional amount of approximately $25 million at December 31, 1994, was fully liquidated by November 1995. The Company recorded any gains or losses associated with the hedge as an adjustment to the capitalized cost of the steam generators. Duke Energy Group, Inc. has entered into a hedge transaction to offset currency fluctuations between the U.S. dollar and the Chilean peso associated with expected equity contributions over the next two years to a joint venture. The hedge transaction had a notional amount of approximately $17 million at December 31, 1995. Duke Energy Group, Inc. records any gains or losses associated with the hedge as an adjustment to investments in joint ventures. NOTE 11. INVESTMENTS IN JOINT VENTURES Certain investments in joint ventures are accounted for by the equity method. The Company's ownership in domestic and international joint ventures is 50 percent or less. The Company's proportionate share of net income in joint ventures for the years ended December 31, 1995, 1994 and 1993 was $9,237,000, $7,049,000 and $2,601,000, respectively. These amounts are reflected in "Operating revenues" on the Consolidated Statements of Income. A summary of assets and liabilities of joint ventures follows (dollars in thousands):
December 31, 1995 December 31, 1994 Company's Company's Proportionate Proportionate Total Share Total Share Assets of joint ventures........................................ $1,445,600 $351,376 $1,117,449 $272,836 Liabilities of joint ventures................................... $ 615,452 $188,102 $ 504,029 $164,506
Of the $615,452,000 and $504,029,000 of total liabilities outstanding at December 31, 1995 and 1994, respectively, $528,289,000 and $407,605,000 represent non-recourse debt at December 31, 1995 and 1994, respectively, for which the Company bears no responsibility beyond the loss of its investment and loans made to certain joint ventures in the event the joint venture defaults on the debt. These loans were approximately $23,170,000 at December 31, 1995. NOTE 12. RETIREMENT BENEFITS A. RETIREMENT PLAN The Company and its operating subsidiaries, with the exception of Nantahala Power and Light Company, which maintains its own retirement plans, have a non-contributory, defined benefit retirement plan covering substantially all their employees. The benefit is based upon an age-related formula which takes into account years of creditable service and the employee's average compensation based upon the highest compensation during a consecutive sixty-month period. The benefit is reduced by an adjustment which is based upon the employee's social security wages. Normal retirement age under the Plan is age 65; however, early retirement benefits are payable as early as age 55 with 10 years of creditable service or age 51 if the employee has at least 30 years of creditable service. The Company's policy is to fund pension costs as accrued. During 1994, the Company made additional contributions of $30,000,000 to enhance the funded position of the plan. Net periodic pension cost for the years ended December 31, 1995, 1994 and 1993, include the following components (dollars in thousands):
1995 1994 1993 Service cost benefit earned during the year.............. $ 46,402 $43,098 $39,514 Interest cost on projected benefit obligation............ 111,110 96,521 93,347 Actual return on plan assets.............................(253,314) (6,138) (117,898) Amount deferred for recognition.......................... 144,022 (86,995) 35,652 Expected return on plan assets........................... (109,292) (93,133) (82,246) Net amortization......................................... 6,161 7,657 4,137 Net periodic pension cost.......................... $ 54,381 $54,143 $54,752
A reconciliation of the funded status of the plan to the amounts recognized in the Consolidated Balance Sheets as of December 31, 1995 and 1994, is as follows (dollars in thousands):
1995 1994 Accumulated benefit obligation: Vested benefits............................................................................... $ (1,289,459) $ (1,070,355) Nonvested benefits............................................................................ (6,216) (4,420) Accumulated benefit obligation............................................................. $ (1,295,675) $ (1,074,775) Fair market value of plan assets, consisting primarily of short-term investments and cash equivalents, common stocks, real estate investments and government and industrial bonds ................... $ 1,424,148 $ 1,167,158 Projected benefit obligation .................................................................... (1,596,747) (1,368,740) Unrecognized net experience loss ................................................................ 286,837 319,519 Unrecognized prior service cost reduction ....................................................... (35,039) (38,872) Remaining unrecognized transitional obligation .................................................. 801 935 Pre-funded pension cost ................................................................... $ 80,000 $ 80,000
In determining the projected benefit obligation, the weighted-average assumed discount rate used was 7.50 percent in 1995, 8.25 percent in 1994 and 7.50 percent in 1993. The assumed increase in future compensation level is determined on an age-related basis. The weighted-average salary increase was 4.75 percent in 1995, 5.40 percent in 1994 and 4.50 percent in 1993. The expected long-term rate of return on plan assets used in determining pension cost was 9.00 percent in 1995, 9.00 percent in 1994 and 8.40 percent in 1993. During 1995, the Company offered to certain employees an Enhanced Vested Benefits program (EVB). The Company recorded an additional one-time expense for special termination benefits associated with EVB of approximately $42,196,000, including $21,600,000 of additional retirement plan costs. During 1993, the Company offered an enhanced early retirement option, Limited Period Separation Opportunity (LPSO), for eligible employees. The Company recorded an additional one-time expense for special termination benefits associated with LPSO of approximately $7,611,000. B. POSTRETIREMENT BENEFITS The Company and its operating subsidiaries, with the exception of Nantahala Power and Light Company (NP&L), which has maintained its own postretirement benefit plans, currently provide certain health care and life insurance benefits for retired employees. However, NP&L employees who retire after January 1, 1996, will be covered by Duke Power Company's postretirement benefit plan. Employees become eligible for these benefits if they retire at age 55 or greater with 10 years of service or if they retire as early as age 51 with 30 years or more of service. Employees retiring after January 1, 1992, receive a fixed Company allowance, based on years of service, to be used to pay medical insurance premiums. The Company reserves the right to terminate, suspend, withdraw, amend or modify the plans in whole or in part at any time. In 1992, the Company commenced funding the maximum amount allowable under section 401(h) of the Internal Revenue Code, which provides for tax deductions for contributions and tax-free accumulation of investment income. Such amounts partially fund the Company's medical and dental postretirement benefits. The Company has also established a Retired Lives Reserve, which has tax attributes similar to 401(h) funding, to partially fund its postretirement life insurance obligation. The Company contributed $23,000,000 into these funding mechanisms in 1995 and $12,269,000 in 1994. Net periodic postretirement benefit cost for the years ended December 31, 1995, 1994 and 1993, include the following components (dollars in thousands):
1995 1994 1993 Service cost benefit earned during the year.................... $ 5,874 $ 5,415 $ 4,974 Interest cost on accumulated postretirement benefit obligation. 27,201 25,321 25,482 Actual return on plan assets................................... (14,726) (1,451) (4,143) Amount deferred for recognition................................ 7,260 (3,469) 334 Expected return on plan assets................................. (7,466) (4,920) (3,809) Straight-line -- 20 year amortization of transitional obligation 13,293 13,293 13,479 Other amortization............................................. 555 366 278 Net periodic postretirement benefit cost.................... $ 39,457 $ 39,475 $ 40,404
A reconciliation of the funded status of the plan to the amounts recognized in the Consolidated Balance Sheets as of December 31, 1995 and 1994, is as follows (dollars in thousands):
Fair market value of plan assets, 1995 1994 consisting primarily of short-term investments and cash equivalents, common stocks, real estate investments and government and industrial bonds...... $ 105,506 $ 69,987 Actives eligible to retire..................................................... (25,780) (11,902) Actives not eligible to retire................................................. (97,389) (90,499) Retirees and surviving spouses.................................................(253,688) (239,978) Accumulated postretirement benefit obligation ................................. (376,857) (342,379) Unrecognized prior service cost................................................ 712 783 Unrecognized net experience loss .............................................. 25,955 14,448 Unrecognized transitional obligation........................................... 212,695 225,988 (Accrued) postretirement benefit cost....................................... $ (31,989) $ (31,173)
In determining the accumulated postretirement benefit obligation (APBO), the weighted-average assumed discount rate used was 7.50 percent in 1995, 8.25 percent in 1994 and 7.50 percent in 1993. The assumed increase in future compensation level is determined on an age-related basis. The weighted-average salary increase was 4.75 percent in 1995, 5.40 percent in 1994 and 4.50 percent in 1993. The expected long-term rate of return on 401(h) assets used in determining postretirement benefits cost was 9.00 percent in 1995, 9.00 percent in 1994 and 8.40 percent in 1993. For Retired Lives Reserve assets, 8.00 percent was used in 1995, 6.50 percent in 1994 and 7.13 percent in 1993. The assumed medical inflation rate was approximately 10.5 percent in 1995. This rate decreases by 0.5 percent to 1.0 percent per year until a rate of 5.5 percent is achieved in the year 2001, which remains fixed thereafter. A 1.0 percent increase in the medical and dental trend rates produces a 4.81 percent ($1,589,000) increase in the aggregate service and interest cost. The increase in the APBO attributable to a 1.0 percent increase in the medical and dental trend rates is 9.22 percent ($38,281,000) as of December 31, 1995. NOTE 13. COMMITMENTS AND CONTINGENCIES A. CONSTRUCTION PROGRAM Projected construction and nuclear fuel costs for Duke Power's electric operations, both including allowance for funds used during construction, are $2.3 billion and $661 million, respectively, for 1996 through 2000. These projections are subject to periodic review and revisions. Actual construction and nuclear fuel costs and capital expenditures incurred may vary from such estimates. Cost variances are due to various factors, including revised load estimates, environmental matters and cost and availability of capital. Projected capital expenditures of subsidiaries and diversified activities are $1.0 billion for 1996 through 2000. These projections are subject to periodic review and revisions and may vary significantly as the business plans of the Associated Enterprises Group evolve to meet the opportunity presented by its markets. B. NUCLEAR INSURANCE The Company maintains nuclear insurance coverage in three areas: liability coverage, property, decontamination and decommissioning coverage, and extended accidental outage coverage to cover increased generating costs and/or replacement power purchases. The Company is being reimbursed by the other joint owners of the Catawba Nuclear Station for certain expenses associated with nuclear insurance premiums paid by the Company. Pursuant to the Price-Anderson Act, the Company is required to insure against public liability claims resulting from nuclear incidents to the full limit of liability of approximately $8.9 billion. The maximum required private primary insurance of $200 million has been purchased along with a like amount to cover certain worker tort claims. The remaining amount, currently $8.7 billion, which will be increased by $79.3 million as each additional commercial nuclear reactor is licensed, has been provided through a mandatory industry-wide excess secondary insurance program of risk pooling. The $8.7 billion could also be reduced by $79.3 million for certain nuclear reactors that are no longer operational and may be exempted from the risk pooling insurance program. Under this program, licensees could be assessed retrospective premiums to compensate for damages in the event of a nuclear incident at any licensed facility in the nation. If such an incident occurs and public liability damages exceed primary insurances, licensees may be assessed up to $79.3 million for each of their licensed reactors, payable at a rate not to exceed $10 million a year per licensed reactor for each incident. The $79.3 million amount is subject to indexing for inflation and may be subject to state premium taxes. This amount is further subject to a surcharge of 5 percent (which is included in the above $8.7 billion figure) if funds are insufficient to pay claims and associated costs. If retrospective premiums were to be assessed, the other joint owners of the Catawba Nuclear Station are obligated to assume their pro rata share of such assessment. The Company is a member of Nuclear Mutual Limited (NML), which provides $500 million in primary property damage coverage for each of the Company's nuclear facilities. If NML's losses ever exceed its reserves, the Company will be liable, on a pro rata basis, for additional assessments of up to $36 million. This amount represents 5 times the Company's annual premium to NML. The other joint owners of Catawba are obligated to assume their pro rata share of any liability for retrospective premiums and other premium assessments resulting from the NML policies applicable to Catawba. The Company is also a member of Nuclear Electric Insurance Limited (NEIL) and purchases insurance through NEIL's excess property, decontamination and decommissioning liability insurance program. NEIL provides excess insurance coverage of $2.25 billion for the Catawba Nuclear Station and $1.5 billion for each of the Oconee and McGuire Nuclear Stations. If losses ever exceed the accumulated funds available to NEIL for the excess property, decontamination and decommissioning liability program, the Company will be liable, on a pro rata basis, for additional assessments of up to $61 million. This amount is limited to 7.5 times the Company's annual premium to NEIL for excess property, decontamination and decommissioning liability insurance. The other joint owners of Catawba are obligated to assume their pro rata share of any liability for retrospective premiums and other premium assessments resulting from the NEIL policies applicable to Catawba. The Company participates in a NEIL program that provides insurance for the increased cost of generation and/or purchased power resulting from an accidental outage of a nuclear unit. Each unit of the Oconee, McGuire and Catawba Nuclear Stations is insured for up to approximately $3.5 million per week, after a 21-week deductible period, with declining amounts per unit where more than one unit is involved in an accidental outage. Coverages continue at 100 percent for 52 weeks and 80 percent for the next 104 weeks. If NEIL's losses for this program ever exceed its reserves, the Company will be liable, on a pro rata basis, for additional assessments of up to $30 million. This amount represents 5 times the Company's annual premium to NEIL for insurance for the increased cost of generation and/or purchased power resulting from an accidental outage of a nuclear unit. The other joint owners of Catawba are obligated to assume their pro rata share of any liability for retrospective premiums and other premium assessments resulting from the NEIL policies applicable to the joint ownership agreements. C. OTHER The Company and North Carolina Municipal Power Agency Number 1 and Piedmont Municipal Power Agency, two of the four other joint owners of the Catawba Nuclear Station, entered into a settlement in September 1995 which resolved outstanding issues related to how certain calculations affecting bills under the Catawba joint ownership contractual agreements should be performed. The settlement was approved by the North Carolina Utilities Commission on January 16, 1996 and the Public Service Commission of South Carolina on January 23, 1996. As part of the settlement, the Company agreed to purchase additional megawatts (MW) of Catawba capacity during the period 1996 through 1999 and remove certain restrictions related to sales of surplus energy by these two joint owners. The additional capacity purchases are 215 MW in 1996, 165 MW in 1997, 120 MW in 1998 and 100 MW in 1999. The Company expects to recover the costs associated with this settlement as part of the purchased capacity levelization, consistent with prior orders of the retail regulatory commissions. Therefore, the Company believes these matters should not have a material adverse effect on the results of operations or financial position of the Company. The Company and all four of the other joint owners of the Catawba Nuclear Station entered into settlement agreements in 1994 which resolved all issues in contention in arbitration proceedings related to the Catawba joint ownership contractual agreements. The basic contention in each proceeding was that certain calculations affecting bills under these agreements should be performed differently. These items are covered by the agreements between the Company and the other Catawba joint owners which have been previously approved by the Company's retail regulatory commissions. (For additional information, see Note 3.) In 1994, the Company settled its cumulative net obligation through 1993 of approximately $205 million related to these settlement agreements. Billings for 1994 and later years will conform to the settlement agreements, which have been approved by the Company's retail regulatory commissions. Because the Company expects the costs associated with these settlements to be recovered as part of the purchased capacity levelization, which has been approved by the Company's retail regulatory commissions, the Company included approximately $205 million as an increase to "Purchased capacity costs" on its Consolidated Balance Sheets in 1994. Therefore, the Company believes these matters should not have a material adverse effect on the results of operations or financial position of the Company. The Company is also involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business, some of which involve substantial amounts. Where appropriate, the Company has made accruals in accordance with Statement of Financial Accounting Standards No. 5, "Accounting for Contingencies," in order to provide for such matters. Management is of the opinion that the final disposition of these proceedings will not have a material adverse effect on the results of operations or financial position of the Company. NOTE 14. NUCLEAR DECOMMISSIONING COSTS Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $1.3 billion stated in 1994 dollars based on decommissioning studies completed in 1994. This amount includes the Company's 12.5 percent ownership in the Catawba Nuclear Station. The other joint owners of the Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. Both the North Carolina Utilities Commission and the Public Service Commission of South Carolina have granted the Company recovery of estimated decommissioning costs through retail rates over the expected remaining service periods of the Company's nuclear plants. Such estimates presume each unit will be decommissioned as soon as possible following the end of their license life. Although subject to extension, the current operating licenses for the Company's nuclear units expire as follows: Oconee 1 and 2 - 2013, Oconee 3 - 2014; McGuire 1 - 2021, McGuire 2 - 2023; and Catawba 1 - - 2024, Catawba 2 - 2026. The Nuclear Regulatory Commission issued a rule-making in 1988 which requires an external mechanism to fund the estimated cost to decommission certain components of a nuclear unit subject to radioactive contamination. In addition to the required external funding, the Company maintains an internal reserve to provide for decommissioning costs of plant components not subject to radioactive contamination. During 1995, the Company expensed approximately $56,470,000 which was contributed to the external funds and accrued an additional $1,319,000 to the internal reserve. Nuclear units are depreciated at a rate of 4.70 percent, of which 1.61 percent is for decommissioning. The balance of the external funds as of December 31, 1995, was $273,466,000. The balance of the internal reserve as of December 31, 1995, was $206,155,000 and is reflected in accumulated depreciation and amortization on the Consolidated Balance Sheets. Management's opinion is that the decommissioning costs being recovered through rates, when coupled with assumed after-tax fund earnings of 5.5 percent to 5.9 percent, are currently sufficient to provide for the cost of decommissioning. NOTE 15. RECLASSIFICATION In the Consolidated Statements of Income and Consolidated Statements of Cash Flows, certain 1993 information has been reclassified to conform with 1994 classifications. INDEPENDENT AUDITORS' REPORT Duke Power Company: We have audited the consolidated financial statements of Duke Power Company and subsidiaries (the Company) listed in the accompanying index for Item 8. Our audits also included the consolidated financial statement schedule listed in the accompanying index. These financial statements and consolidated financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and consolidated financial statement schedule based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1995 and 1994, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein. (Signature of Deloitte & Touche LLP) Deloitte & Touche LLP (Deloitte & Charlotte, North Carolina Touche LLP February 9, 1996 logo appears here) RESPONSIBILITY FOR FINANCIAL STATEMENTS The financial statements of Duke Power Company are prepared by management, which is responsible for their integrity and objectivity. The statements are prepared in conformity with generally accepted accounting principles appropriate in the circumstances to reflect in all material respects the substance of events and transactions which should be included. The other information in the annual report is consistent with the financial statements. In preparing these statements, management makes informed judgments and estimates of the expected effects of events and transactions that are currently being reported. The Company's system of internal accounting control is designed to provide reasonable assurance that assets are safeguarded and transactions are executed according to management's authorization. Internal accounting controls also provide reasonable assurance that transactions are recorded properly, so that financial statements can be prepared according to generally accepted accounting principles. In addition, the Company's accounting controls provide reasonable assurance that errors or irregularities which could be material to the financial statements are prevented or are detected by employees within a timely period as they perform their assigned functions. The Company's accounting controls are continually reviewed for effectiveness. In addition, written policies, standards and procedures, and a strong internal audit program augment the Company's accounting controls. The Board of Directors pursues its oversight role for the financial statements through the audit committee, which is composed entirely of directors who are not employees of the Company. The audit committee meets with management and internal auditors periodically to review the work of each group and to monitor each group's discharge of its responsibilities. The audit committee also meets periodically with the Company's independent auditors, Deloitte & Touche LLP. The independent auditors have free access to the audit committee and the Board of Directors to discuss internal accounting control, auditing and financial reporting matters without the presence of management. (Signature of Jeffrey L. Boyer) Jeffrey L. Boyer Controller QUARTERLY FINANCIAL DATA
First Second Third Fourth Dollars in Thousands (except per-share data) Quarter Quarter Quarter Quarter Total 1995 BY QUARTER Operating revenues....................................... $1,111,065 $1,052,403 $1,379,978 $1,133,238 $4,676,684 Operating income ........................................ $ 369,414 $ 263,876 $ 504,507 $ 211,254 $1,349,051 Net income .............................................. $ 201,276 $ 137,523 $ 285,200 $ 90,539 $ 714,538 Earnings per share....................................... $0.92 $0.61 $1.33 $0.39 $3.25 1994 BY QUARTER Operating revenues....................................... $1,099,002 $1,083,310 $1,272,525 $1,034,076 $4,488,913 Operating income ........................................ $ 326,584 $ 242,419 $ 430,861 $ 179,962 $1,179,826 Net income .............................................. $ 173,617 $ 128,002 $ 243,741 $ 93,516 $ 638,876 Earnings per share....................................... $0.79 $0.56 $1.13 $0.40 $2.88
Generally, quarterly earnings fluctuate with seasonal weather conditions and maintenance of electric generating units, especially nuclear units. SUBSIDIARIES AND DIVERSIFIED ACTIVITIES HIGHLIGHTS During 1994, the Company reorganized, placing all its subsidiaries and diversified activities into the Associated Enterprises Group (AEG). AEG includes the following: o CHURCH STREET CAPITAL CORP. (CSCC) manages investment funds, serves as the parent company and provides equity funding and credit enhancement for the non-electric operating subsidiaries. CSCC investment highlights are as follows (dollars in thousands): SHORT-TERM INVESTMENTS AND MARKETABLE SECURITIES 1995 1994 1993 $76,300 $170,642 $155,871 INVESTMENT INCOME (AFTER TAX) (A) 1995 1994 1993 $4,783 $7,562 $3,548 O CRESCENT RESOURCES, INC. is engaged in real estate development and forest management. O DUKE ENERGY GROUP, INC. develops, owns and manages investments in electric power facilities, both nationally and internationally, and markets electric power and natural gas. o DUKE ENGINEERING & SERVICES, INC. markets engineering, construction, quality assurance, consulting and other engineering-related services for facilities other than coal-fired generating plants, both nationally and internationally. o DUKE/FLUOR DANIEL, a joint venture with Fluor Daniel, Inc., provides engineering, construction, and support of operating and maintenance activities, primarily for coal-fired generating plants, both nationally and internationally. o DUKE MERCHANDISING sells and services quality appliances and electronics primarily to Duke Power customers. o DUKENET COMMUNICATIONS, INC. develops and manages communication systems. o DUKE WATER OPERATIONS serves areas of Anderson, South Carolina, and Rutherfordton, North Carolina. o NANTAHALA POWER AND LIGHT COMPANY provides electric service to a five-county area in western North Carolina by its operation of eleven hydroelectric stations and purchase of supplemental power. OPERATING RESULTS
Dollars in Thousands Year ended December 31, 1995 1994 1993 OPERATING REVENUES Crescent Resources, Inc............................................................... $ 85,361 $ 64,724 $ 46,784 Duke Energy Group, Inc. (b)........................................................... 10,017 9,478 6,033 Nantahala Power and Light Company (c)................................................. 62,510 68,595 67,142 All Other Business Units (d).......................................................... 141,337 109,932 106,340 Total Associated Enterprises Group................................................. $ 299,225 $ 252,729 $ 226,299 OPERATING INCOME Crescent Resources, Inc............................................................... $ 63,973 $ 46,236 $ 30,004 Duke Energy Group, Inc................................................................ (1,422) (1,035) (2,929) Nantahala Power and Light Company..................................................... 9,262 12,224 8,844 All Other Business Units (d).......................................................... 20,407 15,506 1,939 Total Associated Enterprises Group................................................. $ 92,220 $ 72,931 $ 37,858 NET INCOME Crescent Resources, Inc............................................................... $ 35,500 $ 26,525 $ 16,327 Duke Energy Group, Inc. (e)........................................................... 170 5,749 (1,949) Nantahala Power and Light Company..................................................... 4,037 6,169 4,261 All Other Business Units (d).......................................................... 14,550 13,593 2,876 Total Associated Enterprises Group................................................. $ 54,257 $ 52,036 $ 21,515 FINANCIAL POSITION Dollars in Thousands December 31, 1995 1994 1993 TOTAL ASSETS Crescent Resources, Inc............................................................... $ 381,073 $ 294,175 $ 219,206 Duke Energy Group, Inc. (f)........................................................... 149,391 110,656 144,499 Nantahala Power and Light Company..................................................... 144,069 125,883 107,872 All Other Business Units (d).......................................................... 283,774 279,430 265,977 Total Associated Enterprises Group................................................. $ 958,307 $ 810,144 $ 737,554 TOTAL LIABILITIES Crescent Resources, Inc............................................................... $ 185,996 $ 134,574 $ 86,172 Duke Energy Group, Inc................................................................ 9,783 4,672 31,816 Nantahala Power and Light Company..................................................... 86,691 72,542 60,700 All Other Business Units (d).......................................................... 43,498 22,312 30,902 Total Associated Enterprises Group................................................. $ 325,968 $ 234,100 $ 209,590 CASH FLOWS Dollars in Thousands Year ended December 31, 1995 1994 1993 CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES Crescent Resources, Inc............................................................... $ 40,144 $ 37,691 $ 36,254 Duke Energy Group, Inc................................................................ (3,521) (6,614) (1,438) Nantahala Power and Light Company..................................................... 8,419 12,817 14,869 All Other Business Units (d).......................................................... 1,769 10,589 8,795 Total Associated Enterprises Group................................................. $ 46,811 $ 54,483 $ 58,480 CASH PROVIDED BY INVESTING ACTIVITIES Crescent Resources, Inc............................................................... $ 5,910 $ 2,524 $ 1,310 Duke Energy Group, Inc. (g)........................................................... 14,253 40,740 28,785 Nantahala Power and Light Company..................................................... -- -- -- All Other Business Units (h).......................................................... 97,793 5,100 21,377 Total Associated Enterprises Group................................................. $ 117,956 $ 48,364 $ 51,472 CASH USED IN INVESTING ACTIVITIES Crescent Resources, Inc............................................................... $ 84,603 $ 78,689 $ 43,444 Duke Energy Group, Inc................................................................ 44,776 19,575 116,498 Nantahala Power and Light Company..................................................... 23,944 23,989 19,254 All Other Business Units (i).......................................................... 66,768 18,500 1,450 Total Associated Enterprises Group................................................. $ 220,091 $ 140,753 $ 180,646 CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (j) Crescent Resources, Inc. (k).......................................................... $ 38,521 $ 37,589 $ 945 Duke Energy Group, Inc. (l)........................................................... -- -- -- Nantahala Power and Light Company..................................................... 15,536 10,896 3,206 All Other Business Units (m).......................................................... 5,302 (6,993) 71,537 Total Associated Enterprises Group................................................. $ 59,359 $ 41,492 $ 75,688 OTHER INFORMATION December 31, 1995 1994 1993 FULL-TIME EMPLOYEES AT YEAR-END Crescent Resources, Inc............................................................... 94 89 77 Duke Energy Group, Inc................................................................ 43 35 24 Nantahala Power and Light Company..................................................... 182 184 194 All Other Business Units.............................................................. 1,036 703 755 Total Associated Enterprises Group................................................. 1,355 1,011 1,050
(a) Earnings for 1995, 1994 and 1993 exclude elimination of intercompany profits of $59,000, $49,000 and $509,000, respectively. (b) Includes Duke Energy Group, Inc.'s allocable share of net income from Joint Ventures. (See Note 11.) (c) Nantahala Power and Light Company's operating revenues include revenues from the sale of electricity to Duke Power of $1,205,000, $12,131,000 and $13,683,000 for 1995, 1994 and 1993, respectively. (d) All other business units amounts include Associated Enterprises Group intercompany eliminations. (e) 1994 includes a gain of $4,800,000, after tax, from the sale of preferred stock. (f) Includes Duke Energy Group, Inc.'s investments in joint ventures. (see Note 11.) (g) 1994 includes proceeds from the sale of preferred stock of $32,468,000 and debt securities of $3,360,000. 1993 includes proceeds from the sale of debt securities of $19,654,000. (h) 1995 and 1993 include the net change in short-term investments for the period of $56,392,000 and $20,653,000, respectively. Also, 1995 includes proceeds from the sale of a dividend capture program of $40,953,000. (i) 1994 includes the net change in short-term investments for the period of $12,060,000. (j) Excludes capital infusion and return of capital transactions between parent, Church Street Capital Corp., and its subsidiaries. (k) 1993 excludes capital infusion from parent, Church Street Capital Corp., of $6,000,000. (l) 1995 and 1993 exclude net capital infusions from parent, Church Street Capital Corp., of $33,455,000 and $91,864,000, respectively. 1994 excludes net return of capital to Church Street Capital Corp. of $12,100,000. (l) 1993 includes capital infusion from Duke Power to Church Street Capital Corp. of $75,000,000. SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Balance Balance Description Beginning End of Year of Year Dollars in thousands FOR THE YEAR ENDED DECEMBER 31, 1995 Reserves Related to Assets on Balance Sheet. . . . . . . . . . . . . . . . . $ 8,059 $ 7,774 Other Reserves Operating Reserves (1) . . . . . . . . . . . . . . . . . . . . . . 154,722 176,098 FOR THE YEAR ENDED DECEMBER 31, 1994 Reserves Related to Assets on Balance Sheet. . . . . . . . . . . . . . . . . 10,353 8,059 Other Reserves Operating Reserves (1) . . . . . . . . . . . . . . . . . . . . . . 107,477 154,722 FOR THE YEAR ENDED DECEMBER 31, 1993 Reserves Related to Assets on Balance Sheet. . . . . . . . . . . . . . . . . 10,730 10,353 Other Reserves Operating Reserves (1) . . . . . . . . . . . . . . . . . . . . . . 78,103 107,477
(1) Principally consists of Injuries and Damages reserves and Property Insurance reserve which are included in "Deferred Credits and Other Liabilities" in the Consolidated Balance Sheets. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. No events necessary to be disclosed by the Company under this item have occurred. PART III. ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. Information for this item concerning directors of the Company is set forth in the sections entitled "Election of Directors", "Information Regarding the Board of Directors" and "Common Stock Ownership of Certain Beneficial Owners and Management" in the proxy statement of the Company relating to its 1996 annual meeting of shareholders, which are being incorporated herein by reference. Information concerning the executive officers of the Company is set forth in the section entitled "Executive Officers of the Company" in this annual report. ITEM 11. EXECUTIVE COMPENSATION. Information for this item is set forth in the section entitled "Executive Compensation" in the proxy statement of the Company relating to its 1996 annual meeting of shareholders, which is being incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. Information for this item is set forth in the section entitled "Common Stock Ownership of Certain Beneficial Owners and Management" in the proxy statement of the Company relating to its 1996 annual meeting of shareholders, which is being incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. Information for this item is set forth in the sections entitled "Information Regarding the Board of Directors" and "Common Stock Ownership of Certain Beneficial Owners and Management" in the proxy statement of the Company relating to its 1996 annual meeting of shareholders, which are being incorporated herein by reference. PART IV. ITEM 14. EXHIBITS, CONSOLIDATED FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. (a) Consolidated Financial Statements, Supplemental Financial Data and Supplemental Schedules included in Part II of this annual report are as follows: Consolidated Financial Statements Consolidated Statements of Income for the Three Years Ended December 31, 1995 Consolidated Statements of Retained Earnings for the Three Years Ended December 31, 1995 Consolidated Statements of Cash Flows for the Three Years Ended December 31, 1995 Consolidated Balance Sheets -- December 31, 1995 and 1994 Notes to Consolidated Financial Statements Selected Quarterly Financial Data (unaudited) Consolidated Financial Statement Schedule Schedule II -- Valuation and Qualifying Accounts and Reserves for the Three Years Ended December 31, 1995 All other schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements or notes thereto. (b) Reports on Form 8-K No reports on Form 8-K were filed during the last quarter of 1995. (c) Exhibits -- See Exhibit Index immediately following signature page. SIGNATURES Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Charlotte and State of North Carolina on the 12th day of March, 1996. DUKE POWER COMPANY (Registrant) By: W. H. GRIGG Chairman of the Board and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Signature Title Date W. H. GRIGG Chairman of the Board and Chief March 12, 1996 Executive Officer (Principal Executive Officer) RICHARD J. OSBORNE Senior Vice President and Chief Financial March 12, 1996 Officer (Principal Financial Officer) JEFFREY L. BOYER Controller (Principal Accounting March 12, 1996 Officer) G. ALEX BERNHARDT CRANDALL C. BOWLES ROBERT J. BROWN W. A. COLEY STEVE C. GRIFFITH, JR. W. H. GRIGG GEORGE DEAN JOHNSON, JR. A Majority of the Directors March 12, 1996 W. W. JOHNSON MAX LENNON JAMES G. MARTIN BUCK MICKEL R. B. PRIORY RUSSELL M. ROBINSON, II
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 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 3-A -- Restated Articles of Incorporation of registrant, dated as of October 6, 1993 (filed with Form S-3, File No. 33-50617, effective October 20, 1993, as Exhibit 4(A)). 3-B -- Articles of Amendment of registrant dated November 1, 1993, relating to the 6.375% Cumulative Preferred Stock A, 1993 Series (filed with Form S-3, No. 33-52479, effective March 29, 1994, as Exhibit 4(B)). *3-C -- By-Laws of registrant, as amended. 4-B-1 -- First and Refunding Mortgage from registrant to Guaranty Trust Company of New York, Trustee, dated as of December 1, 1927 (filed with Form S-1, File No. 2-7224, effective October 15, 1947, as Exhibit 7(a)). 4-B-2 -- Supplemental Indenture, dated as of March 12, 1930, supplementing said Mortgage (filed with Form S-1, File No. 2-7224, effective October 15, 1947, as Exhibit 7(b)). 4-B-5 -- Supplemental Indenture, dated as of September 1, 1936, supplementing said Mortgage (filed with Form S-1, File No. 2-7224, effective October 15, 1947, as Exhibit 7(e)). 4-B-6 -- Supplemental Indenture, dated as of January 1, 1941, supplementing said Mortgage (filed with Form S-1, File No. 2-7224, effective October 15, 1947, as Exhibit 7(f)). 4-B-7 -- Supplemental Indenture, dated as of April 1, 1944, supplementing said Mortgage (filed with Form S-1, File No. 2-7224, effective October 15, 1947, as Exhibit 7(g)). 4-B-8 -- Supplemental Indenture, dated as of September 1, 1947, supplementing said Mortgage (filed with Form S-1, File No. 2-7224, effective October 15, 1947, as Exhibit 7(h)). 4-B-9 -- Supplemental Indenture, dated as of September 8, 1947, supplementing said Mortgage (filed with Form S-1, File No. 2-10401, effective August 21, 1953, as Exhibit 4-B-9). 4-B-10 -- Supplemental Indenture, dated as of February 1, 1949, supplementing said Mortgage (filed with Form S-1, File No. 2-7808, effective February 3, 1949, as Exhibit 7(j)). 4-B-11 -- Supplemental Indenture, dated as of March 1, 1949, supplementing said Mortgage (filed with Form S-1, File No. 2-8877, effective April 6, 1951, as Exhibit 7(k)). 4-B-14 -- Supplemental Indenture, dated as of October 1, 1954, supplementing said Mortgage (filed with Form S-9, File No. 2-11297, effective December 30, 1954, as Exhibit 2-B-14). 4-B-17 -- Supplemental Indenture, dated as of January 1, 1960, supplementing said Mortgage (filed with Form 10, effective June 29, 1961, as Exhibit 3-B-18). 4-B-18 -- Supplemental Indenture, dated as of February 1, 1960, supplementing said Mortgage (filed with Form 10, effective June 29, 1961, as Exhibit 3-B-19). 4-B-21 -- Supplemental Indenture, dated as of June 15, 1964, supplementing said Mortgage (filed with Form S-1, File No. 2-25367, effective August 3, 1966, as Exhibit 4-B-20). 4-B-23 -- Supplemental Indenture, dated as of April 1, 1967, supplementing said Mortgage (filed with Form S-9, File No. 2-28023, effective February 15, 1968, as Exhibit 2-B-25). 4-B-24 -- Supplemental Indenture, dated as of February 1, 1968, supplementing said Mortgage (filed with Form S-9, File No. 2-31304, effective January 21, 1969, as Exhibit 2-B-26). 4-B-48 -- Supplemental Indenture, dated as of September 1, 1983, supplementing said Mortgage (filed with Form S-3, File No. 2-95931, effective April 1, 1985, as Exhibit 4-B-48). 4-B-49 -- Supplemental Indenture, dated as of September 1, 1984, supplementing said Mortgage (filed with Form S-3, File No. 2-95931, effective April 1, 1985, as Exhibit 4-B-49). 4-B-56 -- Supplemental Indenture, dated as of February 15, 1987, supplementing said Mortgage (filed with Form 10-K for the year ended December 31, 1986, File No. 1-4928, as Exhibit 4-B-56). 4-B-58 -- Supplemental Indenture, dated as of October 1, 1987, supplementing said Mortgage (filed with Form 10-K for the year ended December 31, 1987, File No. 1-4928, as Exhibit 4-B-58). 4-B-60 -- Supplemental Indenture, dated as of March 1, 1990, supplementing said Mortgage (filed with Form 10-K for the year ended December 31, 1990, File No. 1-4928, as Exhibit 4-B-60). 4-B-62 -- Supplemental Indenture, dated as of May 15, 1990, supplementing said Mortgage (filed with Form 10-K for the year ended December 31, 1990, File No. 1-4928, as Exhibit 4-B-62). 4-B-63 -- Supplemental Indenture, dated as of March 1, 1991, supplementing said Mortgage (filed with Form 10-K for the year ended December 31, 1990, File No. 1-4928, as Exhibit 4-B-63). 4-B-64 -- Supplemental Indenture, dated as of July 1, 1991, supplementing said Mortgage (filed with Form S-3, File No. 33-45501, effective February 13, 1992, as Exhibit 4-B-64). 4-B-65 -- Supplemental Indenture, dated as of December 1, 1991, supplementing said Mortgage (filed with Form S-3, File No. 33-45501, effective February 13, 1992, as Exhibit 4-B-65). 4-B-66 -- Supplemental Indenture, dated as of March 1, 1992, supplementing said Mortgage (filed with Form 10-K for the year ended December 31, 1991, File No. 1-4928, as Exhibit 4-B-66). 4-B-67 -- Supplemental Indenture, dated as of June 1, 1992, supplementing said Mortgage (filed with Form S-3, File No. 33-50592, effective August 11, 1992, as Exhibit 4-B-67). 4-B-68 -- Supplemental Indenture, dated as of July 1, 1992, supplementing said Mortgage (filed with Form S-3, File No. 33-50592, effective August 11, 1992, as Exhibit 4-B-68). 4-B-69 -- Supplemental Indenture, dated as of September 1, 1992, supplementing said Mortgage (filed with Form S-3, File No. 33-53308, effective November 24, 1992, as Exhibit 4-B-69). 4-B-70 -- Supplemental Indenture, dated as of February 1, 1993, supplementing said Mortgage (filed with Form 10-K for the year ended December 31, 1992, File No. 1-4928, as Exhibit 4-B-70). 4-B-71 -- Supplemental Indenture, dated as of March 1, 1993, supplementing said Mortgage (filed with Form S-3, File No. 33-59448, effective March 17, 1993, as Exhibit 4-B-71). 4-B-72 -- Supplemental Indenture, dated as of April 1, 1993, supplementing said Mortgage (filed with Form S-3, File No. 33-50543, effective October 20, 1993, as Exhibit 4-B-72). 4-B-73 -- Supplemental Indenture, dated as of May 1, 1993, supplementing said Mortgage (filed with Form S-3, File No. 33-50543, effective October 20, 1993, as Exhibit 4-B-73). 4-B-74 -- Supplemental Indenture, dated as of June 1, 1993, supplementing said Mortgage (filed with Form S-3, File No. 33-50543, effective October 20, 1993, as Exhibit 4-B-74). 4-B-75 -- Supplemental Indenture, dated as of July 1, 1993, supplementing said Mortgage (filed with Form S-3, File No. 33-50543, effective October 20, 1993, as Exhibit 4-B-75). 4-B-76 -- Supplemental Indenture, dated as of August 1, 1993, supplementing said Mortgage (filed with Form S-3, File No. 33-50543, effective October 20, 1993, as Exhibit 4-B-76). 4-B-77 -- Supplemental Indenture, dated as of August 20, 1993, supplementing said Mortgage (filed with Form S-3, File No. 33-50543, effective October 20, 1993, as Exhibit 4-B-77). 4-B-78 -- Supplemental Indenture, dated as of May 1, 1994, supplementing said Mortgage (filed with Form 10-K for the year ended December 31, 1994, File No. 1-4928, as Exhibit 4-B-78). 4-B-79 -- Supplemental Indenture, dated as of November 1, 1994, supplementing said Mortgage (filed with Form 10-K for the year ended December 31, 1994, File No. 1-4928, as Exhibit 4-B-79). *4-B-80 -- Supplemental Indenture, dated as of August 1, 1995, supplementing said Mortgage. 4-C -- Instrument of Resignation, Appointment and Acceptance among Duke Power Company, Morgan Guaranty Trust Company of New York, as Trustee, and Chemical Bank, as Successor Trustee, dated as of August 30, 1994 (filed with Form 10-K for the year ended December 31, 1994, File No. 1-4928, as Exhibit 4-C). 10-A -- Agreement, dated March 6, 1978, between the registrant and the North Carolina Municipal Power Agency No. 1 (filed with Form 8-K for the month of March 1978, File No. 1-4928). 10-B -- Agreement, dated August 1, 1980, between the registrant and Piedmont Municipal Power Agency (filed with Form 8-K for the month of August 1980, File No. 1-4928). 10-C -- Agreement, dated October 14, 1980 between the registrant and North Carolina Electric Membership Corporation (filed with Form 10-Q for the quarter ended September 30, 1980, File No. 1-4928). 10-D -- Agreement, dated October 14, 1980 between the registrant and Saluda River Electric Cooperative, Inc. (filed with Form 10-Q for the quarter ended September 30, 1980, File No. 1-4928). 10-E+ -- Employees' Stock Ownership Plan. 10-F++ -- Employee Incentive Plan. 10-G++ -- 1993 Executive Long-Term Incentive Plan. 10-H+ -- Supplemental Security Plan. 10-I+ -- Stock Purchase-Savings Program for Employees. 10-J+ -- Employees' Retirement Plan. 10-K+ -- Supplemental Retirement Plan. 10-L+ -- Compensation Deferral Plan. 10-M+ -- Compensation Deferral Plan for Outside Directors. 10-N+ -- Retirement Plan for Outside Directors. 10-O+ -- Supplementary Defined Contribution Plan for Employees. 10-P+ -- Directors' Charitable Giving Program. 10-Q+ -- Vacation Banking Plan. 10-R+ -- Estate Conservation Plan. 10-S+ -- Supplemental Insurance Plan. 10-T+ -- Group Life Insurance Plan. 10-U+ -- Stock Ownership Plan for Nonemployee Directors. 10-V+ + + -- Executive Short-Term Incentive Plan. 10-W+ + + -- Executive Long-Term Incentive Plan. *12 -- Computation of Ratio of Earnings to Fixed Charges. *23 -- Consent of Independent Auditors. *24(a) -- Power of attorney authorizing Ellen T. Ruff and others to sign the annual report on behalf of the registrant and certain of its directors and officers. *24(b) -- Certified copy of resolution of the Board of Directors of the registrant authorizing power of attorney. *27 -- Financial Data Schedule. + Compensatory plan or arrangement filed with Form 10-K for the year ended December 31, 1992, File No. 1-4928, under the same exhibit number as listed herein. ++ Compensatory plan or arrangement filed with Form 10-K for the year ended December 31, 1993, File No. 1-4928, under the same exhibit number as listed herein. +++ Compensatory plan or arrangement filed with Form 10-K for the year ended December 31, 1994, File No. 1-4928, under the same exhibit number as listed herein.
EX-3 2 EXHIBIT 3-C EXHIBIT 3-C Amended Effective September 26, 1995 BY-LAWS OF DUKE POWER COMPANY ARTICLE I OFFICES SECTION 1. PRINCIPAL OFFICE. The principal office of the Company shall be located at 422 South Church Street, Charlotte, North Carolina 28242. SECTION 2. OTHER OFFICES. The Company may have offices at such other places, either within or without the State of North Carolina, as the Board of Directors may designate or as the affairs of the Company may require from time to time. ARTICLE II MEETINGS OF SHAREHOLDERS SECTION 1. PLACE OF MEETINGS. All meetings of shareholders shall be held at such place, either within or without the State of North Carolina, as shall be designated in the notice of the meeting. SECTION 2. ANNUAL MEETINGS. The annual meeting of shareholders for the election of directors and the transaction of other business shall be held on any day in each year as determined by the Board of Directors. SECTION 3. SPECIAL MEETINGS. Special meetings of the shareholders may be called at any time by the Board of Directors, the Chairman of the Board or the President. SECTION 4. NOTICE OF MEETINGS. Written notice stating the time and place of the meeting shall be delivered not less than ten nor more than sixty days before the date of any shareholders' meeting, either personally or by mail, by or at the direction of the Chairman of the Board, the President or the Secretary, to each shareholder of record entitled to vote at such meeting. In the case of a special meeting, the notice of meeting shall specifically state the purpose or purposes for which the meeting is called. SECTION 5. QUORUM. A majority of the shares of the Company entitled to vote, represented in person or by proxy, shall constitute a quorum at a meeting of shareholders. SECTION 6. VOTING OF SHARES. Each outstanding share entitled to vote shall be entitled to one vote on each matter submitted to a vote at a meeting of shareholders. Except in the election of directors, the vote of a majority of shares voted on any matter at a meeting of shareholders at which a quorum is present shall be the act of the shareholders on that matter, unless the vote of a greater number is required by law or by the Articles of Incorporation. ARTICLE III BOARD OF DIRECTORS SECTION 1. GENERAL POWERS. The business and affairs of the Company shall be managed by its Board of Directors. SECTION 2. NUMBER AND QUALIFICATIONS. The number of directors constituting the Board of Directors shall be not less than twelve nor more than twenty-four, as may be fixed from time to time by the Board of Directors. A director must be a shareholder of the Company. SECTION 3. ELECTION OF DIRECTORS; CLASSES. The directors, other than those who may be elected by the holders of any class of stock having a preference over the Common Stock as to dividends or upon liquidation to elect directors under specified circumstances, shall be classified, with respect to the time for which they severally hold office into three classes, as nearly equal in number as possible. Such classes shall originally consist of one class (Class I) of seven directors who shall be elected at the annual meeting of shareholders held in 1991 for a term expiring at the annual meeting of shareholders held in 1992; a second class (Class II) of six directors who shall be elected at the annual meeting of shareholders held in 1991 for a term expiring at the annual meeting of shareholders to be held in 1993; and a third class (Class III) of six directors who shall be elected at the annual meeting of shareholders held in 1991 for a term expiring at the annual meeting of shareholders to be held in 1994; with each class to hold office until its successor is elected and qualified. The Board of Directors shall increase or decrease the number of directors in one or more classes as may be appropriate whenever it increases or decreases the number of directors pursuant to the Articles of Incorporation and Section 2 of Article III of these By-Laws, in order to ensure that the three classes shall be as nearly equal in number as possible. At each annual meeting of shareholders, the successors of the class of directors whose term expires at that meeting shall be elected to hold office for a term expiring at the annual meeting of shareholders held in the third year following the year of their election. SECTION 4. REMOVAL. Subject to the rights of any class of stock having a preference over the Common Stock as to dividends or upon liquidation to elect directors under specified circumstances, a director may be removed from office only with cause. "Cause" for removal of a director under this Section means fraudulent or dishonest acts, or gross abuse of authority in the discharge of duties to the Company, and must be established after written notice of specific charges and an opportunity to meet and refute such charges. SECTION 5. NEWLY CREATED DIRECTORSHIPS; VACANCIES. Except as may be otherwise provided for or fixed by or pursuant to any provisions of the Articles of Incorporation, as amended from time to time, relating to the rights of the holders of any class of stock having a preference over the Common Stock as to dividends or upon liquidation to elect directors under specified circumstances, newly created directorships resulting from any increase in the number of directors and any vacancies on the Board of Directors resulting from death, resignation, disqualification, removal or other cause shall be filled only by the affirmative vote of a majority of the remaining directors then in office, even though less than a quorum of the Board of Directors. Any director elected in accordance with the preceding sentence shall hold office until the expiration of the full term of the class for which such director is elected and until such director's successor shall have been elected and qualified. No decrease in the number of directors constituting the Board of Directors shall shorten the term of any incumbent director. ARTICLE IV MEETINGS OF DIRECTORS SECTION 1. REGULAR MEETINGS. A regular meeting of the Board of Directors shall be held as soon as practicable following the annual meeting of shareholders. In addition, the Board of Directors may prescribe the time and place, either within or without the State of North Carolina, for the holding of other regular meetings of the Board of Directors. SECTION 2. SPECIAL MEETINGS. Special meetings of the Board of Directors may be called by or at the request of the Chairman of the Board or any three directors. Such a meeting may be held either within or without the State of North Carolina, as fixed by the person or persons calling the meeting. SECTION 3. NOTICE OF MEETINGS. Regular meetings of the Board of Directors may be held without notice. The person or persons calling a special meeting of the Board of Directors shall, at least two days before the meeting, give notice thereof by any usual means of communication. Such notice need not specify the purpose for which the meeting is called. SECTION 4. WAIVER OF NOTICE. Any director may waive notice of any meeting before or after the meeting. The attendance by a director at a meeting shall constitute a waiver of notice of such meeting, except where a director at the beginning of the meeting (or promptly upon his or her arrival) objects to holding the meeting or to transacting any business at the meeting and does not thereafter vote for or assent to action taken at the meeting. SECTION 5. QUORUM. A majority of the number of directors fixed pursuant to these By-Laws shall constitute a quorum for the transaction of business at any meeting of the Board of Directors. SECTION 6. MANNER OF ACTING. Except as otherwise provided in these By-Laws, the act of the majority of the directors present at a meeting at which a quorum is present shall be the act of the Board of Directors. SECTION 7. INFORMAL ACTION BY DIRECTORS. Action taken by a required majority of the directors without a meeting is nevertheless action of the Board of Directors if written consent to the action in question is signed by all the directors and filed with the minutes of the proceedings of the Board of Directors, whether done before or after the action so taken. Any one or more directors may participate in a meeting of the Board of Directors by means of a conference telephone or similar communications device, which allows all directors participating in the meeting to simultaneously hear each other, and such participation in a meeting shall be deemed presence in person at such meeting. ARTICLE V COMMITTEES OF THE BOARD SECTION 1. MANAGEMENT COMMITTEE. The Board of Directors shall annually elect from its members a Management Committee consisting of four or more persons who are officers of the Company and which shall include the Chairman of the Board who shall act as Chairman. The Management Committee may exercise all of the authority of the Board of Directors, except that the Management Committee shall not have authority to act on the (1) dissolution, merger or consolidation of the Company, or disposition of substantially all of its property, (2) designation of any committee or filling vacancies in the Board of Directors or in any such committee, (3) adoption, amendment or repeal of these By-Laws, (4) authorization of distributions, (5) adoption of amendments to the Articles of Incorporation without shareholder action, (6) authorization or approval of the reacquisition of shares, except according to a formula or method that is prescribed by the Board of Directors, (7) authorization or approval of the issuance or sale or contract for sale of shares, or determination of the designation and relative rights, preferences, and limitations of a class or series of shares, except within limits that are specifically prescribed by the Board of Directors, (8) approval or proposal to the shareholders of an action that is required by the North Carolina Business Corporation Act to be approved by shareholders, or (9) amendment or repeal of any resolution of the Board of Directors which by its terms is not so amendable or repealable. Any resolutions adopted or other action taken by the Management Committee within the scope of its authority shall be deemed for all purposes to be adopted or taken by the Board of Directors. The Management Committee shall fix its own rules of procedure and shall meet as provided by such rules or at the call of the Chairman or any two members thereof. The Management Committee shall elect a Secretary who need not be a member thereof and minutes of its proceedings shall be kept in minute books provided for that purpose. SECTION 2. NOMINATING COMMITTEE. The Board of Directors shall annually elect from its members a Nominating Committee consisting of the Chairman of the Board (who shall not vote on matters affecting the Chairman of the Board) and not less than two other members who are not officers of the Company, one of whom shall be designated as Chairman. The Nominating Committee, subject to any limitations prescribed by the Board of Directors, shall select and present to the Board of Directors the name(s) of a person or persons to be considered for nomination or appointment to membership on the Board of Directors. The Nominating Committee shall select and present to the Board of Directors the name(s) of a person or persons to be considered as successor to the Chief Executive Officer or the President and in the discretion of the Nominating Committee, the successors of the immediate associates of such officers. The Nominating Committee shall conduct periodic review of both management and non-management director performance and should a director's performance be judged unsatisfactory over a reasonable period of time, work with the Chairman of the Board and Chief Executive Officer to remedy the situation. The Nominating Committee will meet at the direction of the Board of Directors or at the call of its Chairman or any two members thereof. The Chairman shall designate a person who need not be a member thereof to act as Secretary. Minutes of its proceedings shall be kept in minute books provided for that purpose. SECTION 3. FINANCE COMMITTEE. The Board of Directors shall annually elect from its members a Finance Committee consisting of two or more persons. The Finance Committee, subject to any limitations prescribed by the Board of Directors, shall have supervision of all the financial and fiscal affairs of the Company and shall make recommendations to the Board of Directors with reference to dividend, financing and fiscal policies of the Company, and such other financial matters as may be assigned from time to time by the Board of Directors. The Finance Committee shall elect a Chairman from among its members and such person as the Chairman shall designate shall act as Secretary. Minutes of its proceedings shall be kept in minute books provided for that purpose. The Finance Committee shall hold such meetings as shall be necessary from time to time to carry out its assigned duties. Meetings may be called by the Chairman or by any member thereof and shall be held at such time and place as specified in the call for such meeting. SECTION 4. AUDIT COMMITTEE. The Board of Directors shall annually elect from such of its members who are not officers of the Company an Audit Committee consisting of two or more persons. The Audit Committee shall select and recommend to the Board of Directors for its approval outside auditors to conduct interim and annual audits of the Company's books and report thereon to the Audit Committee. Subject to any limitations prescribed by the Board of Directors, the Audit Committee shall: 1) Confer with the auditors, determine the scope of the auditing of the books and accounts of the Company, and receive and review the reports submitted by the auditors; 2) Meet with the appropriate officers of the Company to review and examine procedures and methods employed in connection with the Company's internal audit program and management policies relating thereto; and 3) Report its findings to the Board of Directors from time to time with such recommendations as it may deem appropriate. The Audit Committee shall elect a Chairman from among its members and a Secretary who need not be a member thereof. Minutes of its proceedings shall be kept in minute books provided for that purpose. The Audit Committee shall meet at such time or times as it may consider necessary to perform its assigned duties. Meetings of the Audit Committee may be called by the Chairman or by any two members thereof and shall be held at such time and place as specified in the call for such meeting. SECTION 5. COMPENSATION COMMITTEE. The Board of Directors shall annually elect from such of its members who are not officers of the Company a Compensation Committee consisting of two or more persons, one of whom shall be designated as Chairman. The Compensation Committee shall, upon recommendation of the Chairman of the Board, fix the salaries and other compensation, if any, of all employees of the Company, except the Chairman of the Board, Vice Chairman of the Board, President and any other officer the Board of Directors may designate, whose salaries are at a rate at or above a level determined from time to time by the Board of Directors. The Committee shall report at the next meeting of the Board of Directors any action it has taken pursuant to this authority. The Board of Directors shall, upon recommendation of the Compensation Committee, fix the salary of the Chairman of the Board, Vice Chairman of the Board and any President. The Committee shall also recommend to the Board of Directors the fees to be paid to members of the Board of Directors. The salaries of all other employees and agents of the Company shall be fixed in accordance with procedures adopted from time to time by the Management Committee. The Chairman of the Board shall periodically report to the Compensation Committee, in such manner and in such scope as the Committee shall direct, the salaries so fixed. The Compensation Committee shall meet on call of its Chairman. An officer of the Company designated by the Chairman shall act as Secretary and minutes of its proceedings shall be kept in minute books provided for that purpose. SECTION 6. CORPORATE PERFORMANCE REVIEW COMMITTEE. The Board of Directors shall annually elect from such of its members who are not officers of the Company a Corporate Performance Review Committee consisting of two or more persons, one of whom shall be designated as Chairman. The Corporate Performance Review Committee will monitor and make recommendations for improving the overall performance of the Company. At the policy level, the committee will determine the adequacy of and support the Company's emphasis on continuous improvement and will endeavor to increase the knowledge and understanding by the full Board of Directors of continuous improvement opportunities internally and external factors which influence company performance and operations. The Corporate Performance Review Committee shall meet on call of its Chairman. An officer of the Company designated by the Chairman shall act as Secretary, and minutes of its proceedings shall be kept in minute books provided for that purpose. SECTION 7. QUORUM AND MANNER OF ACTING OF COMMITTEES. A majority of the members of a committee of the Board of Directors shall be necessary to constitute a quorum and the affirmative vote of the majority of the members present at a meeting at which a quorum is present shall be necessary to constitute action by the committee. A committee may also act by the written consent of all members thereof although not convened in a meeting provided that such written consent is filed with the minute books of the committee. ARTICLE VI OFFICERS SECTION 1. OFFICERS OF THE COMPANY. The officers of the Company shall consist of a Chairman of the Board, a President, a Secretary, a Treasurer and such Vice Presidents, Assistant Secretaries, Assistant Treasurers, and other officers as the Board of Directors may from time to time elect. SECTION 2. ELECTION AND TERM. The officers of the Company shall be elected by the Board of Directors and each officer shall hold office until his death, resignation, retirement, removal, disqualification or his successor shall have been elected and qualified. SECTION 3. REMOVAL. Any officer or agent elected or appointed by the Board of Directors may be removed by the Board whenever in its judgment the best interests of the Company will be served thereby; but such removal shall be without prejudice to the contract rights, if any, of the person so removed. SECTION 4. CHAIRMAN OF THE BOARD. The Chairman of the Board shall be the chief executive officer of the Company and, subject to the control of the Board of Directors, shall supervise and manage all of the business and affairs of the Company. He shall, when present, preside at all meetings of the shareholders and of the Board of Directors; and in general he shall perform all duties incident to being the chief executive officer of the Company and such other duties as may be prescribed by the Board of Directors. SECTION 5. PRESIDENT. In the absence of the Chairman of the Board, or in the event of his death or inability to act, the President shall perform the duties of the Chairman of the Board, and when so acting shall have all the powers of and be subject to all the restrictions upon the Chairman of the Board. The President shall perform such other duties as may be assigned to him by the Chairman of the Board or by the Board of Directors. SECTION 6. VICE PRESIDENTS. In the absence of the President or in the event of his death or inability to act, the Vice President designated by the Chairman of the Board, unless otherwise determined by the Board of Directors, shall perform the duties of the President, and when so acting shall have all the powers of and be subject to all the restrictions upon the President. The Vice Presidents, one or more of whom may be designated as Executive Vice President or Senior Vice President, shall perform such duties as may be assigned to them by the Chairman of the Board or by the Board of Directors. SECTION 7. SECRETARY. The Secretary shall keep the minutes of the meetings of shareholders and of the Board of Directors in one or more minute books provided for that purpose; see that all notices are duly given in accordance with the provisions of these By-Laws or as required by law; be custodian of the corporate records and of the seal of the Company and in general perform all duties incident to the office of Secretary and such other duties as may be assigned to him by the Chairman of the Board or by the Board of Directors. SECTION 8. ASSISTANT SECRETARIES. In the absence of the Secretary or in the event of his death or inability to act, the Assistant Secretaries in the order of their length of service as such, unless otherwise determined by the Chairman of the Board or by the Board of Directors, shall perform the duties of the Secretary, and when so acting shall have all the powers and be subject to all the restrictions upon the Secretary. They shall perform such other duties as may be assigned to them by the Secretary or by the Chairman of the Board. SECTION 9. TREASURER. The Treasurer shall have charge and custody of and be responsible for all funds and securities of the Company; receive and give receipts for moneys due and payable to the Company from any source whatsoever, and deposit all such moneys in the name of the Company in authorized depositories of the Company and in general perform all of the duties incident to the office of Treasurer and such other duties as may be assigned to him by the Chairman of the Board or by the Board of Directors. SECTION 10. ASSISTANT TREASURERS. In the absence of the Treasurer or in the event of his death or inability to act, the Assistant Treasurers in the order of their length of service as such, unless otherwise determined by the Chairman of the Board or by the Board of Directors, shall perform the duties of the Treasurer, and when so acting shall have all the powers of and be subject to all the restrictions upon the Treasurer. They shall perform such other duties as may be assigned to them by the Treasurer or by the Chairman of the Board. ARTICLE VII CHECKS AND DEPOSITS SECTION 1. CHECKS AND DRAFTS. All checks, drafts or other orders for the payment of money, issued in the name of the Company, shall be signed by two officers of the Company or in such other manner as shall from time to time be determined by the Board of Directors. SECTION 2. DEPOSITS. All funds of the Company not otherwise employed shall be deposited to the credit of the Company as the Board of Directors may from time to time determine. ARTICLE VIII GENERAL PROVISIONS SECTION 1. WAIVER OF NOTICE. Whenever any notice is required to be given to any shareholder or director by law, by the Articles of Incorporation or by these By-Laws, a waiver thereof in writing signed by the person or persons entitled to such notice, whether before or after the time stated therein, shall be equivalent to the giving of such notice. SECTION 2. FIXING RECORD DATE. For the purpose of determining shareholders entitled to notice of or to vote at any meeting of shareholders or any adjournment thereof, or entitled to receive payment of any dividend, or in order to make a determination of shareholders for any other proper purpose, the Board of Directors may fix in advance a date as the record date for any such determination of shareholders, such record date in any case to be not more than seventy days and, in case of a meeting of shareholders, not less than ten days immediately preceding the date on which the particular action, requiring such determination of shareholders, is to be taken. SECTION 3. INDEMNIFICATION. Any person who is or was serving as a director, officer, employee or agent of the Company or who, at the request of the Company, is or was serving as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise or as a trustee or administrator under an employee benefit plan, shall be indemnified by the Company, to the fullest extent permitted by law, against a) litigation expenses, including costs, expenses and reasonable attorneys' fees incurred by him in connection with any threatened, pending or completed action, suit or proceedings, whether civil, criminal, administrative or investigative, whether formal or informal, and whether or not brought by or on behalf of the Company, arising out of his status as such or his activities in any of the foregoing capacities, b) liability, including payments made by him in satisfaction of any judgment, money decree, fine (including an excise tax assessed with respect to an employee benefit plan), penalty or settlement for which he may have become liable in any such action, suit or proceeding, and c) reasonable costs, expenses and attorneys' fees incurred by him in connection with the enforcement of the indemnification rights provided herein. Any person who is or was serving in any of the foregoing capacities for or on behalf of the Company shall be conclusively deemed to be doing or to have done so in reliance upon, and as consideration for, the indemnification rights provided herein. Any such litigation expenses shall be paid by the Company in advance of the final disposition of any action, suit or proceeding upon receipt of an unsecured written promise by or on behalf of any such person to repay such amount unless it shall ultimately be determined that such person is entitled to be indemnified by the Company against such expenses. The rights of indemnification provided herein (which shall be deemed to be a contract between any such person and the Company enforceable on the part of such person notwithstanding any subsequent amendment or repeal of this By-Law) shall inure to the benefit of the estates or legal representatives of any such person and shall not be exclusive of any other rights to which such person may be entitled apart from this By-Law, by contract, resolution or otherwise. SECTION 4. AMENDMENTS. Except as otherwise provided by law, these By-Laws may be amended or repealed and new By-Laws may be adopted by the affirmative vote of a majority of the directors then holding office at any regular or special meeting of the Board of Directors. * * * * EX-4 3 EXHIBIT 4-B-80 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- DUKE POWER COMPANY TO CHEMICAL BANK, TRUSTEE ------------------ EIGHTIETH SUPPLEMENTAL INDENTURE DATED AS OF AUGUST 1, 1995 ------------------ CREATING AN ISSUE OF FIRST AND REFUNDING MORTGAGE BONDS, 7 1/2% SERIES B DUE 2025 ------------------ SUPPLEMENTAL TO FIRST AND REFUNDING MORTGAGE DATED AS OF DECEMBER 1, 1927 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SUPPLEMENTAL INDENTURE, bearing date as of the first day of August, 1995, made and entered into by and between DUKE POWER COMPANY, a corporation duly organized and existing under the laws of the State of North Carolina, hereinafter called the "Company", party of the first part, and CHEMICAL BANK (successor to Morgan Guaranty Trust Company of New York as Trustee), a corporation duly organized and existing under the laws of the State of New York, having its principal place of business in the Borough of Manhattan, City and State of New York, hereinafter called the "Trustee", as Trustee, party of the second part. WHEREAS Duke Power Company, a New Jersey corporation, hereinafter called the "New Jersey Company", duly executed and delivered its First and Refunding Mortgage, dated as of December 1, 1927, to Guaranty Trust Company of New York, as Trustee, to secure its First and Refunding Mortgage Gold Bonds, to be issued from time to time in series as provided in said Mortgage, and has from time to time duly executed and delivered supplemental indentures, including supplemental indentures dated as of September 1, 1947 and February 1, 1949, to Guaranty Trust Company of New York (the corporate name of which has been changed to Morgan Guaranty Trust Company of New York), as Trustee, and a supplemental indenture dated as of February 1, 1960 to Morgan Guaranty Trust Company of New York, as Trustee, supplementing and modifying said Mortgage (said Mortgage, as so supplemented and modified, being hereinafter referred to as the "original indenture"); and WHEREAS bonds of a series known as the "First and Refunding Mortgage Bonds, 2.65% Series Due 1977" (herein called "bonds of the 2.65% Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, 2 7/8% Series Due 1979" (herein called "bonds of the 1979 Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, 5 3/8% Series Due 1997" (herein called "bonds of the 1997 Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, 6 3/8% Series Due 1998" (herein called "bonds of the 1998 Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, Annual Tender Pollution Control Series 1987 A" (herein called "bonds of the 1987 Pollution Control Series A"), bonds of a series known as the "First and Refunding Mortgage Bonds, Annual Tender Pollution Control Series 1987 B" (herein called "bonds of the 1987 Pollution Control Series B"), bonds of a series known as the "First and Refunding Mortgage Bonds, Annual Tender Pollution Control Series 1987 C" (herein called "bonds of the 1987 Pollution Control Series C"), bonds of a series known as the "First and Refunding Mortgage Bonds, Pollution Control Facilities Revenue Refunding Series Due 2014" (herein called "bonds of the 1990 Pollution 2 Control Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, 8 3/4% Series Due 2021" (herein called "bonds of the 2021 Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, City of Greensboro Series Due 2027" (herein called "bonds of the 2027 City of Greensboro Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, Medium-Term Notes Series" (herein called "bonds of the Medium-Term Notes Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, 8 3/8% Series B Due 2021" (herein called "bonds of the 2021 Series B"), bonds of a series known as the "First and Refunding Mortgage Bonds, 8% Series Due 2004" (herein called "bonds of the 2004 Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, 8 5/8% Series Due 2022" (herein called "bonds of the 2022 Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, 7% Series Due 2000" (herein called "bonds of the 2000 Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, 7% Series B Due 2000" (herein called "bonds of the 2000 Series B"), bonds of a series known as the "First and Refunding Mortgage Bonds, 7% Series Due 2005" (herein called "bonds of the 2005 Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, 6 5/8% Series B Due 2003" (herein called "bonds of the 2003 Series B"), bonds of a series known as the "First and Refunding Mortgage Bonds, 7 3/8% Series Due 2023" (herein called "bonds of the 2023 Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, 6 3/8% Series Due 2008" (herein called "bonds of the 2008 Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, 5 7/8% Series C Due 2003" (herein called "bonds of the 2003 Series C"), bonds of a series known as the "First and Refunding Mortgage Bonds, Pollution Control Facilities Revenue Refunding Series Due 2014" (herein called "bonds of the 1993 Pollution Control Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, 6 1/4% Series B 2004" (herein called "bonds of the 2004 Series B"), bonds of a series known as the "First and Refunding Mortgage Bonds, 5 7/8% Series Due 2001" (herein called "bonds of the 2001 Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, 7% Series Due 2033" (herein called "bonds of the 2033 Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, 6 7/8% Series B Due 2023" (herein called "bonds of the 2023 Series B"), bonds of a series known as the "First and Refunding Mortgage Bonds, 6 3/4% Series Due 2025" (herein called "bonds of the 2025 Series"), bonds of a series known as the "First and Refunding Mortgage Bonds, 7 7/8% Series Due 2024" (herein called "bonds of the 2024 Series") and bonds of a series known as the "First and Refunding Mortgage Bonds, 8% Series B Due 1999" (herein 3 called "bonds of the 1999 Series B") have heretofore been issued and (except for bonds of the 2.65% Series, bonds of the 1979 Series and bonds of the 1998 Series which have been retired in their entirety) are the only bonds now outstanding under the original indenture as heretofore supplemented; and WHEREAS the Company has duly executed and delivered a supplemental indenture, dated as of June 15, 1964, to Morgan Guaranty Trust Company of New York, as Trustee, for the purpose of evidencing the succession by merger of the Company to the New Jersey Company and the assumption by the Company of the covenants and conditions of the New Jersey Company in the original indenture and to enable the Company to have and exercise the powers and rights of the New Jersey Company under the original indenture in accordance with the terms thereof and whereby the Company assumed and agreed to pay duly and punctually the principal of and interest on the bonds issued under the original indenture in accordance with the provisions of said bonds and the coupons thereto appertaining and the original indenture, and agreed to perform and fulfill all the terms, covenants and conditions of the original indenture binding upon the New Jersey Company; and WHEREAS Morgan Guaranty Trust Company of New York resigned as Trustee under the original indenture as heretofore supplemented and Chemical Bank was appointed successor Trustee, said resignation and appointment having taken effect on August 30, 1994 pursuant to an Instrument of Resignation, Appointment and Acceptance dated as of August 30, 1994 among the Company, Morgan Guaranty Trust Company of New York, as Trustee, and Chemical Bank, as successor Trustee; and WHEREAS the Company desires to create under the original indenture, as heretofore supplemented and as to be supplemented by this supplemental indenture, a new series of bonds, to be known as its "First and Refunding Mortgage Bonds, 7 1/2% Series B Due 2025", and to determine the terms and provisions and the form of the bonds of such series; and WHEREAS for the purposes hereinabove recited, and pursuant to due corporate action, the Company has duly determined to execute and deliver to the Trustee a supplemental indenture in the form hereof supplementing the original indenture (the original indenture, as supplemented by the aforesaid supplemental indenture dated as of June 15, 1964, by supplemental indentures dated as of April 1, 1967, February 1, 1968, February 15, 1987, October 1, 1987, March 1, 1990, May 15, 1990, March 1, 1991, July 1, 1991, December 1, 1991, March 1, 1992, June 1, 1992, July 1, 1992, September 1, 1992, February 1, 1993, March 1, 1993, April 1, 1993, May 1, 4 1993, June 1, 1993, July 1, 1993, August 1, 1993, August 20, 1993, May 1, 1994, November 1, 1994 and as hereby supplemented, being sometimes hereinafter referred to as the "Indenture"); and WHEREAS all conditions and requirements necessary to make this supplemental indenture a valid, legal and binding instrument in accordance with its terms have been done and performed, and the execution and delivery hereof have been in all respects duly authorized: NOW, THEREFORE, THIS INDENTURE WITNESSETH: That in consideration of the premises and of the sum of one dollar duly paid by the Company to the Trustee at or before the execution and delivery of these presents, the receipt whereof is hereby acknowledged, the Company hereby covenants and agrees with the Trustee and its successors in the trust under the Indenture as follows: PART ONE. BONDS OF THE 7 1/2% SERIES B DUE 2025. SECTION 1. The Company hereby creates a new series of bonds to be issued under and secured by the Indenture and known as its First and Refunding Mortgage Bonds, 7 1/2% Series B Due 2025 (herein called "bonds of the 2025 Series B"), and the Company hereby establishes, determines and fixes the terms and provisions of the bonds of the 2025 Series B as hereinafter in this Part One set forth. Each bond of the 2025 Series B shall be dated the date of its authentication (except that if any such bond shall be authenticated on any interest payment date, it shall be dated the following day) and interest shall be payable on the principal represented thereby commencing February 1, 1996, from the February 1 or August 1, as the case may be, next preceding the date thereof to which interest has been paid, unless such date of authentication is prior to February 1, 1996, in which case interest shall be payable from August 1, 1995; provided, however, that interest shall be payable on each bond of the 2025 Series B authenticated after the record date (as defined in the next succeeding paragraph of this Section 1) with respect to any interest payment date and prior to such interest payment date, only from such interest payment date. Interest on any bond of the 2025 Series B shall be paid to the person who, according to the bond register of the Company, is the registered holder of such bond of the 2025 Series B at the close of business on the applicable record date, and such interest payments shall be made by check mailed to such registered holder at his last address shown on such bond register; 5 provided, however, that, if the Company shall default in the payment of the interest due on any interest payment date on any bond of the 2025 Series B, such defaulted interest shall be paid to the registered holder of such bond (or any bond or bonds of the 2025 Series B issued upon transfer, exchange or substitution thereof) on the date of subsequent payment of such defaulted interest or, at the election of the Company, to the person in whose name such bond (or any bond or bonds of the 2025 Series B issued upon transfer, exchange or substitution thereof) is registered on a subsequent record date established by notice given by mail by or on behalf of the Company to the holders of all bonds of the 2025 Series B not less than ten (10) days preceding such subsequent record date. The term "record date" as used in this Section 1 shall mean, with respect to any semi-annual interest payment date, the close of business on the January 15 or July 15, as the case may be, next preceding such interest payment date or, in the case of a payment of defaulted interest, the close of business on any subsequent record date established as provided above. SECTION 2. All bonds of the 2025 Series B shall mature as to principal on August 1, 2025, and shall bear interest at the rate of 7 1/2% per annum, payable semi-annually on the first day of February and August in each year. SECTION 3. The bonds of the 2025 Series B shall be fully registered bonds, without coupons, in denominations of one thousand dollars ($1,000) and any integral multiple of one thousand dollars ($1,000), all such bonds to be numbered, and shall be transferable and exchangeable as provided in the form of bond set forth in this supplemental indenture. The provisions of sec. 1.19 and any other provision in the Indenture in respect of coupon bonds or reservation of coupon bond numbers shall be inapplicable to the bonds of the 2025 Series B. SECTION 4. The bonds of the 2025 Series B are not subject to redemption (otherwise than through the operation of the Replacement Fund provided in Part Two of this supplemental indenture or through the application of moneys paid to the Trustee pursuant to the provisions of sec. 5.05 of the Indenture) prior to August 1, 2000. On and after August 1, 2000, the bonds of the 2025 Series B are subject to redemption (otherwise than through the operation of the Replacement Fund provided in Part Two of this supplemental indenture or through the application of moneys paid to the Trustee pursuant to the provisions of sec. 5.05 of the Indenture) prior to maturity, at the option of the Company, as a whole at any time or in part from time to time, in principal amounts equal to $1,000 or any multiple thereof, upon prior notice as hereinafter provided, at the redemption prices 6 specified in the third paragraph of the reverse side of the form of bond set forth in this supplemental indenture, together with interest accrued thereon to the date fixed for redemption thereof. The bonds of the 2025 Series B are also subject to redemption through the operation of the Replacement Fund provided in Part Two of this supplemental indenture or through the application of moneys paid to the Trustee pursuant to the provisions of sec. 5.05 of the Indenture, at any time or from time to time prior to maturity, upon prior notice as hereinafter provided, at the redemption prices specified in the fourth paragraph of the reverse side of the form of bond set forth in this supplemental indenture, together with interest accrued thereon to the date fixed for redemption thereof. All such redemption of bonds of the 2025 Series B shall be effected as provided in Article 3 of the Indenture except that, in case a part only of the bonds of the 2025 Series B is to be paid and redeemed, the particular bonds or part thereof shall be selected by the Trustee in such manner as the Trustee in its uncontrolled discretion shall determine to be fair and in any case where several bonds are registered in the same name, the Trustee may treat the aggregate principal amount so registered as if it were represented by one bond and except that when bonds are redeemed in part only the notice given to any particular holder need state only the principal amount of the bonds of that holder which are to be redeemed and except that notice to the holders of bonds to be redeemed shall be given by mailing to such holders a notice of such redemption, first class mail postage prepaid, not later than the thirtieth day, and not earlier than the sixtieth day, before the date fixed for redemption, at their last addresses as they shall appear upon the bond register of the Company. Any notice which is mailed in the manner herein provided shall be conclusively presumed to have been duly given, whether or not the holder receives such notice; and failure duly to give such notice by mail, or any defect in such notice, to the holder of any bond designated for redemption as a whole or in part shall not affect the validity of the proceedings for the redemption of any other bond. No publication of notice of such redemption shall be required. SECTION 5. The aggregate principal amount of the bonds of the 2025 Series B shall be unlimited. SECTION 6. The place or places of payment (as to principal and premium, if any, and interest), redemption, transfer, exchange and registration of the bonds of the 2025 Series B shall be the office or offices or the agency or agencies of the Company in the Borough of Manhattan, The City of New York, designated from time to time by the Board of Directors of the Company. 7 SECTION 7. The form of the bonds of the 2025 Series B and the certificate of the Trustee to be endorsed on the bonds, respectively, shall be substantially as follows: [FORM OF BOND OF THE 2025 SERIES B] [FACE SIDE OF BOND] DUKE POWER COMPANY FIRST AND REFUNDING MORTGAGE BOND, 7 1/2% Series B Due 2025 No. $ DUKE POWER COMPANY, a North Carolina corporation (hereinafter called the "Company"), for value received, hereby promises to pay to or registered assigns, the principal sum of Dollars on August 1, 2025, in any coin or currency of the United States of America which at the time of payment shall be legal tender for the payment of public and private debts, at the office or agency of the Company in the Borough of Manhattan, The City of New York, and to pay interest thereon at said office or agency from the interest payment date next preceding the date hereof to which interest on outstanding bonds of this series has been paid (unless the date hereof is prior to February 1, 1996, in which case from August 1, 1995, and unless the date hereof is a January date subsequent to January 15, or a July date subsequent to July 15, in which case from the next succeeding February 1 or August 1, as the case may be), at the rate of seven and one-half per cent per annum, in like coin or currency, semi-annually on February 1 and August 1 in each year until the principal hereof shall become due and payable. Such interest payments shall be made by check mailed to the person in whose name this bond is registered at the close of business on the 15th day of January or July preceding each semi-annual interest payment date, as the case may be (subject to certain exceptions provided in the Indenture hereinafter mentioned), at his last address as it shall appear upon the bond register of the Company. The provisions of this bond are continued on the reverse hereof and such continued provisions shall for all purposes have the same effect as though fully set forth in this place. This bond shall not become or be valid or obligatory for any purpose until the Trustee shall have signed the form of certificate endorsed hereon. 8 IN WITNESS WHEREOF, the Company has caused this instrument to be signed in its name by its President or one of its Vice Presidents, manually or by facsimile signature, and its corporate seal to be hereto affixed, or a facsimile thereof to be hereon engraved, lithographed or printed, and to be attested by the manual or facsimile signature of its Secretary or one of its Assistant Secretaries. Dated: DUKE POWER COMPANY By: .......................................... President Attest: .............................................. Secretary [FORM OF TRUSTEE'S CERTIFICATE FOR BOND OF THE 2025 SERIES B] This bond is one of the bonds, of the series designated therein, described in the within-mentioned Indenture. CHEMICAL BANK, Trustee By: .......................................... Authorized Officer 9 [REVERSE SIDE OF BOND] This bond is one of the bonds of a series, designated specially as First and Refunding Mortgage Bonds, 7 1/2% Series B Due 2025, of an authorized issue of bonds of the Company, without limit as to aggregate principal amount, designated generally as First and Refunding Mortgage Bonds, all issued and to be issued under and equally and ratably secured by an indenture dated as of December 1, 1927, duly executed by Duke Power Company, a New Jersey corporation (hereinafter called the "New Jersey Company"), to Guaranty Trust Company of New York (now Morgan Guaranty Trust Company of New York), as Trustee (Chemical Bank, successor Trustee), as supplemented and modified by indentures supplemental thereto, including supplemental indentures dated as of September 1, 1947, February 1, 1949, February 1, 1960, June 15, 1964 (under which the Company succeeded to and was substituted for the New Jersey Company), April 1, 1967, February 1, 1968, February 15, 1987, October 1, 1987, March 1, 1990, May 15, 1990, March 1, 1991, July 1, 1991, December 1, 1991, March 1, 1992, June 1, 1992, July 1, 1992, September 1, 1992, February 1, 1993, March 1, 1993, April 1, 1993, May 1, 1993, June 1, 1993, July 1, 1993, August 1, 1993, August 20, 1993, May 1, 1994, November 1, 1994 and August 1, 1995, the latter providing for said series (said indenture as so supplemented and modified being hereinafter referred to as the "Indenture"), to which Indenture reference is made for a description of the property mortgaged, the nature and extent of the security, the rights of the holders of the bonds in respect thereof, the terms and conditions upon which the bonds are secured and the restrictions subject to which additional bonds secured thereby may be issued. To the extent permitted by, and as provided in, the Indenture, modifications or alterations of the Indenture, or of any indenture supplemental thereto, and of the rights and obligations of the Company and of the holders of the bonds, may be made with the consent of the Company by the affirmative vote, or with the written consent, of the holders of not less than 66 2/3% in principal amount of the bonds then outstanding, and by the affirmative vote, or with the written consent, of the holders of not less than 66 2/3% in principal amount of the bonds of any series then outstanding and affected by such modification or alteration, in case one or more but less than all of the series of bonds then outstanding under the Indenture are so affected, evidenced, in each case, as provided in the Indenture; provided that any supplemental indenture may be modified in accordance with the provisions contained therein for its modification; and provided, further, that no such modification or alteration shall be made 10 which will affect the terms of payment of the principal of, or interest or premium on, this bond, or the right of any bondholder to institute suit for the enforcement of any such payment on or after the respective due dates expressed in this bond, or reduce the percentage required for the taking of any such action. Any such affirmative vote of, or written consent given by, any holder of this bond is binding upon all subsequent holders hereof as provided in the Indenture. In case an event of default as defined in the Indenture shall occur, the principal of all the bonds outstanding thereunder may become or be declared due and payable, at the time, in the manner and with the effect provided in the Indenture. The bonds of this series are not subject to redemption (otherwise than for the Replacement Fund hereinafter mentioned or upon application of certain moneys included in the trust estate) prior to August 1, 2000. On and after August 1, 2000, the bonds of this series are subject to redemption (otherwise than for the Replacement Fund hereinafter mentioned or upon application of certain moneys included in the trust estate) prior to maturity, at the option of the Company, as a whole at any time or in part from time to time, at the following redemption prices (expressed as percentages of their principal amounts), in each case together with accrued interest to the date fixed for redemption: If redeemed during the twelve-month period beginning August 1:
REDEMPTION YEAR PRICE - --------------------- ---------- 2000................. 103.355 % 2001................. 103.131 2002................. 102.907 2003................. 102.684 2004................. 102.460 2005................. 102.236 2006................. 102.013 2007................. 101.789 2008................. 101.566 2009................. 101.342 2010................. 101.118 2011................. 100.895 2012................. 100.671 2013................. 100.447 2014................. 100.224 2015................. 100.000 2016................. 100.000 2017................. 100.000 2018................. 100.000 2019................. 100.000 2020................. 100.000 2021................. 100.000 2022................. 100.000 2023................. 100.000 2024................. 100.000
11 The bonds of this series are also subject to redemption for the Replacement Fund for bonds of this series provided for in the supplemental indenture dated as of August 1, 1995, providing for this series, or upon application of certain moneys included in the trust estate, at any time or from time to time prior to maturity, at the following redemption prices (expressed as percentages of their principal amounts), in each case together with accrued interest to the date fixed for redemption: If redeemed during the twelve-month period beginning August 1:
REDEMPTION YEAR PRICE - --------------------- ---------- 1995................. 100.000 % 1996................. 100.000 1997................. 100.000 1998................. 100.000 1999................. 100.000 2000................. 100.000 2001................. 100.000 2002................. 100.000 2003................. 100.000 2004................. 100.000 2005................. 100.000 2006................. 100.000 2007................. 100.000 2008................. 100.000 2009................. 100.000 2010................. 100.000 2011................. 100.000 2012................. 100.000 2013................. 100.000 2014................. 100.000 2015................. 100.000 2016................. 100.000 2017................. 100.000 2018................. 100.000 2019................. 100.000 2020................. 100.000 2021................. 100.000 2022................. 100.000 2023................. 100.000 2024................. 100.000
Redemption is in every case to be effected at the office or agency of the Company in the Borough of Manhattan, The City of New York, upon at least thirty days' prior notice, given by mail as more fully provided in the Indenture. If this bond or any portion hereof ($1,000 or a multiple thereof) is called for redemption and payment is duly provided, this bond or such portion thereof shall cease to bear interest from and after the date fixed for such redemption. This bond is transferable, as provided in the Indenture, by the registered owner hereof in person or by duly authorized attorney, at the office or agency of the Company in the Borough of Manhattan, The City of New York, upon surrender and cancellation of this bond, and thereupon a new bond of the same series and of like aggregate principal amount will be 12 issued to the transferee in exchange herefor as provided in the Indenture; or the registered owner of this bond, at his option, may surrender the same for cancellation at said office or agency of the Company and receive in exchange herefor the same aggregate principal amount of bonds of the same series of authorized denominations; all subject to the terms of the Indenture but without payment of any charges other than a sum sufficient to reimburse the Company for any stamp taxes or other governmental charges incident thereto. This bond is a corporate obligation only and no recourse whatsoever, either directly or through the Company or any trustee, receiver, assignee or any other person, shall be had for the payment of the principal of or premium, if any, or interest on this bond, or for the enforcement of any claim based hereon, or otherwise in respect hereof or of the Indenture, against any promoter, subscriber to the capital stock, incorporator, or any past, present or future stockholder, officer or director of the Company as such, or of any successor or predecessor corporation, whether by virtue of any constitutional provision, statute or rule of law, or by the enforcement of any assessment, penalty, subscription or otherwise, any and all such liability of promoters, subscribers, incorporators, stockholders, officers and directors being waived and released by each successive holder hereof by the acceptance of this bond, and as a part of the consideration for the issue hereof, and being likewise waived and released by the terms of the Indenture. [END OF BOND FORM] PART TWO. REPLACEMENT FUND. SECTION 1. So long as any of the bonds of the 2025 Series B are outstanding, the Company will continue to maintain the Replacement Fund set forth in, and in accordance with the applicable terms and conditions now contained in, Part Two of the supplemental indenture dated as of February 1, 1949, and the covenants on the part of the Company contained in such Part Two shall continue and remain in full force and effect, whether or not bonds of the 1979 Series are outstanding and to the same extent as though the words "or any bonds of the 2025 Series B" were inserted after the word "Series" appearing in the second line of Section 1 and the second line of Section 4 of said Part Two of said supplemental indenture dated as of February 1, 1949. 13 SECTION 2. If at any time (a) bonds of the 2025 Series B are outstanding and (b) no bonds of the 1997 Series, of the 2021 Series, of the Medium-Term Notes Series, of the 2021 Series B, of the 2004 Series, of the 2022 Series, of the 2000 Series, of the 2000 Series B, of the 2005 Series, of the 2003 Series B, of the 2023 Series, of the 2008 Series, of the 2003 Series C, of the 2004 Series B, of the 2001 Series, of the 2033 Series, of the 2023 Series B, of the 2025 Series, of the 2024 Series or of the 1999 Series B are outstanding and (c) cash which shall have been deposited with the Trustee pursuant to such Replacement Fund shall not within five years from the date of deposit thereof have been paid out, or used or set aside by the Trustee for the payment, purchase or redemption of bonds, pursuant to such Replacement Fund, such cash shall, if in excess of fifty thousand dollars ($50,000), be applied to the redemption of bonds of the 2025 Series B in an aggregate principal amount sufficient to exhaust as nearly as possible the full amount of such cash. Anything in Section 5 of Part Two of the aforesaid supplemental indenture dated as of February 1, 1949, in Section 3 of Part Two of the supplemental indentures dated as of April 1, 1967, March 1, 1991, December 1, 1991, June 1, 1992, July 1, 1992, September 1, 1992, February 1, 1993, May 1, 1993, June 1, 1993, July 1, 1993, August 1, 1993, August 20, 1993, May 1, 1994 and November 1, 1994, in Section 3 of Part Three of the supplemental indenture dated as of March 1, 1990, in Section 4 of Part Three of the supplemental indenture dated as of March 1, 1992 and in Section 5 of Part Four of the supplemental indenture dated as of March 1, 1993 to the contrary notwithstanding, no cash shall be paid over to the Company thereunder if at the time any bonds of the 2025 Series B are then outstanding, and such cash shall in such event be applied as in this Part Two set forth. SECTION 3. Whenever all of the bonds of the 2025 Series B, the 1997 Series, the 2021 Series, the Medium-Term Notes Series, the 2021 Series B, the 2004 Series, the 2022 Series, the 2000 Series, the 2000 Series B, the 2005 Series, the 2003 Series B, the 2023 Series, the 2008 Series, the 2003 Series C, the 2004 Series B, the 2001 Series, the 2033 Series, the 2023 Series B, the 2025 Series, the 2024 Series and the 1999 Series B shall have been paid, purchased or redeemed, the Trustee shall, upon application of the Company, pay to or upon the order of the Company all cash theretofore deposited with the Trustee pursuant to the provisions of the Replacement Fund and not previously disposed of pursuant to the provisions of the Replacement Fund, and shall deliver to the Company any bonds which shall theretofore have been deposited with the Trustee pursuant to the provisions 14 of the Replacement Fund or paid, purchased or redeemed pursuant to the provisions of the Replacement Fund. PART THREE. ADDITIONAL COVENANTS OF THE COMPANY. SECTION 1. Whether or not the covenants on the part of the Company contained in Part Three of the supplemental indenture dated as of February 1, 1949 are modified with the consent of the holders of bonds of the 1997 Series, the 1987 Pollution Control Series A, the 1987 Pollution Control Series B, the 1987 Pollution Control Series C, the 1990 Pollution Control Series, the 2021 Series, the 2027 City of Greensboro Series, the Medium-Term Notes Series, the 2021 Series B, the 2004 Series, the 2022 Series, the 2000 Series, the 2000 Series B, the 2005 Series, the 2003 Series B, the 2023 Series, the 2008 Series, the 2003 Series C, the 1993 Pollution Control Series, the 2004 Series B, the 2001 Series, the 2033 Series, the 2023 Series B, the 2025 Series, the 2024 Series or the 1999 Series B and whether or not the bonds of the 1997 Series, the 1987 Pollution Control Series A, the 1987 Pollution Control Series B, the 1987 Pollution Control Series C, the 1990 Pollution Control Series, the 2021 Series, the 2027 City of Greensboro Series, the Medium-Term Notes Series, the 2021 Series B, the 2004 Series, the 2022 Series, the 2000 Series, the 2000 Series B, the 2005 Series, the 2003 Series B, the 2023 Series, the 2008 Series, the 2003 Series C, the 1993 Pollution Control Series, the 2004 Series B, the 2001 Series, the 2033 Series, the 2023 Series B, the 2025 Series, the 2024 Series or the 1999 Series B are outstanding, such covenants on the part of the Company contained in said Part Three shall continue and remain in full force and effect so long as any of the bonds of the 2025 Series B are outstanding and to the same extent as though the words "or so long as any bonds of the 2025 Series B are outstanding" were inserted after the words "so long as any of the bonds of the 1979 Series or any bonds of the 2.65% Series are outstanding" wherever such words appear in said Part Three of the supplemental indenture dated as of February 1, 1949. SECTION 2. Whether or not the second sentence of paragraph (a) of sec. 2.08 of the original indenture (making certain provisions for the definition of the term "net amount" applicable while bonds of the 2.65% Series were outstanding and which was originally set forth in Section 4 of Article One of the supplemental indenture dated as of September 1, 1947 and which is corrected and clarified by Section 2 of Part Four of the supplemental 15 indenture dated as of February 1, 1968) is modified with the consent of the holders of bonds of the 1997 Series, the 1987 Pollution Control Series A, the 1987 Pollution Control Series B, the 1987 Pollution Control Series C, the 1990 Pollution Control Series, the 2021 Series, the 2027 City of Greensboro Series, the Medium-Term Notes Series, the 2021 Series B, the 2004 Series, the 2022 Series, the 2000 Series, the 2000 Series B, the 2005 Series, the 2003 Series B, the 2023 Series, the 2008 Series, the 2003 Series C, the 1993 Pollution Control Series, the 2004 Series B, the 2001 Series, the 2033 Series, the 2023 Series B, the 2025 Series, the 2024 Series or the 1999 Series B and whether or not bonds of the 1997 Series, the 1987 Pollution Control Series A, the 1987 Pollution Control Series B, the 1987 Pollution Control Series C, the 1990 Pollution Control Series, the 2021 Series, the 2027 City of Greensboro Series, the Medium-Term Notes Series, the 2021 Series B, the 2004 Series, the 2022 Series, the 2000 Series, the 2000 Series B, the 2005 Series, the 2003 Series B, the 2023 Series, the 2008 Series, the 2003 Series C, the 1993 Pollution Control Series, the 2004 Series B, the 2001 Series, the 2033 Series, the 2023 Series B, the 2025 Series, the 2024 Series or the 1999 Series B are outstanding, said sentence shall continue and remain in full force and effect so long as any bonds of the 2025 Series B are outstanding, and with the same force and effect as though said sentence had stated that such provisions were to be applicable so long as any of the bonds of the 2025 Series B are outstanding. PART FOUR. MISCELLANEOUS. SECTION 1. (a) For the purposes of sec. 2.10 of the Indenture and for the purposes of any modification of the provisions of the Replacement Fund referred to in Part Two of this supplemental indenture, the covenants and provisions on the part of the Company which are set forth or incorporated in Part Two of this supplemental indenture shall be for the benefit only of the holders of the bonds of the 2025 Series B. Such covenants and provisions shall remain in force and be applicable only so long as any bonds of the 2025 Series B shall be outstanding, and, subject to the provisions of paragraph (2) of subdivision (c) of sec. 10.01 of the Indenture, any such covenants and provisions may be modified with the consent, in writing or by vote at a bondholders' meeting, of the holders of sixty-six and two-thirds per cent (66 2/3%) of the principal amount of the bonds of the 2025 Series B at the time outstanding and without the consent of the holders of any other bonds 16 then outstanding under the Indenture; provided that no such consent shall be effective to waive any past default under such covenants and provisions, and its consequences, unless the consent of the holders of at least a majority in principal amount of all bonds then outstanding under the Indenture is obtained. Such covenants shall be deemed to be additional covenants and none of them shall affect or derogate from, or relieve the Company from, its obligation to comply with any of the other covenants, conditions, requirements or provisions of the Indenture or any other supplemental indenture. (b) For the purposes of sec. 2.10 of the Indenture and for the purposes of any modification of the provisions of Part Three of this supplemental indenture, the covenants and provisions on the part of the Company which are set forth or incorporated in said Part Three shall be for the benefit only of the holders of the bonds of the 2025 Series B. Such covenants and provisions shall remain in force and be applicable only so long as any bonds of the 2025 Series B shall be outstanding, and, subject to the provisions of paragraph (2) of subdivision (c) of sec. 10.01 of the Indenture, any such covenants and provisions may be modified with the consent, in writing or by vote at a bondholders' meeting, of the holders of sixty-six and two-thirds per cent (66 2/3%) of the principal amount of the bonds of the 2025 Series B at the time outstanding and without the consent of the holders of any other bonds then outstanding under the Indenture; provided that no such consent shall be effective to waive any past default under such covenants and provisions, and its consequences, unless the consent of the holders of at least a majority in principal amount of all bonds then outstanding under the Indenture is obtained. Such covenants shall be deemed to be additional covenants and none of them shall affect or derogate from, or relieve the Company from, its obligation to comply with any of the other covenants, conditions, requirements or provisions of the Indenture or any other supplemental indenture. SECTION 2. All terms contained in this supplemental indenture shall, except as specifically provided herein or except as the context may otherwise require, have the meanings given to such terms in the Indenture. SECTION 3. In case any one or more of the provisions contained in this supplemental indenture should be invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provision contained in this supplemental indenture, and, to the extent, but only to the extent, that such provision is invalid, illegal or 17 unenforceable, this supplemental indenture shall be construed as if such provision had never been contained herein. SECTION 4. The Trustee hereby accepts the trusts herein declared and provided upon the terms and conditions in the Indenture set forth. SECTION 5. This supplemental indenture may be executed in several counterparts, each of which shall be an original, and all collectively but one instrument. 18 IN WITNESS WHEREOF, Duke Power Company, the party of the first part hereto, has caused this supplemental indenture to be signed in its name by one of its Vice Presidents and its corporate seal to be hereunto affixed, and the same to be attested by one of its Assistant Secretaries, and Chemical Bank, the party of the second part hereto, in token of its acceptance of the trust hereby created, has caused this supplemental indenture to be signed in its name by one of its Vice Presidents and its corporate seal to be hereunto affixed, and the same to be attested by one of its Assistant Secretaries, all as of the day and year first above written. DUKE POWER COMPANY By:...................................... RICHARD J. OSBORNE Senior Vice President ATTEST: .............................................. ROBERT T. LUCAS III Assistant Secretary Signed, sealed, executed, acknowledged and delivered by DUKE POWER COMPANY, in the presence of: .............................................. CHERYL ANN TERRELL .............................................. SUE C. HARRINGTON CHEMICAL BANK By:...................................... P. J. GILKESON Vice President ATTEST: .............................................. R. LORENZEN Senior Trust Officer Signed, sealed, executed, acknowledged and delivered by CHEMICAL BANK, in the presence of: .............................................. P. KELLY .............................................. B. SKIBA 19 STATE OF NEW YORK COUNTY OF NEW YORK SS.: Personally appeared before me P. KELLY and made oath that she saw P. J. GILKESON, a Vice President, and R. LORENZEN, a Senior Trust Officer, respectively, of CHEMICAL BANK, sign, attest and affix hereto the corporate seal of said Chemical Bank, and, as the act and deed of said corporation, deliver the within written and foregoing deed, and that she, with B. SKIBA, witnessed the execution thereof. .............................................. P. KELLY Sworn and subscribed before me this 17th day of August, 1995. .............................................. ANNABELLE DELUCA Notary Public, State of New York No. 01DE 5013759 Qualified in Kings County Certificate Filed in New York County Commission Expires July 15, 1997. STATE OF NEW YORK COUNTY OF NEW YORK SS.: I, ANNABELLE DELUCA, a Notary Public in and for the State and County aforesaid, certify that R. LORENZEN personally came before me this day and acknowledged that he is a Senior Trust Officer of CHEMICAL BANK, a New York corporation, and that, by authority duly given and as the act of the corporation, the foregoing instrument was signed in its name by one of its Vice Presidents, sealed with its corporate seal, and attested by himself as one of its Senior Trust Officers. Witness my hand and official seal, this 17th day of August, 1995. .............................................. ANNABELLE DELUCA Notary Public, State of New York No. 01DE 5013759 Qualified in Kings County Certificate Filed in New York County Commission Expires July 15, 1997. 20 STATE OF NORTH CAROLINA COUNTY OF MECKLENBURG SS.: Personally appeared before me CHERYL ANN TERRELL and made oath that she saw RICHARD J. OSBORNE, a Senior Vice President, and ROBERT T. LUCAS III, an Assistant Secretary, respectively, of DUKE POWER COMPANY, sign, attest and affix hereto the corporate seal of said Duke Power Company, and, as the act and deed of said corporation, deliver the within written and foregoing deed, and that she, with SUE C. HARRINGTON, witnessed the execution thereof. .............................................. CHERYL ANN TERRELL Sworn and subscribed before me this 18th day of August, 1995. .............................................. BRENDA M. ATCHLEY Notary Public Union County, N.C. My Commission expires December 1, 1999. STATE OF NORTH CAROLINA COUNTY OF MECKLENBURG SS.: I, SUE C. HARRINGTON, a Notary Public in and for the State and County aforesaid, certify that ROBERT T. LUCAS III personally came before me this day and acknowledged that he is an Assistant Secretary of DUKE POWER COMPANY, a North Carolina corporation, and that, by authority duly given and as the act of the corporation, the foregoing instrument was signed in its name by one of its Senior Vice Presidents, sealed with its corporate seal, and attested by himself as one of its Assistant Secretaries. My commission expires October 3, 1996. Witness my hand and official seal, this 18th day of August, 1995. .............................................. SUE C. HARRINGTON Notary Public Mecklenburg County, N.C. EX-12 4 EXHIBIT 12 EXHIBIT 12 COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES (DOLLARS IN THOUSANDS)
YEAR ENDED DECEMBER 31 1995 1994 1993 1992 1991 Earnings Before Income Tax. . . . . . . . . . . . . . . . . $1,180,979 $1,035,895 $1,036,392 $ 812,053 $ 876,641 Fixed Charges . . . . . . . . . . . . . . . . . . . . . . . 299,633 278,117 281,428 326,575 310,030 Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,480,612 $1,314,012 $1,317,820 $1,138,628 $1,186,671 Fixed Charges Interest on long-term debt. . . . . . . . . . . . . . . . . 253,058 237,063 243,047 257,149 269,419 Other interest. . . . . . . . . . . . . . . . . . . . . . . 21,143 16,814 17,704 47,239 23,947 Amortization of debt discount, premium and expense. . . . . 16,239 16,340 13,300 8,497 5,243 Interest component of rentals . . . . . . . . . . . . . . . 9,193 7,900 7,377 13,690 11,421 Fixed Charges . . . . . . . . . . . . . . . . . . . . . . . $ 299,633 $ 278,117 $ 281,428 $ 326,575 $ 310,030 Ratio of Earnings to Fixed Charges. . . . . . . . . . . . . 4.94 4.72 4.68 3.49 3.83
EX-23 5 EXHIBIT 23 EXHIBIT 23 CONSENT OF INDEPENDENT AUDITORS We consent to the incorporation by reference in Registration Statement Nos. 33-19274, 33-50543, 33-50715 and 33-50617 of Duke Power Company on Form S-3 and Registration Statement No. 2-72172 of Duke Power Company on Form S-8 of our report dated February 9, 1996, appearing in this Form 10-K of Duke Power Company filed with the Securities and Exchange Commission on March 12, 1996. DELOITTE & TOUCHE LLP Charlotte, North Carolina March 12, 1996 EX-24 6 EXHIBIT 24(A) EXHIBIT 24(a) DUKE POWER COMPANY POWER OF ATTORNEY FORM 10-K Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 1995 (Annual Report) The undersigned DUKE POWER COMPANY, a North Carolina corporation and certain of its officers and/or directors, do each hereby constitute and appoint W. H. Grigg, Richard J. Osborne, Ellen T. Ruff, Jeffrey L. Boyer, and each of them, to act as attorneys-in-fact for and in the respective names, places, and stead of the undersigned, to execute, seal, sign, and file with the Securities and Exchange Commission the Annual Report of said Duke Power Company on Form 10-K and any and all amendments thereto, hereby granting to said attorneys-in-fact, and each of them, full power and authority to do and perform all and every act and thing whatsoever requisite, necessary, or proper to be done in and about the premises, as fully to all intents and purposes as the undersigned, or any of them, might or could do if personally present, hereby ratifying and approving the acts of said attorneys-in-fact. Executed the 27th day of February, 1996. DUKE POWER COMPANY By W. H. Grigg Chairman and Chief Executive Officer (Corporate Seal) ATTEST: Robert T. Lucas III Assistant Secretary
W. H. Grigg Chairman and Chief Executive Officer W. H. Grigg (Principal Executive Officer and Director) Richard J. Osborne Senior Vice President and Chief Financial Richard J. Osborne Officer (Principal Financial Officer) Jeffrey L. Boyer Controller (Principal Accounting Officer) Jeffrey L. Boyer G. Alex Bernhardt (Director) G. Alex Bernhardt Crandall C. Bowles (Director) Crandall C. Bowles Robert J. Brown (Director) Robert J. Brown William A. Coley (Director) William A. Coley Steve C. Griffith, Jr. (Director) Steve C. Griffith, Jr. (Director) Paul H. Henson George Dean Johnson, Jr. (Director) George Dean Johnson, Jr. (Director) James V. Johnson W. W. Johnson (Director) W. W. Johnson Max Lennon (Director) Max Lennon James G. Martin (Director) James G. Martin Buck Mickel (Director) Buck Mickel Richard B. Priory (Director) Richard B. Priory Russell M. Robinson, II (Director) Russell M. Robinson, II
EX-24 7 EXHIBIT 24(B) EXHIBIT 24(b) CERTIFIED COPY OF A RESOLUTION FROM THE MINUTES OF A REGULAR MEETING OF THE BOARD OF DIRECTORS OF DUKE POWER COMPANY HELD ON FEBRUARY 27, 1996 Mr. Grigg then referred to the Company's Form 10-K Annual Report for the year ended December 31, 1995. He presented to the meeting a preliminary copy of the Form 10-K, indicating that it would be in order to approve such document subject to such changes as may be deemed necessary or advisable. Dr. Lennon then advised the Audit Committee had reviewed the Form 10-K and found it to be in order and recommended its approval. Upon motion duly made and seconded, it was RESOLVED, That the Form 10-K Annual Report, as presented to the meeting, with such changes therein as may be deemed necessary or advisable by the officers of the Company be and hereby is in all respects approved; and FURTHER RESOLVED, That the Power of Attorney as presented to the meeting and executed by all the Directors present be and hereby is approved in form and content for purposes of filing the Form 10-K Annual Report with the Securities and Exchange Commission. *********************** I, Ellen T. Ruff, Secretary of Duke Power Company, do hereby certify that the above is a full, true and complete extract from the Minutes of the regular meeting of the Board of Directors of Duke Power Company held on February 27, 1996, at which meeting a quorum was present; as taken from and compared with the original Minutes of said meeting. IN WITNESS WHEREOF, I have hereunto set my hand and affixed the Corporate Seal of said Duke Power Company this 28th day of February, 1996. Ellen T. Ruff Secretary [SEAL] EX-27 8 EXHIBIT 27
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED STATEMENTS OF INCOME, CONSOLIDATED STATEMENTS OF CASH FLOWS, CONSOLIDATED BALANCE SHEETS AND CONSOLIDATED STATEMENTS OF RETAINED EARNINGS FOR THE 12 MONTHS ENDED 12/31/95 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000030371 DUKE POWER COMPANY 1000 YEAR DEC-31-1995 JAN-01-1995 DEC-31-1995 PER-BOOK 9360533 956647 1176154 1865150 0 13358484 1926909 0 2858275 4785184 234000 450000 3711405 155300 0 0 12071 0 6278 1198 4010524 13358484 4676684 466441 3327633 3794074 1349051 121246 1003856 289318 714538 48903 665635 409716 242699 1311658 3.25 0
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