ITEM 1. BUSINESS. Duke Power Company (the Company) is engaged in the generation, transmission, distribution and sale of electric energy in the central portion of North Carolina and the western portion of South Carolina, comprising the area in both States known as the Piedmont Carolinas. Its service area, approximately two-thirds of which lies in North Carolina, covers about 20,000 square miles with an estimated population of 4.8 million and includes a number of cities, of which the largest are Charlotte, Greensboro, Winston-Salem and Durham in North Carolina and Greenville and Spartanburg in South Carolina. During 1993, the Company's electric revenues amounted to approximately $4.3 billion, of which about 70 percent was derived from North Carolina and about 30 percent from South Carolina. The Company ranks sixth in the United States among investor-owned utilities in kilowatt-hour sales. Its executive offices are located in the Power Building, 422 South Church Street, Charlotte, North Carolina 28242-0001 (Telephone No. 704-594-0887). THE STATISTICS PRESENTED HEREIN DO NOT INCLUDE INFORMATION RELATING TO THE COMPANY'S UTILITY SUBSIDIARY, NANTAHALA POWER AND LIGHT COMPANY, UNLESS OTHERWISE INDICATED. (SEE "ENERGY REQUIREMENTS AND CAPABILITY.") SERVICE AREA The Company supplies electric service directly to approximately 1.7 million residential, commercial and industrial customers in more than 200 cities, towns and unincorporated communities in North Carolina and South Carolina. Electricity is sold at wholesale to nine incorporated municipalities and to several private utilities. In addition, in 1993 approximately 9% of total sales were made through contractual arrangements to former wholesale municipal or cooperative customers of the Company who had purchased portions of the Catawba Nuclear Station (collectively, the "Other Catawba Joint Owners") (See "Joint Ownership of Generating Facilities.") The Company's service area is undergoing increasingly diversified industrial development. The textile, manufacture of machinery and equipment, chemical and chemical related industries are of major significance to the economy of the area. Other industrial activity includes the paper and allied products, rubber and plastic products and various other light and heavy manufacturing and service businesses. The largest industry served by the Company is the textile industry, which accounted for approximately $488 million of the Company's revenues for 1993, representing 11 percent of electric revenues and 40 percent of electric industrial revenues. ENERGY REQUIREMENTS AND CAPABILITY The following table sets forth the Company's generating capability at December 31, 1993, its sources of electric energy for 1993, and certain information presently projected for 1994:
(a) The data relating to capability does not reflect the possible unavailability or reduction of capability of facilities at any given time because of scheduled maintenance, repair requirements or regulatory restrictions. (b) Nuclear capability and related generation for 1993 and projected for 1994 give no effect to the joint ownership of the Catawba Nuclear Station. (See "Joint Ownership of Generating Facilities.")
(c) Includes Bad Creek and Jocassee pumped storage hydroelectric stations at licensed generating capabilities of 1,065,000 KW and 610,000 KW, respectively. (d) Excludes firm purchases. (See "Energy Management and Future Power Needs.") Nantahala Power and Light Company (NP&L), which operates 11 hydroelectric stations and buys supplemental power to provide service to its 51,000 mostly residential customers located in five counties in western North Carolina, operates as a separate subsidiary of the Company. The Company is supplying supplemental power to NP&L under the terms of an interconnect agreement approved by the Federal Energy Regulatory Commission (FERC). The Company has a bulk power sales agreement with Carolina Power & Light Company (CP&L) to provide CP&L 400 megawatts of capacity as well as associated energy when needed for a six-year period which began July 1, 1993. Electric rates in all regulatory jurisdictions were reduced by adjustment riders to reflect capacity revenues received from this agreement. According to industry statistics published in 1993, the Company ranked first in the nation in terms of efficiency of its steam-fossil generating system as measured by the conversion of fuel energy to electric energy. Published rankings indicate that individual units at Marshall Steam Station ranked first, second and sixth most efficient in the nation in 1992. The Company's nuclear system continued its tradition of operating efficiency, operating at 78 percent of capacity for the year, in comparison with the industry's most current average capacity factor of 71 percent for 1992. The Company normally experiences seasonal peak loads in summer and winter which are relatively in balance. The Company currently forecasts a 2.1 percent compound annual growth in peak load through 2008. This amount is not reduced by those future demand-side management program contributions considered resources for meeting peak demand (See "Energy Management and Future Power Needs"). The 1992-1993 winter peak load of 13,314,000 KW occurred on February 19, 1993. On July 29, 1993, the Company experienced its summer peak load of 15,720,000 KW during unusually hot weather. A new all-time peak load of 16,070,000 KW occurred on January 19, 1994 during extremely cold weather. RATE MATTERS The North Carolina Utilities Commission (NCUC) and The Public Service Commission of South Carolina (PSCSC) must approve the Company's rates for retail sales within the respective states. FERC must approve the Company's rates for sales to wholesale customers, including the contractual arrangements between the Company and the Other Catawba Joint Owners. Rate requests filed by the Company in its most recent general rate case in 1991 with the NCUC, PSCSC and FERC were principally designed to reflect the Company's investment in the Bad Creek Hydroelectric Station. Rate orders issued by the NCUC and PSCSC in November, 1991 recognized costs of the Bad Creek Hydroelectric Station, including an amortization of costs deferred between commercial operation and the rate order, which the Company had requested. The Company's wholesale customers challenged its proposed rate increase and in 1991 FERC issued an order that accepted the Company's proposed rates for filing. A negotiated settlement with these customers, which provided for an increase in wholesale rates consistent with the increase in retail rates, was approved by FERC and became effective in April 1992 (See "Management's Discussion and Analysis of Results of Operations and Financial Condition, Liquidity and Resources -- RATE MATTERS"). In its most recent general rate case, the NCUC authorized a jurisdictional rate of return on common equity of 12.50 percent and the PSCSC authorized a jurisdictional rate of return on common equity of 12.25 percent. The North Carolina Supreme Court, on April 22, 1992, remanded for the second time the Company's 1986 rate order to the NCUC. In its ruling, the Court held that the record from the 1986 proceedings failed to support the rate of return of 13.2 percent on common equity authorized by the NCUC after the initial decision of the Court remanding the 1986 rate order. The NCUC issued a final order dated October 26, 1992, authorizing a 12.8 percent return on common equity for the period October 31, 1986 through November 11, 1991, that resulted in a refund to North Carolina retail customers in 1992 of approximately $95 million, including interest. FUEL COST ADJUSTMENT PROCEDURES. The Company has procedures in all three of its regulatory jurisdictions to adjust rates for fluctuations in fuel expense. The NCUC ordered the Company to follow these procedures in its
August 1986 order, which was effective for periods beginning January 1, 1986. The prospective adjustment in rates of past over- or under-recovery of fuel costs was challenged in the North Carolina courts. North Carolina adopted legislation assuring the legality of such adjustments, which contains a sunset provision effective June 30, 1997. CONSTRUCTION WORK IN PROGRESS (CWIP). The NCUC is permitted in its discretion to include CWIP in rate base after giving consideration to the public interest and the Company's financial stability. The PSCSC may include CWIP in rate base in its discretion. ENERGY MANAGEMENT AND FUTURE POWER NEEDS The Company's strategy for meeting customers' present and future energy needs is composed of three components: demand-side resources, purchased power resources and supply-side resources. By utilizing these resources, the Company expects to maintain a reserve margin of approximately 20 to 25 percent of its anticipated peak load requirements through 1996. Demand-side management programs are a part of meeting the Company's future power needs. These programs benefit the Company and its customers by providing for load control through interruptible control features, shifting usage to off-peak periods, increasing usage during off-peak periods, and by promoting energy efficiency. In return for participation in demand-side management programs, customers may be eligible to receive various incentives which help to reduce their electric bills. Demand-side management programs such as Industrial Interruptible Service and Residential Load Control can be used to manage capacity availability problems. Energy-efficiency programs such as high-efficiency chillers, high-efficiency heat pumps and high-efficiency air conditioners are other examples of current demand-side management programs. The November 1991 rate orders of the NCUC and the PSCSC provided for recovery in rates of a designated level of costs for demand-side management programs and allowed the deferral for later recovery of certain demand-side management costs that exceed the level reflected in rates, including a return on the deferred costs. As additional demand-side costs are incurred, the Company ultimately expects recovery of associated costs, which are currently being deferred, through rates. The annual costs deferred, including the return, were approximately $26 million in 1993 and $18 million in 1992. The Company continues to engage in a comprehensive energy management program as part of its Integrated Resource Plan. Integrated Resource Planning is the process used by utilities to evaluate a variety of resources. The goal is to provide adequate and reliable electricity in an environmentally responsible manner through cost-effective power management. In January 1993, the PSCSC issued an order approving the Company's 1992 Integrated Resource Plan as reasonable, and approving a "shared savings" proposal for accomplishments made in the Company's demand-side management programs. In June 1993, the NCUC approved the 1992 plan, including the shared savings mechanism. The Company's current plan reduces supply side requirements in excess of 1,900 megawatts by the year 2000 due to the Company's effective use of demand side options. The purchase of capacity and energy is also an integral part of meeting future power needs. The Company currently has under contract 500 megawatts of capacity from other generators of electricity. The Company's construction program and the estimated construction costs set forth below are subject to continuing review and are revised from time to time in light of changes in load forecasts, the Company's financial condition (including cash flow, earnings and levels of rates), changing regulatory and environmental standards (See "Regulation -- ENVIRONMENTAL MATTERS") and other factors.
Projected construction and nuclear fuel costs, excluding costs related to portions of the Catawba Nuclear Station owned by the Other Catawba Joint Owners, for each of 1994, 1995 and 1996 and for the three-year period 1994-1996, as now scheduled, are as follows (in millions of dollars):
The Company's procedures for estimating construction costs (which include allowance for funds used during construction) utilize, among other things, past construction experience, current construction costs and allowances for inflation. The Company is building a combustion turbine facility in Lincoln County, North Carolina to provide capacity at periods of peak demand. The Lincoln Combustion Turbine Station will consist of 16 combustion turbines with a total generating capacity of 1,184 megawatts. The estimated total cost of the project is approximately $500 million. Current plans are for ten units to begin commercial operation by the end of 1995 and the remaining six to begin commercial operation before the end of 1996. During 1991, the NCUC granted the Certificate of Public Convenience and Necessity and the North Carolina Division of Environmental Management issued a final air permit for the facility. The issuance of the final air permit for the facility has been appealed. Legal proceedings with regard to the appeal are ongoing. The Company believes the permit will be upheld. The Company has nearly completed a Plant Modernization Program (PMP) to improve the efficiency and reliability of 15 older coal-fired generating units. These units, once modernized, will help the Company meet anticipated future demand. The cost of this program is estimated to average approximately $200-$300 per installed KW, a fraction of the cost of building new plants. As of December 31, 1993, eleven coal-fired units with a nameplate generating capability of 1,241,000 KW had been returned to the system. It is anticipated that three additional coal-fired generating units with nameplate generating capability of 160,000 KW will be returned to the system during 1994. The Company expects the final unit remaining in the PMP after 1994, which unit has 40,000 KW of nameplate generating capability, to be returned to the system in 1995. JOINT OWNERSHIP OF GENERATING FACILITIES In order to reduce its need for external financing, the Company, through several transactions beginning in 1978, sold an 87 1/2 percent undivided interest in the Catawba Nuclear Station to the Other Catawba Joint Owners. These transactions contemplate that the Company will operate the facility, interconnect its transmission system, wheel a certain portion of the capacity and energy of such facility to the respective participants, provide back-up services for such capacity, buy for its own use (whether or not the facility is generating electricity) that portion of the capacity not then contractually required by the respective participants, and provide supplemental power as required by the purchasers to enable them to provide service on a firm basis. The transactions also include a reliability exchange between the Catawba Nuclear Station and the McGuire Nuclear Station of the Company, which provides for an exchange of 50 percent of each Other Catawba Joint Owner's retained capacity from its ownership interest in the Catawba units for like amounts of capability and output from units of the McGuire Nuclear Station. The implementation of the reliability exchange has not had nor does the Company anticipate that such implementation will have a material effect on earnings. The Other Catawba Joint Owners and the Company are involved in various proceedings related to the Catawba joint ownership contractual agreements. The basic contention in each proceeding is that certain calculations affecting bills under these agreements should be performed differently. These items are covered by the agreements between the Company and the Other Catawba Joint Owners which have been previously approved by the Company's retail regulatory commissions (See Note 3, "Notes to Consolidated Financial Statements"). The Company and two of the four Other Catawba Joint Owners have entered into a proposed settlement agreement
which, if approved by the regulators, will resolve all issues in contention in such proceedings between the Company and these owners. The Company recorded a liability as an increase to Other current liabilities on its Consolidated Balance Sheets of approximately $105 million in 1993 to reflect this proposed settlement. In addition, future estimated obligations in connection with the settlement are reflected in estimates of purchased capacity obligations in Note 3, "Notes to Consolidated Financial Statements". As the Company expects the costs associated with this settlement will be recovered as part of the purchased capacity levelization, the Company has included approximately $105 million as an increase to Purchased capacity costs on its Consolidated Balance Sheets. Therefore, the Company believes the ultimate resolution of these matters should not have a material adverse effect on the results of operations or financial position of the Company. Although the two Other Catawba Joint Owners, who are not parties to the above settlement, have not fully quantified the dollars associated with their claims in the presently outstanding proceedings, information associated with these proceedings indicates that the amount in contention could be as high as $110 million, through December 31, 1993. Arbitration hearings were held in 1992 involving substantially all of the disputed amounts, and a decision interpreting the language of the agreements on certain of these matters was issued on October 1, 1993. Further proceedings will be required to determine the amounts associated with this decision as it relates to these owners, some of which may involve refunds. However, the Company expects the costs associated with this decision will be included in and recovered as part of the purchased capacity levelization consistent with prior orders of the retail regulatory commissions. Therefore, the Company believes the ultimate resolution of these matters should not have a material adverse effect on the results of operations or financial position of the Company. FUEL SUPPLY The Company presently relies principally on nuclear and coal for the generation of electric energy. The Company's reliance on oil and gas is minimal. Information regarding the utilization of sources of power and cost of fuels is set forth in the following table:
* Generating figures are net of that output required to replenish pumped storage units during off-peak periods. COAL. The Company obtains a large amount of its coal under long-term supply contracts with mining operators utilizing both underground and surface mining. The Company has on hand an adequate supply of coal. The Company's long-term supply contracts, all of which have price adjustment and price renegotiation provisions, have expiration dates ranging from 1995 to 2003. The Company believes that it will be able to renew such contracts as they expire or to enter into similar contractual arrangements with other coal suppliers for quantities and qualities of coal required. However, due to the Clean Air Act Amendments of 1990, fuel premiums may be required as contracts are renewed. The coal covered by the Company's long-term supply contracts is produced from mines located in eastern Kentucky, southern West Virginia and southwestern Virginia. The Company's short-term requirements have been and will be fulfilled with spot market purchases. The average sulfur content of coal being purchased by the Company is approximately 1 percent. Such coal satisfies the current emission limitation for sulfur dioxide for existing facilities. (See "Management's Discussion and Analysis of Results of Operations and Financial Condition, Current Issues -- The Clean Air Act Amendments of 1990.") NUCLEAR. Generally, the supply of fuel for nuclear generating units involves the mining and milling of uranium ore to produce uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, enrichment of that gas and fabrication of the enriched uranium hexafluoride into usable fuel assemblies. After a region (approximately one-third of the nuclear fuel assemblies in the reactor at any time) of spent fuel is removed
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 Company purchased uranium material during 1993 at an average price of approximately $28 per pound. The Company's material nuclear supply contracts generally contain FORCE MAJEURE provisions. The Nuclear Waste Policy Act of 1982 requires that the Department of Energy (DOE) begin disposing of spent fuel no later than January 31, 1998. The Company has entered into the required contracts with the DOE for the disposal of nuclear fuel and began making payments in July 1983 for disposal costs of fuel currently being utilized. These payments, combined with a one-time payment for disposal costs of fuel consumed prior to April 7, 1983, have totaled about $525 million through 1993. In November 1989, the DOE released a report which indicated that it expects that a facility for spent fuel disposal will not be available until the year 2010. The DOE stated further that it planned an initiative to establish a monitored retrievable storage facility, with a target operation date of 1998, for earlier acceptance of spent fuel from utilities. The Company believes that it will be able to provide adequate on-system storage capacity until such time as the DOE begins receiving spent fuel. REGULATION The Company is subject to the jurisdiction of the NCUC and the PSCSC which, among other things, must approve the issuance of securities. The Company also is subject, as to some phases of its business, to the jurisdiction of FERC, the Environmental Protection Agency (EPA) and state environmental agencies and to the jurisdiction of the Nuclear Regulatory Commission (NRC) as to design, construction and operation of its nuclear power facilities. The Company is exempt from regulation as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA), except with respect to the acquisition of the securities of other public utilities. ENVIRONMENTAL MATTERS. The Company is subject to federal, state, and local regulations with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. North Carolina has enacted a declaration of environmental policy requiring all state agencies to administer their responsibilities in accordance with such policy. The NCUC has adopted rules requiring consideration of environmental effects in determining whether certificates of public convenience and necessity will be granted for proposed generation facilities. South Carolina law also requires consideration by the PSCSC of environmental effects in determining whether certificates of public convenience and necessity will be granted for proposed major utility facilities, which include certain generation and transmission facilities. All of the Company's facilities which are currently under construction have been designed to comply with presently applicable environmental regulations. Such compliance has, however, increased the cost of electric service by requiring changes in the design and operation of existing facilities, as well as changes or delays in the design, construction and operation of new facilities. In 1993, the Company's construction costs for environmental protection totaled approximately $18 million, while the on-going environmental operation costs were approximately $20 million. The Company's 1994 -- 1996 construction program includes costs for environmental protection which are estimated to be approximately $101 million, including $22.3 million in 1994, $41.8 million in 1995 and $36.9 million in 1996. These costs include expenditures to begin compliance with the Clean Air Act Amendments of 1990. However, governmental regulations establishing environmental protection standards are continually evolving and have not, in some cases, been fully established. Therefore, the Company may have to revise the estimates in response to developments in these and other areas.
AIR QUALITY. See "Management's Discussion and Analysis of Results of Operations and Financial Condition, Current Issues -- The Clean Air Act Amendments of 1990" for a discussion of the Company's plans for compliance with federal clean air standards. WATER QUALITY. The Federal Water Pollution Control Act Amendments of 1987 (otherwise known as the "Clean Water Act") require permits for facilities that discharge into waters, to ensure compliance with its provisions. The Company holds numerous such permits, and such permits are reissued periodically. The Federal Water Pollution Control Act is scheduled for reauthorization by Congress in 1994. Until Congress acts upon the reauthorization, management will be unable to assess what effect, if any, such reauthorization will have on the Company's operations. OTHER ENVIRONMENTAL REGULATIONS. Contingencies associated with environmental matters are principally related to possible obligations to remove or mitigate the effects on the environment resulting from the disposal of certain substances at contamination sites. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), commonly known as "Superfund", requires any individual or entity which may have owned or operated a contaminated site, as well as transporters or generators of hazardous wastes which were sent to such site, to assume joint and several responsibility for remediation of the site. Such parties are known as "potentially responsible parties" (PRPs). In 1993, Duke as a PRP, resolved litigation at a Superfund site in West Virginia, and is currently participating in a PRP group with regard to a Superfund site in Concord, North Carolina. Additionally, the Company is a DE MINIMUS contributor at two sites in Pennsylvania. The Company is also a PRP at contamination sites in Charlotte, North Carolina and Lenoir, North Carolina, which will likely be remediated in accordance with state acts which are similar to CERCLA. While the total cost of remediation at these federal and state contamination sites may be substantial, the Company shares probable liability with other PRPs, many of which have substantial assets. Other contamination sites relate to the Company's operation of manufactured gas plant (MGP) sites prior to the early 1950s, some of which are still owned by the Company and some of which are now owned by third parties. The Company is participating in a state-sponsored program which will result in the investigation and, where appropriate, remediation of MGP sites. Management is of the opinion that resolution of these matters will not have a material adverse effect on the results of operations or financial position of the Company. CERCLA is scheduled for reauthorization by Congress in 1994. Until Congress acts upon the reauthorization, management will be unable to assess what effect, if any, such reauthorization will have on the Company's operations. GENERAL. Over the past few decades, the issue of the possible health effects of electric and magnetic fields has generated a number of generally inconclusive studies, some public concern and litigation as well as legislative action in some states regarding high voltage transmission lines. The impact of this issue on the Company cannot presently be determined. NUCLEAR FACILITIES. The Company's nuclear facilities are subject to continuing regulation by the NRC. The steam generators at the McGuire and Catawba Nuclear Stations have experienced stress corrosion cracking in their tubes. Stress corrosion cracking is a phenomenon that typically occurs in tight U-bends, at tube support plates, and where tubes are attached to the tube sheets. Stress corrosion cracking has been identified as a problem in steam generators of certain designs, including those at the McGuire and Catawba Stations. The Company believes that the stress corrosion cracking is caused by defective design, workmanship and materials used by the manufacturer of the steam generators. Both primary side and secondary side cracking and corrosion have been observed in the steam generators at the McGuire and Catawba Stations. In addition, recent inspections at McGuire Units 1 and 2 have revealed a different type of secondary side stress corrosion cracking in the free-span area of the steam generator tubes located on the "cold-leg" side of those Units (cold-leg free-span cracking). The Company conducts tests at each refueling outage to determine the extent of stress corrosion cracking during the preceding fuel cycle. The steam generators at Catawba Unit 2 have certain design differences from those at Catawba Unit 1 or either McGuire Unit, but it is too early in the life of Catawba Unit 2 to determine the extent to which stress corrosion cracking will be a problem.
Although the Company has taken steps to mitigate the effects of stress corrosion cracking in the McGuire and Catawba steam generator tubes, including examining the steam generator tubes at each refueling outage, tube plugging, tube sleeving, more stringent water chemistry control, shot peening, and tight U-bend heat treatment, further stress corrosion cracking in the McGuire Units 1 and 2 and Catawba Unit 1 steam generators appears likely. Potential consequences of future stress corrosion cracking include extensive tube plugging and sleeving, additional water chemistry control, additional inspections and testing resulting in longer outages, mid-cycle outages, reduction in plant output, and requests for license amendments. The Company has compared the cost of continued repair of the steam generators with the cost of early steam generator replacement and has determined that for McGuire Units 1 and 2 and Catawba Unit 1, the most cost-effective alternative is to replace the steam generators as soon as it is feasible to do so. The Company has begun planning for the replacement of steam generators and has set the following schedule to begin the process: McGuire Unit 1 -- 1995; Catawba Unit 1 -- 1996; McGuire Unit 2 -- 1997. The order of replacement is subject to change based on performance of the existing steam generators and on the overall performance of the three units. The Company has signed an agreement with Babcock & Wilcox International to purchase 12 replacement steam generators for the McGuire and Catawba Stations. Each unit's steam generator replacement is expected to take approximately four months and cost approximately $170 million, excluding the cost of replacement power and without consideration of reimbursement of applicable costs by the Other Catawba Joint Owners of Catawba Unit 1. Stress corrosion problems are excluded under the nuclear insurance policies. The Company anticipates that the replacement of the steam generators should not have a material adverse effect on the Company's results of operations or financial position. Because Catawba Unit 2 has not shown the degree of stress corrosion cracking which has occurred in McGuire Units 1 and 2 and Catawba Unit 1, the Catawba Unit 2 steam generators have not been scheduled for replacement. The Company in connection with its McGuire and Catawba stations and on behalf of the Other Catawba Joint Owners commenced a legal action on March 22, 1990, in the United States District Court for the District of South Carolina (Charleston Division) seeking damages from Westinghouse Electric Corporation (Westinghouse) for supplying to the McGuire and Catawba Stations steam generators that were alleged to be defective in design, workmanship and materials, and that will require replacement well short of their stated design life. In the action, the Company sought a judgment against Westinghouse for damages of approximately $600 million, including the cost of necessary remedial measures, the cost of replacement of steam generators and payment for replacement power during the outages to accomplish replacement. In addition to these damages, the Company sought punitive or treble damages and attorneys' fees. The lawsuit was settled on March 17, 1994. (See "Subsequent Events.") NUCLEAR DECOMMISSIONING COSTS. Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $955 million stated in 1990 dollars. This amount includes the Company's 12.5 percent ownership in the Catawba Nuclear Station. The Other Catawba Joint Owners are liable for providing decommissioning related to their ownership interest in the Catawba Nuclear Station. Both the NCUC and the PSCSC have granted the Company recovery of the estimated site-specific decommissioning costs through retail rates over the expected remaining service periods of the Company's nuclear plants. Such estimates presume that units will be decommissioned as soon as possible following the end of their license life. Although subject to extension, the current operating licenses for the Company's nuclear units expire as follows: Oconee 1 and 2 -- 2013, Oconee 3 -- 2014; McGuire 1 -- 2021, McGuire 2 -- 2023; and Catawba 1 -- 2024, Catawba 2 -- 2026. The Nuclear Regulatory Commission (NRC) issued a rulemaking in 1988 which requires an external mechanism to fund the estimated cost to decommission certain components of a nuclear unit subject to radioactive contamination. In addition to the required external funding, the Company maintains an internal reserve to provide for decommissioning costs of plant components not subject to radioactive contamination. During 1993, the Company expensed approximately $52.5 million which was contributed to the external funds and accrued an additional $5 million to the internal reserve. The balance of the external funds as of December 31, 1993, was $118.5 million. The balance of the internal reserve as of December 31, 1993, was $200 million and is reflected in Accumulated depreciation and amortization on the Consolidated Balance Sheets. Management's opinion is that the estimated site-specific decommissioning costs being recovered through rates, when coupled with assumed after-tax fund earnings of 4.5 percent to 5.5 percent, are currently sufficient to provide for the cost of decommissioning based on Company's current decommissioning schedule.
A provision in the Energy Policy Act of 1992 established a fund for the decontamination and decommissioning of the DOE's uranium enrichment plants. Licensees are subject to an annual assessment for 15 years based on their pro rata share of past enrichment services. The annual assessment is recorded as fuel expense. The Company paid approximately $8.3 million during 1993 related to its ownership interest in nuclear plants. The Company has reflected the remaining liability and regulatory asset of approximately $117 million in the Consolidated Balance Sheets. NUCLEAR INSURANCE. For a discussion of the Company's nuclear insurance coverage, see "Notes to Consolidated Financial Statements, Note 13 -- Commitments and Contingencies -- Nuclear Insurance." HYDROELECTRIC LICENSES. The principal hydroelectric projects of the Company are licensed by FERC under Part I of the Federal Power Act. Eleven developments on the Catawba-Wateree River in North Carolina and South Carolina, with a nameplate rating of 804,940 KW, are licensed for a term expiring in 2008. The Company also holds a license for the Keowee-Toxaway Project for a term expiring in 2016, covering the Keowee Hydro Station and the Jocassee Pumped Storage Station for a combined total of 769,500 KW, on the upper tributaries of the Savannah River in northwestern South Carolina. Additionally, the Company is the licensee through 2027 for the Bad Creek Hydroelectric Station which uses Lake Jocassee as its lower reservoir and has a nameplate rating of 1,065,000 KW. The Federal Power Act provides, among other things, that, upon the expiration of any license issued thereunder, the United States may (a) grant a new license to the licensee for the project, (b) take over the project upon payment to the licensee of its "net investment" in the project (but not in excess of the fair value thereof) plus severance damages, or (c) grant a license for the project to a new licensee subject to payment to the former licensee of the amount specified in (b) above. INTERCONNECTIONS The Company has major interconnections and arrangements with its neighboring utilities which it considers adequate for coordinated planning, emergency assistance, exchange of capacity and energy, and reliability of power supply. COMPETITION The Company currently is subject to competition in some areas from government-owned power systems, municipally-owned electric systems, rural electric cooperatives and, in certain instances, from other private utilities. Statutes in North Carolina and South Carolina provide for the assignment by the NCUC and the PSCSC, respectively, of all areas outside municipalities in such states to power companies and rural electric cooperatives. Substantially all of the territory comprising the Company's service area has been so assigned. The remaining areas have been designated as unassigned and in such areas the Company remains subject to competition. A decision of the North Carolina Supreme Court limits, in some instances, the right of North Carolina municipalities to serve customers outside their corporate limits. In South Carolina there continues to be competition between municipalities and other electric suppliers outside the corporate limits of the municipalities, subject, however, to the regulation of the PSCSC. In addition, the Company is engaged in continuing competition with various natural gas providers. The Energy Policy Act of 1992 has far-reaching implications for the Company by moving utilities toward a more competitive environment. The Act reformed certain provisions of the Public Utility Holding Company Act of 1935 (PUHCA) and removed certain regulatory barriers. For example, the Act allows utilities to develop independent electric generating plants in the United States for sales to wholesale customers, as well as to contract for utility projects internationally, without becoming subject to registration under PUHCA as an electric utility holding company. The Act requires transmission of power for third parties to wholesale customers, provided that the reliability of service to the utility's local customer base is protected and the local customer base does not subsidize the third-party service. Although the Act does not require transmission access to retail customers, states can authorize such transmission access to and for retail electric customers. The electric utility industry is predominantly regulated on a basis designed to recover the cost of providing electric power to its retail and wholesale customers. If cost-based regulation were to be discontinued in the industry for any reason, including competitive pressure on the price of electricity, utilities might be forced to reduce their assets to reflect market basis if such basis is less than cost. Discontinuation of cost-based regulation could also require some utilities to write off their regulatory assets. Management cannot predict the potential impact, if
any, of these competitive forces on the future financial position and results of operations of the Company. However, the Company is continuing to position itself to effectively meet these challenges by maintaining prices that are regionally and nationally competitive. NON-UTILITY ACTIVITIES The Company is engaged in a variety of non-utility operations, including real estate development and forest management, marketing of electrical appliances, management of passive financial investments, developing and investing in electric generation and transmission facilities outside the Company's service area and providing engineering and technical services. Most of the Company's non-utility operations are organized in separate subsidiaries. Subsidiary and diversified operations contributed $22 million after tax to corporate earnings in 1993. A major part of the future growth in the electric power market is anticipated to be outside the traditional regulated framework and, to a large extent, outside the United States. The Company, through its subsidiaries, is participating in these international opportunities and continues participating in domestic opportunities to provide additional value to its shareholders. Internationally, the Company is seeking opportunities to provide engineering consulting services, construction, operation and maintenance of generating facilities, and ownership of transmission and generating facilities. Although these opportunities are concentrated in areas that utilize the Company's expertise, they present different and greater risks than the Company's core business. The Company considers only opportunities in which the expected return is commensurate with the risks, and makes efforts to mitigate such risks. In March 1993, Duke Energy Group (DEG) invested $25 million in convertible preferred stock of J. Makowski & Company (Makowski), a developer of natural gas-fired electric projects, and is providing $10.2 million in credit support for a Makowski project. Additionally, DEG has one seat on the Board of Directors of Makowski. In June 1993, after a competitive bidding process, the Argentine government awarded the right to buy 65 percent of the stock of Compania de Transporte de Energia Electrica en Alta Tension S. A. (Transener) to a consortium led by DEG. Transener is Argentina's primary transmission company. It employs about 1,100 persons, and has 6,867 kilometers of 500 kilovolt lines, 284 kilometers of 220 kilovolt lines, and 27 substations. The consortium assumed ownership and operation of the system on July 16, 1993. Another consortium, also led by DEG, was awarded the majority ownership and operation of Hidroelectrica Piedra del Aguila S.A. on November 29, 1993. Hidroelectrica Piedra del Aguila S.A. owns a hydroelectric facility located in southwestern Argentina. When fully operational in 1995, the facility will have a capacity of 1,400 megawatts. The consortium assumed ownership of 59 percent of the stock of Hidroelectrica Piedra del Aguila S.A., and took over operation of the hydroelectric complex on December 29, 1993. EMPLOYEES At December 31, 1993, the Company employed 18,274 full-time persons, which includes 789 full-time employees of subsidiaries and affiliates. About 2,000 electrical operating employees are represented by the International Brotherhood of Electrical Workers (IBEW). The Company reached a new labor agreement with the IBEW, effective October 1, 1993, for a one year term. The Company has been engaged in a concentrated effort to more efficiently and effectively utilize its resources through better work practices. During the first quarter of 1993, the Company offered a Limited Period Separation Opportunity Program (LPSO) which gave employees the option of leaving the Company for a lump sum severance payment and, for qualifying employees, enhanced retirement benefits. On March 15, 1994, the Company announced plans to offer Enhanced Voluntary Separation (EVS), a severance package, for employees who choose to leave the Company voluntarily during the second quarter of 1994. Implementing programs such as LPSO, EVS and other efficiency practices has resulted in continued workforce reduction and in streamlined workflows. The number of full-time employees has decreased to the present level from 19,945 at year-end 1990. The 1990 amount included 496 employees of subsidiaries and affiliates.
SUBSEQUENT EVENTS On January 25, 1994, the Board of Directors selected William H. Grigg, Vice Chairman of the Board, to succeed William S. Lee as Chairman of the Board, President and Chief Executive Officer, effective at the Annual Meeting of Shareholders to be held on April 28, 1994. Mr. Lee will serve the Company as a consultant after that date until his retirement following his 65th birthday in June 1994. On March 2, 1994, the Duke Endowment announced its intention to diversify its investment portfolio by selling up to 16 million shares of its Duke Power Common Stock. A registration statement was filed with the Securities and Exchange Commission on that day and underwriting agreements were entered into on March 29, 1994 relating to the sale of 14 million of such shares, with over-allotment options of up to 2 million shares. The Duke Endowment will retain approximately 10 million shares after the sale (assuming the over-allotment options are exercised), and has announced that it has no present intention to dispose of any additional shares of Common Stock. On March 17, 1994, the Company, together with the Other Catawba Joint Owners, settled the lawsuit initiated by the Company on March 22, 1990 against Westinghouse Electric Corporation seeking damages for supplying to the McGuire and Catawba Nuclear Stations steam generators that were alleged to be defective in design, workmanship and materials and that would require replacement well short of their stated design life. While the terms of the settlement may not be disclosed pursuant to court order, the Company believes the litigation was settled on terms that provided satisfactory consideration to the Company. Such settlement will not have a material effect on the Company's results of operations or financial position. (See "Regulation -- Nuclear Facilities" and "Management's Discussion and Analysis of Results of Operations and Financial Condition, Current Issues -- Stress Corrosion Cracking.")
(graphic--full page map showing the Duke Power Service Area)
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 years 1989 and 1990 include a reclassification for certain power transactions previously classified as Net interchange and purchased power prior to a 1990 FERC order. (d) Does not reflect operating statistics, kilowatt-hour sales and revenues of Nantahala Power and Light Company. (e) Includes sales to Nantahala Power and Light Company. (f) 1991 restated to eliminate certain duplicate customers.
EXECUTIVE OFFICERS OF THE COMPANY
OTHER OFFICERS
* As of February 1, 1994. **Member of the Management Committee.
Executive officers are elected annually by the Board of Directors and serve until the first meeting of the Board of Directors following the next annual meeting of shareholders and until their successors are duly elected. There are no family relationships between any of the executive officers nor any arrangement or understanding between any executive officer and any other person pursuant to which the officer was selected. All of the above executive officers have held responsible positions with the Company for the past five years. There have been no events under any bankruptcy act, no criminal proceedings and no judgments or injunctions material to the evaluation of the ability and integrity of any executive officer during the past five years. ITEM 2.
ITEM 2. PROPERTIES. The map on page 12 shows the location of the Company's service area and generating stations. Reference is made to Schedule V -- Property, Plant and Equipment for information concerning the Company's investment in utility plant. Substantially all electric plant is mortgaged under the Indenture relating to the First and Refunding Mortgage Bonds of the Company. For additional information concerning the properties of the Company, see "Business -- Energy Management and Future Power Needs". ITEM 3.
ITEM 3. LEGAL PROCEEDINGS. Reference is made to "Notes to Consolidated Financial Statements, Note 13 -- Commitments and Contingencies", "Business -- Regulation -- NUCLEAR FACILITIES" and "Subsequent Events". ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. No matters were submitted to a vote of the Company's security holders during the last quarter of 1993. PART II. ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. The Common Stock of the Company is traded on the New York Stock Exchange. At December 31, 1993, there were approximately 127,688 holders of shares of such Common Stock. The following table sets forth for the periods indicated the dividends paid per share of Common Stock and the high and low sales prices of such shares reported by the New York Stock Exchange Composite Transactions:
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
(a) Electric revenues, Electric expenses, Kilowatt-hour sales and Net interchange and purchased power for the years 1989 and 1990 include a reclassification for certain power transactions previously classified as Net interchange and purchased power prior to a 1990 FERC order. (b) All common stock data reflects the two-for-one split of common stock on September 28, 1990.
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 27 percent from $2.21 in 1992 to $2.80 in 1993. The increase was primarily due to higher kilowatt-hour sales and a one-time charge taken in 1992 related to a rate refund to North Carolina retail customers of $.32 per share. (For additional information on the refund, see Liquidity and Resources "Rate Matters," page 18.) The increase was partially offset by higher operating and maintenance expenses, additional charitable contributions to the Duke Power Company Foundation and an increase in the federal income tax rate caused by the Omnibus Budget Reconciliation Act of 1993. Higher general taxes also decreased earnings.
Earnings per share increased from $2.60 in 1991 to $2.80 in 1993, indicating an average annual growth rate of 4 percent. Total Company earned return on average common equity was 13.6 percent in 1993 compared to 11.1 percent in 1992 and 13.5 percent in 1991.
The Company continued its practice of increasing the common stock dividend annually. Common dividends per share increased from $1.68 in 1991 to $1.84 in 1993, rising at an average annual rate of 5 percent. Indicated annual dividends per share increased to $1.88.
Revenue and Sales Revenues increased at an average annual rate of 6 percent from 1991 to 1993, primarily because of increased overall kilowatt-hour sales and the November 1991 rate increases.
Kilowatt-hour sales for 1993 increased 7 percent compared to 1992. Sales to residential customers increased by 9 percent reflecting colder winter weather and a hotter-than-normal summer. General service customer kilowatt-hour sales increased by 7 percent as a result of both continued economic growth and weather trends cited above. Sales to other-industrial customers and textile customers increased by 6 percent and 2 percent, respectively, as a result of the continued economic growth in the Company's service area.
Operating Expenses From 1992 to 1993, non-fuel operating and maintenance expenses rose 4 percent. Administrative and general expenses increased partly because of increased pension expenses to reflect more conservative investment return assumptions and one-time costs associated with a voluntary separation option offered during the first quarter of 1993. A winter storm during the first quarter of 1993 also increased non-fuel operating and maintenance expenses. These increases from 1992 to 1993 were partially offset by lower nuclear and fossil maintenance expenses resulting from lower outage costs.
Non-fuel operating and maintenance expenses increased at an average annual rate of 5 percent from 1991 to 1993. Administrative and general expenses increased over this period because of the implementation of a new accounting standard in January 1992 that reflects accrual basis accounting for certain postretirement health care and life insurance benefits, in addition to the reasons cited in the preceding paragraph. Operating and maintenance expenses for fossil and hydro plants also increased from 1991 to 1993. Fossil increases were caused by bringing refurbished units back on-line, and hydro increases were the result of the completion of the Bad Creek Hydroelectric Station in late 1991.
Net interchange and purchased power decreased at an average annual rate of 1 percent from 1991 to 1993. A slight decline in the amount of purchased power from the other Catawba joint owners as recognized on the income statement was substantially offset by increased purchases from other utilities. (For additional information on the Catawba purchase power agreements, see Note 3 to the Consolidated Financial Statements.)
Fuel expense increased at an average annual rate of 6 percent from 1991 to 1993. The increase was due primarily to higher system production requirements that were satisfied by increased fossil generation. A continued decline of fuel prices over this period helped to offset the overall increase in fuel expenses.
From 1991 to 1993, depreciation and amortization expense increased at an average annual rate of 6 percent primarily because of the completion of the Bad Creek Hydroelectric Station in 1991 and added investment in distribution property.
Other Income and Interest Deductions Allowance for funds used during construction (AFUDC) represented 5 percent of earnings for common stock in 1993 compared to 13 percent in 1991. The decrease is primarily the result of the completion of the Bad Creek Hydroelectric Station in 1991. AFUDC is expected to represent less than 10 percent of total earnings during the next three years.
The carrying charge, net of associated taxes, on the purchased capacity levelization deferral related to the joint ownership of the Catawba Nuclear Station represented 6 percent of total earnings in 1993, compared to 6 percent in 1992 and 5 percent in 1991. This carrying charge and the related tax benefits are included in Other, net and Income taxes -- other, net, respectively. The growth in this carrying charge is due to the increasing cumulative impact of the Company's funding of purchased power costs which current rates are expected to collect in future periods. The Company recovers the accumulated balance, including the carrying charge, when the declining purchased capacity payments drop below the levelized revenues. (For additional information on purchased capacity levelization, see Capital Needs "Purchased Capacity Levelization," page 19.)
Interest on long-term debt decreased at an average annual rate of 3 percent from 1991 to 1993. The decrease is due to the Company's refinancing of higher cost debt beginning in late 1991 and continuing throughout 1993. From 1992 to 1993, Other interest decreased as a result of the one-time impact in 1992 of approximately $27 million in interest paid to North Carolina retail customers due to a rate refund.
Income provided by diversified activities and the Company's subsidiaries was $22.0 million in 1993 compared to $25.7 million in 1992 and $23.6 million in 1991. The activities of Crescent Resources, Inc., the Company's real estate development and forest management subsidiary, generated the majority of subsidiary and non-electric earnings. Other components include subsidiary investment income, fees for engineering services, construction and operation of generation and transmission
facilities outside the Company's service area, water operations and merchandising.
Liquidity and Resources Rate Matters During 1991, the Company filed in both the North Carolina and South Carolina retail jurisdictions its only requests for general rate increases since 1986. The rate increases were primarily needed to recover costs associated with the construction of the Bad Creek Hydroelectric Station. In North Carolina, the Company requested a 9.22 percent rate increase and was granted a 4.15 percent increase, which resulted in additional annual revenues of $100.1 million. In South Carolina, a 7.29 percent increase was requested and a 3.0 percent rate increase was granted, resulting in additional annual revenues of $30.2 million.
Also in 1991, the Company filed a request for a wholesale rate increase with the Federal Energy Regulatory Commission (FERC). A negotiated settlement between the Company and the wholesale customers was approved by the FERC on March 31, 1992. The approved agreement, effective April 1, 1992, provided for a 3.3 percent rate increase, resulting in $2.1 million in additional annual revenues.
The North Carolina Supreme Court on April 22, 1992, remanded for the second time the Company's 1986 rate order to the North Carolina Utilities Commission (NCUC). In this ruling, the Court held that the record from the 1986 proceedings failed to support the rate of return on common equity of 13.2 percent authorized by the NCUC after the initial decision of the Court remanding the 1986 rate order. The NCUC issued a final order dated October 26, 1992, authorizing a 12.8 percent return on common equity for the period October 31, 1986, through November 11, 1991. This order resulted in a 1992 refund to North Carolina retail customers of approximately $95 million, including interest.
The Company has a bulk power sales agreement with Carolina Power & Light Company (CP&L) to provide CP&L 400 megawatts of capacity as well as associated energy when needed for a six-year period which began July 1, 1993. Electric rates in all regulatory jurisdictions were reduced by adjustment riders to reflect capacity revenues received from this CP&L bulk power sales agreement.
The other joint owners of the Catawba Nuclear Station and the Company are involved in various proceedings related to the Catawba joint ownership contractual agreements. The basic contention in each proceeding is that certain calculations affecting bills under these agreements should be performed differently. These items are covered by the agreements between the Company and the other Catawba joint owners which have been previously approved by the Company's retail regulatory commissions. (For additional information on Catawba joint ownership, see Note 3 to the Consolidated Financial Statements.) The Company and two of the four joint owners have entered into a proposed settlement agreement which, if approved by the regulators, will resolve all issues in contention in such proceedings between the Company and these owners. The Company recorded a liability as an increase to Other current liabilities on its Consolidated Balance Sheets of approximately $105 million in 1993 to reflect this proposed settlement. In addition, future estimated obligations in connection with the settlement are reflected in estimates of purchased capacity obligations in Note 3. As the Company expects the costs associated with this settlement will be recovered as part of the purchased capacity levelization, the Company has included approximately $105 million as an increase to Purchased capacity costs on its Consolidated Balance Sheets. Therefore, the Company believes the ultimate resolution of these matters should not have a material adverse effect on the results of operations or financial position of the Company.
Although the two other Catawba joint owners, who are not parties to the above settlement, have not fully quantified the dollars associated with their claims in the presently outstanding proceedings, information associated with these proceedings indicates that the amount in contention could be as high as $110 million, through December 31, 1993. Arbitration hearings were held in 1992 involving substantially all the disputed amounts, and a decision interpreting the language of the agreements on certain of these matters was issued on October 1, 1993. Further proceedings will be required to determine the amounts associated with this decision as it relates to these owners, some of which may involve refunds. However, the Company expects the costs associated with this decision will be included in and recovered as part of the purchased capacity levelization consistent with prior orders of the retail regulatory commissions. Therefore, the Company believes the ultimate resolution of these matters should not have a material adverse effect on the results of operations or financial position of the Company.
The Company is also involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business, some of which involve substantial amounts. Management is of the opinion that the final disposition of these proceedings will not have a material adverse effect on the results of operations or the financial position of the Company.
Cash From Operations In 1993, net cash provided by operating activities accounted for 46 percent of total cash from operating, financing and investing activities compared to 50 percent in 1992 and 77 percent in 1991. For 1993 and 1992, essentially all the Company's capital needs, exclusive of refinancing activities, were met by cash generated from operations.
Financing and Investing Activities The Company's capital structure, including subsidiary capitalization, at year- end 1993 was 52 percent common equity, 39 percent long-term debt and 9 percent preferred stock. This structure is consistent with the Company's target to maintain an "AA" credit rating. As of December 31, 1993, the Company's bonds were rated "AA" by Fitch Investors Service, "Aa2" by Moody's Investors Service, and "AA-" by Standard & Poor's Ratings Group and Duff & Phelps.
As a result of favorable market conditions, the Company continued refinancing activities to retire higher cost debt and preferred stock. During 1993, the Company obtained proceeds from the issuance of $1.5 billion in long-term debt and $220 million in preferred stock, most of which were used to retire $1.4 billion of long-term debt and $216 million of preferred stock.
In 1992, the Company issued $940 million in long-term debt. Most of these proceeds, combined with the proceeds from bonds issued in late 1991, were used to redeem $884 million of long-term debt. During 1992, the Company also issued $284 million of preferred stock, most of which was used to redeem $229 million of preferred stock.
Also on April 6, 1992, the Company redeemed all outstanding shares of the Cumulative Preference Stock 6 3/4 percent Convertible Series AA at its par value of $100 per share.
The Company's embedded cost of long-term debt for 1993 decreased to 8.01 percent compared to 8.39 percent in 1992 and 8.72 percent in 1991. The embedded cost of preferred stock declined to 6.76 percent in 1993 from 7.05 percent in 1992 and 7.48 percent in 1991. These decreases are primarily the result of the Company's refinancing activities. Downward trends in embedded costs may level off because of fewer refinancing opportunities.
Fixed Charges Coverage Fixed charges coverage using the SEC method increased to 4.68 times for 1993 compared to 3.48 and 3.85 times, respectively, in 1992 and 1991. Fixed charges coverage, excluding AFUDC and the return on purchased capacity levelization, was 4.40 times in 1993 compared to 3.27 in 1992 and 3.46 in 1991 and the Company goal of 3.5 times. In 1992, the coverage under both methods was lower because of the impact of the rate refund.
Capital Needs Property Additions and Retirements Additions to property and nuclear fuel of $676 million and retirements of $312 million resulted in an increase in gross plant of $364 million in 1993.
Since January 1, 1991, additions to property and nuclear fuel of $2.1 billion and retirements of $780 million have resulted in an increase in gross plant of $1.3 billion.
Construction Expenditures Plant construction costs for generating facilities, including AFUDC, decreased from $232 million in 1991 to $182 million in 1993. Completion of the Bad Creek Hydroelectric Station in 1991 was a significant part of the decrease. Construction costs for distribution plant, including AFUDC, decreased from $275 million in 1991 to $240 million in 1993.
Projected construction and nuclear fuel costs, both including AFUDC, are $2.3 billion and $394 million, respectively, for 1994 through 1996. Total projected construction costs include expenditures for the construction of the Lincoln Combustion Turbine Station and replacement of certain steam generators at the McGuire Nuclear Station and the Catawba Nuclear Station. (For additional information on steam generator replacement, see Current Issues "Stress Corrosion Cracking," page 21.) For 1994 through 1996, the Company anticipates funding its projected construction and nuclear fuel costs through the internal generation of funds and, to a lesser extent, through the issuance of securities, primarily First and Refunding Mortgage Bonds.
Purchased Capacity Levelization The rates established in the Company's retail jurisdictions permit the Company to recover its investment in both units of the Catawba Nuclear Station and the costs associated with contractual purchases of capacity from the other Catawba joint owners. The contracts relating to the sales of portions of the station obligate the Company to purchase a declining amount of capacity from the other joint owners. In the North Carolina retail jurisdiction, regulatory treatment of these contracts provides revenue for recovery of the capital costs and the fixed operating and maintenance costs of purchased capacity on a levelized basis. In the South Carolina retail jurisdiction, revenues are provided for the recovery of the capital costs of purchased capacity on a levelized basis, while current rates include recovery of fixed operating and maintenance expenses.
These rate treatments require the Company to fund portions of the purchased power payment until these costs, including carrying charges, are recovered at a later date. The Company recovers the accumulated costs and carrying charges when the declining purchased capacity payments drop below the levelized revenues. In the North Carolina and wholesale jurisdictions, purchased capacity payments continue to exceed levelized revenues. In the South Carolina jurisdiction, cumulative levelized revenues have exceeded purchased capacity payments. Jurisdictional levelizations are intended to recover total costs, including allowed returns, and are subject to adjustments, including final true-ups.
Meeting Future Power Needs The Company's strategy for meeting customers' present and future energy needs is composed of three components: supply-side resources, demand-side resources and purchased power resources. To assist in determining the optimal combination of these three resources, the Company uses its integrated resource planning process. The goal is to provide adequate and reliable electricity in an environmentally responsible manner through cost-effective power management.
The Company is building a combustion turbine facility in Lincoln County, North Carolina. The Lincoln Combustion Turbine Station will consist of 16 combustion turbines with a total generating capacity of 1,184 megawatts. The estimated total cost of the project is approximately $500 million. Current plans are for ten units to begin commercial operation by the end of 1995 and the remaining six to begin commercial operation before the end of 1996. The Lincoln facility will provide capacity at periods of peak demand.
Demand-side management programs are a part of meeting the Company's future power needs. These programs benefit the Company and its customers by providing for load control through interruptible control features, shifting usage to off-peak periods, increasing usage during off-peak periods, and by promoting energy efficiency. In return for participation in demand-side management programs, customers may be eligible to receive various incentives which help to reduce their electric bills. Demand-side management programs such as Industrial Interruptible Service and Residential Load Control can be used to manage capacity availability problems. Energy-efficiency programs such as high-efficiency chillers, high-efficiency heat pumps and high-efficiency air conditioners are other examples of current demand-side management programs. The November 1991 rate orders of the NCUC and The Public Service Commission of South Carolina (PSCSC) provided for recovery
in rates of a designated level of costs for demand-side management programs and allowed the deferral for later recovery of certain demand-side management costs that exceed the level reflected in rates, including a return on the deferred costs. As additional demand-side costs are incurred, the Company ultimately expects recovery of associated costs, which are currently being deferred, through rates. The annual costs deferred, including the return, were approximately $26 million in 1993 and $18 million in 1992.
The purchase of capacity and energy is also an integral part of meeting future power needs. The Company currently has under contract 500 megawatts of capacity from other generators of electricity.
Current Issues While the Company improved its financial performance in 1993 compared to 1992, the ability to maintain and improve its current level of earnings will depend on several factors. Future trends in the Company's earnings will depend on the continued economic growth in the Piedmont Carolinas, the Company's ability to contain costs, its ability to maintain competitive prices, the outcome of various legislative and regulatory actions and the success of the Company's diversified activities.
Resource Optimization. The Company has been engaged in a concentrated effort to more efficiently and effectively use its resources through better work practices. During the first quarter of 1993, the Company offered a Limited Period Separation Opportunity program (LPSO) which gave employees the option of leaving the Company for a lump sum severance payment and, for qualifying employees, enhanced retirement benefits. Implementing programs such as LPSO and other efficiency practices has resulted in a continued workforce reduction and in streamlined workflows. The number of full-time employees has decreased from 19,945 at year-end 1990 to 18,274 at year-end 1993. Included in these amounts are 496 and 789 employees of subsidiaries and affiliates for 1990 and 1993, respectively.
Income Tax Accounting Change. In January 1993, the Company implemented a standard as required by the Financial Accounting Standards Board (FASB) that requires a liability approach for financial accounting and reporting for income taxes. While classification of certain items on the Consolidated Balance Sheets has changed, principally because certain items previously reported net of tax are now being reported on a gross basis, there is no material effect on the Company's results of operations.
Nuclear Decommissioning Costs. Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $955 million stated in 1990 dollars. This amount includes the Company's 12.5 percent ownership in the Catawba Nuclear Station. The other joint owners of the Catawba Nuclear Station are liable for providing decommissioning related to their ownership interests in the station. Both the NCUC and the PSCSC have granted the Company recovery of the estimated site-specific decommissioning costs through retail rates over the expected remaining service periods of the Company's nuclear plants. Such estimates presume that units will be decommissioned as soon as possible following the end of their license life. Although subject to extension, the current operating licenses for the Company's nuclear units expire as follows: Oconee 1 and 2 - 2013, Oconee 3 - 2014; McGuire 1 - 2021, McGuire 2 - 2023; and Catawba 1 - 2024, Catawba 2 - 2026.
The Nuclear Regulatory Commission (NRC) issued a rule-making in 1988 which requires an external mechanism to fund the estimated cost to decommission certain components of a nuclear unit subject to radioactive contamination. In addition to the required external funding, the Company maintains an internal reserve to provide for decommissioning costs of plant components not subject to radioactive contamination. During 1993, the Company expensed approximately $52.5 million which was contributed to the external funds and accrued an additional $5.0 million to the internal reserve. The balance of the external funds as of December 31, 1993, was $118.5 million. The balance of the internal reserve as of December 31, 1993, was $200.0 million and is reflected in Accumulated depreciation and amortization on the Consolidated Balance Sheets. Management's opinion is that the estimated site-specific decommissioning costs being recovered through rates, when coupled with assumed after-tax fund earnings of 4.5 percent to 5.5 percent, are currently sufficient to provide for the cost of decommissioning based on the Company's current decommissioning schedule.
Environmental Update. The Company is subject to federal, state and local regulations with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. The Company was an operator of manufactured gas plants prior to the early 1950s. The Company is entering into a cooperative effort with the State of North Carolina and other owners of certain former manufactured gas plant sites to investigate and, where necessary, remediate these contaminated sites. The State of South Carolina has expressed interest in entering into a similar arrangement. The Company is considered by regulators to be a potentially responsible party and may be subject to liability at two federal Superfund sites and two comparable state sites. While the cost of remediation of these sites may be substantial, the Company will share in any liability associated with remediation of contamination at such sites with other potentially responsible parties. Management is of the opinion that resolution of these matters will not have a material adverse effect on the results of operations or financial position of the Company.
The Clean Air Act Amendments of 1990. The Clean Air Act Amendments of 1990 require a two-phase reduction by electric utilities in the aggregate annual emissions of sulfur dioxide and nitrogen oxide by the year 2000. The Company currently meets all requirements of Phase I. The Company supports the national objective of clean air in the most cost-effective manner and has already reduced emissions through the use of low-sulfur coal in its fossil plants, through efficient operations and by using nuclear generation. The sulfur dioxide provisions of the Act allow utilities to choose among various alternatives for compliance. The Company is currently developing a detailed
compliance plan for Phase II requirements which must be filed with the Environmental Protection Agency (EPA) by 1996. A preliminary strategy, which allows for varying options, indicates that one-time costs associated with bringing the Company into compliance with the Act could be as high as $1 billion, and that approximately $75 million in additional annual operating and maintenance expenses will be incurred as well. These one-time costs could be less depending on favorable developments in the emissions allowance market, future regulatory and legislative actions, and advances in clean air technology. All options within the preliminary strategy allow for full compliance of Phase II requirements by the year 2000.
Stress Corrosion Cracking (SCC). Stress corrosion cracking has occurred in the steam generators of Units 1 and 2 at the McGuire Nuclear Station and Unit 1 at the Catawba Nuclear Station. The Company is of the opinion that the SCC is caused by the defective design, workmanship and materials used by the manufacturer of the steam generators. Catawba Unit 2, which has certain design differences and came into service at a later date, has not yet shown the degree of SCC which has occurred in McGuire Units 1 and 2 and Catawba Unit 1. It is, however, too early in the life of Catawba Unit 2 to determine the extent to which SCC will be a problem. Although the Company has taken steps to mitigate the effects of SCC, the inherent potential for future SCC in the Catawba and McGuire steam generators still exists. The Company has begun planning for the replacement of steam generators and has set the following schedule to begin the process: McGuire Unit 1 - 1995, Catawba Unit 1 - 1996, McGuire Unit 2 - 1997. The Catawba Unit 2 steam generators have not been scheduled for replacement. The order of replacement is subject to change based on performance of the existing steam generators and on the overall performance of the three units. The Company has signed an agreement with Babcock & Wilcox International to purchase replacement steam generators. Steam generator replacement at each unit is expected to take approximately four months and cost approximately $170 million, excluding the cost of replacement power and without consideration of reimbursement of applicable costs by the other joint owners of Catawba Unit 1. Stress corrosion problems are excluded under the nuclear insurance policies.
The Company in connection with its McGuire and Catawba stations and on behalf of the other joint owners of the Catawba Station--North Carolina Municipal Power Agency Number 1, North Carolina Electric Membership Corporation, Piedmont Municipal Power Agency and Saluda River Electric Cooperative, Inc.-- commenced a legal action on March 22, 1990. This action alleges that Westinghouse Electric Corporation (Westinghouse), the supplier of the steam generators, knew, or recklessly disregarded information in its possession, that the steam generators supplied to McGuire and Catawba stations would be susceptible to SCC and that Westinghouse deliberately concealed such information from the Company. The Company is seeking a judgment against Westinghouse for damages of approximately $600 million, including the cost of necessary remedial measures, the cost of replacement steam generators and payment for replacement power during the outages to accomplish the replacement. In addition to these damages, the Company is seeking punitive or treble damages and attorneys' fees. A trial date has been set for March 14, 1994.
Competition. The Energy Policy Act of 1992 has far-reaching implications for the Company by moving utilities toward a more competitive environment. The Act reformed certain provisions of the Public Utility Holding Company Act of 1935 (PUHCA) and removed certain regulatory barriers. For example, the Act allows utilities to develop independent electric generating plants in the United States for sales to wholesale customers, as well as to contract for utility projects internationally, without becoming subject to registration under PUHCA as an electric utility holding company. The Act requires transmission of power for third parties to wholesale customers, provided the reliability of service to the utility's local customer base is protected and the local customer base does not subsidize the third-party service. Although the Act does not require transmission access to retail customers, states can authorize such transmission access to and for retail electric customers.
The electric utility industry is predominantly regulated on a basis designed to recover the cost of providing electric power to its retail and wholesale customers. If cost-based regulation were to be discontinued in the industry, for any reason, including competitive pressure on the price of electricity, utilities might be forced to reduce their assets to reflect their market basis if such basis is less than cost. Discontinuance of cost-based regulation could also require some utilities to write off their regulatory assets. Management cannot predict the potential impact, if any, of these competitive forces on the Company's future financial position and results of operations. However, the Company is continuing to position itself to effectively meet these challenges by maintaining prices that are regionally and nationally competitive.
Subsidiary Activities. A major part of the future growth in the electric power market is anticipated to be outside the traditional regulated framework and, to a large extent, outside the United States. The Company, through its subsidiaries, is participating in these international opportunities and continues participating in domestic opportunities to provide additional value to its shareholders. Internationally, the Company is seeking opportunities to provide engineering consulting services, construction, operation and maintenance of generation facilities, and ownership of transmission and generation facilities. Although these opportunities are concentrated in areas that utilize the Company's expertise, they present different and greater risks than does the Company's core business. The Company considers only opportunities in which the expected returns are commensurate with the risks and makes efforts to mitigate such risks. At December 31, 1993, the Company had equity investments of $84.5 million in international transmission and generation facilities and $17.1 million in electric assets within the United States, but outside its current service area. The Company is actively pursuing additional international and domestic opportunities to capitalize on the future potential growth of this market.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. DUKE POWER COMPANY INDEX
CONSOLIDATED STATEMENTS OF INCOME
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENTS OF CASH FLOWS
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CONSOLIDATED BALANCE SHEETS ASSETS
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CONSOLIDATED STATEMENTS OF CAPITALIZATION AND RETAINED EARNINGS
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Notes To Consolidated Financial Statements
Note 1. Summary of Significant Accounting Policies A. Revenues
Revenues are recorded as service is rendered to customers. "Receivables" on the Consolidated Balance Sheets include $175,726,000 and $167,610,000 as of December 31, 1993 and 1992, respectively, for service that has been rendered but not yet billed to customers.
B. Additions to Electric Plant
The Company capitalizes all construction-related direct labor and materials as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of money (allowance for funds used during construction). The cost of renewals and betterments of units of property is capitalized. The cost of repairs and replacements representing less than a unit of property is charged to electric expenses. The original cost of property retired, together with removal costs less salvage value, is charged to accumulated depreciation.
C. Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new facilities. AFUDC, a non- cash item, is recognized as a cost of "Construction work in progress" (CWIP), with offsetting credits to "Other income" and "Interest deductions." After construction is completed, the Company is permitted to recover these construction costs, including a fair return, through their inclusion in rate base and in the provision for depreciation. The 1993 AFUDC rate of 9.29 percent reflects "Allowance for borrowed funds used during construction" calculated using a pre-tax cost of debt. The rates for 1992 and 1991 of 8.07 percent and 8.86 percent have been calculated using a net of tax cost of debt. Rates for all periods are compounded semiannually. The change in calculation from a net of income tax to a pre-tax basis is a result of the adoption of Statement of Financial Accounting Standards No. 109 (SFAS 109). (See Note 4.)
D. Depreciation and Amortization
Provisions for depreciation are recorded using the straight-line method. The year-end composite weighted-average depreciation rates were 3.47 percent for 1993 and 3.48 percent for 1992 and 1991. Effective with the implementation of new retail rates in November 1991, all coal-fired generating units are depreciated at a rate of 2.57 percent and all nuclear units are depreciated at a rate of 4.70 percent, of which 1.61 percent is for decommissioning. (See Note 16.) Amortization of nuclear fuel is included in "Fuel used in electric generation" in the Consolidated Statements of Income. The amortization is recorded using the units-of-production method. Under provisions of the Nuclear Waste Policy Act of 1982, the Company has entered into contracts with the Department of Energy (DOE) for the disposal of spent nuclear fuel. Payments made to the DOE for disposal costs are based on nuclear output and are included in "Fuel used in electric generation" in the Consolidated Statements of Income. A provision in the Energy Policy Act of 1992 established a fund for the decontamination and decommissioning of the DOE's uranium enrichment plants. Licensees are subject to an annual assessment for 15 years based on their pro rata share of past enrichment services. The annual assessment is recorded as fuel expense. The Company paid $8,338,000 during 1993 related to its ownership interest in nuclear plants. The Company has reflected the remaining liability and regulatory asset of $116,731,000 in the Consolidated Balance Sheets.
E. Subsidiaries
The Company's consolidated financial statements reflect consolidation of all of its wholly-owned subsidiaries. Intercompany transactions have been eliminated in consolidation. (See Note 11 and "Subsidiary Highlights," page 41.)
F. Income Taxes
The Company implemented SFAS 109, "Accounting for Income Taxes," effective January 1, 1993. (See Note 4.) The Company and its subsidiaries file a consolidated federal income tax return. Income taxes have been allocated to each company based on its separate company taxable income or loss. Income taxes are allocated to non-electric operations under "Other income" and to electric operating expense. The "Income taxes - credit" classified under "Other income" results from tax deductions of interest costs relating primarily to deferred purchased capacity costs and CWIP. Deferred income taxes have been provided for temporary differences between book and tax income, principally resulting from accelerated tax depreciation and levelization of purchased power costs. Investment tax credits have been deferred and are being amortized over the estimated useful lives of the related properties.
G. Unamortized Debt Premium, Discount and Expense
Expenses incurred in connection with the issuance of presently outstanding long-term debt, and premiums and discounts relating to such debt, are being amortized over the terms of the respective issues. Also, any expenses or call premiums associated with refinancing higher-cost debt obligations are being amortized over the lives of the new issues of long-term debt.
H. Fuel Cost Adjustment Procedures
Fuel costs are reviewed semiannually in the wholesale and South Carolina retail jurisdictions, with provisions for changing such costs in base rates. In the North Carolina retail jurisdiction, a review of fuel costs in rates is required annually and during general rate case proceedings. All jurisdictions allow the Company to adjust rates for past over- or under-recovery of fuel costs. Therefore, the Company reflects in revenues the difference between actual fuel costs incurred and fuel costs recovered through rates. The North Carolina legislature ratified a bill in July 1987 assuring the legality of such adjustments in rates. In 1991, the statute was extended through June 30, 1997.
I. Consolidated Statements of Cash Flows
For purposes of the Consolidated Statements of Cash Flows, the Company's investments in highly liquid debt instruments, with an original maturity of three months or less, are included in cash flows from investing activities and thus are not considered cash equivalents. Total income taxes paid were $352,697,000, $215,465,000 and $245,945,000 for years ended December 31, 1993, 1992 and 1991, respectively. Interest paid, net of amount capitalized, was $244,829,000, $298,455,000 and $269,330,000 for the years ended December 31, 1993, 1992 and 1991, respectively.
Note 2. Rate Matters
The North Carolina Utilities Commission (NCUC) and The Public Service Commission of South Carolina (PSCSC) must approve rates for retail sales within their respective states. The Federal Energy Regulatory Commission (FERC) must approve the Company's rates for sales to wholesale customers. Sales to the other joint owners of the Catawba Nuclear Station, which represent a substantial majority of the Company's wholesale revenues, are set through contractual agreements. (See Note 3.) During 1991, the Company filed in both the North Carolina and the South Carolina retail jurisdictions its only requests for general rate increases since 1986. The rate increase requested by the Company in North Carolina was 9.22 percent; a 4.15 percent increase was granted resulting in $100.1 million in additional annual revenues. In South Carolina, a rate increase of 7.29 percent was requested; a 3.0 percent increase was granted resulting in $30.2 million in additional annual revenues. These increases were requested primarily to recover costs associated with the Bad Creek Hydroelectric Station. In 1991, the Company filed a request with the FERC seeking a 7.47 percent rate increase for its wholesale customers, who represent approximately 2 percent of the Company's total revenues. A negotiated settlement between the Company and the wholesale customers was approved by the FERC on March 31, 1992. The approved agreement, effective April 1, 1992, provided for a 3.3 percent rate increase, resulting in $2.1 million in additional annual revenues. The North Carolina Supreme Court on April 22, 1992, remanded for the second time the Company's 1986 rate order to the NCUC. In this ruling, the Court held that the record from the 1986 proceedings failed to support the rate of return of 13.2 percent on common equity authorized by the NCUC after the initial decision of the Court remanding the 1986 rate order. The NCUC issued a final order dated October 26, 1992, authorizing a 12.8 percent return on common equity for the period October 31, 1986, through November 11, 1991, that resulted in a refund to North Carolina retail customers in 1992 of approximately $95 million, including interest. The Company has a bulk power sales agreement with Carolina Power & Light Company (CP&L) to provide CP&L 400 megawatts of capacity as well as associated energy when needed for a six-year period which began July 1, 1993. Electric rates in all regulatory jurisdictions were reduced by adjustment riders to reflect capacity revenues received from this CP&L bulk power sales agreement.
Note 3. Joint Ownership of Generating Facilities
The Company has sold interests in both units of the Catawba Nuclear Station. The other owners of portions of the Catawba Nuclear Station and supplemental information regarding their ownership are as follows:
Each participant has provided its own financing for its ownership interest in the plant. The Company retains a 12.5 percent ownership interest in the Catawba Nuclear Station. As of December 31, 1993, $498,930,000 of Electric plant in service and Nuclear fuel
represents the Company's investment in Units 1 and 2. Accumulated depreciation and amortization of $152,698,000 associated with Catawba had been recorded as of year-end. The Company's share of operating costs of Catawba are included in the corresponding electric expenses in the Consolidated Statements of Income. In connection with the joint ownership, the Company has entered into contractual agreements with the other joint owners to purchase declining percentages of the generating capacity and energy from the plant. These agreements were effective beginning with the commercial operation of each unit. Unit 1 and Unit 2 began commercial operation in June 1985 and in August 1986, respectively. Such agreements were established for 15 years for NCMPA and PMPA and 10 years for NCEMC and Saluda River. Energy cost payments are based on variable operating costs, a function of the generation output. Capacity payments are based on the fixed costs of the plant. The estimated purchased capacity obligations through 1998 are $392,000,000 for 1994, $293,000,000 for 1995, $55,000,000 for 1996, $44,000,000 for 1997 and $32,000,000 for 1998. Payment obligations include the terms of a proposed settlement agreement between the Company and two of the four joint owners of the Catawba Nuclear Station which was executed in January 1994 and is subject to regulatory approval. (See Note 13.) Effective in its November 1991 rate order, the North Carolina Utilities Commission (NCUC) reaffirmed the Company's recovery, on a levelized basis, of the capital costs and fixed operating and maintenance costs of capacity purchased from the other joint owners. The new NCUC rate order changed the levelized basis to a 15-year period ending 2001 for all of the other joint owners compared to the previous 15-year levelization period for NCMPA and PMPA and 10-year levelization period for NCEMC and Saluda River. The Public Service Commission of South Carolina (PSCSC), in its November 1991 rate order, reaffirmed the Company's recovery on a levelized basis of the capital costs of capacity purchased from the other joint owners. The new PSCSC rate order retained the levelized basis of a 7 1/2-year period for PMPA and NCMPA; for NCEMC and Saluda River, the new levelized basis reflects the projected purchased capacity payments for the twelve-month period ended October 1992. The Federal Energy Regulatory Commission granted the Company recovery on a levelized basis of the capital costs and fixed operating and maintenance costs of capacity purchased from the other joint owners over their contractual purchased power buyback periods. As currently provided in rates in all jurisdictions, the Company recovers the costs of purchased energy and a portion of purchased capacity. The portion of costs not currently recovered through rates is being accumulated, and the Company is recording a carrying charge on the accumulated balance. The Company recovers the accumulated balance including the carrying charge when the capacity payments drop below the levelized revenues. In the North Carolina and wholesale jurisdictions, purchased capacity payments continue to exceed levelized revenues. In the South Carolina jurisdiction, cumulative levelized revenues have exceeded purchased capacity payments. Jurisdictional levelizations are intended to recover total costs, including allowed returns, and are subject to adjustments, including final true-ups. For the years ended December 31, 1993, 1992 and 1991, the Company recorded purchased capacity and energy costs from the other joint owners of $547,900,000, $514,300,000 and $536,500,000, respectively. These amounts, adjusted for the cost of capacity purchased not reflected in current rates, are included in "Net interchange and purchased power" in the Consolidated Statements of Income. As of December 31, 1993 and 1992, $768,099,000 pre-tax and $378,095,000 net of income tax, respectively, associated with the costs of capacity purchased but not reflected in current rates had been accumulated in the Consolidated Balance Sheets as "Purchased capacity costs." Accumulated deferred income taxes associated with "Purchased capacity costs" were $254,789,000 as of December 31, 1993. As of December 31, 1992, deferred income taxes reduced "Purchased capacity costs" on the Consolidated Balance Sheet by $265,255,000. The change in presentation from a net of tax to pre-tax basis is a result of the adoption of SFAS 109. (See Note 4.)
Note 4. Income Tax Expense
The Company implemented Statement of Financial Accounting Standards No. 109 (SFAS 109), "Accounting for Income Taxes," effective January 1, 1993. No prior periods have been restated. SFAS 109 requires a liability approach for financial accounting and reporting of income taxes. While classification of certain items on the Consolidated Balance Sheets has changed, principally because of certain items previously reported net of tax now being reported on a gross basis, there is no material effect on the Company's results of operations. As a result of implementing SFAS 109, the December 1993 Consolidated Balance Sheet reflects an increase of $778 million in both Total assets and Accumulated deferred income taxes (ADIT). The increase was primarily because of a change in presentation from a net of tax to pre-tax basis which resulted in an increase in "Purchased capacity costs" of $255 million and in the creation of the "Regulatory asset related to income taxes" of $486 million. Effective January 1, 1993, "Allowance for borrowed funds used during construction" on the Consolidated Statement of Income reflects a pre-tax cost of debt. Accumulated deferred income taxes after implementation of SFAS 109 consist primarily of the following temporary differences (dollars in thousands):
* The net regulatory asset related to income taxes is $486,440,000.
Total deferred income tax liability was $2,701,374,000 as of December 31, 1993. Total deferred income tax asset was $493,666,000 as of December 31, 1993.
Income tax expense consisted of the following (dollars in thousands):
Total current income taxes were $354,366,000 for 1993, $258,800,000 for 1992 and $268,686,000 for 1991. Of these amounts, state income taxes were $61,237,000 for 1993, $44,149,000 for 1992 and $48,671,000 for 1991. Total deferred income taxes were $67,572,000 for 1993, $55,780,000 for 1992 and $38,664,000 for 1991. Of these amounts, deferred state income taxes were $14,279,000 for 1993, $13,786,000 for 1992 and $10,833,000 for 1991.
Income taxes differ from amounts computed by applying the statutory tax rate to pre-tax income as follows (dollars in thousands):
On August 10, 1993, President Clinton signed the Omnibus Budget Reconciliation Act of 1993 which includes an increase in the federal corporate income tax rate from 34% to 35%, retroactive to January 1, 1993. Accordingly, the Company's income tax expense reflects an increase of approximately $10 million for 1993.
Note 5. Short-Term Borrowings and Compensating-Balance Arrangements
To support short-term obligations, the Company had credit facilities of $324,980,000, $329,385,000 and $340,385,000 as of December 31, 1993, 1992 and 1991, with 29, 49 and 52 commercial banks, respectively. Included in these facilities is a three-year, $300,000,000 revolving credit agreement with the balance in separate, annually-renewable lines of credit. These facilities are on a fee or compensating-balance basis. No short-term debt resulting from these credit facilities was outstanding as of December 31, 1993, 1992 and 1991. Cash balances maintained at the banks on deposit were $12,988,000 and $7,243,000 as of December 31, 1993 and 1992, respectively. Cash balances and fees compensate banks for their services, even though the Company has no formal compensating-balance arrangements. To compensate certain banks for credit facilities, the Company maintained balances of $49,000 and $509,000 as of December 31, 1993 and 1992, respectively. The Company retains the right of withdrawal with respect to the funds used for compensating-balance arrangements.
A summary of short-term borrowings is as follows (dollars in thousands):
Note 6. Common Stock and Retained Earnings
Common Stock Effective April 1, 1991, the Company began issuing common stock in lieu of purchasing shares on the open market for its various stock purchase plans. The Company discontinued issuances of common stock, effective December 1, 1991, and resumed open market purchases to satisfy the requirements of the various stock purchase plans. Except as discussed earlier, open market purchases were used to satisfy the requirements of the Company's various stock plans from 1991 through 1993. During 1991 and through April 6, 1992, the Company issued common stock to satisfy the conversion rights of preference stock. (See Note 7.) As of December 31, 1993, a total of 7,004,659 shares was reserved for issuance to stock plans.
Retained Earnings As of December 31, 1993, none of the Company's retained earnings were restricted as to the declaration or payment of dividends.
Note 7. Preferred and Preference Stock Without Sinking Fund Requirements
The following shares of stock were authorized with or without sinking fund requirements as of December 31, 1993 and 1992:
On April 6, 1992, the Company redeemed all outstanding shares of the Cumulative Preference Stock, 63/4% Convertible Series AA at its par value of $100 per share.
In 1992 and 1991, shares of preference stock were converted into shares of common stock as follows:
Preferred and preference stock without sinking fund requirements as of December 31, 1993 and 1992, were as follows (dollars in thousands):
Note 8. Preferred Stock With Sinking Fund Requirements
The following shares of stock were authorized with or without sinking fund requirements as of December 31, 1993 and 1992:
Preferred stock with sinking fund requirements as of December 31, 1993 and 1992, was as follows (dollars in thousands):
The annual sinking fund requirements through 1998 are $1,500,000 in 1994, 1995, 1996 and 1997 and $5,750,000 in 1998. Some additional redemptions are permitted at the Company's option. The Company reacquired 15,000 shares of 7.12% Series Q Preferred Stock in 1992 to satisfy 1993 sinking fund requirements. The call provisions for the outstanding preferred stock specify various redemption prices not exceeding 105 percent of par value, plus accumulated dividends to the redemption date.
Note 9. Long-Term Debt
Long-term debt outstanding as of December 31, 1993 and 1992, was as follows (dollars in thousands):
(a) Substantially all the Company's electric plant was mortgaged as of December 31, 1993. (b) Substantial amounts of Crescent Resources, Inc.'s real estate development projects, land and buildings are pledged as collateral. (c) Nantahala Power and Light's loan agreements impose net worth restrictions and limitations on disposal of assets and payment of cash dividends.
As of December 31, 1993 and 1992, the Company had $40,000,000 in pollution-control revenue bonds backed by an unused, two-year revolving credit facility of $40,000,000 and $130,000,000 in commercial paper backed by an unused, three-year $130,000,000 revolving credit facility. These facilities are on a fee basis. Both the $40,000,000 in pollution-control bonds and the $130,000,000 in commercial paper are included in long-term debt.
As of December 31, 1993, Crescent Resources, Inc. had $52,064,000 in mortgage loans which mature in 1997 and require monthly payments of principal. Interest rates are variable and ranged from 4.21 percent to 5.08 percent as of December 31, 1993. Nantahala Power and Light had $33,000,000 in senior notes maturing in 2011 and 2012 as of December 31, 1993. The two notes carry fixed interest rates of 9.21 percent and 7.45 percent and require prepayments beginning 1997 and 1998, respectively.
The annual maturities of consolidated long-term debt, including capitalized lease principal payments through 1998, are $90,398,000 in 1994; $89,888,000 in 1995; $13,264,000 in 1996; $223,810,000 in 1997 and $54,522,000 in 1998.
Note 10. Fair Value of Financial Instruments
Estimated fair value amounts have been determined by the Company using available market information and appropriate valuation methodologies. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 1993, are not necessarily indicative of the amounts that the Company could realize in a current market exchange.
Cash, Short-term investments and Notes payable The carrying amount approximates fair value because of the short maturity of these instruments.
Long-term debt (excluding Capitalized leases) and Preferred stock with sinking fund requirements Fair value is based on market price estimates. As a result of substantial refinancing activity in 1993 and 1992, the Company's book value of consolidated long-term debt and preferred stock is not materially different from fair market value as of December 31, 1993.
Nuclear decommissioning trust funds External funds have been established, as required by the Nuclear Regulatory Commission, as a mechanism to fund certain costs of nuclear decommissioning. (See Note 16.) These nuclear decommissioning trust funds are primarily invested in intermediate-term municipal bonds. As of December 31, 1993, the Company's book value of its nuclear decommissioning trust funds is not materially different from fair market value.
Note 11. Investment in Joint Ventures
Certain investments in joint ventures are accounted for by the equity method. The Company's ownership in domestic and international joint ventures is 50 percent or less. Total assets of these joint ventures as of December 31, 1993 and 1992, were $972 million and $433 million, respectively. The Company's proportionate share of these assets was $241 million and $163 million, respectively. Total liabilities of these joint ventures as of December 31, 1993 and 1992, were $413 million and $321 million, respectively. The Company's proportionate share of the liabilities was $139 million and $132 million, respectively. Of the $413 million total liabilities outstanding at December 31, 1993, $290 million represents non-recourse debt for which the Company bears no responsibility in the event the joint venture defaults on the debt. The Company's portion of net income from the joint ventures for the years ended December 31, 1993 and 1992, was $2,601,000 and ($1,179,000).
Note 12. Retirement Benefits A. Retirement Plan
The Company and its operating subsidiaries, with the exception of Nantahala Power and Light Company, which maintains its own retirement plans, have a non-contributory, defined benefit retirement plan covering substantially all their employees. The benefit is based on years of creditable service and the employee's average compensation based on the highest compensation during a consecutive sixty-month period. Prior to 1992, benefits have been reduced by a Social Security adjustment for employees age sixty-five and over and for early retirees with no creditable service prior to September 1, 1980. During 1991, the Company amended its plan for employees who retire after December 31, 1991. The effect of this amendment was to reduce benefits by a Social Security adjustment for all retirees. The plan was amended in 1992 to permit participants with 30 years of creditable service to retire as early as age 51. The Company's policy is to fund pension costs as accrued. During 1993, the Company made a one-time contribution of $50,000,000 to enhance the funded position of the plan.
Net periodic pension cost for the years ended December 31, 1993, 1992 and 1991, include the following components (dollars in thousands):
A reconciliation of the funded status of the plan to the amounts recognized in the Consolidated Balance Sheets as of December 31, 1993 and 1992, is as follows (dollars in thousands):
In determining the projected benefit obligation, the weighted-average assumed discount rate used was 7.50 percent in 1993 and 8.25 percent in 1992 and 1991. The assumed increase in future compensation level for determining the projected benefit obligation is based on an age-related basis. The weighted-average salary increase was 4.50 percent in 1993, 5.40 percent in 1992 and 5.65 percent in 1991. The expected long-term rate of return on plan assets used in determining pension cost was 8.40 percent in 1993 and 9.25 percent in 1992 and 1991. During 1993 the Company offered an enhanced early retirement option, Limited Period Separation Opportunity (LPSO), for eligible employees. The Company recorded an additional one-time expense for special termination benefits associated with LPSO of approximately $7,611,000.
B. Postretirement Benefits
The Company and its operating subsidiaries, with the exception of Nantahala Power and Light Company, which maintains its own postretirement benefit plans, currently provides certain health care and life insurance benefits for retired employees. Employees become eligible for these benefits if they retire at age 55 or greater with 10 years of service; or if they retire as early as age 51 with 30 years or more of service. Employees retiring after January 1, 1992, receive a fixed Company allowance, based on years of service, to be used to pay medical insurance premiums. The Company reserves the right to terminate, suspend, withdraw, amend or modify the plans in whole or in part at any time. In 1992, the Company commenced funding the maximum amount allowable under section 401(h) of the Internal Revenue Code, which provides for tax deductions for contributions and tax-free accumulation of investment income. Such amounts partially fund the Company's medical and dental postretirement benefits. The Company has also established a Retired Lives Reserve, which has tax attributes similar to 401(h) funding, to partially fund its postretirement life insurance obligation. The Company contributed $14,648,000 into these funding mechanisms in 1993 and $19,338,000 in 1992. In 1992, the Company implemented a new accounting standard that requires postretirement benefits to be recognized as earned by employees rather than recognized as paid. Prior to 1992, the cost of retiree benefits was recognized as the benefits were paid. Amounts paid by the Company for 1991 amounted to $11,900,000.
Net periodic postretirement benefit cost for the years ended December 31, 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, 1993 and 1992, is as follows (dollars in thousands):
In determining the accumulated postretirement benefit obligation (APBO), the weighted-average assumed discount rate used was 7.50 percent in 1993 and 8.25 percent in 1992. The assumed increase in future compensation level is determined on an age-related basis. The weighted-average salary increase was 4.50 percent in 1993, 5.40 percent in 1992 and 5.65 percent in 1991. The expected long-term rate of return on 401(h) assets used in determining postretirement benefits cost was 8.40 percent in 1993 and 9.25 percent in 1992. For Retired Lives Reserve assets, 7.125 percent was used in 1993 and 1992. The assumed medical inflation rate was approximately 13 percent in 1993. This rate decreases by 0.5 percent to 1.0 percent per year until a rate of 5.5 percent is achieved in the year 2002, which remains fixed thereafter. A 1.0 percent increase in the medical and dental trend rates produces a 6.25 percent ($1,903,213) increase in the aggregate service and interest cost. The increase in the APBO attributable to a 1.0 percent increase in the medical and dental trend rates is 6.69 percent ($23,483,182) as of December 31, 1993.
Note 13. Commitments and Contingencies A. Construction Program
Projected construction and nuclear fuel costs, both including allowance for funds used during construction, are $2.3 billion and $394 million, respectively, for 1994 through 1996. The program is subject to periodic review and revisions, and actual construction costs incurred may vary from such estimates. Cost variances are due to various factors, including revised load estimates, environmental matters and cost and availability of capital.
B. Nuclear Insurance
The Company maintains nuclear insurance coverage in three areas: liability coverage, property, decontamination and decommissioning coverage, and extended accidental outage coverage to cover increased generating costs and/or replacement power purchases. The Company is being reimbursed by the other joint owners of the Catawba Nuclear Station for certain expenses associated with nuclear insurance premiums paid by the Company. Pursuant to the Price-Anderson Act, the Company is required to insure against public liability claims resulting from nuclear incidents to the full limit of liability of approximately $9.4 billion. The maximum required private primary insurance of $200 million has been purchased along with a like amount to cover certain worker tort claims. The remaining amount, currently $9.2 billion, which will be increased by $75.5 million as each additional commercial nuclear reactor is
licensed, has been provided through a mandatory industry-wide excess secondary insurance program of risk pooling. The $9.2 billion could also be reduced by $75.5 million for certain nuclear reactors that are no longer operational and may be exempted from the risk pooling insurance program. Under this program, licensees could be assessed retrospective premiums to compensate for damages in the event of a nuclear incident at any licensed facility in the nation. If such an incident occurs and public liability damages exceed primary insurances, licensees may be assessed up to $75.5 million for each of their licensed reactors, payable at a rate not to exceed $10 million a year per licensed reactor for each incident. The $75.5 million amount is subject to indexing for inflation. This amount is further subject to a surcharge of 5 percent (which is included in the above $9.4 billion figure) if funds are insufficient to pay claims and associated costs. If retrospective premiums were to be assessed, the other joint owners of the Catawba Nuclear Station are obligated to assume their pro rata share of such assessment. The Company is a member of Nuclear Mutual Limited (NML), which provides $500 million in primary property damage coverage for each of the Company's nuclear facilities. If NML's losses ever exceed its reserves, the Company will be liable, on a pro rata basis, for additional assessments of up to $42 million. This amount represents 5 times the Company's annual premium to NML. The Company is also a member of Nuclear Electric Insurance Limited (NEIL) and purchases $1.4 billion of insurance through NEIL's excess property, decontamination and decommissioning liability insurance program. If losses ever exceed the accumulated funds available to NEIL for the excess property, decontamination and decommissioning liability program, the Company will be liable, on a pro rata basis, for additional assessments of up to $46 million. This amount is limited to 7.5 times the Company's annual premium to NEIL for excess property, decontamination and decommissioning liability insurance. The other joint owners of Catawba are obligated to assume their pro rata share of any liability for retrospective premiums and other premium assessments resulting from the NEIL policies applicable to Catawba. The Company has also purchased an additional $400 million of excess property damage insurance for its Oconee and McGuire plants and $800 million for its Catawba plant through a pool of stock and mutual insurance companies. The Company participates in a NEIL program that provides insurance for the increased cost of generation and/or purchased power resulting from an accidental outage of a nuclear unit. Each unit of the Oconee, McGuire and Catawba Nuclear Stations is insured for up to approximately $3.5 million per week, after a 21-week deductible period, with declining amounts per unit where more than one unit is involved in an accidental outage. Coverages continue at 100 percent for 52 weeks, and 67 percent for the next 104 weeks. If NEIL's losses for this program ever exceed its reserves, the Company will be liable, on a pro rata basis, for additional assessments of up to $30 million. This amount represents 5 times the Company's annual premium to NEIL for insurance for the increased cost of generation and/or purchased power resulting from an accidental outage of a nuclear unit. The other joint owners of Catawba are obligated to assume their pro rata share of any liability for retrospective premiums and other premium assessments resulting from the NEIL policies applicable to the joint ownership agreements.
C. Other
The other joint owners of the Catawba Nuclear Station and the Company are involved in various proceedings related to the Catawba joint ownership contractual agreements. The basic contention in each proceeding is that certain calculations affecting bills under these agreements should be performed differently. These items are covered by the agreements between the Company and the other Catawba joint owners which have been previously approved by the Company's retail regulatory commissions. (For additional information, see Note 3.) The Company and two of the four joint owners have entered into a proposed settlement agreement which, if approved by the regulators, will resolve all issues in contention in such proceedings between the Company and these owners. The Company recorded a liability as an increase to Other current liabilities on its Consolidated Balance Sheets of approximately $105 million in 1993 to reflect this proposed settlement. In addition, future estimated obligations in connection with the settlement are reflected in estimates of purchased capacity obligations in Note 3. As the Company expects the costs associated with this settlement will be recovered as part of the purchased capacity levelization, the Company has included approximately $105 million as an increase to Purchased capacity costs on its Consolidated Balance Sheets. Therefore, the Company believes the ultimate resolution of these matters should not have a material adverse effect on the results of operations or financial position of the Company. Although the two other Catawba joint owners, who are not parties to the above settlement, have not fully quantified the dollars associated with their claims in the presently outstanding proceedings, information associated with these proceedings indicates that the amount in contention could be as high as $110 million through December 31, 1993. Arbitration hearings were held in 1992 involving substantially all the disputed amounts, and a decision interpreting the language of the agreements on certain of these matters was issued on October 1, 1993. Further proceedings will be required to determine the amounts associated with this decision as it relates to these owners, some of which may involve refunds. However, the Company expects the costs associated with this decision will be included in and recovered as part of the purchased capacity levelization consistent with prior orders of the retail regulatory commissions. Therefore, the Company believes the ultimate resolution of these matters should not have a material adverse effect on the results of operations or financial position of the Company. The Company is also involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business, some of which involve substantial amounts. Management is of the opinion that the final disposition of these proceedings will not have a material adverse effect on the results of operations or the financial position of the Company.
Note 14. Other Income
For the years ended December 31, 1993, 1992 and 1991, the Company reported carrying charges on purchased capacity levelization deferral related to the joint ownership of the Catawba Nuclear Station of $32,180,000, $28,820,000 and $28,765,000 (net of taxes), respectively, as components of "Other, net" and "Income taxes - other, net"on the Consolidated Statements of Income. (For additional information on purchased capacity levelization, see Note 3.) Also included in "Other, net" and "Income taxes - other, net" on the Consolidated Statements of Income is income provided by diversified activities and the Company's subsidiaries of $21,996,000, $25,728,000 and $23,587,000 (net of taxes) for years ended December 31, 1993, 1992 and 1991, respectively. The activities of Crescent Resources, Inc., the Company's real estate development and forest management subsidiary, generated the majority of subsidiary and non-electric earnings. Other components include subsidiary investment income, fees for engineering services, construction and operation of generation and transmission facilities outside the Company's current service area, water operations and merchandising. For the year ended December 31, 1991, the Company recorded a net of tax carrying charge of $36,765,000 on costs incurred on the Bad Creek Hydroelectric Station after commercial operation but prior to recovery of costs through rates. This carrying charge is a component of "Other, net" in the Consolidated Statements of Income.
Note 15. Reclassification
In the Consolidated Statements of Cash Flows, Consolidated Balance Sheets and the Consolidated Statements of Capitalization, certain prior-year information has been reclassified to conform with 1993 classifications.
Note 16. Nuclear Decommissioning Costs
Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $955 million stated in 1990 dollars. This amount includes the Company's 12.5 percent ownership in the Catawba Nuclear Station. The other joint owners of the Catawba Nuclear Station are liable for providing decommissioning related to their ownership interests in the station. Both the NCUC and the PSCSC have granted the Company recovery of the estimated site-specific decommissioning costs through retail rates over the expected remaining service periods of the Company's nuclear plants. Such estimates presume that units will be decommissioned as soon as possible following the end of their license life. Although subject to extension, the current operating licenses for the Company's nuclear units expire as follows: Oconee 1 and 2 - 2013, Oconee 3 - 2014; McGuire 1 - 2021, McGuire 2 - 2023; and Catawba 1 - 2024, Catawba 2 - 2026. The Nuclear Regulatory Commission (NRC) issued a rule-making in 1988 which requires an external mechanism to fund the estimated cost to decommission certain components of a nuclear unit subject to radioactive contamination. In addition to the required external funding, the Company maintains an internal reserve to provide for decommissioning costs of plant components not subject to radioactive contamination. During 1993, the Company expensed approximately $52.5 million which was contributed to the external funds and accrued an additional $5.0 million to the internal reserve. The balance of the external funds as of December 31, 1993, was $118.5 million. The balance of the internal reserve as of December 31, 1993, was $200.0 million and is reflected in Accumulated depreciation and amortization on the Consolidated Balance Sheets. Management's opinion is that the estimated site-specific decommissioning costs being recovered through rates, when coupled with assumed after-tax fund earnings of 4.5 percent to 5.5 percent, are currently sufficient to provide for the cost of decommissioning based on the Company's current decommissioning schedule.
Independent Auditors' Report
Duke Power Company:
We have audited the consolidated financial statements of Duke Power Company and subsidiaries (the Company) listed in the accompanying index on page 22. Our audits also included the consolidated financial statement schedules listed in the accompanying index on page 22. These financial statements and consolidated financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and consolidated financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. Also, in our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As discussed in Note 4 to the consolidated financial statements, in 1993, the Company changed its method of accounting for income taxes to conform with Statement of Financial Accounting Standards No. 109.
DELOITTE & TOUCHE Deloitte & Touche Charlotte, North Carolina February 11, 1994
Responsibility for Financial Statements
The financial statements of Duke Power Company are prepared by management, which is responsible for their integrity and objectivity. The statements are prepared in conformity with generally accepted accounting principles appropriate in the circumstances to reflect in all material respects the substance of events and transactions which should be included. The other information in the annual report is consistent with the financial statements. In preparing these statements, management makes informed judgments and estimates of the expected effects of events and transactions that are currently being reported.
The Company's system of internal accounting control is designed to provide reasonable assurance that assets are safeguarded and transactions are executed according to management's authorization. Internal accounting controls also provide reasonable assurance that transactions are recorded properly, so that financial statements can be prepared according to generally accepted accounting principles. In addition, the Company's accounting controls provide reasonable assurance that errors or irregularities which could be material to the financial statements are prevented or are detected by employees within a timely period as they perform their assigned functions. The Company's accounting controls are continually reviewed for effectiveness. In addition, written policies, standards and procedures, and a strong internal audit program augment the Company's accounting controls.
The Board of Directors pursues its oversight role for the financial statements through the audit committee, which is composed entirely of directors who are not employees of the Company. The audit committee meets with management and internal auditors periodically to review the work of each group and to monitor each group's discharge of its responsibilities. The audit committee also meets periodically with the Company's independent auditors, Deloitte & Touche. The independent auditors have free access to the audit committee and the Board of Directors to discuss internal accounting control, auditing and financial reporting matters without the presence of management.
DAVID L. HAUSER David L. Hauser Controller
SELECTED QUARTERLY FINANCIAL DATA
Generally, quarterly earnings fluctuate with seasonal weather conditions, timing of rate changes and maintenance of electric generating units, especially nuclear units.
SUBSIDIARY HIGHLIGHTS The earnings contribution of the Company's diversified activities and subsidiaries was $22.0 million in 1993, $25.7 million in 1992 and $23.6 million in 1991. (a)(b) Highlights of selected subsidiaries are presented below. (dollars in thousands) ELECTRIC POWER SUPPLY Nantahala Power and Light Company provides service to a five-county area in the western North Carolina mountains by its operation of 11 hydroelectric stations and purchases of supplemental power.
FUNDS MANAGEMENT Church Street Capital Corp. (CSCC) manages investment of funds for the Company and is the parent company of several subsidiaries. CSCC has no full-time employees.
Highlights of CSCC's subsidiaries are presented below: REAL ESTATE MANAGEMENT, LAND DEVELOPMENT Crescent Resources, Inc. is engaged in forest management, real estate development, and sales and leasing.
ENGINEERING, CONSTRUCTION, TECHNICAL SERVICES AND POWER DEVELOPMENT Engineering, construction, technical services and power development opportunities are pursued nationally and internationally. Duke Engineering & Services, Inc. markets engineering, construction, quality assurance, consulting and other engineering-related services for utility facilities other than coal-fired plants. Duke/Fluor Daniel, a joint venture with Fluor Daniel, Inc., provides design, construction, operation and maintenance support primarily for coal-fired generating plants. Duke Energy Group, parent of Duke Energy Corp., structures, finances and manages investments in electric generation and transmission facilities.
(a) 1991 EXCLUDES THE CUMULATIVE EFFECT OF AN ACCOUNTING CHANGE OF $6,727,000, AFTER TAX. (b) THE EARNINGS CONTRIBUTION OF THE COMPANY'S SUBSIDIARIES AND NON-ELECTRIC OPERATIONS INCLUDES ELIMINATION OF INTERCOMPANY PROFIT OF $509,000 AND $1,211,000, AFTER TAX, IN 1993 AND 1992, RESPECTIVELY. (c) FULL-TIME EMPLOYEES.
DUKE POWER COMPANY SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT (DOLLARS IN THOUSANDS)
DUKE POWER COMPANY SCHEDULE VI -- ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT (DOLLARS IN THOUSANDS)
DUKE POWER COMPANY SCHEDULE VIII -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (DOLLARS IN THOUSANDS)
(1) Principally consists of Injuries and Damages reserves and Property Insurance reserve which are included in "Deferred credits and other liabilities" in the Consolidated Balance Sheets. SCHEDULE X -- SUPPLEMENTARY CONSOLIDATED INCOME STATEMENT INFORMATION
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" and "Information Regarding the Board of Directors" in the proxy statement of the Company relating to its 1994 annual meeting of shareholders, which is being incorporated herein by reference. Information concerning the executive officers of the Company is set forth under the section entitled "Executive Officers of the Company" in this annual report. ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION. Information for this item is set forth in the section entitled "Executive Compensation" in the proxy statement of the Company relating to its 1994 annual meeting of shareholders, which is being incorporated herein by reference. ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. Information for this item is set forth in the sections entitled "Voting Securities Outstanding" and "Election of Directors" in the proxy statement of the Company relating to its 1994 annual meeting of shareholders, which is being incorporated herein by reference. ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. Information for this item is set forth in the section entitled "Election of Directors" in the proxy statement of the Company relating to its 1994 annual meeting of shareholders, which is being incorporated herein by reference. PART IV. ITEM 14.
ITEM 14. EXHIBITS, CONSOLIDATED FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. (a) Consolidated Financial Statements, Supplemental Financial Data and Consolidated Financial Statement Schedules included in Part II of this annual report are as follows:
All other schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements or notes thereto. (b) Reports on Form 8-K No reports on Form 8-K were filed during the last quarter of 1993. (c) Exhibits -- See Exhibit Index on page 48.
SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED, IN THE CITY OF CHARLOTTE AND STATE OF NORTH CAROLINA ON THE 29TH DAY OF MARCH, 1994. DUKE POWER COMPANY (REGISTRANT) By: W. S. LEE CHAIRMAN OF THE BOARD AND PRESIDENT PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATE INDICATED.
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.
(dagger) Compensatory plan or arrangement required to be filed as an exhibit, and filed with Form 10-K for the year ended December 31, 1992, File No. 1-4928, under the same exhibit number as listed herein.