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. During 1994, the Company reorganized, placing all its subsidiaries and diversified activities except for the core electric utility business into 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" on page 9, "Management's Discussion and Analysis of Results of Operations and Financial Condition, Current Issues -- Subsidiaries and Diversified Activities" on page 22 and "Subsidiaries and Diversified Activities Highlights" on page 46. During 1994, the Company's operating revenues, including AEG, were $4.5 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 4.9 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 1.7 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, in 1994 approximately 8% of total sales were 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, manufacture of machinery and equipment, and chemical and chemical related industries are of major significance to the economy of the area. Other industrial activity includes the 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 $498 million of the Company's revenues for 1994, representing 12 percent of electric revenues and 40 percent of industrial revenues. ENERGY REQUIREMENTS AND CAPABILITY The following table sets forth the Company's generating capability at December 31, 1994, its sources of electric energy for 1994, and certain information presently projected for 1995:
(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. (See "Energy Management and Future Power Needs.") (c) Excludes NP&L. (d) Includes the 38,000 KW fossil unit returned to service from the Plant Modernization Program on January 1, 1995. (e) Nuclear capability and related generation for 1994 and projected for 1995 give no effect to the joint ownership of the Catawba Nuclear Station. (See "Joint Ownership of Generating Facilities.") (f) Includes 12 units of the Lincoln Combustion Turbine Station with generating capacity of 888,000 KW scheduled to begin commercial operation in 1995. Four additional units with generating capacity of 296,000 KW are scheduled to begin commercial operation in 1996. (See "Capital Requirements.") NP&L operates 11 hydroelectric stations with a total capacity of 100,000 kilowatts, and also buys 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 1993 industry statistics published in 1994, 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, fifth, eighth and tenth most efficient in the nation in 1993. The Company's nuclear system continued its tradition of operating efficiency, operating at 82 percent of capacity for 1994, in comparison with the industry's most current average capacity factor of 71 percent for 1993. The Company normally experiences seasonal peak loads in summer and winter which are relatively in balance. The Company currently forecasts a 2.1 percent compound annual growth in peak load through 2009. An all-time peak load of 16,070,000 KW occurred on January 19, 1994 during extremely cold winter weather. RATE MATTERS The North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (PSCSC) must approve the Company's rates for retail sales within their respective states. FERC must approve the Company's rates for sales to wholesale customers, including the contractual arrangements between the Company and the Other Catawba Joint Owners. Rate requests filed by the Company in its most recent general rate case in 1991 with the NCUC, PSCSC and FERC were principally designed to reflect the Company's investment in the Bad Creek Hydroelectric Station. Rate orders issued by the NCUC and PSCSC in November 1991 recognized costs of the Bad Creek Hydroelectric Station, including an amortization of costs deferred between commercial operation and the rate order, which the Company had requested. The Company's wholesale customers challenged its proposed rate increase and in 1991 FERC issued an order that accepted the Company's proposed rates for filing. A negotiated settlement with these customers, which provided for an increase in wholesale rates consistent with the increase in retail rates, was approved by FERC and became effective in April 1992. (See Note 2, "Notes to Consolidated Financial Statements.") 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. In 1992, the North Carolina Supreme Court remanded to the NCUC the Company's 1986 rate order for the second time. In this ruling, the Court held that the record from the 1986 proceedings failed to support the rate of return on common equity authorized by the NCUC after the initial decision of the Court remanding the 1986 rate order. The NCUC issued a final order in 1992 which resulted in a 1992 refund to North Carolina retail customers of approximately $95 million, including interest. 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 NCUC ordered Duke Power to follow these procedures in its August 1986 order, which was effective for periods beginning January 1, 1986. The prospective adjustment in rates of past over- or under-recovery of fuel costs was challenged in the North Carolina courts. The North Carolina legislature ratified a bill in July 1987 assuring the legality of such adjustments in rates. In 1991, the statute was extended through June 30, 1997. 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 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 17 to 23 percent of its anticipated peak load requirements through 1999. 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. The annual costs deferred, including the return, were approximately $25 million in 1994 and $26 million in 1993. The Company continues to engage in a comprehensive energy management program as part of its Integrated Resource Plan. Integrated Resource Planning is the process used by utilities to evaluate a variety of resources. The goal is to provide adequate and reliable electricity in an environmentally responsible manner through cost-effective power management. In January 1993, the PSCSC issued an order approving the Company's 1992 Integrated Resource Plan as reasonable, and approving a "shared savings" proposal for accomplishments made in the Company's demand-side management programs. In June 1993, the NCUC approved the 1992 plan, including the shared savings mechanism. The Integrated Resource Plan is filed every three years. Each of the other years, the Company files a Short Term Action Plan which updates the Integrated Resource Plan for any changes in projections for the next three years. The purchase of capacity and energy is also an integral part of meeting future power needs. As of January 1, 1995, the Company has under contract 300 megawatts of capacity from other generators of electricity, including 62 megawatts from qualifying facilities. The Company expects to use a competitive bidding process to provide for the next increment of generating capacity beyond the Lincoln Combustion Turbine Station.
CAPITAL REQUIREMENTS Projected capital expenditures, excluding costs related to portions of the Catawba Nuclear Station owned by the Other Catawba Joint Owners, for each of 1995, 1996, 1997, 1998 and 1999 and for the five-year period 1995-1999, as now scheduled, are as follows (in millions of dollars):
The Company's procedures for estimating capital expenditures (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, which includes the expansion of the business activities of AEG. 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. The Company is building a combustion turbine facility in Lincoln County, North Carolina to provide capacity at periods of peak demand. The Lincoln Combustion Turbine Station will consist of 16 combustion turbines with a total generating capacity of 1,184 megawatts. The estimated total cost of the project is approximately $500 million. Current plans are for 12 units to begin commercial operation by the end of 1995 and the remaining four to begin commercial operation in 1996. During 1991, the NCUC granted the Certificate of Public Convenience and Necessity and the North Carolina Division of Environmental Management issued a final air permit for the facility. The issuance of the final air permit for the facility was appealed, and one of the two appeals was settled and dismissed in March 1995. The other appeal has not been pursued by the appellant and is expected to be dismissed during the second quarter of 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 Other Catawba Joint Owners and the Company were involved 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.") The Company and the Other Catawba Joint Owners entered into settlement agreements in 1994 which resolved all issues in contention in the proceedings. The Company has settled its cumulative net obligation through 1993 of approximately $205 million with the Other Catawba Joint Owners. Billings for 1994 and later years will conform to the settlement agreements,
which have been approved by the Company's retail regulatory commissions. Because it expects the costs associated with these settlements to be recovered as part of the purchased capacity levelization, the Company has included approximately $205 million as an increase to Purchased capacity costs on its Consolidated Balance Sheets. 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. Information regarding the utilization of sources of power and cost of fuels is set forth in the following table:
(1) Generating figures are net of that output required to replenish pumped storage units during off-peak periods. Does 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 1995 to 2003. The Company believes that it will be able to renew such contracts as they expire or to enter into similar contractual arrangements with other coal suppliers for quantities and qualities of coal required. However, due to the Clean Air Act Amendments of 1990, fuel premiums may be required as contracts are renewed. The coal covered by the Company's long-term supply contracts is produced from mines located in eastern Kentucky, southern West Virginia and southwestern Virginia. The Company's short-term requirements have been and will be fulfilled with spot market purchases. The average sulfur content of coal being purchased by the Company is approximately 1 percent. Such coal satisfies the current emission limitation for sulfur dioxide for existing facilities. (See "Management's Discussion and Analysis of Results of Operations and Financial Condition, Current Issues -- The Clean Air Act Amendments of 1990.") NUCLEAR. Generally, the supply of fuel for nuclear generating units involves the mining and milling of uranium ore to produce uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, enrichment of that gas and fabrication of the enriched uranium hexafluoride into usable fuel assemblies. After a region (approximately one-third of the nuclear fuel assemblies in the reactor at any time) of spent fuel is removed 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 material requirements will be met through various supplier contracts, with uranium material produced primarily in the U.S., Canada and Australia. The Company believes that it will be able to renew contracts as they expire or to enter into similar contractual arrangements with other nuclear fuel materials and services suppliers. Short-term requirements have been and will be fulfilled with uranium spot market purchases.
The Nuclear Waste Policy Act of 1982 requires that the Department of Energy (DOE) begin disposing of spent fuel no later than January 31, 1998. The Company has entered into the required contracts with the DOE for the disposal of nuclear fuel and began making payments in July 1983 for disposal costs of fuel currently being utilized. These payments, combined with a one-time payment for disposal costs of fuel consumed prior to April 7, 1983, have totaled about $563 million through 1994. In November 1989, the DOE released a report which indicated that it expects that a facility for spent fuel disposal will not be available until the year 2010. The DOE 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 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 1994, the Company's construction costs for environmental protection totaled approximately $22 million, while the on-going environmental operation costs were approximately $25 million. The Company's 1995-1999 construction program includes costs for environmental protection which are estimated to be approximately $50 million, including $18.1 million in 1995, $8.5 million in 1996, $6.6 million in 1997, $8.6 million in 1998 and $8.5 million in 1999. 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 (otherwise known as the "Clean Water Act") require permits for facilities that discharge into waters, to ensure compliance with its provisions. The Company holds numerous such permits and such permits are reissued periodically. The Clean Water Act was scheduled for reauthorization by Congress in 1994. Congress did not act to reauthorize the Clean Water Act in 1994, but it is likely that action will be taken on such reauthorization in 1995. 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). The Company is currently participating in PRP groups with regard to Superfund sites in Concord, North Carolina, and two sites in Pennsylvania. The Company is a PRP at a contamination site in Charlotte, North Carolina which is being remediated in accordance with a state act similar to CERCLA.
The Company is also a PRP at a site in Lenoir, North Carolina which will likely be remediated in accordance with federal or state law. In addition, the Company has agreed to remediate a small volume of PCB-contaminated soil at a site in Chester, South 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. Other contamination sites arise from the Company's operation of manufactured gas plant (MGP) sites until the early 1950's, some of which are still owned by the Company and some of which 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. The State of South Carolina has expressed interest in entering into a similar arrangement. 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 was scheduled for reauthorization by Congress in 1994. An administration bill to reform CERCLA was acted upon by several Senate and House committees, but was never voted upon by either body. While CERCLA reform is likely to be acted upon by Congress in 1995, until such action 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. 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. 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 Catawba Joint Owners, began a legal action on March 22, 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. On March 17, 1994, the Company together with the Other Catawba Joint Owners, settled the lawsuit. 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 Catawba Joint Owners are responsible for decommissioning costs related to their ownership interest 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 1994, the Company expensed approximately $52.5 million which was contributed to the external funds and accrued an additional $4.8 million to the internal reserve. The balance of the external funds as of December 31, 1994, was $172.4 million. The balance of the internal reserve as of December 31, 1994, was $204.8 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 $18 million during 1994 and $26.3 million cumulatively related to its ownership interest in nuclear plants. The Company has reflected the remaining liability and regulatory asset of approximately $102 million in the Consolidated Balance Sheets at December 31, 1994. 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 804,940 KW, are licensed for a term expiring in 2008. The Company also holds a license for the Keowee-Toxaway Project for a term expiring in 2016, covering the Keowee Hydro Station and the Jocassee Pumped Storage Station for a combined total of 769,500 KW, on the upper tributaries of the Savannah River in northwestern South Carolina. Additionally, the Company is the licensee through 2027 for the Bad Creek Hydroelectric Station which uses Lake Jocassee as its lower reservoir and has a nameplate rating of 1,065,000 KW. NP&L holds licenses for 11 hydroelectric projects with a nameplate rating of 100,000 KW 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 moving utilities toward a more competitive environment. The EPACT reformed certain provisions of the Public Utility Holding Company Act of 1935 (PUHCA) and Part II of the Federal Power Act to remove certain regulatory barriers. For example, the 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. The EPACT requires transmission of power for third parties to wholesale customers on issuance of an order by the FERC, provided the reliability of service to the utility's local customer base is protected and the local customer base does not subsidize the third-party service. The EPACT does not permit the FERC to issue an order requiring transmission access to retail customers. The electric utility industry currently 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 could also require some utilities to write off their regulatory assets. Management cannot predict the potential impact, if any, of these competitive forces on the Company's future financial position and results of operations. However, the Company continues to position itself to effectively meet these challenges by maintaining prices that are regionally and nationally competitive. The Company filed an open access transmission tariff with the FERC in early 1995 (See "Subsequent Events"). SUBSIDIARIES AND DIVERSIFIED ACTIVITIES The Company continues to 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 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. (See "Subsidiaries and Diversified Activities Highlights" on page 46.) 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, 1994, Crescent owned approximately 2,223,000 square feet of office, retail and warehouse space and had approximately 818,000 square feet of commercial properties under construction. Additionally, Crescent had approximately 266,000 acres of land under its management at year end. DUKE ENERGY GROUP, INC. (Duke Energy) develops, owns and operates electric power-related facilities in the United States and abroad. 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. In 1994, Duke Energy announced plans to participate in power marketing activities in North America with Louis Dreyfus Electric Power (LDEP), following regulatory approvals. LDEP is currently the largest power marketer in the United States. (See "Subsequent Events.") NANTAHALA POWER AND LIGHT COMPANY (NP&L) is a franchised electric utility which operates 11 hydroelectric plants with a total capacity of 100,000 kilowatts. NP&L has approximately 53,000 customers in western North Carolina. NP&L sold 907 million KWH in 1994 compared to 889 million KWH in 1993, excluding sales to Duke Power. OTHER BUSINESS UNITS include Church Street Capital Corp., which is engaged in investment management 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/Flour 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 merchandise and electronics; DukeNet Communications, Inc. (DukeNet), which was formed in 1994 to develop and manage communications systems (See "Subsequent Events"); and Duke Water Operations, which provides franchised water services for Anderson, South Carolina and Rutherfordton, North Carolina. EMPLOYEES At December 31, 1994, the Company had 17,052 full-time employees, which included 1,011 full-time employees of subsidiaries and diversified activities. About 2,000 electrical operating employees are represented by the International Brotherhood of Electrical Workers (IBEW). During the last quarter of 1994, the Company reached new labor agreements with the IBEW for one year terms. The Company has been engaged in a concentrated effort to more efficiently and effectively utilize its resources through better work practices. During 1994, the Company offered a voluntary separation program which gave most employees the option of leaving the Company for a lump-sum payment and severance pay based on years of service. This voluntary separation program resulted in the departure of approximately 1,300 employees in 1994. Implementing programs such as the voluntary separation program and other efficiency practices has resulted in continued work-force reduction and in streamlined work flows. The number of full-time employees has decreased to the present level from 19,945 at year-end 1990.
SUBSEQUENT EVENTS DukeNet entered into an agreement on December 8, 1994, as part of a consortium which includes BellSouth Personal Communications, Inc. and other companies, to bid for a personal communication services (PCS) license auctioned by the Federal Communications Commission (FCC). On March 13, 1995 the consortium won the bid and has agreed to pay for the license and, in compliance with FCC requirements, construct a substantial portion of the communication system. DukeNet has a 19.98% equity commitment to the consortium. Projected DukeNet capital commitments through 1999 are included in the Company's projected capital expenditures (See "Capital Requirements" on page 4). On March 17, 1995, the Company filed for permission to sell wholesale electricity at market-driven prices with FERC. To date, the Company has sold wholesale power based on its bundled transmission, generation and distribution costs with an allowed return. The Company believes that this filing will strategically position the Company to become involved in the developing wholesale power market. The filing also included an open-access wholesale transmission tariff. This tariff sets the rates, terms and conditions under which the Company will transmit or wheel electricity from a third party through its system to a wholesale customer. Open access will provide the Company with increased opportunities to sell and deliver energy and capacity at market-based prices, thereby improving the utilization of existing assets. In addition, such access will provide an opportunity to buy energy and capacity at attractive rates, serving to further enhance the Company's competitive price position. In addition, Duke Energy Marketing Corp. (DEMC), an affiliate of Duke Energy, filed a request for power marketer status with FERC. Louis Dreyfus Electric Power and DEMC, in a joint venture, also filed an application with FERC for power marketer status. A power marketer buys blocks of electricity for immediate or eventual resale. Conditional approval is expected from FERC within six to eight months after filing. Final FERC approval for the filings is not expected for at least one year. Recent liquidity problems in Argentina have caused a significant increase in Argentine interest rates and a severe limitation on local funds. Until such liquidity problems are resolved, Duke Energy is arranging financing alternatives which include additional equity infusions in its Argentine projects. Such infusions would not be material to the Company.
(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
(a) Includes 100% of Catawba generation.
(b) 1991 includes KWH of the Bad Creek Hydroelectric Station prior to commercial operation. (c) Kilowatt-hour sales, electric revenues, and Net interchange and purchased power for the year 1990 include a reclassification for certain power transactions previously classified as Net interchange and purchased power prior to a 1990 FERC order. (d) Does not 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, 62, 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., 61, 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, 48, 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, 51, 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, 43, 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, 38, 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.
ITEM 2. PROPERTIES. At December 31, 1994, 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, 1994:
(a) The Catawba Nuclear Station is a jointly-owned facility, of which the Company's ownership share is 12 1/2 percent. The Company is currently constructing the Lincoln Combustion Turbine Station, a 16-turbine facility designed to provide capacity at periods of peak demand. The station will have a total generating capacity of 1,184 megawatts. 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, 1994, approximately 8,300 conductor miles of transmission lines and approximately 72,500 conductor miles of distribution lines. As of such date, the Company's transmission and distribution systems comprised approximately 1,700 substations with an installed transformer capacity of approximately 83,100,000 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 on page 11 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" and "Capital Requirements". ITEM 3.
ITEM 3. LEGAL PROCEEDINGS. Reference is made to "Business -- Regulation", "Management Discussion and Analysis of Results of Operations and Financial Condition, Current Issues -- Commitment and Contingencies" and "Note 13, Notes to Consolidated Financial Statements, Commitments and Contingencies -- Other". ITEM 4.
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 1994.
PART II. ITEM 5.
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, 1994, there were approximately 129,637 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:
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
(a) Operating revenues and operating expenses for the year 1990 include a reclassification for certain power transactions previously classified as Net interchange and purchased power prior to 1990 FERC order. (b) All common stock data reflects the two-for-one split of common stock on September 28, 1990.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION RESULTS OF OPERATIONS EARNINGS AND DIVIDENDS. Earnings per share increased 3 percent from $2.80 in 1993 to $2.88 in 1994. The increase was primarily due to increased earnings of subsidiaries and diversified activities, increased allowance for funds used during construction and other deferred returns, and pre-funding of charitable contributions to the Duke Power Foundation in 1993. These items were offset by higher operating and maintenance expenses including recognition of certain non-recurring costs. Excluding $.32 for the effect of a one-time refund to North Carolina retail customers in 1992, earnings per share increased from $2.53 in 1992 to $2.88 in 1994, indicating an average annual growth rate of 7 percent. Total Company earned return on average common equity was 13.3 percent in 1994 compared with 13.6 percent in 1993 and 12.8 percent in 1992, excluding the effects of the 1992 refund. 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 $1.76 in 1992 to $1.92 in 1994. Indicated annual dividends per share increased to $1.96. REVENUES AND SALES. Operating revenues increased at an average annual rate of 4 percent from 1992 to 1994, primarily because of increased overall kilowatt-hour sales to all retail customer classes. Revenues from subsidiaries and diversified activities contributed $49 million to the increase in Operating revenues over the three-year period, primarily from increased developed lot sales, land sales and equity earnings from investments in domestic and international joint ventures. The Company does not expect the trend of annually increasing electric revenues to continue for 1995 and 1996 if normal weather conditions occur. Total electric revenues in 1995 and 1996 are expected to remain approximately the same as 1994 and increase thereafter. Revenues from retail customers are expected to increase because of continued growth in the service area. However, wholesale revenues are expected to decline as the other joint owners of the Catawba Nuclear Station retain a significantly larger portion of their ownership entitlement in 1995 and 1996, thereby reducing supplemental requirements supplied by the Company. The effect on earnings of such wholesale revenue decline will be partially offset by a decline 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 decreased 1 percent in 1994 compared with 1993. Sales to general service, textile and other-industrial customers increased by 2 percent, 3 percent and 5 percent, respectively, as a result of continued economic growth in Duke Power's service area. A new record peak demand of 16,070 megawatts was set in January 1994 for Duke Power's electric operations during a period of extremely cold temperatures. However, weather for most of the year was milder than normal and milder than 1993. As a result, sales to residential customers decreased by 3 percent. Kilowatt-hour sales to the other joint owners of the Catawba Nuclear Station decreased 18 percent primarily because of improved output of the Catawba and McGuire Nuclear Stations from which they receive their energy entitlements. OPERATING EXPENSES. From 1993 to 1994, Other operation and maintenance expenses rose 7 percent. Nuclear plant maintenance expenses increased primarily as a result of increased refueling outages, while fossil plant maintenance expenses increased primarily as a result of turbine and boiler outages. Administrative and general expenses increased primarily because of costs associated with a voluntary separation program offered during 1994 and non-recurring claims. (For additional information on the voluntary separation program, see Current Issues "Resource Optimization," page 20.) Other operation and maintenance expenses increased at an average annual rate of 7 percent from 1992 to 1994. Administrative and general expenses increased over the period principally because of the voluntary separation program offered in 1994 and non-recurring claims. Fossil operating and maintenance expenses increased as a result of bringing refurbished units back on-line and increased boiler and turbine outages. Fuel expense increased at an average annual rate of 3 percent from 1992 to 1994. The increase was due primarily to higher system production requirements satisfied by increased fossil generation. A continued decline of fuel prices over this period partially offset the overall increase in fuel expenses. Net interchange and purchased power increased from $539 million in 1992 to $553 million in 1994, an average annual increase of 1 percent.
From 1992 to 1994, 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 depreciation associated with additional investments. These investments are primarily associated with distribution plant including investment to support customer growth, and fossil plant resulting from bringing refurbished units back on-line. INTEREST EXPENSE AND OTHER INCOME. Interest expense decreased at an average annual rate of 7 percent from 1992 to 1994. Interest on long-term debt decreased because of the Company's refinancing of higher-cost debt beginning in late 1991 and continuing throughout 1993. Interest expense also decreased as a result of the one-time impact in 1992 of approximately $27 million in interest paid to North Carolina retail customers because of a rate refund. Allowance for funds used during construction (AFUDC) and other deferred returns, net of associated taxes, represented 13 percent of earnings for common stock in 1994 compared with 11 percent in 1992. AFUDC and other deferred returns are expected to be less than 14 percent of total earnings during the next three years. AFUDC, net of associated taxes, represented 6 percent of earnings for common stock in 1994 compared with 5 percent in 1992. The increase was primarily the result of increased investment in the Lincoln Combustion Turbine Station. (For additional information on the Lincoln Combustion Turbine Station, see Capital Needs "Meeting Future Power Needs," page 20.) The accrued 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 1994 compared with 6 percent in 1993 and 1992. The growth in this return is due to the increasing cumulative impact of the Company's funding of purchased power costs, which the Company expects to collect through current rates in future periods. (For additional information on purchased capacity levelization, see Capital Needs "Purchased Capacity Levelization," page 19.) LIQUIDITY AND RESOURCES SIGNIFICANT RATE MATTERS. During 1991, Duke Power filed in both the North Carolina and South Carolina retail jurisdictions its only requests for general rate increases since 1986. General rate increases approved in November 1991 resulted in additional annual revenues of $100.1 million and $30.2 million in North Carolina and South Carolina, respectively. The increases were needed primarily to recover costs associated with the commercial operation of the Bad Creek Hydroelectric Station. In 1992, the North Carolina Supreme Court remanded to the North Carolina Utilities Commission (NCUC) Duke Power's 1986 rate order for the second time. In this ruling, the Court held that the record from the 1986 proceedings failed to support the rate of return on common equity authorized by the NCUC after the initial decision of the Court remanding the 1986 rate order. The NCUC issued a final order in 1992 which resulted in a 1992 refund to North Carolina retail customers of approximately $95 million, including interest. 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 other joint owners of the Catawba Nuclear Station and the Company were involved 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.) The Company and the other joint owners entered into settlement agreements in 1994 which resolved all issues in contention in the proceedings. The Company has settled its cumulative net obligation through 1993 of approximately $205 million with the other joint owners. Billings for 1994 and later years will conform to the settlement agreements, which have been approved by the Company's retail regulatory commissions. Because it expects the costs associated with these settlements to be recovered as part of the purchased capacity levelization, the Company has included approximately $205 million as an increase to Purchased capacity costs on its Consolidated Balance Sheets. 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 1994 accounted for 67 percent of total cash from operating, financing and investing activities compared with 46 percent in 1993 and 51 percent in 1992. Substantially all of the Company's capital needs were met by cash generated from operating activities for 1993 and 1992 when refinancing activities are excluded. Refinancing activities were insignificant in 1994. FINANCING AND INVESTING ACTIVITIES. The Company's consolidated capital structure at year-end 1994, including subsidiary long-term debt, was 51 percent common equity, 40 percent long-term debt and 9 percent preferred stock. This structure is consistent with the Company's target to maintain a double-A credit rating. As of December 31, 1994, 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. In response to favorable market conditions in 1992 and 1993, the Company refinanced $2.3 billion of long-term debt and $445 million of preferred stock. While there were no significant refinancings in 1994, the Company issued $407 million in debt, primarily First and Refunding Mortgage Bonds. Duke Power's embedded cost of long-term debt, excluding debt of subsidiaries, was 7.98 percent for 1994 compared with 8.01 percent in 1993 and 8.39 percent in 1992. The embedded cost of preferred stock was 6.99 percent in 1994 compared with 6.76 percent in 1993 and 7.05 percent in 1992. The decreases are primarily the result of the Company's refinancing activities. The increase in the embedded cost of preferred stock from 1993 to 1994 reflects the impact of increasing dividend rates on variable rate preferred stocks. FIXED CHARGES COVERAGE. Consolidated fixed charges coverage using the SEC method increased to 4.72 times for 1994 compared with 4.68 and 3.49 times in 1993 and 1992, respectively. Coverage increased primarily because of lower interest as a result of refinancing activities. Consolidated fixed charges coverage, excluding AFUDC and other deferred returns, was 4.32 for 1994 compared with 4.39 in 1993 and 3.27 in 1992 and the Company goal of 3.5 times. Coverage was somewhat lower in 1994 than 1993 as a result of a decrease in earnings excluding AFUDC and other deferred returns and higher in 1994 than 1992 because of higher earnings and lower interest expense. CAPITAL NEEDS PROPERTY ADDITIONS AND RETIREMENTS. Additions to property and nuclear fuel of $883 million and retirements of $238 million resulted in an increase in gross plant of $645 million in 1994. Since January 1, 1992, additions to property and nuclear fuel of $2.2 billion and retirements of $839 million have resulted in an increase in gross plant of $1.4 billion. CONSTRUCTION EXPENDITURES. Plant construction costs for generating facilities supporting Duke Power electric operations, including AFUDC, increased from $145 million in 1992 to $309 million in 1994, primarily because of construction of the Lincoln Combustion Turbine Station. (For more information, see Capital Needs "Meeting Future Power Needs," page 20.) Construction costs for distribution plant, including AFUDC, decreased from $224 million in 1992 to $203 million in 1994. Projected construction and nuclear fuel costs for Duke Power's electric operations, both including AFUDC, are $3.0 billion and $620 million, respectively, for 1995 through 1999. Total projected construction costs include expenditures for the construction of the Lincoln Combustion Turbine Station and the replacement of certain steam generators at the McGuire and Catawba Nuclear Stations. (For additional information on steam generator replacement, see Current Issues "Stress Corrosion Cracking," page 21.) Projected capital expenditures of subsidiaries and diversified activities are $661 million for 1995 through 1999. 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. For 1995 through 1999, the Company anticipates funding its projected construction expenditures through the internal generation of funds and, to a lesser extent, through the issuance of debt securities. 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 Catawba joint owners. The contracts relating to the sales of portions of the station obligate the Company to purchase a declining amount of capacity from the other joint owners. In the North Carolina retail jurisdiction, regulatory treatment of these contracts provides revenue for recovery of the capital costs and the fixed operating and maintenance costs of purchased capacity on a levelized basis. In the South Carolina retail jurisdiction, revenues are provided for the recovery of
the capital costs of purchased capacity on a levelized basis, while current rates include recovery of fixed operating and maintenance expenses. Such rate treatments require the Company to fund portions of the purchased capacity payments until these costs, including accrued 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 continue to exceed levelized revenues. In the South Carolina retail jurisdiction, cumulative levelized revenues have exceeded purchased capacity payments. 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 building 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 1,184 megawatts. The estimated total cost of the project is approximately $500 million. Current plans are for 12 units to begin commercial operation by the end of 1995 and the remaining four to begin commercial operation in 1996. 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 Public Service Commission of South Carolina (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. The annual costs deferred, including the return, were approximately $25 million in 1994 and $26 million in 1993. As of January 1, 1995, the Company has under contract 300 megawatts of firm purchased capacity from other generators of electricity, including 62 megawatts from qualifying facilities. The purchase of capacity and energy is also an integral part of meeting future power needs. The Company expects to use a competitive bidding process to provide for the next increment of generating capacity beyond the Lincoln Combustion Turbine Station. CURRENT ISSUES While the Company improved its financial performance in 1994 compared with 1993, the 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. While retail wheeling is presently not allowed in any form in the Company's service territory, the Company is focusing on providing competitive cost-based prices to its industrial customers, as well as to wholesale customers who already have access to alternative sources of energy. Other significant factors impacting the Company's future earnings levels include continued economic growth in the Piedmont Carolinas, the success of the Company's subsidiaries and diversified activities, and the outcome of various legislative and regulatory actions. RESOURCE OPTIMIZATION. The Company has been engaged in a concentrated effort to more efficiently and effectively use its resources through better work practices. During 1994, the Company offered a voluntary separation program which gave most employees the option of leaving the Company for a lump-sum payment and severance pay based on years of service. This voluntary separation program resulted in the departure of approximately 1,300 employees in 1994. Implementing programs such as the voluntary separation program and other efficiency practices has resulted in continued work-force reduction and in streamlined work flows. The number of full-time employees has decreased from 19,945 at year-end 1990 to 17,052 at year-end 1994. 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 (NRC) issued a rule-making in 1988 which requires an external mechanism to fund the estimated cost to decommission certain components of a nuclear unit subject to radioactive contamination. In addition to the required external funding, the Company maintains an internal reserve to provide for decommissioning costs of plant components not subject to radioactive contamination. During 1994, the Company expensed approximately $52.5 million which was contributed to the external funds and accrued an additional $4.8 million to the internal reserve. The balance of the external funds as of December 31, 1994, was $172.4 million. The balance of the internal reserve as of December 31, 1994, was $204.8 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 three comparable state sites. While the cost of remediation of these sites may be substantial, the Company will share in any liability associated with remediation of contamination at such sites with other potentially responsible parties. Management is of the opinion that resolution of these matters will not have a material adverse effect on the results of operations or financial position of the Company. THE CLEAN AIR ACT AMENDMENTS OF 1990. The Clean Air Act Amendments of 1990 require a two-phase reduction by electric utilities in the aggregate annual emissions of sulfur dioxide and nitrogen oxide by the year 2000. The Company currently meets all requirements of Phase I. The Company supports the national objective of clean air in the most cost-effective manner and has already reduced emissions through the use of low-sulfur coal in its fossil plants, efficient plant operations and by using nuclear generation. The sulfur dioxide provisions of the Act allow utilities to choose among various alternatives for compliance. The Company is currently developing a detailed compliance plan for Phase II requirements which must be filed with the Environmental Protection Agency (EPA) by 1996. A preliminary strategy, which allows for varying options, indicates one-time costs associated with bringing the Company into compliance with the Act could range from $260 million to $750 million, depending on the compliance options the Company selects. The final strategy is contingent upon developments in the emissions allowance market, future regulatory and legislative actions, and advances in clean air technology. Additional annual operating and maintenance expenses will be incurred as well. All options within the preliminary strategy provide for full compliance with Phase II requirements by the year 2000. 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. 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 for 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 Nuclear Station, began a legal action on March 22, 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. On March 17, 1994, the Company, together with the other joint owners of the Catawba Station, settled the lawsuit. 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 operation or financial position of the Company. COMPETITION. The Energy Policy Act of 1992 (EPACT) is moving utilities toward a more competitive environment. The EPACT reformed certain provisions of the Public Utility Holding Company Act of 1935 (PUHCA) and Part II of the Federal Power Act to remove certain regulatory barriers. For example, the 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. The EPACT requires transmission of power for third parties to wholesale customers on issuance of an order by the FERC, provided the reliability of service to the utility's local customer base is protected and the local customer base does not subsidize the third-party service. The EPACT does not permit the FERC to issue an order requiring transmission access to retail customers. The electric utility industry currently 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 recorded asset balances to reflect a market basis less than cost. Discontinuance of cost-based regulation could also require some utilities to write off their regulatory assets. Management cannot predict the potential impact, if any, of these competitive forces on the Company's future financial position and results of operations. However, the Company continues to position itself to effectively meet these challenges by maintaining prices that are regionally and nationally competitive. The Company anticipates filing an open access transmission tariff with the FERC in early 1995. Open access would provide the Company with increased opportunities to sell and deliver energy and capacity at market-based prices, thereby improving the utilization of existing assets. In addition, such access would provide an opportunity to buy energy and capacity at attractive rates, serving to further enhance the Company's competitive price position. 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 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 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's subsidiaries and diversified activities contributed $52 million to net income in 1994 compared with $22 million in 1993 and $25 million in 1992. Increased developed lot and land sales, the sale of commercial rental property and the operation of generation and transmission facilities outside Duke Power's regulated service area generated additional income in 1994. A one-time gain on the sale of an investment in the preferred stock of an independent power development company also contributed to diversified income. Earnings of subsidiaries and diversified activities also include income from passive financial investments, engineering services fees, water operations and merchandising. Domestically, the Company is seeking opportunities to: provide communications, water and engineering consulting services; construct, operate and maintain generation and transmission facilities; own generation facilities outside Duke Power's regulated service area; develop real estate; sell and service appliances and electronics; and participate in power marketing activities. The Company had equity investments in joint ventures, which own assets within the United States, of $14 million and $17 million at December 31, 1994 and 1993, respectively. Non-electric property of the Company's subsidiaries and diversified activities was $286 million and $216 million at December 31, 1994 and 1993, respectively. Internationally, the Company is seeking opportunities to construct, own, operate and maintain generation and transmission facilities and to provide engineering consulting services. The Company had equity investments in international joint ventures, which own generation and transmission facilities, of $94 million and $85 million at December 31, 1994 and 1993, respectively.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. DUKE POWER COMPANY INDEX
DUKE POWER COMPANY CONSOLIDATED STATEMENTS OF INCOME
See Notes to Consolidated Financial Statements.
DUKE POWER COMPANY CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
See Notes to Consolidated Financial Statements.
DUKE POWER COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
See Notes to Consolidated Financial Statements.
DUKE POWER COMPANY CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements.
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. REVENUES Electric revenues are recorded as service is rendered to customers. "Receivables" on the Consolidated Balance Sheets include $163,270,000 and $175,726,000 as of December 31, 1994 and 1993, respectively, for electric service that has been rendered but not yet billed to customers. B. ADDITIONS TO ELECTRIC PLANT The Company capitalizes all construction-related direct labor and materials as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of money (allowance for funds used during construction). The cost of renewals and betterments of units of property is capitalized. The cost of repairs and replacements representing less than a unit of property is charged to electric expenses. The original cost of property retired, together with removal costs less salvage value, is charged to accumulated depreciation. C. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC) AFUDC represents the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated facilities. AFUDC, a non-cash item, is recognized as a cost of "Construction work in progress" (CWIP), 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 1994 and 1993 AFUDC rates of 9.64 and 9.29 percent for Duke Power include a component for debt cost on a pre-tax basis. The 1992 rate of 8.07 percent includes a component for debt cost on a net of tax basis. The change in calculation from a net of income tax basis to a pre-tax basis is a result of the adoption of Statement of Financial Accounting Standards No. 109 (SFAS 109). (See Note 4.) Rates for all periods are compounded semiannually. D. 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 cost 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." E. 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 3.46 percent for 1994, 3.47 percent for 1993 and 3.48 percent for 1992. 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 $18,008,000 during 1994 and has paid $26,346,000 cumulatively related to its ownership interest in nuclear plants. The Company has reflected the remaining liability and regulatory asset of $102,467,000 in the Consolidated Balance Sheets at December 31, 1994. F. SUBSIDIARIES The Company's consolidated financial statements reflect consolidation of all of its majority-owned subsidiaries. Intercompany transactions have been eliminated in consolidation.
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- Continued G. 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. H. 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. I. 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 $372,416,000, $354,981,000 and $217,144,000 for the years ended December 31, 1994, 1993 and 1992, respectively. Interest paid, net of amounts capitalized, was $236,696,000, $249,659,000 and $303,222,000 for the years ended December 31, 1994, 1993 and 1992, respectively. NOTE 2. RATE MATTERS DUKE POWER COMPANY The North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (PSCSC) must approve rates for retail sales within their respective states. The Federal Energy Regulatory Commission (FERC) must approve Duke Power's rates for sales to wholesale customers. Sales to the other joint owners of the Catawba Nuclear Station, which represent a substantial majority of Duke Power's wholesale revenues, are set through contractual agreements. (See Note 3.) During 1991, Duke Power filed in both the North Carolina and South Carolina retail jurisdictions its only requests for general rate increases since 1986. General rate increases approved in November 1991 resulted in additional annual revenues of $100.1 million and $30.2 million in North Carolina and South Carolina, respectively. The increases were primarily needed to recover costs associated with the construction of the Bad Creek Hydroelectric Station. Also in 1991, Duke Power filed a request for a wholesale rate increase with the FERC. A negotiated settlement between Duke Power and the wholesale customers was approved by the FERC in 1992 and resulted in an increase in annual revenues of $2.1 million. In 1992, the North Carolina Supreme Court remanded to the NCUC Duke Power's 1986 rate order for the second time. In this ruling, the Court held that the record from the 1986 proceedings failed to support the rate of return on common equity authorized by the NCUC after the initial decision of the Court remanding the 1986 rate order. The NCUC issued a final order in 1992 which resulted in a 1992 refund to North Carolina retail customers of approximately $95 million, including interest. 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.
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 2. RATE MATTERS -- Continued The North Carolina legislature ratified a bill in July 1987 assuring the legality of such adjustments in rates. In 1991, the statute was extended through June 30, 1997. 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:
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, 1994, $492,429,000 of "Electric plant in service" and "Nuclear fuel" represents the Company's investment in Units 1 and 2. Accumulated depreciation and amortization of $165,568,000 associated with Catawba has been recorded as of year-end. The Company's share of operating costs of Catawba are 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 occurs in 1995 for Unit 1 and 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.
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 3. JOINT OWNERSHIP OF GENERATING FACILITIES -- Continued 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. Energy cost payments are based on variable operating costs and are a function of the generation output of Catawba. 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 1994 and projected obligations for 1995 through 1999 are as follows (dollars in thousands):
Effective in its November 1991 rate order, the North Carolina Utilities Commission (NCUC) reaffirmed the Company's recovery, on a levelized basis, of the capital costs and fixed operating and maintenance costs of capacity purchased from the other joint owners. The Public Service Commission of South Carolina (PSCSC) in its November 1991 rate order reaffirmed the Company's recovery on a levelized basis of the capital costs of capacity purchased from the other joint owners. 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 drop 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 the North Carolina retail and FERC wholesale jurisdictions, purchased capacity payments continue to exceed levelized revenues. In the South Carolina retail jurisdiction, cumulative levelized revenues have exceeded purchased capacity payments. For the years ended December 31, 1994, 1993 and 1992, the Company recorded purchased capacity and energy costs from the other joint owners of $604,505,000, $547,899,000 and $514,327,000, 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, 1994 and 1993, $932,324,000 and $768,099,000, 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." The cumulative impact of settlement agreements reflected in 1994 resulted in additional purchased capacity costs. (See Note 13.)
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 4. INCOME TAX EXPENSE The Company implemented Statement of Financial Accounting Standards No. 109 (SFAS 109), "Accounting for Income Taxes," effective January 1, 1993. SFAS 109 requires a liability approach for financial accounting and reporting of income taxes. No prior periods were restated because of the implementation of SFAS 109. Accumulated deferred income taxes consist primarily of the following temporary differences (dollars in thousands):
* The net regulatory asset related to income taxes is $489,292,000 for 1994 and $486,440,000 for 1993. Total deferred income tax liability was $2,873,373,000 as of December 31, 1994, and $2,745,431,000 as of December 31, 1993. Total deferred income tax asset was $524,742,000 as of December 31, 1994, and $502,065,000 as of December 31, 1993. Income tax expense for the years ended December 31, 1994, 1993 and 1992 consisted of the following (dollars in thousands):
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 4. INCOME TAX EXPENSE -- Continued Income taxes differ from amounts computed by applying the statutory tax rate to pre-tax income for the years ended December 31, 1994, 1993 and 1992 as follows (dollars in thousands):
NOTE 5. SHORT-TERM BORROWINGS AND COMPENSATING-BALANCE ARRANGEMENTS At December 31, 1994, the Company had a three-year revolving credit facility of $355,000,000 with 15 commercial banks. At December 31, 1993, the Company had two three-year revolving credit facilities of $300,000,000 and $130,000,000, with 17 and 5 commercial banks, respectively. The Company had $130,000,000 in commercial paper outstanding throughout 1994 and 1993 backed by the unused portion of the above three-year revolving credit facilities. The $130,000,000 in commercial paper is included in long-term debt. In addition, the Company had $44,980,000 in annually renewable lines of credit at December 31, 1994 and 1993. All such facilities are on a fee or compensating-balance basis with the exception of $20,000,000 in annually renewable lines of credit. The amount of short-term debt outstanding from these credit facilities as of December 31, 1994 and 1993 was $10,100,000 and $2,800,000, respectively. Additionally, as of December 31, 1994 and 1993, the Company had $40,000,000 in pollution-control bonds backed by an unused, two-year revolving credit facility of $40,000,000. This facility is on a fee basis and the bonds are included in long-term debt. Cash balances maintained at the banks on deposit were $13,214,000 as of December 31, 1994, and $12,988,000 as of December 31, 1993. Cash balances and fees compensate banks for their services, even though the Company has no formal compensating-balance arrangements. To compensate certain banks for credit facilities, the Company maintained balances of $49,000 as of December 31, 1994 and 1993. 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):
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 6. COMMON STOCK AND RETAINED EARNINGS COMMON STOCK The Company issued common stock to satisfy the conversion rights of preference stock through April 6, 1992. (See Note 7.) As of December 31, 1994, a total of 7,004,659 shares was reserved for issuance to stock plans. RETAINED EARNINGS As of December 31, 1994, 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, 1994 and 1993:
On April 6, 1992, the Company redeemed all outstanding shares of the Cumulative Preference Stock, 6 3/4% Convertible Series AA at its par value of $100 per share. In 1992, 19,060 shares of preference stock were converted into 159,386 shares of common stock. Preferred and preference stock without sinking fund requirements as of December 31, 1994 and 1993, were as follows (dollars in thousands):
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, 1994 and 1993:
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 8. PREFERRED AND PREFERENCE STOCK WITH SINKING FUND REQUIREMENTS -- Continued Preferred and preference stock with sinking fund requirements as of December 31, 1994 and 1993, were as follows (dollars in thousands):
The annual sinking fund requirements through 1999 are $1,500,000 in 1995, 1996 and 1997, $5,750,000 in 1998 and $25,750,000 in 1999. 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.
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 9. LONG-TERM DEBT Long-term debt outstanding as of December 31, 1994 and 1993, was as follows (dollars in thousands):
(a) Substantially all of Duke Power's electric plant was mortgaged as of December 31, 1994. (b) Substantial amounts of Crescent Resources, Inc.'s real estate development projects, land and buildings are pledged as collateral. (c) Nantahala Power and Light's loan agreements impose net worth restrictions and limitations on disposal of assets and payment of cash dividends. As of December 31, 1994 and 1993, 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 1994 and 1993 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.
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 9. LONG-TERM DEBT -- Continued As of December 31, 1994, Crescent Resources, Inc. had $68,142,000 in mortgage loans which mature through 1999 and $23,960,000 in mortgage loans maturing in 2000 or thereafter, most requiring monthly payments of principal. Interest rates are variable and at December 31, 1994 ranged from 4.50 percent to 7.22 percent. As of December 31, 1994, 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 1999, are $92,259,000 in 1995; $12,540,000 in 1996; $212,708,000 in 1997; $62,559,000 in 1998; and $438,490,000 in 1999. NOTE 10. FAIR VALUE OF FINANCIAL INSTRUMENTS The carrying amounts of Cash, Short-term investments, Other investments, at cost or less, and Notes payable approximate fair value primarily because of the short maturities of these instruments. The majority of estimated fair value amounts 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, 1994 and 1993, 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 primarily invested in municipal and U.S. government bonds. "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):
In order to obtain variable rate financing at an attractive cost, the Company has entered into an interest rate swap agreement associated with the issuance on November 29, 1994, of $200,000,000 aggregate principal amount of its First and Refunding Mortgage Bonds, 8% Series B due 1999. The five-year interest rate swap is tied to the London Interbank Offered Rate (LIBOR), which is reset quarterly, and initially was set at 5.95%. As a result of the interest rate swap contract, interest expense on the Consolidated Statements of Income is recognized at the weighted average rate for the year tied to the LIBOR rate. 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 contracts. The Company records any gains or losses associated with the hedge as an adjustment to the capitalized cost of the steam generators.
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 11. INVESTMENT IN JOINT VENTURES Certain investments in joint ventures are accounted for by the equity method. The Company's ownership in domestic and international joint ventures is 50 percent or less. The Company's proportionate share of net income in joint ventures for the years ended December 31, 1994, 1993 and 1992 was $7,049,000, $2,601,000 and ($1,179,000), 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):
Of the $504,029,000 and $413,453,000 of total liabilities outstanding at December 31, 1994 and 1993, respectively, $407,605,000 and $290,178,000 represent non-recourse debt at December 31, 1994 and 1993, respectively, for which the Company bears no responsibility beyond the loss of its investment in the event the joint venture defaults on the debt. 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 and 1993, the Company made additional contributions of $30,000,000 and $50,000,000, respectively, to enhance the funded position of the plan. Net periodic pension cost for the years ended December 31, 1994, 1993 and 1992, include the following components (dollars in thousands):
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 12. RETIREMENT BENEFITS -- Continued A reconciliation of the funded status of the plan to the amounts recognized in the Consolidated Balance Sheets as of December 31, 1994 and 1993, is as follows (dollars in thousands):
In determining the projected benefit obligation, the weighted-average assumed discount rate used was 8.25 percent in 1994, 7.50 percent in 1993 and 8.25 percent in 1992. The assumed increase in future compensation level is determined on an age-related basis. The weighted-average salary increase was 5.40 percent in 1994, 4.50 percent in 1993 and 5.40 percent in 1992. The expected long-term rate of return on plan assets used in determining pension cost was 9.00 percent in 1994, 8.40 percent in 1993 and 9.25 percent in 1992. During 1993, the Company offered an enhanced early retirement option, Limited Period Separation Opportunity (LPSO), for eligible employees. The Company recorded an additional one-time expense for special termination benefits associated with LPSO of approximately $7,611,000. B. POSTRETIREMENT BENEFITS The Company and its operating subsidiaries, with the exception of Nantahala Power and Light Company, which maintains its own postretirement benefit plans, currently provides certain health care and life insurance benefits for retired employees. Employees become eligible for these benefits if they retire at age 55 or greater with 10 years of service or if they retire as early as age 51 with 30 years or more of service. Employees retiring after January 1, 1992, receive a fixed Company allowance, based on years of service, to be used to pay medical insurance premiums. The Company reserves the right to terminate, suspend, withdraw, amend or modify the plans in whole or in part at any time. In 1992, the Company commenced funding the maximum amount allowable under section 401(h) of the Internal Revenue Code, which provides for tax deductions for contributions and tax-free accumulation of investment income. Such amounts partially fund the Company's medical and dental postretirement benefits. The Company has also established a Retired Lives Reserve, which has tax attributes similar to 401(h) funding, to partially fund its postretirement life insurance obligation. The Company contributed $12,269,000 into these funding mechanisms in 1994 and $14,648,000 in 1993.
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 12. RETIREMENT BENEFITS -- Continued Net periodic postretirement benefit cost for the years ended December 31, 1994, 1993 and 1992 include the following components (dollars in thousands):
A reconciliation of the funded status of the plan to the amounts recognized in the Consolidated Balance Sheets as of December 31, 1994 and 1993, is as follows (dollars in thousands):
In determining the accumulated postretirement benefit obligation (APBO), the weighted-average assumed discount rate used was 8.25 percent in 1994, 7.50 percent in 1993 and 8.25 percent in 1992. The assumed increase in future compensation level is determined on an age-related basis. The weighted-average salary increase was 5.40 percent in 1994, 4.50 percent in 1993 and 5.40 percent in 1992. The expected long-term rate of return on 401(h) assets used in determining postretirement benefits cost was 9.00 percent in 1994, 8.40 percent in 1993 and 9.25 percent in 1992. For Retired Lives Reserve assets, 6.50 percent was used in 1994 and 7.125 percent was used in 1993 and 1992. The assumed medical inflation rate was approximately 12.50 percent in 1994. This rate decreases by 0.5 percent to 1.0 percent per year until a rate of 5.5 percent is achieved in the year 2002, which remains fixed thereafter. A 1.0 percent increase in the medical and dental trend rates produces a 5.05 percent ($1,552,000) 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 4.10 percent ($14,029,000) as of December 31, 1994. 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 $3.0 billion and $620 million, respectively, for 1995 through 1999. Projected capital expenditures of subsidiaries and diversified activities are $661 million for 1995 through 1999. These projections are subject to
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 13. COMMITMENTS AND CONTINGENCIES -- Continued 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. 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 $62 million. This amount is limited to 7.5 times the Company's annual premium to NEIL for excess property, decontamination and decommissioning liability insurance. The other joint owners of Catawba are obligated to assume their pro rata share of any liability for retrospective premiums and other premium assessments resulting from the NEIL policies applicable to Catawba. The Company has also purchased an additional $850 million of excess property damage insurance for its Catawba plant through a pool of stock and mutual insurance companies. The Company participates in a NEIL program that provides insurance for the increased cost of generation and/or purchased power resulting from an accidental outage of a nuclear unit. Each unit of the Oconee, McGuire and Catawba Nuclear Stations is insured for up to approximately $3.5 million per week, after a 21-week deductible period, with declining amounts per unit where more than one unit is involved in an accidental outage. Coverages continue at 100 percent for 52 weeks and 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
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 13. COMMITMENTS AND CONTINGENCIES -- Continued of a nuclear unit. The other joint owners of Catawba are obligated to assume their pro rata share of any liability for retrospective premiums and other premium assessments resulting from the NEIL policies applicable to the joint ownership agreements. C. OTHER The other joint owners of the Catawba Nuclear Station and the Company were involved 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.) The Company and the other joint owners entered into settlement agreements in 1994 which resolved all issues in contention in the proceedings. The Company has settled its cumulative net obligation through 1993 of approximately $205 million with the other joint owners. Billings for 1994 and later years will conform to the settlement agreements, which have been approved by the Company's retail regulatory commissions. Because it expects the costs associated with these settlements to be recovered as part of the purchased capacity levelization, the Company has included approximately $205 million as an increase to Purchased capacity costs on its Consolidated Balance Sheets. 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 1994, the Company expensed approximately $52,524,000 which was contributed to the external funds and accrued an additional $4,841,000 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, 1994, was $172,390,000. The balance of the internal reserve as of December 31, 1994, was $204,837,000 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.
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 15. RECLASSIFICATION In the Consolidated Statements of Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows, certain prior-year 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 on page 23. Our audits also included the consolidated financial statement schedule listed in the accompanying index on page 23. These financial statements and consolidated financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the 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, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. Also, in our opinion, such consolidated financial statement schedule when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein. DELOITTE & TOUCHE LLP Charlotte, North Carolina February 10, 1995
RESPONSIBILITY FOR FINANCIAL STATEMENTS The financial statements of Duke Power Company are prepared by management, which is responsible for their integrity and objectivity. The statements are prepared in conformity with generally accepted accounting principles appropriate in the circumstances to reflect in all material respects the substance of events and transactions which should be included. The other information in the annual report is consistent with the financial statements. In preparing these statements, management makes informed judgments and estimates of the expected effects of events and transactions that are currently being reported. The Company's system of internal accounting control is designed to provide reasonable assurance that assets are safeguarded and transactions are executed according to management's authorization. Internal accounting controls also provide reasonable assurance that transactions are recorded properly, so that financial statements can be prepared according to generally accepted accounting principles. In addition, the Company's accounting controls provide reasonable assurance that errors or irregularities which could be material to the financial statements are prevented or are detected by employees within a timely period as they perform their assigned functions. The Company's accounting controls are continually reviewed for effectiveness. In addition, written policies, standards and procedures, and a strong internal audit program augment the Company's accounting controls. The Board of Directors pursues its oversight role for the financial statements through the Audit Committee, which is composed entirely of directors who are not employees of the Company. The Audit Committee meets with management and internal auditors periodically to review the work of each group and to monitor each group's discharge of its responsibilities. The Audit Committee also meets periodically with the Company's independent auditors, Deloitte & Touche LLP. The independent auditors have free access to the Audit Committee and the Board of Directors to discuss internal accounting control, auditing and financial reporting matters without the presence of management. JEFFREY L. BOYER CONTROLLER
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
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: (Bullet) CHURCH STREET CAPITAL CORP. (CSCC) manages investment funds and serves as the parent company for the non-electric operating subsidiaries. CSCC investment highlights are as follows (dollars in thousands): SHORT-TERM INVESTMENTS AND MARKETABLE SECURITIES
INVESTMENT INCOME (AFTER TAX) (A)
(Bullet) CRESCENT RESOURCES, INC. is engaged in real estate development and forest management. (Bullet) DUKE ENERGY GROUP, INC., parent of Duke Energy Corp., structures, finances and manages investments in electric generation and transmission facilities, both nationally and internationally. (Bullet) 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. (Bullet) 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. (Bullet) DUKE MERCHANDISING sells and services quality electric merchandise and electronics primarily to Duke Power customers. (Bullet) DUKENET COMMUNICATIONS, INC. develops and manages communication systems. (Bullet) DUKE WATER OPERATIONS serves areas of Anderson, South Carolina, and Rutherfordton, North Carolina. (Bullet) 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
FINANCIAL POSITION
CASH FLOWS
OTHER INFORMATION
(a) Earnings for 1994, 1993 and 1992 exclude elimination of intercompany profits of $49,000, $509,000 and $1,211,000, respectively. (b) Includes Duke Energy Group, Inc.'s allocable share of net income from joint ventures. (See "Note 11, Notes to Consolidated Financial Statements.") (c) Nantahala Power and Light Company's Operating revenues include revenues from the sale of electricity to Duke Power of $12,131,000, $13,683,000 and $12,640,000 for 1994, 1993 and 1992, 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, Notes to Consolidated Financial Statements.")
(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) 1993 includes the net change in short-term investments for the period of $20,653,000. (i) 1994 and 1992 include the net change in short-term investments for the period of $12,060,000 and $49,282,000, respectively. (j) Excludes capital infusion and return of capital transactions between Church Street Capital Corp. and its subsidiaries. (k) 1993 and 1992 exclude capital infusions from parent, Church Street Capital Corp., of $6,000,000 and $5,000,000, respectively. (l) 1994 excludes net return of capital to parent, Church Street Capital Corp., of $12,100,000. 1993 and 1992 exclude net capital infusions from Church Street Capital Corp. of $91,864,000 and $24,360,000, respectively. (m) 1993 and 1992 each include capital infusions from Duke Power to Church Street Capital Corp. of $75,000,000.
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
(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.
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.
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 1995 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.
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 1995 annual meeting of shareholders, which is being incorporated herein by reference. ITEM 12.
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 1995 annual meeting of shareholders, which is being incorporated herein by reference. ITEM 13.
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 1995 annual meeting of shareholders, which are being incorporated herein by reference.
PART IV. ITEM 14.
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, Consolidated Statements of Retained Earnings for the Three Years Ended December 31, 1994 Consolidated Statements of Cash Flows for the Three Years Ended December 31, 1994 Consolidated Balance Sheets -- December 31, 1994 and 1993 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, 1994 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 1994. (c) Exhibits -- See Exhibit Index on page 54.
SIGNATURES Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Charlotte and State of North Carolina on the 29th day of March, 1995. 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.
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.
(|) 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.