ITEM 1. BUSINESS. Duke Power Company (the Company) is primarily engaged in the generation, transmission, distribution and sale of electric energy in the central portion of North Carolina and the western portion of South Carolina, comprising the area in both states known as the Piedmont Carolinas. It is one of the nation's largest investor-owned electric utilities. The Company is also engaged in a variety of diversified operations, most of which are organized in separate subsidiaries. The Company's subsidiaries and diversified activities are in the Associated Enterprises Group (AEG). AEG includes Church Street Capital Corp.; Crescent Resources, Inc.; Duke Energy Group, Inc.; Duke Engineering & Services, Inc.; Duke/Fluor Daniel; Duke/Louis Dreyfus, LLC; Duke Merchandising; DukeNet Communications, Inc.; Duke Water Operations; and Nantahala Power and Light Company (NP&L). For additional information on subsidiaries and diversified activities, see "Subsidiaries and Diversified Activities," "Management's Discussion and Analysis of Results of Operations and Financial Condition, Current Issues -- Subsidiaries and Diversified Operations" and "Subsidiaries and Diversified Activities Highlights." On November 25, 1996, the Company and PanEnergy Corp announced a proposed stock-for-stock transaction creating an integrated energy company. Upon consummation of the merger, PanEnergy will be a wholly owned subsidiary of the Company, and the Company's name will be changed to Duke Energy Corporation. The transaction is expected to close by December 31, 1997, subject to approval of the shareholders of both companies and all applicable regulatory approvals. The shareholders of each company will vote on the proposed merger at their annual meetings, which are scheduled for April 24, 1997 for both companies. Applications for regulatory approval were filed with the North Carolina Utilities Commission (NCUC) and The Public Service Commission of South Carolina (PSCSC) on December 19, 1996, and with the Federal Energy Regulatory Commission (FERC) on February 3, 1997. Regulatory proceedings are expected to be successfully completed by year-end 1997. In connection with the transaction, each share of PanEnergy common stock will be converted into 1.0444 shares of common stock of the Company. The transaction will be accounted for as a pooling of interests. Further details about the proposed acquisition are provided in the Company's reports on Form 8-K, filed with the Securities and Exchange Commission on December 9, 1996 and March 20, 1997, and in the Joint Proxy Statement- Prospectus provided to shareholders in connection with the Company's annual meeting. Unless otherwise indicated, all information presented in this Form 10-K relates to the Company only and does not take into account the proposed merger with PanEnergy. During 1996, the Company's operating revenues, including AEG, were $4.8 billion. The Company's executive offices are located in the Power Building, 422 South Church Street, Charlotte, North Carolina 28242-0001 (Telephone No. 704-594-0887). SERVICE AREA The Company's service area (excluding NP&L), approximately two-thirds of which lies in North Carolina, covers about 20,000 square miles with an estimated population of 5.1 million and includes a number of cities, of which the largest are Charlotte, Greensboro, Winston-Salem and Durham in North Carolina and Greenville and Spartanburg in South Carolina. The Company supplies electric service directly to approximately 1.8 million residential, commercial and industrial customers in more than 200 cities, towns and unincorporated communities. Electricity is sold at wholesale to incorporated municipalities and to several public and private utilities. In addition, sales are made through contractual agreements to former wholesale municipal or cooperative customers of the Company who had purchased portions of the Catawba Nuclear Station (collectively, the "other Catawba joint owners") (See "Joint Ownership of Generating Facilities"). NP&L services an additional 55,000 mostly residential customers in five counties in western North Carolina. The Company's service area is undergoing increasingly diversified industrial development. The textile industry, machinery and equipment manufacturing, and chemical and chemical-related industries are of major significance to the economy of the area. Other industrial activities include rubber and plastic products, paper and allied products, and various other light and heavy manufacturing and service businesses. The largest industry served is the textile industry, which accounted for approximately $459 million of the Company's revenues for 1996, representing 10 percent of electric revenues and 37 percent of industrial revenues.
ENERGY REQUIREMENTS AND CAPABILITY The following table sets forth the Company's generating capability as of December 31, 1996, its sources of electric energy for 1996 and certain information presently projected for 1997:
(a) The data relating to capability does not reflect the possible unavailability or reduction of capability of facilities at any given time because of scheduled maintenance, repair requirements or regulatory restrictions. (b) Excludes firm purchases and sales. (See "Energy Management and Future Power Needs.") (c) Excludes NP&L. (d) Nuclear capability and related generation for 1996 and related projections for 1997 reflect the Company's 12.5% ownership share of the Catawba Nuclear Station. (See "Joint Ownership of Generating Facilities.") NP&L operates 11 hydroelectric stations with a total capacity of 100 megawatts and also purchases supplemental power. The Company supplies supplemental power to NP&L under the terms of an interconnection agreement approved by FERC. The Company has a bulk power sales agreement with Carolina Power & Light Company (CP&L) to provide CP&L 400 megawatts of capacity as well as associated energy when needed for a six-year period which began July 1, 1993. Electric rates in all regulatory jurisdictions were reduced by adjustment riders to reflect capacity revenues received from this CP&L bulk power agreement. The Company's steam-fossil generating system continued its tradition of operating efficiently and achieved a combined availability of 86 percent for 1996. The Company's nuclear system operated at 74 percent of capacity for 1996, which reflects the impact of the steam generator replacement outage at the Catawba Nuclear Station (See "Regulation -- Nuclear Facilities") and the removal from service of the Oconee Nuclear Station in October 1996 for inspection and modification of the piping system after a steam line on the non-nuclear side of the plant ruptured. Oconee Units 1, 2, and 3 returned to service in 1997 on February 12, February 3, and March 14, respectively. The Company's system nuclear capacity factor reflects the Company's 12.5% ownership share of the Catawba Nuclear Station. The Company normally experiences seasonal peak loads in summer and winter which are relatively in balance. The Company currently forecasts a 1.8 percent compound annual growth in peak load through 2011. The Company experienced an all-time peak load of 15,542 MW on August 14, 1995 during exceptionally warm summer weather. This peak load excludes the portion of the demand of the other Catawba joint owners met by their retained ownership. RATE MATTERS The NCUC and the PSCSC must approve the Company's rates for retail sales within their respective states. The FERC must approve the Company's rates for sales to wholesale customers, including the contractual arrangements between the Company and the other Catawba joint owners. The most recent general rate increase requests in the Company's retail jurisdictions were filed and approved in 1991. The Company also filed its most recent general rate increase request within the FERC wholesale jurisdiction in 1991. A negotiated settlement between the Company and the wholesale customers was approved by the FERC in 1992. In its most recent general rate case, the NCUC authorized a jurisdictional rate of return on common equity of 12.50 percent, and the PSCSC authorized a jurisdictional rate of return on common equity of 12.25 percent.
The PSCSC, on May 7, 1996, ordered a rate reduction in the form of a decrement rider of 0.432 cents per kilowatt-hour, or an average of approximately 8 percent, affecting South Carolina retail customers. South Carolina retail sales represent approximately 30 percent of the Company's total retail sales. The rate reduction was reflected on bills rendered on or after June 1, 1996. This net decrement rider reflects an interim true-up decrement adjustment associated with the levelization of Catawba Nuclear Station purchased capacity costs and an interim true-up increment associated with amortization of the demand-side management deferral account. The rate adjustment was made because, in the South Carolina retail jurisdiction, cumulative levelized revenues associated with the recovery of Catawba purchased capacity costs had exceeded purchased capacity payments and accrual of deferred returns, and certain demand-side costs had exceeded the level reflected in rates. Certain of the Company's wholesale customers, excluding the other Catawba joint owners, initiated proceedings in 1995 before the FERC concerning rate matters. The Company and nine of its eleven wholesale customers entered into a settlement in July 1996 which reduced the customers' rates by approximately 9 percent and renewed their contracts with the Company through the year 2000. Both of the customers that did not enter into the settlement have signed agreements to purchase energy from other suppliers beginning in 1997. The eleven wholesale customers involved in this matter accounted for less than 2 percent of the Company's overall electric revenues during 1996. The two customers that have signed agreements with other suppliers accounted for less than 0.5 percent of the Company's 1996 overall electric revenues. During 1996, NP&L filed an application with and received approval from the NCUC to increase its annual retail service revenues by $4.6 million. FUEL AND PURCHASED POWER COST ADJUSTMENT PROCEDURES. Duke Power has procedures in all three of its regulatory jurisdictions to adjust rates for fluctuations in fuel expense. In the North Carolina retail jurisdiction, a review of fuel costs in rates is required annually and during general rate case proceedings. In 1996, the South Carolina General Assembly amended the Code of Laws of South Carolina to provide for annual reviews of fuel costs. In the wholesale jurisdiction, fuel costs are reviewed semiannually. All jurisdictions allow Duke Power to adjust rates for past over- or under-recovery of fuel costs. Therefore, Duke Power reflects in revenues the difference between actual fuel costs incurred and fuel costs recovered through rates. NP&L's wholesale rates are adjusted annually to reflect current costs. Purchased power costs of NP&L are reviewed annually and during general rate case proceedings by the NCUC. NP&L is allowed to adjust rates for past over- or under-recovery of purchased power costs. Therefore, NP&L defers the difference between actual purchased power costs incurred and those recovered through rates. ENERGY MANAGEMENT AND FUTURE POWER NEEDS The Company's strategy for meeting customers' present and future energy needs consists of three components: supply-side resources, demand-side resources, and purchased power resources. The Company uses a 20 percent planning reserve margin as a baseline to meet contingencies such as forecast uncertainties, unit outages, weather extremes, and historically long lead times for new generation resources. With the increased flexibility from the purchased power market offering short lead time resources and shortened lead times for new generation construction, the Company expects to maintain an operating reserve margin of approximately 17 percent of its anticipated peak load requirements through 2001. The Company continues to engage in a comprehensive energy management program as part of its Integrated Resource Plan (IRP). Integrated resource planning is the process used by utilities to evaluate a variety of resources. The goal is to provide adequate and reliable electricity in an environmentally responsible manner through cost-effective power management. As customers elect to procure generation from other suppliers, as two of the Company's wholesale customers have indicated they will do beginning in 1997, the Company will no longer be obligated to plan for the future generation needs of those customers. The Company files an IRP with the NCUC and the PSCSC once every three years. During each of the intervening years, the Company files a Short Term Action Plan which updates the IRP for any changes in projections for the next three years. The PSCSC issued an order on December 14, 1995 approving the Company's 1995 IRP. On February 20, 1996, the NCUC issued a similar order. Short-term action plans were filed with both the NCUC and the PSCSC in April 1996. The Company has completed the construction of a combustion turbine facility in Lincoln County, North Carolina, to provide capacity at periods of peak demand. The station consists of sixteen combustion turbines with a total generating capacity of 1,200 megawatts. During 1995, twelve units of the Lincoln Combustion Turbine Station began commercial operation. The last four units began commercial operation in the first quarter of 1996. Demand-side management (DSM) programs benefit the Company and its customers by providing cost-effective energy efficiency, providing for load control through interruptible control features, shifting usage to off-peak periods and increasing
strategic sales of electricity. The November 1991 rate orders of the NCUC and the PSCSC provided for recovery in rates of a designated level of costs for DSM programs and allowed the deferral for later recovery of certain DSM costs that exceed the level reflected in rates, including a return on the deferred costs. In 1993, the NCUC and the PSCSC issued orders approving "shared savings" mechanisms for accomplishments achieved in the Company's DSM programs, and deferral of such shared savings. The May 1996 rate rider in South Carolina included an increment for DSM cost recovery. (See "Rate Matters.") The Company ultimately expects recovery through rates of associated deferred costs, not to exceed $75 million including deferred returns in the North Carolina retail jurisdiction. The annual costs deferred, including the return, were approximately $11 million in 1996 and $27 million in 1995. The total costs deferred, including the return, are $67 million and $40 million in North Carolina and South Carolina, respectively. The purchase of capacity and energy is an integral part of meeting future power needs. As of December 31, 1996, the Company had under contract 329 MW of capacity from other generators of electricity, including 91 MW from qualifying facilities. In 1995, the Company issued two requests for proposals (RFP) to solicit both short-term and long-term competitive bids to provide future electric generating capacity resources. After review of all bids, the Company selected a short-term bid from PECO Energy Co. of Philadelphia. The agreement gives the Company the option to purchase up to 250 megawatts of capacity during the summer months of 1998 through 2001. Contract arrangements between the parties were finalized on August 1, 1996. The long-term RFP was closed and no bids were accepted. CAPITAL REQUIREMENTS Projected capital expenditures, excluding costs related to portions of the Catawba Nuclear Station owned by the other Catawba joint owners, for the years set forth below, as now scheduled, are as follows (in millions):
The Company's procedures for estimating capital expenditures for Duke Power -- Electric (which include allowance for funds used during construction) utilize, among other things, past construction experience, current construction costs, allowances for inflation and the Company's business plan. These projections are subject to periodic review and revisions. Actual construction and nuclear fuel costs and capital expenditures incurred may vary from such estimates. Cost variances for Duke Power -- Electric are due to various factors, including revised load estimates, environmental matters and cost and availability of capital. Projections of the AEG capital expenditures are subject to periodic review and revision and may vary significantly as the business plans of the AEG evolve to meet the opportunities presented by their markets. JOINT OWNERSHIP OF GENERATING FACILITIES The Company, through several transactions beginning in 1978, sold an 87.5% undivided interest in the Catawba Nuclear Station to the other Catawba joint owners. These transactions contemplate that the Company will operate the facility, interconnect its transmission system, wheel a certain portion of the capacity and energy of such facility to the respective participants, provide back-up services for such capacity, buy for its own use (whether or not the facility is generating electricity) that portion of the capacity not then contractually required by the respective participants, and provide supplemental power as required by the purchasers to enable them to provide service on a firm basis. The transactions also include a reliability exchange between the Catawba Nuclear Station and the McGuire Nuclear Station of the Company, which provides for an exchange of 50 percent of each other Catawba joint owner's retained capacity from its ownership interest in the Catawba units for like amounts of capability and output from units of the McGuire Nuclear Station. The implementation of the reliability exchange has not had, nor does the Company anticipate that such implementation will have, a material effect on earnings. (See Note 3, "Notes to Consolidated Financial Statements.")
The Company and North Carolina Municipal Power Agency Number 1 (NCMPA) and Piedmont Municipal Power Agency (PMPA), two of the four other joint owners of the Catawba Nuclear Station, entered into a settlement in 1995 which resolved outstanding issues related to how certain calculations affecting bills under the Catawba joint ownership contractual agreements should be performed. The settlement was approved by the NCUC on January 16, 1996, and the PSCSC on January 23, 1996. As part of the settlement, the Company agreed to purchase additional megawatts (MW) of Catawba capacity during the period 1996 through 1999 and remove certain restrictions related to sales of surplus energy by these two joint owners. The additional capacity purchases are 215 MW in 1996, 165 MW in 1997, 120 MW in 1998 and 100 MW in 1999. The Company expects to recover the costs associated with this settlement as part of the purchased capacity levelization, consistent with prior orders of the retail regulatory commissions. Therefore, the Company believes these matters should not have a material adverse effect on its results of operations or its financial position. The Company and all four of the other joint owners of the Catawba Nuclear Station entered into settlement agreements in 1994 which resolved all issues in contention in arbitration proceedings related to the Catawba joint ownership contractual agreements. The basic contention in each proceeding was that certain calculations affecting bills under these agreements should be performed differently. These items are covered by the agreements between the Company and the other Catawba joint owners, which previously have been approved by the Company's retail regulatory commissions. (For additional information on Catawba joint ownership, see Note 3, "Notes to the Consolidated Financial Statements.") In 1994, the Company settled its cumulative net obligation through 1993 of approximately $205 million related to these settlement agreements. Billings for 1994 and later years conform to the settlement agreements, which were approved by the Company's retail regulatory commissions. Because the Company expects the costs associated with these settlements to be recovered as part of the purchased capacity levelization, which has been approved by the Company's retail regulatory commissions, the Company included approximately $205 million as an increase to "Purchased capacity costs" on its Consolidated Balance Sheet in 1994. Therefore, the Company believes these matters should not have a material adverse effect on its results of operations or its financial position. FUEL SUPPLY The Company presently relies principally on nuclear fuel and coal for the generation of electric energy. The Company's reliance on oil and gas is minimal even with the addition of the Lincoln Combustion Turbine Station, which is designed to operate on either natural gas or oil. Information regarding the utilization of sources of power and cost of fuels is set forth in the following table:
(1) Statistics related to nuclear generation and all fuels reflect the Company's 12.5% ownership in the Catawba Nuclear Station. (2) Statistics related to oil and gas generation and all fuels reflect precommercial generation at the Lincoln Combustion Turbine Station in 1995 and 1996. (3) Oil and gas cost statistics include amounts for light-off fuel at the Company's coal-fired stations. (4) Generating figures are net of that output required to replenish pumped storage units during off-peak periods and do not include NP&L. COAL. The Company obtains a large amount of its coal under long-term supply contracts with mining operators utilizing both underground and surface mining. The Company has on hand an adequate supply of coal. The Company's long-term supply contracts, all of which have price adjustment provisions, have expiration dates ranging from 1997 to 2003. The Company believes that it will be able to renew such contracts as they expire or to enter into similar contractual arrangements with
other coal suppliers for quantities and qualities of coal required. The coal covered by the Company's long-term supply contracts is produced from mines located in eastern Kentucky, southern West Virginia and southwestern Virginia. The Company's requirements not met by long-term supply contracts have been and will be fulfilled with spot market purchases. The average sulfur content of coal being purchased by the Company is approximately 1 percent. Such coal satisfies the current emission limitation for sulfur dioxide for existing facilities. (See "Management's Discussion and Analysis of Results of Operations and Financial Condition, Current Issues -- The Clean Air Act Amendments of 1990.") NUCLEAR. Generally, the supply of fuel for nuclear generating units involves the mining and milling of uranium ore to produce uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, enrichment of that gas and fabrication of the enriched uranium hexafluoride into usable fuel assemblies. After a region (approximately one-third of the nuclear fuel assemblies in the reactor at any time) of spent fuel is removed from a nuclear reactor, it is placed in temporary storage for cooling in a spent fuel pool at the nuclear station site. The Company has contracted for uranium materials and services required to fuel the Oconee, McGuire and Catawba Nuclear Stations. Based upon current projections, these contracts will meet the Company's requirements through the following years:
Uranium material requirements will be met through various supplier contracts, with uranium material produced primarily in the U.S. and Canada. The Company believes that it will be able to renew contracts as they expire or to enter into similar contractual arrangements with other nuclear fuel materials and services suppliers. Requirements not met by long-term supply contracts have been and will be fulfilled with uranium spot market purchases. The Department of Energy (DOE) requested Expressions of Interest (EOI) to facilitate in the disposal of plutonium. The Company and Commonwealth Edison, along with the other joint owners of the Catawba Nuclear Station, responded to the EOI in early 1996. As this project is in its early developmental stage, management cannot predict the outcome of this process. However, the Company believes these matters should not have a material effect on the results of operations or financial position of the Company. The Nuclear Waste Policy Act of 1982 requires that the DOE begin disposing of spent fuel no later than January 31, 1998. The Company has entered into the required contracts with the DOE for the disposal of nuclear fuel and began making payments in July 1983 for disposal costs of fuel currently being utilized. These payments, combined with a one-time payment for disposal costs of fuel consumed prior to April 7, 1983, have totaled about $540 million through 1996 related to the Company's ownership interest in nuclear plants. The DOE has announced that the department anticipates a delay in accepting the waste materials on the contract date of January 31, 1998. The Company has joined with 35 other utilities in a lawsuit attempting to force the DOE to meet its obligations as called for in the contract. While it is uncertain what interim storage will be provided by the DOE due to its inability to meet the contract date, the Company has satisfactory plans in place to provide storage of spent nuclear fuel if the DOE cannot accept it. REGULATION The Company is subject to the jurisdiction of the NCUC and the PSCSC which, among other things, must approve the issuance of securities. The Company also is subject, as to some phases of its business, to the jurisdiction of the FERC, the Environmental Protection Agency (EPA) and state environmental agencies and to the jurisdiction of the Nuclear Regulatory Commission (NRC) as to design, construction and operation of its nuclear power facilities. The Company is exempt from regulation as a holding company under the Public Utility Holding Company Act of 1935 (PUHCA), except with respect to the acquisition of the securities of other public utilities. ENVIRONMENTAL MATTERS. The Company is subject to federal, state, and local regulations with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. North Carolina has enacted a declaration of environmental policy requiring all state agencies to administer their responsibilities in accordance with such policy. The NCUC has adopted rules requiring consideration of environmental effects in determining whether certificates of public convenience and necessity will be granted for proposed generation facilities. South Carolina law also requires consideration by the PSCSC of environmental effects in determining whether certificates of public convenience and necessity will be granted
for proposed major utility facilities, which include certain generation and transmission facilities. All of the Company's facilities which are currently under construction have been designed to comply with presently applicable environmental regulations. Such compliance has, however, increased the cost of electric service by requiring changes in the design and operation of existing facilities. In 1996, the Company's construction costs for environmental protection totaled approximately $9 million, while the on-going environmental operation costs were approximately $24 million. The Company's 1997-2001 construction program includes costs for environmental protection which are estimated to be approximately $152 million, including $4.2 million in 1997, $44.5 million in 1998, $55.5 million in 1999, $25.6 million in 2000 and $22.5 million in 2001. These costs include expenditures associated with the Clean Air Act Amendments of 1990. However, governmental regulations establishing environmental protection standards are continually evolving and have not, in some cases, been fully established. These projections are subject to periodic review and revisions. Actual construction costs and capital expenditures incurred may vary from such estimates. Cost variances are due to various factors, including cost and availability of capital. AIR QUALITY. See "Management's Discussion and Analysis of Results of Operations and Financial Condition, Current Issues -- The Clean Air Act Amendments of 1990" for a discussion of the Company's plans for compliance with federal clean air standards. The EPA has recently proposed revisions to two of its air quality standards, one for ozone and the other for particulate matter. These two proposals will not be final until the summer of 1997, and will likely take years to implement fully. The rules as proposed would likely require significant capital expenditures by electric utilities, particularly with respect to coal-fired generation facilities, as well as by businesses in many other industries. If promulgated without revision, it is expected that the rules will be challenged in court, which could delay the effective implementation date or could result in the rules being overturned altogether. Thus, it is too early to estimate with accuracy the impact these rules could have on the Company. Nevertheless, if implemented as proposed, the cost of compliance for the Company could range from approximately $30 million to approximately $600 million over a period currently estimated to be from 2002 through 2005. WATER QUALITY. The Federal Water Pollution Control Act Amendments of 1987 (referred to herein as the "Clean Water Act") require permits for facilities that discharge treated wastewater to the environment. The Company holds numerous such permits, which are issued periodically. The issuance of such permits is delegated by the EPA to state agencies in North and South Carolina. The Clean Water Act has been scheduled for review and reauthorization by Congress since 1994, but no legislation has been enacted. Until Congress acts upon the reauthorization, management will be unable to assess what effect, if any, such reauthorization will have on the Company's operations. OTHER ENVIRONMENTAL REGULATIONS. Contingencies associated with environmental matters are principally related to possible obligations to remove or mitigate the effects of contaminants resulting from the disposal of certain substances. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), commonly known as "Superfund," can require any individual or entity which may have owned or operated a disposal site, as well as transporters or generators of hazardous wastes which were sent to such site, to share in remediation costs for the site. Such parties are known as "potentially responsible parties" (PRPs). Some sites are remediated pursuant to state acts which are similar to CERCLA. The Company is currently participating in PRP groups with regard to Superfund sites near Concord, North Carolina and Lenoir, North Carolina. While the total cost of remediation at these federal and state contamination sites may be substantial, the Company shares probable liability with other PRPs, many of which have substantial assets. Management is of the opinion that resolution of these matters will not have a material adverse effect on the results of operations or financial position of the Company. Other clean-up sites in which the Company is involved arise from the former operation of manufactured gas plants (MGP), which were commonplace in the Carolinas until the 1950s. Some such sites are still owned by the Company, and others are now owned by third parties. In North Carolina, the Company is participating in a state-sponsored program to investigate and, where appropriate, remediate MGP sites. In South Carolina, the Company is in the process of remediating an MGP site in Greenville. Management is of the opinion that resolution of these matters will not have a material adverse effect on the results of operations or financial position of the Company. CERCLA has been scheduled for review and reauthorization by Congress since 1994, but no legislation has been enacted. Until CERCLA reform occurs, management will be unable to assess what effect, if any, such reauthorization will have on the Company's operations. GENERAL. Over the past few decades, the issue of the possible health effects of electric and magnetic fields has generated a number of generally inconclusive studies, some public concern and litigation as well as legislative action in some states regarding high voltage transmission lines. The impact of this issue on the Company cannot presently be determined. NUCLEAR FACILITIES. The Company's nuclear facilities are subject to continuing regulation by the NRC.
Stress corrosion cracking (SCC) has occurred in the steam generators of Units 1 and 2 at the McGuire Nuclear Station and Unit 1 at the Catawba Nuclear Station. Catawba Unit 2, which has certain design differences and came into service at a later date, has not yet shown the degree of SCC which has occurred in McGuire Units 1 and 2 and Catawba Unit 1. It is, however, too early in the life of Catawba Unit 2 to determine the extent to which SCC may be a problem. Although the Company has taken steps to mitigate the effects of SCC, the inherent potential for future SCC in the McGuire and Catawba steam generators still exists. The Company planned for the replacement of steam generators at three units that have experienced SCC and purchased the replacement steam generators from Babcock & Wilcox International. Replacement of the steam generators at Catawba Unit 1 was successfully completed at a lower cost than projected on October 4, 1996, after a 115-day outage that included replacement work and other maintenance. Steam generator replacement in both McGuire units is scheduled for completion during 1997. The Catawba Unit 2 steam generators have not been scheduled for replacement. Steam generator replacement at each McGuire unit is expected to take approximately four months and cost approximately $170 million, excluding the cost of replacement power. Stress corrosion problems are excluded under the Company's nuclear insurance policies. The Company, in connection with its McGuire and Catawba stations and on behalf of the other joint owners of the Catawba Station, began a legal action in 1990, alleging that Westinghouse Electric Corporation knowingly supplied to the McGuire and Catawba stations steam generators that were defective in design, workmanship and materials, requiring replacement well short of their stated design life. The lawsuit was settled in 1994. While the court order does not allow disclosure of the terms of the settlement, the Company believes the litigation was settled on terms that provided satisfactory consideration to the Company and will not have a material effect on the Company's results of operations or financial position. NUCLEAR DECOMMISSIONING COSTS. Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $1.3 billion stated in 1994 dollars based on decommissioning studies completed in 1994. This amount includes the Company's 12.5% ownership in the Catawba Nuclear Station. The other Catawba joint owners are responsible for decommissioning costs related to their ownership interests in the station. Such estimates presume each unit will be decommissioned as soon as possible following the end of its license life. Although subject to extension, the current operating licenses for the Company's nuclear units expire as follows: Oconee 1 and 2 -- 2013, Oconee 3 -- 2014; McGuire 1 -- 2021, McGuire 2 -- 2023; and Catawba 1 -- 2024, Catawba 2 -- 2026. The NRC issued a rulemaking in 1988 which requires an external mechanism to fund the estimated cost to decommission certain components of a nuclear unit subject to radioactive contamination. In addition to the required external funding, the Company maintains an internal reserve to provide for decommissioning costs of plant components not subject to radioactive contamination. During 1996, the Company expensed approximately $56 million, which was contributed to the external funds and accrued an additional $2 million to the internal reserve. The balance of the external funds as of December 31, 1996, was $363 million. The balance of the internal reserve as of December 31, 1996, was $208 million and is reflected in accumulated depreciation and amortization on the Consolidated Balance Sheets. Management's opinion is that the decommissioning costs being recovered through rates, invested at assumed after-tax earnings rates of 5.5 percent to 5.9 percent, are sufficient to provide for the estimated cost of decommissioning. A provision in the Energy Policy Act of 1992 established a fund for the decontamination and decommissioning of the DOE's uranium enrichment plants. Licensees are subject to an annual assessment for 15 years based on their pro rata share of past enrichment services. The annual assessment is recorded as fuel expense. The Company paid $9.5 million during 1996 and has paid $45.0 million cumulatively related to its ownership interest in nuclear plants. The Company has reflected the remaining liability and regulatory asset of $94.7 million in the Consolidated Balance Sheet at December 31, 1996. NUCLEAR INSURANCE. For a discussion of the Company's nuclear insurance coverage, see "Note 13, Notes to Consolidated Financial Statements, Commitments and Contingencies -- Nuclear Insurance." HYDROELECTRIC LICENSES. The principal hydroelectric projects of the Company are licensed by FERC under Part I of the Federal Power Act. Eleven developments on the Catawba-Wateree River in North Carolina and South Carolina, with a nameplate rating of approximately 805 MW, are licensed for a term expiring in 2008. The Company also holds a license for the Keowee-Toxaway Project for a term expiring in 2016, covering the Keowee Hydro Station and the Jocassee Pumped Storage Station for a combined total of approximately 770 MW, on the upper tributaries of the Savannah River in northwestern South Carolina. Additionally, the Company is the licensee through 2027 for the Bad Creek Hydroelectric Station which uses Lake Jocassee as its lower reservoir and has a nameplate rating of 1,065 MW. The Company received new 40-year licenses in 1996 for two existing projects on the Broad River. The Company sold seven small hydroelectric projects in 1996. NP&L holds licenses for 11 hydroelectric projects with a nameplate rating of 100 MW with license terms expiring 2001-2006. The Federal
Power Act provides, among other things, that, upon the expiration of any license issued thereunder, the United States may (a) grant a new license to the licensee for the project, (b) take over the project upon payment to the licensee of its "net investment" in the project (but not in excess of the fair value thereof) plus severance damages, or (c) grant a license for the project to a new licensee subject to payment to the former licensee of the amount specified in (b) above. INTERCONNECTIONS The Company has major interconnections and arrangements with its neighboring utilities which it currently considers adequate for coordinated planning, emergency assistance, exchange of capacity and energy, and reliability of power supply. COMPETITION The Company currently is subject to competition in some areas from government-owned power systems, municipally-owned electric systems, rural electric cooperatives and, in certain instances, from other private utilities. Statutes in North Carolina and South Carolina provide for the assignment by the NCUC and the PSCSC, respectively, of all areas outside municipalities in such states to power companies and rural electric cooperatives. Substantially all of the territory comprising the Company's service area has been so assigned. The remaining areas have been designated as unassigned and in such areas the Company remains subject to competition. A decision of the North Carolina Supreme Court limits, in some instances, the right of North Carolina municipalities to serve customers outside their corporate limits. In South Carolina there continues to be competition between municipalities and other electric suppliers outside the corporate limits of the municipalities, subject, however, to the regulation of the PSCSC. In addition, the Company is engaged in continuing competition with various natural gas providers. The Energy Policy Act of 1992 (EPACT) and the FERC's subsequent rulemaking activities are major drivers toward a more competitive market for electric generation. EPACT reformed provisions of PUHCA and Part II of the Federal Power Act to remove certain barriers to competition for the supply of electricity. For example, EPACT allows utilities to participate in the development of independent electric generating plants in the United States for sales to wholesale customers, as well as to contract for utility projects internationally, without becoming subject to regulation under PUHCA as an electric utility holding company. In addition, EPACT permits the FERC to order transmission access for third parties to transmission facilities owned by another entity so that energy suppliers can sell to wholesale customers wherever they are located. It does not, however, permit the FERC to issue an order requiring transmission access to retail customers. The FERC, responsible in large measure for implementation of the EPACT, has moved vigorously to implement its mandate, interpreting the statute broadly in issuing orders for third-party transmission service and issuing a number of rules of general applicability. On April 24, 1996, the FERC issued its Order Numbers 888 and 889, which established the final form of transmission tariff to provide comparable service to all users of a utility's transmission system. Open-access transmission for wholesale customers as defined by the FERC's final rules provides energy suppliers, including the Company, with opportunities to sell and deliver capacity and energy at market-based prices. Engaging in such transactions may result in improved utilization of the Company's existing assets. In addition, such access provides another supply option through which the Company can buy capacity and energy at attractive rates, influencing its competitive price position. However, sales to existing wholesale customers of the Company may continue to be impacted by open access either due to competitive pressure on the wholesale price of electricity, or the potential loss of sales as wholesale customers seek other options to meet their capacity and energy requirements at market-based prices. (For additional information about sales to wholesale customers, see "Liquidity and Resources -- Duke Power Company Rate Matters," and Note 3, "Notes to Consolidated Financial Statements.") Wholesale sales represented approximately 8.8 percent of the Company's total kilowatt-hour sales in 1996. Supplemental sales to the other joint owners of the Catawba Nuclear Station comprised the majority of such sales. Such supplemental sales will continue to decline in 1997 as a result of the retention of larger portions of ownership entitlement by the other joint owners. (For additional information on Catawba joint ownership, see Note 3, "Notes to Consolidated Financial Statements.") In early 1995, prior to issuance of the FERC's Notice of Proposed Rulemaking, the Company and certain of its affiliates filed three applications with the FERC, all of which were designed to enable effective participation in the competitive environment of the changing electric utility industry. Duke Power filed an application for permission to sell at market-based rates up to 2,500 megawatts of capacity and energy from its own assets. Two of the Company's affiliates, Duke Energy Marketing Corp. (DEMC) and Duke/Louis Dreyfus LLC (D/LD), filed applications with the FERC to become power marketers. All of the applications were supported by transmission tariffs which complied with then applicable FERC standards and established the rates, terms and conditions for transmission service to third parties on the Company's transmission system. Late in 1995,
the FERC granted the applications of Duke, DEMC, and D/LD; accepted Duke's transmission tariffs; and ordered a hearing on the rates to be charged for service under those tariffs. On July 9, 1996, in compliance with the standards and schedules set forth in Order Number 888, the Company filed a pro forma open access transmission tariff complying with the requirements of the FERC's final rules. Such a filing was required of all transmission-owning utilities subject to the FERC's jurisdiction. The Company also filed on that date a proposed settlement in the proceeding earlier ordered by the FERC. The proposed settlement resolves all rate issues related to transmission services under Duke's tariff and contains the rates agreed upon under the settlement. The settlement and the July 9, 1996 tariff filing remain subject to final FERC approval. Competition for retail customers is not generally allowed in the Company's service territory. However, there are discussions and events at the national level and within certain states regarding retail competition which could result in changes in the industry. Such changes, should they occur, could impact all entities owning generation, including the other joint owners of the Catawba Nuclear Station. The process of assessing changes to the regulatory structure is just beginning in the Company's retail jurisdictions and has not progressed as rapidly as in some other states. A bill was passed in the North Carolina General Assembly to establish a group to study the issues surrounding retail competition. The study group is to report the results of its study to the 1999 General Assembly. While a bill has been introduced to provide for retail competition in South Carolina, the bill does not have the support of all interested parties and in effect just begins the process of addressing the relevant issues in that state. In addition, a bill has been recently introduced in the South Carolina legislature to create an electric deregulation study committee on retail competition. In addition, at the federal level, several bills have been introduced in Congress, and it is likely that other bills will be introduced in the future, that may cover many different issues, including the following: repeal of PUHCA and certain provisions of the Public Utility Regulatory Policies Act of 1978, retail competition, disaggregation of electric utilities and the restructuring of the electric utility industry. This activity is at an early stage, and no assessment of its impact, if any, upon the Company can be made at this time. (See "Management's Discussion and Analysis of Results of Operations and Financial Condition, Current Issues -- Competition.") Currently, the electric utility industry is predominantly regulated on a basis designed to recover the cost of providing electric power to its retail and wholesale customers. If cost-based regulation were to be discontinued in the industry, for any reason, including competitive pressure on the cost-based prices of electricity, profits could be reduced and utilities might be required to reduce their asset balances to reflect a market basis less than cost. Discontinuance of cost-based regulation would also require affected utilities to write off their associated regulatory assets. The regulatory assets of the Company are classified as "Deferred debits" on the Consolidated Balance Sheets. Substantially all of the "Deferred debits" are regulatory assets. Management cannot predict the potential impact, if any, of these competitive forces on the Company's future financial position and results of operations. However, the Company continues to position itself to effectively meet these challenges by maintaining prices that are locally, regionally and nationally competitive. In addition to the changing regulatory environment, another trend toward increasing competition in the electric utility industry is the convergence of markets for electricity and natural gas. The Company's management has noted the emergence of a national market for energy products and services in which demands for energy in the forms of electricity and gas are increasingly being met by vendors who have the ability to supply both. The Company's proposed merger with PanEnergy Corp is its primary strategic response to this trend. (See "Management's Discussion and Analysis of Results of Operations and Financial Condition, Current Issues -- Proposed Merger with PanEnergy Corp.") SUBSIDIARIES AND DIVERSIFIED ACTIVITIES The Company continues to aggressively pursue both domestic and international diversified business opportunities that are synergistic with the Company's core business to provide additional value to the Company's shareholders. Among the Company's current industry pursuits are ownership of electric power facilities, energy marketing, real estate, communications, engineering consulting and various energy services. Although these opportunities are primarily concentrated in areas that utilize the Company's expertise, they present different and potentially greater risks than does the Company's core business. The Company only pursues opportunities in which the expected returns are commensurate with the risks and makes efforts to mitigate such risks. The Company undertakes a continuous evaluation of the various lines of business it may enter or exit, with the objective of enhancing shareholder value and managing any associated risk. (See "Subsidiaries and Diversified Activities Highlights.") Major subsidiaries and diversified activities include the following: CRESCENT RESOURCES, INC. (Crescent) provides high-quality residential and commercial real estate development services in the Southeast in addition to providing forest management activities focused on growing trees suitable for use in the construction, furniture and paper industries. During 1996, Crescent sold 869 residential developed lots compared to 600 lots in 1995. At December 31, 1996, Crescent owned approximately 2.5 million square feet of office, retail and warehouse space and had approximately 900,000 square feet of commercial properties under construction. Additionally, Crescent had approximately 249,000 acres of land under its management at year end.
DUKE ENERGY GROUP, INC. (Duke Energy Group) develops, owns, manages and operates energy facilities worldwide. Domestically, Duke Energy Group concentrates on advanced fossil-fueled generation including pulverized coal, circulating fluidized bed, coal gasification and natural gas technologies. Internationally, Duke Energy Group pursues advanced coal-fueled, hydroelectric and gas-fueled generation as well as transmission projects. Duke Energy Group has equity interests in two U.S. electric generation facilities and six international projects. DUKE ENGINEERING & SERVICES, INC. (DE&S) provides engineering, project management, quality assurance, construction management, operating and maintenance and environmental services for utilities, industry and government worldwide. During 1996, DE&S continued to expand primarily due to the acquisition of the nuclear engineering, government services and power services businesses of VECTRA Technologies, Inc. DE&S was awarded 984 contracts in 1996, including a contract to manage and integrate spent nuclear fuel activities at the Department of Energy's Hanford facility in Washington state. DE&S's domestic and global presence is evident by its 23 U.S. business offices, 13 international offices and projects underway in more than 50 countries. NANTAHALA POWER AND LIGHT COMPANY (NP&L) is a franchised electric utility which operates 11 hydroelectric plants with a total capacity of 100 megawatts. NP&L has approximately 55,000 customers in western North Carolina. NP&L sold 1,085,000 MWH in 1996 compared with 949,000 MWH in 1995, excluding firm sales and sales to Duke Power. OTHER BUSINESS UNITS include Church Street Capital Corp., which provides equity funding and credit enhancement services for its subsidiaries and manages investment funds; Duke/Fluor Daniel, a joint venture with Fluor Daniel, Inc., which provides engineering, procurement, construction and operating and maintenance services for fossil-fueled electric generating stations worldwide; Duke/Louis Dreyfus, LLC, which markets electric power, natural gas and energy-related services to utilities, municipalities and other large energy users in North America; Duke Merchandising, which sells and services home appliances, electronics and wireless communications devices; DukeNet Communications, Inc., which develops and manages communications systems, including fiber optic and wireless digital network services; and Duke Water Operations, which provides franchised water service to customers in parts of North and South Carolina. EMPLOYEES At December 31, 1996, the Company had 17,726 full-time employees, which included 2,724 full-time employees of subsidiaries and diversified activities. About 1,850 electrical operating employees are represented by the International Brotherhood of Electrical Workers (IBEW). During the last quarter of 1996, the Company and the IBEW were unable to reach a new labor agreement and, in December 1996, the Company unilaterally implemented its final offer for settlement. The number of full-time employees has decreased to the 1996 year-end level from 18,551 at year-end 1991. (See "Management's Discussion and Analysis of Results of Operations and Financial Condition, Current Issues -- Resource Optimization.") SUBSEQUENT EVENTS On March 18, 1997, the PSCSC unanimously voted in favor of the merger of the Company and PanEnergy Corp and approved the issuance of securities for the merger. Hearings were held in the PSCSC proceeding on March 6, 1997 and in the NCUC proceeding on March 18, 1997. In connection with the hearings, the Company entered into stipulations with the South Carolina Consumer Advocate and the Public Staff of the NCUC. The stipulations contain certain conditions that, among other things, are generally designed to ensure (i) that the rates of the Company's retail electric and water customers will not be affected by any costs of, or increased costs attributable to, the merger or by any commitments made by the Company in other jurisdictions relating to the merger, (ii) that the Company's future conduct of business with its subsidiaries and affiliates, and its allocation of costs among the Company and its subsidiaries and affiliates, do not lessen competition or adversely impact rates, (iii) that the Company will not seek to increase its retail rates through the year 2000, except to reflect substantial financial impacts of governmental action affecting the industry generally, or a segment thereof, including the Company, or major expenditures attributable to FORCE MAJEURE events, and (iv) that North Carolina's regulatory jurisdiction will not be diminished by preemption, to the detriment of retail customers, should the Company in the future engage in an action that causes it to cease to be exempt from registration under PUHCA. Orders to be issued in both the PSCSC and NCUC proceedings may contain some or all of the conditions set forth in the stipulations.
(Picture Graphic of a Map of North and South Carolina appears here)
DUKE POWER COMPANY OPERATING STATISTICS
(a) Does not include operating statistics of NP&L. (b) Includes 12.5% of Catawba generation. (c) 1996 and 1995 include KWH of the Lincoln Combustion Turbine Station prior to commercial operation. (d) Includes sales to NP&L. EXECUTIVE OFFICERS OF THE COMPANY WILLIAM H. GRIGG, 64, Chairman of the Board and Chief Executive Officer. Mr. Grigg served as Chairman of the Board, President and Chief Executive Officer, effective April 28, 1994, until July 27, 1994 when he assumed his present position. He served as Vice Chairman of the Board beginning in 1991, and Executive Vice President, Customer Group, beginning in 1988. STEVE C. GRIFFITH, JR., 63, Vice Chairman of the Board and General Counsel. Mr. Griffith served as Executive Vice President and General Counsel from 1991 until he assumed his present position in July 1994. He served as Senior Vice President and General Counsel from 1982 until 1991. RICHARD B. PRIORY, 50, President and Chief Operating Officer. Mr. Priory served as Executive Vice President, Power Generation Group, from 1991 until he assumed his present position in July 1994. He was Senior Vice President, Generation and Information Services, from 1988 to 1991. WILLIAM A. COLEY, 53, President, Associated Enterprises Group. Mr. Coley was named Senior Vice President, Power Delivery, in 1988; Senior Vice President, Customer Group, in 1990; and Executive Vice President, Customer Group, in 1991. He was named to his present position in July 1994. RICHARD J. OSBORNE, 45, Senior Vice President and Chief Financial Officer. Prior to assuming his current position in July 1994, Mr. Osborne served as Vice President and Chief Financial Officer beginning in 1991 and Vice President, Finance, from 1988 to 1991. JEFFREY L. BOYER, 40, Controller. Mr. Boyer served as Director of Corporate Accounting for more than five years prior to assuming his present position in July 1994. Executive officers are elected annually by the Board of Directors and serve until the first meeting of the Board of Directors following the next annual meeting of shareholders and until their successors are duly elected. There are no family relationships between any of the executive officers nor any arrangement or understanding between any executive officer and any other person pursuant to which the officer was selected. There have been no events under any bankruptcy act, no criminal proceedings and no judgments or injunctions material to the evaluation of the ability and integrity of any executive officer during the past five years.
ITEM 2.
ITEM 2. PROPERTIES. At December 31, 1996, the Company, excluding its subsidiary NP&L, operated three nuclear generating stations, eight coal-fired stations and twenty hydroelectric stations, all of which are located in North Carolina or South Carolina. The following is a list of the major generating stations owned by the Company at December 31, 1996:
(a) Represents Duke's 12.5% ownership share in Catawba Nuclear Station. In addition to the electric generating plants described above, the Company owned, as of December 31, 1996, approximately 8,300 conductor miles of transmission lines, including 600 conductor miles of 500 kilovolts, 1,400 conductor miles of 220 kilovolts, 3,400 conductor miles of 100 kilovolts, and 2,900 conductor miles of 13 to 66 kilovolts. The Company also owned approximately 74,200 conductor miles of distribution lines, including 47,200 conductor miles of rural overhead lines, 14,700 conductor miles of urban overhead lines, 6,900 conductor miles of rural underground lines and 5,400 conductor miles of urban underground lines. As of such date, the Company's transmission and distribution systems comprised approximately 1,600 substations with an installed transformer capacity of approximately 85,200,000 kVA. NP&L's generation facilities consist of 11 hydroelectric plants with an aggregate nameplate capacity of approximately 100 MW. Duke Power supplies all of NP&L's supplemental power needs from Duke Power's Tuckaseegee Substation near NP&L's Thorpe Plant. NP&L also has an interconnection of 161 kV with the Tennessee Valley Authority (TVA) at Santeetlah, North Carolina. The transmission backbone of the NP&L system is a 161 kV line from Duke's Tuckaseegee Substation to the interconnection with TVA at Santeetlah, with NP&L substations at Robbinsville, Nantahala Plant, Oak Grove, Webster and Thorpe Plant. The map found at the end of Item 1 shows the locations of the Company's and NP&L's service areas and generating stations. Substantially all electric plant is mortgaged under the Indenture relating to the First and Refunding Mortgage Bonds of the Company. For additional information concerning the properties of the Company, see "Business -- Energy Requirements and Capability." ITEM 3.
ITEM 3. LEGAL PROCEEDINGS. Reference is made to "Business -- Regulation," "Management's Discussion and Analysis of Results of Operations and Financial Condition, Current Issues -- Commitments and Contingencies" and "Note 13, Notes to Consolidated Financial Statements, Commitments and Contingencies -- Other." ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. No matters were submitted to a vote of the Company's security holders during the last quarter of 1996.
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, 1996, there were approximately 130,683 holders of shares of such Common Stock. During 1996, the Company repurchased 3,269,743 shares of its Common Stock, at a total cost of $159 million, through a stock repurchase program. On January 28, 1997, the Board of Directors amended the program to expressly limit the number of shares authorized for repurchase under the program, from the initiation of the program through a date two years after the consummation of the proposed merger with PanEnergy Corp, to an amount not to exceed 15 million shares. (For additional information on the stock repurchase program, see Note 6, "Notes to the Consolidated Financial Statements.") The following table sets forth for the periods indicated the dividends paid per share of Common Stock and the high and low sales prices of such shares reported by the New York Stock Exchange Composite Transactions:
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION. This Management's Discussion and Analysis presents the financial condition, results of operations and certain forward-looking information about Duke Power Company and its subsidiaries. On November 25, 1996, the Company and PanEnergy Corp announced a proposed stock-for-stock merger. Unless otherwise indicated, all information presented herein relates to Duke Power Company only and does not take into account the proposed merger with PanEnergy. (For additional information on the proposed merger, see "Current Issues -- Proposed Merger with PanEnergy Corp.") RESULTS OF OPERATIONS EARNINGS AND DIVIDENDS. Earnings per share increased 4 percent from $3.25 in 1995 to $3.37 in 1996. The increase was primarily due to electric customer growth. Earnings per share increased from $2.88 in 1994 to $3.37 in 1996, indicating an average annual growth rate of 8 percent. Total Company earned return on average common equity was 14.2 percent in 1996 compared to 14.3 percent in 1995 and 13.3 percent in 1994. The Company continued its practice of annually increasing the common stock dividend. Common dividends per share increased at an average annual rate of 4 percent from $1.92 in 1994 to $2.08 in 1996. Indicated annual dividends per share increased to $2.12. REVENUES AND SALES. Operating revenues increased at an average annual rate of 3 percent from 1994 to 1996, primarily because of growth in the residential and general service customer classes and increased retail kilowatt-hour sales to weather-sensitive customer classes. As discussed below, increased retail sales were partially offset by decreased sales to wholesale customers. A South Carolina retail rate reduction also decreased revenues in 1996. (For additional information on the South Carolina rate reduction, see "Liquidity and Resources -- Duke Power Company Rate Matters.") Revenues from subsidiaries and diversified operations contributed $162 million to the increase in revenues over the three-year period, primarily from increased engineering service fees and developed lot and land sales. Wholesale revenues declined in 1996 as a result of the retention of significantly larger portions of ownership entitlement by the other joint owners of the Catawba Nuclear Station. This increased retention reduces the joint owners' supplemental requirements supplied by the Company. The effect on earnings of such wholesale revenue declines is partially offset by declines in purchased power costs from the other joint owners which are not subject to levelization. (For additional information on Catawba joint ownership, see Note 3, "Notes to the Consolidated Financial Statements.") Kilowatt-hour sales from Duke Power electric operations were flat from 1995 to 1996. Sales to residential, general service, and other industrial customers increased by 7 percent, 6 percent and 2 percent, respectively, as a result of colder winter weather and continued economic growth in Duke Power's service area. However, sales to textile customers decreased 5 percent, due to a weaker demand for textile goods. Wholesale sales decreased 16 percent primarily due to a decrease of 24 percent in supplemental sales requirements to the other joint owners of the Catawba Nuclear Station. OPERATING EXPENSES. From 1995 to 1996, other operation and maintenance expenses increased 7 percent. Increased activities of subsidiaries and diversified operations contributed to this increase. Distribution maintenance expenses also increased, primarily because of restoration costs associated with a February ice storm and Hurricane Fran. Other operation and maintenance expenses increased at an average annual rate of 6 percent from 1994 to 1996. Increased activities of the subsidiaries and diversified operations associated with engineering services contributed to this increase. Fuel expense increased at an average annual rate of 4 percent from 1994 to 1996. The increase was due primarily to higher system production requirements and higher levels of fossil generation as a percentage of total generation. These increases were partially offset by lower fossil fuel costs. Net interchange and purchased power expenses decreased from $553 million in 1994 to $379 million in 1996, an average annual decrease of 17 percent. This decrease was primarily the result of lower purchased power costs from the other joint owners not subject to levelization as the other joint owners retained significantly larger portions of their ownership entitlement, and lower levelized costs as a result of the substantial completion of the recovery of such costs from South Carolina customers.
From 1994 to 1996, depreciation and amortization expense increased at an average annual rate of 3 percent, primarily due to increased depreciation associated with additional investments. These investments were primarily associated with distribution plant, including investment to support customer growth, and the completion of the Lincoln Combustion Turbine Station. (For additional information on the Lincoln Combustion Turbine Station, see "Capital Needs -- Meeting Future Power Needs.") INTEREST EXPENSE AND OTHER INCOME. Interest expense increased at an average annual rate of 2 percent from 1994 to 1996, primarily due to long-term debt financing activities in 1994. Allowance for funds used during construction (AFUDC) and other deferred returns, net of associated taxes, represented 11 percent of earnings for common stock in 1996 compared to 13 percent in 1994. AFUDC and other deferred returns are expected to be less than 11 percent of total earnings during the next three years. The deferred return, net of associated taxes, on the purchased capacity levelization deferral related to the joint ownership of the Catawba Nuclear Station represented 7 percent of earnings for common stock in 1996, 1995 and 1994. The cumulative deferred purchased capacity balance began to decline in 1996 and will continue to decline in 1997. (For additional information on purchased capacity levelization, see "Capital Needs -- Purchased Capacity Levelization.") AFUDC, net of associated taxes, represented 3 percent of earnings for common stock in 1996 compared to 5 percent in 1995 and 6 percent in 1994. The changes were primarily the result of the construction and subsequent commercial operation of the Lincoln Combustion Turbine Station as 12 units were brought on-line in 1995 and the remaining 4 units were brought on-line during the first quarter of 1996. (For additional information on the Lincoln Combustion Turbine Station, see "Capital Needs -- Meeting Future Power Needs.") LIQUIDITY AND RESOURCES DUKE POWER COMPANY RATE MATTERS. Duke Power Company's most recent general rate increase requests in the North Carolina and South Carolina retail jurisdictions were filed and approved in 1991. Additionally, Duke Power has a bulk power sales agreement with Carolina Power & Light Company (CP&L) to provide CP&L 400 megawatts of capacity as well as associated energy when needed for a six-year period which began July 1, 1993. Electric rates in all of Duke Power's regulatory jurisdictions were reduced by adjustment riders to reflect capacity revenues received from this CP&L bulk power sales agreement. The Public Service Commission of South Carolina (PSCSC), on May 7, 1996, ordered a rate reduction in the form of a decrement rider of 0.432 cents per kilowatt-hour, or an average of approximately 8 percent, affecting South Carolina retail customers. South Carolina retail sales represent approximately 30 percent of the Company's total retail sales. The rate reduction was reflected on bills rendered on or after June 1, 1996. This net decrement rider reflects an interim true-up decrement adjustment associated with the levelization of Catawba Nuclear Station purchased capacity costs and an interim true-up increment associated with amortization of the demand-side management deferral account. The rate adjustment was made because, in the South Carolina retail jurisdiction, cumulative levelized revenues associated with the recovery of Catawba purchased capacity costs had exceeded purchased capacity payments and accrual of deferred returns, and certain demand-side costs had exceeded the level reflected in rates. Certain of the Company's wholesale customers, excluding the other Catawba joint owners, initiated proceedings in 1995 before the Federal Energy Regulatory Commission (FERC) concerning rate matters. The Company and nine of its eleven wholesale customers entered into a settlement in July 1996 which reduced the customers' rates by approximately 9 percent and renewed their contracts with the Company through the year 2000. Both of the customers that did not enter into the settlement have signed agreements to purchase energy from other suppliers beginning in 1997. The eleven wholesale customers involved in this matter accounted for less than 2 percent of the Company's overall electric revenues during 1996. The two customers that have signed agreements with other suppliers accounted for less than 0.5 percent of the Company's 1996 overall electric revenues. (For additional information about sales to wholesale customers, see "Current Issues -- Competition.") CATAWBA SETTLEMENTS. The Company and North Carolina Municipal Power Agency Number 1 (NCMPA) and Piedmont Municipal Power Agency (PMPA), two of the four other joint owners of the Catawba Nuclear Station, entered into a settlement in 1995 which resolved outstanding issues related to how certain calculations affecting bills under the Catawba joint ownership contractual agreements should be performed. The settlement was approved by the North Carolina Utilities Commission (NCUC) on January 16, 1996, and the PSCSC on January 23, 1996. As part of the settlement, the Company agreed to
purchase additional megawatts (MW) of Catawba capacity during the period 1996 through 1999 and remove certain restrictions related to sales of surplus energy by these two joint owners. The additional capacity purchases are 215 MW in 1996, 165 MW in 1997, 120 MW in 1998 and 100 MW in 1999. The Company expects to recover the costs associated with this settlement as part of the purchased capacity levelization, consistent with prior orders of the retail regulatory commissions. Therefore, the Company believes these matters should not have a material adverse effect on its results of operations or its financial position. The Company and all four of the other joint owners of the Catawba Nuclear Station entered into settlement agreements in 1994 which resolved all issues in contention in arbitration proceedings related to the Catawba joint ownership contractual agreements. The basic contention in each proceeding was that certain calculations affecting bills under these agreements should be performed differently. These items are covered by the agreements between the Company and the other Catawba joint owners, which previously have been approved by the Company's retail regulatory commissions. (For additional information on Catawba joint ownership, see Note 3, "Notes to the Consolidated Financial Statements.") In 1994, the Company settled its cumulative net obligation through 1993 of approximately $205 million related to these settlement agreements. Billings for 1994 and later years conform to the settlement agreements, which were approved by the Company's retail regulatory commissions. Because the Company expects the costs associated with these settlements to be recovered as part of the purchased capacity levelization, which has been approved by the Company's retail regulatory commissions, the Company included approximately $205 million as an increase to "Purchased capacity costs" on its Consolidated Balance Sheets in 1994. Therefore, the Company believes these matters should not have a material adverse effect on its results of operations or its financial position. CASH FROM OPERATIONS. Consolidated net cash provided by operating activities in 1996 accounted for 97 percent of total cash from operating, financing and investing activities compared with 81 percent in 1995 and 67 percent in 1994. When 1996 stock repurchase activities are excluded, cash generated from operating activities exceeded the Company's capital needs. (For additional information on the stock repurchase program, see Note 6, "Notes to the Consolidated Financial Statements.") FINANCING AND INVESTING ACTIVITIES. The Company's consolidated capital structure at year-end 1996, including subsidiary long-term debt, was 54 percent common equity, 39 percent long-term debt and 7 percent preferred stock. This structure is consistent with the Company's target to maintain a double-A credit rating. As of December 31, 1996, Duke Power's bonds were rated "AA" by Fitch Investors Service and Duff & Phelps, "Aa2" by Moody's Investors Service and "AA-" by Standard & Poor's Group. As a result of the announcement of the proposed merger with PanEnergy Corp, the Company has been placed on credit review by the rating agencies. (For additional information on the proposed merger, see "Current Issues -- Proposed Merger with PanEnergy Corp.") The Company had total credit facilities of $694.9 million and $669.9 million as of December 31, 1996 and 1995, respectively. The Company had unused credit facilities of $474.4 million and $440.6 million as of December 31, 1996 and 1995, respectively. During July 1996, the Company began purchasing shares of its common stock. The Company has repurchased approximately 3.3 million shares of common stock for $159 million as of December 31, 1996. (For additional information on the stock repurchase program, see Note 6, "Notes to the Consolidated Financial Statements.") In 1995, the Company issued $178 million of long-term debt, of which $72 million was used to retire higher cost long-term debt. The Company also retired $96 million of preferred stock and $80 million of long-term debt in 1995. In 1994, the Company issued $407 million in debt, primarily First and Refunding Mortgage Bonds. The Company has authority to issue up to $1 billion aggregate principal amount of debt securities under a shelf registration statement filed with the Securities and Exchange Commission (SEC). Such debt securities may be issued as First and Refunding Mortgage Bonds, Senior Notes, or Subordinated Debentures. In order to obtain variable rate financing at an attractive cost, the Company entered into interest rate swap agreements associated with the November 1994 issuance of $200 million aggregate principal amount of its First and Refunding Mortgage Bonds 8% Series B due 1999 and the August 1995 issuance of $100 million aggregate principal amount of its First and Refunding Mortgage Bonds 7 1/2% Series B due 2025. The interest rate swaps are reset quarterly based upon the three-month London Interbank Offered Rate (LIBOR). As a result of the interest rate swap contracts, interest expense is recognized at the weighted average rate for the year tied to the LIBOR rate. The weighted average rates at December 31, 1996, 1995 and 1994 were 5.64%, 6.14% and 5.95%, respectively, for the 8% Series B due 1999. The weighted average rates at December 31, 1996 and 1995 were 6.69% and 7.06%, respectively, for the 7 1/2% Series B due 2025.
Duke Energy Group, Inc. entered into a hedge transaction in 1995 to offset currency fluctuations between the U.S. dollar and the Chilean peso associated with expected equity contributions to an affiliate in 1995, 1996 and 1997. The hedge transaction has a notional amount of approximately $4.4 million at December 31, 1996. Duke Energy Group, Inc. records any realized gains or losses associated with the hedge as an adjustment to investments in affiliates. Duke/Louis Dreyfus (D/LD) enters into various derivative financial instruments involving future settlement. These transactions include exchange-traded futures and options and over-the-counter swaps and options for commodities, primarily natural gas and electricity. D/LD's derivative financial instruments are used for trading and marketing activities. These instruments are accounted for at market value and the related unrealized gains and losses are recognized in income. D/LD utilizes various risk management procedures to monitor its exposure and minimize counterparty risk. Duke Power's embedded cost of long-term debt, excluding debt of subsidiaries, was 7.95 percent for 1996 compared to 7.94 percent in 1995 and 7.98 percent in 1994. The embedded cost of preferred stock was 6.99 percent in 1996 compared to 7.06 percent in 1995 and 6.99 percent in 1994. The increase in the embedded cost of long-term debt from 1995 to 1996 is primarily the result of maturing lower cost debt. The decrease in the embedded cost of preferred stock from 1995 to 1996 reflects the impact of decreased adjustable dividend rates on a certain series of preferred stock. FIXED CHARGES COVERAGE. Consolidated fixed charges coverage using the SEC method was 5.07 times for 1996 compared to 4.94 and 4.72 times for 1995 and 1994, respectively. The increase is primarily a result of higher earnings. Consolidated fixed charges coverage, excluding AFUDC and other deferred returns, was 4.69 times for 1996 compared with 4.52 for 1995 and 4.32 for 1994 and the Company goal of 3.5 times. The increase in coverage is primarily the result of higher earnings, excluding AFUDC and other deferred returns. CAPITAL NEEDS PROPERTY ADDITIONS AND RETIREMENTS. Additions to property and nuclear fuel of $720 million and retirements of $396 million resulted in an increase in gross plant of $324 million in 1996. Since January 1, 1994, additions to property and nuclear fuel of $4 billion and retirements of $2.5 billion have resulted in an increase in gross plant of $1.5 billion. CONSTRUCTION EXPENDITURES. Plant construction costs for generating facilities supporting Duke Power electric operations, including AFUDC, decreased from $309 million in 1994 to $164 million in 1996, primarily because of the completion of the Lincoln Combustion Turbine Station. (For more information, see "Capital Needs -- Meeting Future Power Needs.") Construction costs for distribution plant, including AFUDC, increased from $203 million in 1994 to $227 million in 1996. Projected construction and nuclear fuel costs for Duke Power's electric operations, both including AFUDC, are $2.6 billion and $716 million, respectively, for 1997 through 2001. These construction expenditures are primarily for distribution and production-related activities representing $1.3 billion and $864 million, respectively. These projections are subject to periodic reviews and revisions. Actual construction and nuclear fuel costs and capital expenditures incurred may vary from such estimates. Cost variances are due to various factors, including revised load estimates, environmental matters and cost and availability of capital. Projected capital expenditures of subsidiaries and diversified activities are $1.5 billion for 1997 through 2001, of which a significant portion is real estate and power project development. These projections are subject to periodic reviews and revisions and may vary significantly as business plans evolve to meet the opportunities presented by their markets. For 1997 through 2001, the Company anticipates substantially funding its projected construction and capital expenditures through the internal generation of funds. PURCHASED CAPACITY LEVELIZATION. The rates established in Duke Power's electric retail jurisdictions permit recovery of its investment in both units of the Catawba Nuclear Station and the costs associated with contractual purchases of capacity from the other joint owners of the Catawba Nuclear Station. The contracts relating to the sales of portions of the station obligate the Company to purchase a declining amount of capacity from the other joint owners. In the North Carolina retail jurisdiction, regulatory treatment of these contracts provides revenue for recovery of the capital costs and the fixed operating and maintenance costs of purchased capacity on a levelized basis. In the South Carolina retail jurisdiction, revenues have been provided for the recovery of the capital costs of purchased capacity on a levelized basis, while current rates include recovery of fixed operating and maintenance expenses.
Such rate treatments require the Company to fund portions of the purchased capacity payments until these costs, including returns, are recovered at a later date. The Company recovers the accumulated costs and returns when the sum of the declining purchased capacity payments and accrual of returns for the current period drop below the levelized revenues. During 1996, in the North Carolina retail jurisdiction and the wholesale jurisdiction regulated by the Federal Energy Regulatory Commission (FERC), annual levelized revenues exceeded purchased capacity payments and the accrual of deferred returns for the first time. In the South Carolina retail jurisdiction, cumulative levelized revenues have exceeded purchased capacity payments and accrual of deferred returns. The PSCSC, on May 7, 1996, ordered a rate reduction in the form of a decrement rider for an interim true-up adjustment. (For additional information on the South Carolina rate reduction, see "Liquidity and Resources -- Duke Power Company Rate Matters.") Jurisdictional levelizations are intended to recover total costs, including returns, and are subject to adjustments, including final true-ups. MEETING FUTURE POWER NEEDS. The Company's strategy for meeting customers' present and future energy needs consists of three components: supply-side resources, demand-side resources and purchased power resources. To assist in determining the optimal combination of these three resources, the Company uses an integrated resource planning process. The goal is to provide adequate and reliable electricity in an environmentally responsible, cost-effective manner. As customers elect to procure generation from other suppliers, as two of the Company's wholesale customers have indicated they will do beginning in 1997, the Company will no longer be obligated to plan for the future generation needs of those customers. The Company has completed the construction of a combustion turbine facility in Lincoln County, North Carolina, to provide capacity at periods of peak demand. The station consists of 16 combustion turbines with a total generating capacity of 1,200 megawatts. During 1995, twelve units of the Lincoln Combustion Turbine Station began commercial operation. The last four units began commercial operation in the first quarter of 1996. The purchase of capacity and energy is also an integral part of meeting future power needs. As of January 1, 1997, the Company has 329 megawatts of firm purchased capacity from other generators of electricity under contract, including 91 megawatts from qualifying facilities. In 1995, the Company issued two requests for proposals (RFP) to solicit both short-term and long-term competitive bids to provide future electric generating capacity resources. After review of all the bids, the Company selected a short-term bid from PECO Energy Co. of Philadelphia. The agreement gives the Company the option to purchase up to 250 megawatts of capacity during the summer months of 1998 through 2001. Contract arrangements between the parties were finalized on August 1, 1996. The long-term RFP was closed and no bids were accepted. Demand-side management programs benefit the Company and its customers by providing cost-effective energy efficiency, providing for load control through interruptible control features, shifting usage to off-peak periods and increasing strategic sales of electricity. The November 1991 rate orders of the NCUC and the PSCSC provided for recovery in rates of a designated level of costs for demand-side management programs and allowed the deferral for later recovery of certain demand-side management costs that exceed the level reflected in rates, including a return on the deferred costs. The May 1996 rate rider in South Carolina included an increment for demand-side management cost recovery. (For additional information on the South Carolina rate rider, see "Liquidity and Resources -- Duke Power Company Rate Matters.") The Company ultimately expects recovery through rates of associated deferred costs, not to exceed $75 million including deferred returns in the North Carolina retail jurisdiction. The annual costs deferred, including the return, were approximately $9 million and $2 million in North Carolina and South Carolina, respectively, in 1996 and $16 million and $11 million in North Carolina and South Carolina, respectively, in 1995. As of December 31, 1996, the balance of deferred demand-side management costs as presented on the Consolidated Balance Sheets in "Other deferred debits" is $67 million and $40 million in North Carolina and South Carolina, respectively. CURRENT ISSUES While the Company improved its financial performance in 1996 compared to 1995, its ability to maintain and improve its current level of earnings will depend on several factors. As the electric industry becomes increasingly competitive, the Company's ability to control costs will be an important factor in maintaining a pricing structure that is both attractive to customers and profitable to the Company. Wheeling of third-party energy to a retail customer is not generally allowed in the Company's service territory. However, there are discussions and events at the national level and within certain states regarding retail competition which could result in changes in the industry. On April 24, 1996, the FERC issued its final rules on open-access transmission, providing energy suppliers with opportunities to sell and deliver capacity and energy at market-based prices. (For additional information on competition, see "Current Issues -- Competition.") Management cannot predict the outcome of these matters and their impact, if any, on the Company's financial position and results of operation. The
Company is focusing on providing competitive prices to its industrial customers, as well as to wholesale customers who have access to alternative sources of energy. Other significant factors impacting the Company's future earnings levels include continued economic growth in the Piedmont Carolinas, the success of the Company's subsidiaries and diversified activities, and the outcome of various legislative and regulatory actions. PROPOSED MERGER WITH PANENERGY CORP. On November 25, 1996, the Company and PanEnergy Corp announced a proposed stock-for-stock transaction creating an integrated energy company. Upon consummation of the merger, PanEnergy will be a wholly owned subsidiary of the Company, and the Company's name will be changed to Duke Energy Corporation. The transaction is expected to close by December 31, 1997, subject to approval of the shareholders of both companies and all applicable regulatory approvals. The shareholders of each company will vote on the proposed merger at their annual meetings, which are scheduled for April 24, 1997 for both companies. Applications for regulatory approval were filed with the NCUC and the PSCSC on December 19, 1996, and with the FERC on February 3, 1997. Regulatory proceedings are expected to be successfully completed by year-end 1997. In connection with the transaction, each share of PanEnergy common stock will be converted into 1.0444 shares of common stock of the Company. The transaction will be accounted for as a pooling of interests. Further details about the proposed acquisition are provided in the Company's report on Form 8-K, filed with the Securities and Exchange Commission on December 9, 1996, and in the Joint Proxy Statement-Prospectus provided to shareholders in connection with the Company's annual meeting. Unless otherwise indicated, all information presented herein relates to the Company only and does not take into account the proposed merger with PanEnergy. RESOURCE OPTIMIZATION. The Company has been engaged in a concentrated effort to more efficiently and effectively use its resources through better work practices. In 1995, the Company offered to certain employees an Enhanced Vested Benefits program (EVB) which gave targeted employees, who left the Company, an enhanced vested retirement package and the Company's standard severance pay based on years of service. This program resulted in the elimination of approximately 900 positions during 1996. During 1994, the Company offered an Enhanced Voluntary Separation program (EVS) which gave most employees the option of leaving the Company for a lump-sum payment and the Company's standard severance pay based on years of service. This program resulted in the departure of approximately 1,300 employees in 1994. Implementing various efficiency practices has resulted in streamlined work flows and provided the opportunity for work force reduction programs such as EVB and EVS. FULL-TIME EMPLOYEES
The increase in workforce of subsidiaries and diversified businesses is commensurate with the growth in their business opportunities. NUCLEAR DECOMMISSIONING COSTS. Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $1.3 billion stated in 1994 dollars based on decommissioning studies completed in 1994. This amount includes the Company's 12.5 percent ownership in the Catawba Nuclear Station. The other joint owners of the Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. Such estimates presume each unit will be decommissioned as soon as possible following the end of its license life. Although subject to extension, the current operating licenses for the Company's nuclear units expire as follows: Oconee 1 and 2 -- 2013, Oconee 3 -- 2014; McGuire 1 -- 2021, McGuire 2 -- 2023; and Catawba 1 -- 2024, Catawba 2 -- 2026. In accordance with a 1988 Nuclear Regulatory Commission order, during 1996, the Company expensed approximately $56 million which was contributed to the external funds and accrued an additional $2 million to the internal reserve. The balance of the external funds as of December 31, 1996, was $363 million. The balance of the internal reserve as of December 31, 1996, was $208 million and is reflected in accumulated depreciation and amortization on the Consolidated Balance Sheets. Both the NCUC and the PSCSC have granted the Company recovery of estimated decommissioning costs through retail rates over the expected remaining service periods of the Company's nuclear plants. Decommissioning costs being recovered
through rates, invested at assumed after-tax earnings rate of 5.5 percent to 5.9 percent, are sufficient to provide for the estimated cost of decommissioning. As required under the Nuclear Waste Policy Act of 1982, the Company entered into a contract with the U.S. Department of Energy (DOE) under which the DOE agreed to dispose of the Company's spent nuclear fuel. The DOE has announced that the department anticipates a delay in accepting the waste materials on the contract date of January 31, 1998. The Company has joined with 35 other utilities in a lawsuit attempting to force the DOE to meet its obligations as called for in the contract. While it is uncertain what interim storage will be provided by the DOE due to its inability to meet the contract date, the Company has satisfactory plans in place to provide storage of spent nuclear fuel if the DOE cannot accept it. ENVIRONMENTAL ISSUES. The Company is subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal, and other environmental matters. The Company was an operator of manufactured gas plants until the early 1950s. The Company has entered into a cooperative effort with the State of North Carolina and other owners of certain former manufactured gas plant sites to investigate and, where necessary, remediate these contaminated sites. The State of South Carolina has expressed interest in entering into a similar arrangement. The Company is considered by regulators to be a potentially responsible party and may be subject to liability at four federal Superfund sites. While the cost of remediation of these sites may be substantial, the Company will share in any liability associated with remediation of contamination at such sites with other potentially responsible parties. Management is of the opinion that resolution of these matters will not have a material adverse effect on the results of operations or financial position of the Company. THE CLEAN AIR ACT AMENDMENTS OF 1990. The Clean Air Act Amendments of 1990 require a two-phase reduction by electric utilities in the aggregate annual emissions of sulfur dioxide and nitrogen oxide by the year 2000. The Company currently meets all requirements of Phase I. The Company supports the national objective of clean air in the most cost-effective manner and has already reduced emissions through the use of low-sulfur coal in its fossil plants, efficient plant operations and by using nuclear generation. The sulfur dioxide provisions of the Act allow utilities to choose among various alternatives for compliance. To meet the Phase II requirements by 2000, the Company's current strategy includes the use of lower sulfur coal, emission allowance purchases, low nitrogen oxide burners and emission monitoring equipment. A one-time cost associated with bringing the Company into compliance with the Act could range from $94 million to $260 million. Additional operating expenses of approximately $25 million will be incurred for fuel premiums and emission allowance purchases each year after 2000. This strategy is contingent upon developments in the emissions allowance market, lower sulfur coal premiums, future regulatory and legislative actions, and advances in clean air technology. STRESS CORROSION CRACKING. Stress corrosion cracking (SCC) has occurred in the steam generators of Units 1 and 2 at the McGuire Nuclear Station and Unit 1 at the Catawba Nuclear Station. Catawba Unit 2, which has certain design differences and came into service at a later date, has not yet shown the degree of SCC which has occurred in McGuire Units 1 and 2 and Catawba Unit 1. It is, however, too early in the life of Catawba Unit 2 to determine the extent to which SCC may be a problem. Although the Company has taken steps to mitigate the effects of SCC, the inherent potential for future SCC in the McGuire and Catawba steam generators still exists. The Company planned for the replacement of steam generators at three units that have experienced SCC and purchased the replacement steam generators from Babcock & Wilcox International. Replacement of the steam generators at Catawba Unit 1 was successfully completed at a lower cost than projected on October 4, 1996, after a 115-day outage that included replacement work and other maintenance. Steam generator replacement in both McGuire units is scheduled for completion during 1997. The Catawba Unit 2 steam generators have not been scheduled for replacement. Steam generator replacement at each McGuire unit is expected to take approximately four months and cost approximately $170 million, excluding the cost of replacement power. Stress corrosion problems are excluded under the Company's nuclear insurance policies. The Company, in connection with its McGuire and Catawba stations and on behalf of the other joint owners of the Catawba Station, began a legal action in 1990, alleging that Westinghouse Electric Corporation knowingly supplied to the McGuire and Catawba stations steam generators that were defective in design, workmanship and materials, requiring replacement well short of their stated design life. The lawsuit was settled in 1994. While the court order does not allow disclosure of the terms of the settlement, the Company believes the litigation was settled on terms that provided satisfactory consideration to the Company and will not have a material effect on the Company's results of operations or financial position. COMPETITION. The Energy Policy Act of 1992 (EPACT) and the FERC's subsequent rulemaking activities are major drivers towards a more competitive market for electric generation. EPACT reformed provisions of the Public Utility Holding Company Act of 1935 (PUHCA) and Part II of the Federal Power Act to remove certain barriers to competition for the supply of electricity. For example, EPACT allows utilities to participate in the development of independent electric generating plants in the United States for sales to wholesale customers, as well as to contract for utility projects internationally,
without becoming subject to regulation under PUHCA as an electric utility holding company. In addition, EPACT permits the FERC to order transmission access for third parties to transmission facilities owned by another entity so that energy suppliers can sell to wholesale customers wherever they are located. It does not, however, permit the FERC to issue an order requiring transmission access to retail customers. The FERC, responsible in large measure for implementation of the EPACT, has moved vigorously to implement its mandate, interpreting the statute broadly in issuing orders for third-party transmission service and issuing a number of rules of general applicability. On April 24, 1996, the FERC issued its Order Numbers 888 and 889, which established the final form of transmission tariff to provide comparable service to all users of a utility's transmission system. Open-access transmission for wholesale customers as defined by the FERC's final rules provides energy suppliers, including the Company, with opportunities to sell and deliver capacity and energy at market-based prices. Engaging in such transactions may result in improved utilization of the Company's existing assets. In addition, such access provides another supply option through which the Company can buy capacity and energy at attractive rates, influencing its competitive price position. However, sales to existing wholesale customers of the Company may continue to be impacted by open access either due to competitive pressure on the wholesale price of electricity, or the potential loss of sales as wholesale customers seek other options to meet their capacity and energy requirements at market-based prices. (For additional information about sales to wholesale customers, see "Liquidity and Resources -- Duke Power Company Rate Matters," and Note 3, "Notes to Consolidated Financial Statements.") Wholesale sales represented approximately 8.8 percent of the Company's total kilowatt-hour sales in 1996. Supplemental sales to the other joint owners of the Catawba Nuclear Station comprised the majority of such sales. Such supplemental sales will continue to decline in 1997 as a result of the retention of larger portions of ownership entitlement by the other joint owners. (For additional information on Catawba joint ownership, see Note 3, "Notes to the Consolidated Financial Statements.") In early 1995, prior to issuance of the FERC's Notice of Proposed Rulemaking, the Company and certain of its affiliates filed three applications with the FERC, all of which were designed to enable effective participation in the competitive environment of the changing electric utility industry. Duke Power filed an application for permission to sell at market-based rates up to 2,500 megawatts of capacity and energy from its own assets. Two of the Company's affiliates, Duke Energy Marketing Corp. (DEMC) and Duke/Louis Dreyfus L.L.C. (D/LD), filed applications with the FERC to become power marketers. All of the applications were supported by transmission tariffs which complied with then-applicable FERC standards and established the rates, terms and conditions for transmission service to third parties on the Company's transmission system. Late in 1995, the FERC granted the applications of Duke, DEMC, and D/LD; accepted Duke's transmission tariffs; and ordered a hearing on the rates to be charged for service under those tariffs. On July 9, 1996, in compliance with the standards and schedules set forth in Order Number 888, the Company filed a pro forma open access transmission tariff complying with the requirements of the FERC's final rules. Such a filing was required of all transmission-owning utilities subject to the FERC's jurisdiction. The Company also filed on that date a proposed settlement in the proceeding earlier ordered by the FERC. The proposed settlement resolves all rate issues related to transmission services under Duke's tariff and contains the rates agreed upon under the settlement. The settlement and the July 9, 1996 tariff filing remain subject to final FERC approval. Competition for retail customers is not generally allowed in the Company's service territory. However, there are discussions and events at the national level and within certain states, including North and South Carolina, regarding retail competition which could result in changes in the industry. Such changes, should they occur, could impact all entities owning generation, including the other joint owners of the Catawba Nuclear Station. Currently, the electric utility industry is predominantly regulated on a basis designed to recover the cost of providing electric power to its retail and wholesale customers. If cost-based regulation were to be discontinued in the industry, for any reason, including competitive pressure on the cost-based prices of electricity, profits could be reduced and utilities might be required to reduce their asset balances to reflect a market basis less than cost. Discontinuance of cost-based regulation would also require affected utilities to write off their associated regulatory assets. The regulatory assets of the Company are classified as "Deferred debits" on the Consolidated Balance Sheets. Substantially all of the "Deferred debits" are regulatory assets. Management cannot predict the potential impact, if any, of these competitive forces on the Company's future financial position and results of operations. However, the Company continues to position itself to effectively meet these challenges by maintaining prices that are locally, regionally and nationally competitive. COMMITMENTS AND CONTINGENCIES. The Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business, some of which may involve substantial amounts. Where appropriate, the Company has made accruals in accordance with Statement of Financial Accounting Standards No. 5, "Accounting for Contingencies," in order to provide for such matters. Management
is of the opinion that the final disposition of these proceedings will not have a material adverse effect on the results of operations or the financial position of the Company. SUBSIDIARIES AND DIVERSIFIED OPERATIONS. The Company continues to aggressively pursue both domestic and international diversified business opportunities that are synergistic with the Company's core business to provide additional value to the Company's shareholders. Among the Company's current industry pursuits are ownership of electric power facilities, energy marketing, real estate, communications, engineering consulting and various energy services. Although these opportunities are primarily concentrated in areas that utilize the Company's expertise, they present different and potentially greater risks than does the Company's core business. The Company only pursues opportunities in which the expected returns are commensurate with the risks and makes efforts to mitigate such risks. The Company undertakes a continuous evaluation of the various lines of business it may enter or exit, with the objective of enhancing shareholder value and managing any associated risk. Domestically, non-electric property of the Company's subsidiaries and diversified activities was $404 million and $335 million at December 31, 1996 and 1995, respectively. The Company had equity investments in affiliates, which own assets within the United States, of $82 million and $58 million at December 31, 1996 and 1995, respectively. Internationally, the Company had equity investments in affiliates, which own generation and transmission facilities, of $107 million and $105 million at December 31, 1996 and 1995, respectively. Additionally, the Company, through its non-regulated subsidiaries, had loaned $3 million and $23 million to certain of these affiliates at December 31, 1996 and 1995, respectively. The Company's subsidiaries and diversified activities contributed $51 million to net income in 1996 compared with $54 million in 1995 and $52 million in 1994. From 1994 to 1996, increased developed lot and land sales, and engineering services and construction fees generated additional income. These increases were offset by personal communications services joint venture start-up losses and a provision for an investment in a plant in Argentina.
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 RETAINED EARNINGS
See notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
See notes to consolidated financial statements.
CONSOLIDATED BALANCE SHEETS
See notes to consolidated financial statements.
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. NATURE OF OPERATIONS The Company is primarily engaged in the generation, transmission, distribution and sale of electric energy in the central portion of North Carolina and the western portion of South Carolina, comprising the area in both states known as the Piedmont Carolinas. The Company is one of the nation's largest investor-owned electric utilities. The Company is also engaged in a variety of diversified operations, most of which are organized in separate subsidiaries. The Company's subsidiaries and diversified activities are in the Associated Enterprises Group (AEG). AEG includes Church Street Capital Corp.; Crescent Resources, Inc.; Duke Energy Group, Inc.; Duke Engineering & Services, Inc.; Duke/Fluor Daniel; Duke/Louis Dreyfus, LLC; Duke Merchandising; DukeNet Communications, Inc.; Duke Water Operations; and Nantahala Power and Light Company. Certain subsidiaries have invested in both domestic and international affiliates. (See Note 11.) The financial statements are prepared in conformity with generally accepted accounting principles appropriate in the circumstances to reflect in all material respects the substance of events and transactions which should be included. In preparing these statements, management makes informed judgments and estimates of the expected effects of events and transactions that are currently being reported. However, actual results could differ from these estimates. B. REVENUES Electric revenues are recorded as service is rendered to customers. "Receivables" on the Consolidated Balance Sheets include $205,656,000 and $206,792,000 as of December 31, 1996 and 1995, respectively, for electric service that has been rendered but not yet billed to customers by Duke Power, and $4,294,000 as of December 31, 1996 for electric service that has been rendered but not yet billed to customers by Nantahala Power and Light Company. C. ADDITIONS TO ELECTRIC PLANT The Company capitalizes all construction-related direct labor and materials as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of money (allowance for funds used during construction). The cost of renewals and betterments of units of property is capitalized. The cost of repairs and replacements representing less than a unit of property is charged to electric expenses. The original cost of property retired, together with removal costs less salvage value, is charged to accumulated depreciation. D. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC) AFUDC represents the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated facilities. AFUDC, a non-cash item, is recognized as a cost of "Construction work in progress," with an offsetting credit to "Interest expense and other income." After construction is completed, the Company is permitted to recover these construction costs, including a fair return, through their inclusion in rate base and in the provision for depreciation. The AFUDC rates of 9.7, 9.3 and 9.6 percent for Duke Power for 1996, 1995 and 1994, respectively, include a component for debt cost on a pre-tax basis. Rates for all periods are compounded semiannually. E. OTHER DEFERRED RETURNS Other deferred returns represent the estimated financing costs associated with funding certain regulatory assets. These regulatory assets primarily arise from the Company's funding of purchased capacity costs above levels collected in rates. Other deferred returns are non-cash items. They are primarily recognized as an addition to "Purchased capacity costs" and as an offsetting credit to "Interest expense and other income." F. DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT Provisions for electric plant depreciation are recorded using the straight-line method. The year-end composite weighted-average depreciation rates were 3.44, 3.48 and 3.46 percent for 1996, 1995 and 1994, respectively.
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- Continued Amortization of nuclear fuel is included in "Fuel used in electric generation" in the Consolidated Statements of Income. The amortization is recorded using the units-of-production method. Under provisions of the Nuclear Waste Policy Act of 1982, the Company has entered into contracts with the Department of Energy (DOE) for the disposal of spent nuclear fuel. Payments made to the DOE for disposal costs are based on nuclear output and are included in "Fuel used in electric generation" in the Consolidated Statements of Income. A provision in the Energy Policy Act of 1992 established a fund for the decontamination and decommissioning of the DOE's uranium enrichment plants. Licensees are subject to an annual assessment for 15 years based on their pro rata share of past enrichment services. The annual assessment is recorded as fuel expense. The Company paid $9,472,000 during 1996 and has paid $45,022,000 cumulatively related to its ownership interest in nuclear plants. The Company has reflected the remaining liability and regulatory asset of $94,717,000 in the Consolidated Balance Sheet at December 31, 1996. G. SUBSIDIARIES The Company's consolidated financial statements reflect consolidation of all of its majority-owned subsidiaries. Intercompany transactions have been eliminated in consolidation. H. INCOME TAXES The Company and its subsidiaries file a consolidated federal income tax return. Deferred income taxes have been provided for temporary differences. Temporary differences occur when events and transactions recognized for financial reporting result in taxable or tax-deductible amounts in different periods. Investment tax credits have been deferred and are being amortized over the estimated useful lives of the related properties. I. UNAMORTIZED DEBT PREMIUM, DISCOUNT AND EXPENSE Expenses incurred in connection with the issuance of presently outstanding long-term debt issued for regulated operations, and premiums and discounts relating to such debt, are being amortized over the terms of the respective issues. Also, any call premiums or unamortized expenses associated with refinancing higher-cost debt obligations used to finance regulated assets and operations are being amortized over the lives of the new issues of long-term debt. J. CONSOLIDATED STATEMENTS OF CASH FLOWS For purposes of the Consolidated Statements of Cash Flows, the Company's short-term investments in highly liquid debt instruments, with an original maturity of three months or less, are included in cash flows from investing activities and thus are not considered cash equivalents. Total income taxes paid were $491,340,000, $441,440,000 and $372,416,000 for the years ended December 31, 1996, 1995 and 1994, respectively. Interest paid, net of amounts capitalized, was $269,219,000, $258,698,000 and $236,696,000 for the years ended December 31, 1996, 1995 and 1994, respectively. K. COST-BASED REGULATION As a regulated entity, the Company is subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Accordingly, the Company records certain assets and liabilities that result from the effects of the ratemaking process that would not be recorded under generally accepted accounting principles for non-regulated entities. Currently, the electric utility industry is predominantly regulated on a basis designed to recover the cost of providing electric power to its retail and wholesale customers. If cost-based regulation were to be discontinued in the industry for any reason, including competitive pressure on the cost-based prices of electricity, profits could be reduced, and utilities might be required to reduce their asset balances to reflect a market basis less than cost. Discontinuance of cost-based regulation would also require affected utilities to write off their associated regulatory assets. The regulatory assets of the Company are classified as
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- Continued "Deferred debits" on the Consolidated Balance Sheets. Substantially all of the "Deferred debits" are regulatory assets. Management cannot predict the potential impact, if any, of these competitive forces on the Company's future financial position and results of operations. However, the Company continues to position itself to effectively meet these challenges by maintaining prices that are locally, regionally and nationally competitive. NOTE 2. RATE MATTERS DUKE POWER COMPANY The North Carolina Utilities Commission (NCUC) and The Public Service Commission of South Carolina (PSCSC) must approve rates for retail sales within their respective states. The Federal Energy Regulatory Commission (FERC) must approve Duke Power's rates for sales to wholesale customers. Sales to the other joint owners of the Catawba Nuclear Station, which represent a substantial majority of Duke Power's wholesale revenues, are set through contractual agreements. (See Note 3.) The most recent general rate increase requests in Duke Power's retail jurisdictions were filed and approved in 1991. Duke Power also filed its most recent general rate increase request within the FERC wholesale jurisdiction in 1991. A negotiated settlement between Duke Power and the wholesale customers was approved by the FERC in 1992. Fuel costs are reviewed semiannually in the wholesale jurisdiction and annually in the South Carolina retail jurisdiction, with provisions for changing such costs in base rates. In the North Carolina retail jurisdiction, a review of fuel costs in rates is required annually and during general rate case proceedings. All jurisdictions allow Duke Power to adjust rates for past over- or under-recovery of fuel costs. Therefore, Duke Power reflects in revenues the difference between actual fuel costs incurred and fuel costs recovered through rates. The PSCSC, on May 7, 1996, ordered a rate reduction in the form of a decrement rider of 0.432 cents per kilowatt-hour, or an average of approximately 8 percent, affecting South Carolina retail customers. South Carolina retail sales represent approximately 30 percent of the Company's total retail sales. The rate reduction was reflected on bills rendered on or after June 1, 1996. This net decrement rider reflects an interim true-up decrement adjustment associated with the levelization of Catawba Nuclear Station purchased capacity costs and an interim true-up increment associated with amortization of the demand-side management deferral account. The rate adjustment was made because, in the South Carolina retail jurisdiction, cumulative levelized revenues associated with the recovery of Catawba purchased capacity costs had exceeded purchased capacity payments and accrual of deferred returns, and certain demand-side costs had exceeded the level reflected in rates. Certain of the Company's wholesale customers, excluding the other Catawba joint owners, initiated proceedings in 1995 before the FERC concerning rate matters. The Company and nine of its eleven wholesale customers entered into a settlement in July 1996 which reduced the customers' rates by approximately 9 percent and renewed their contracts with the Company through the year 2000. Both of the customers that did not enter into the settlement have signed agreements to purchase energy from other suppliers beginning in 1997. The eleven wholesale customers involved in this matter accounted for less than 2 percent of the Company's overall electric revenues during 1996. The two customers that have signed agreements with other suppliers accounted for less than 0.5 percent of the Company's 1996 overall electric revenues. NANTAHALA POWER AND LIGHT COMPANY During 1996, Nantahala Power and Light Company (NP&L) filed an application with and received approval from the NCUC to increase its annual retail service revenues by $4.6 million. NP&L's wholesale rates are adjusted annually to reflect current costs. Purchased power costs of NP&L are reviewed annually and during general rate case proceedings by the NCUC. NP&L is allowed to adjust rates for past over- or under-recovery of purchased power costs. Therefore, NP&L defers the difference between actual purchased power costs incurred and those recovered through rates.
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 3. JOINT OWNERSHIP OF GENERATING FACILITIES The Company previously sold interests in both units of the Catawba Nuclear Station. The other owners of portions of the Catawba Nuclear Station and supplemental information regarding their ownership are as follows:
Each owner has provided its own financing for its ownership interest in the station. The Company retains a 12.5 percent ownership interest in the Catawba Nuclear Station. As of December 31, 1996, $497,304,000 of "Electric plant in service" and "Nuclear fuel" represents the Company's investment in Units 1 and 2. Accumulated depreciation and amortization of $192,057,000 associated with Catawba has been recorded as of year-end. The Company's share of operating costs of Catawba is included in the Consolidated Statements of Income. In connection with the joint ownership, the Company has entered into contractual agreements with the other joint owners to purchase declining percentages of the generating capacity and energy from the plant. These purchased power agreements were effective beginning with the commercial operation of each unit. Unit 1 and Unit 2 began commercial operation in June 1985 and August 1986, respectively. The purchased power agreements were established for 15 years for NCMPA and PMPA and 10 years for NCEMC and Saluda River. While the purchased power agreements with NCMPA and PMPA extend for 15 years, a significant decrease in the percentage of capacity and energy the Company is obligated to purchase occurs in the 11th calendar year of operation for each unit. This significant decrease occurred in 1995 for Unit 1 and 1996 for Unit 2. The agreements also provide for supplemental power sales by the Company to the other joint owners. Such power sales are to satisfy capacity and energy needs of the other joint owners beyond the capacity and energy which they retain from Catawba or potentially acquire in the form of other resources. The agreements further provide the other joint owners the ability to secure such supplemental requirements outside of these contractual agreements following an appropriate notice period. NCEMC and Saluda River have given appropriate notice that they intend to acquire their supplemental capacity requirements outside of these agreements effective January 1, 2001 and January 1, 2002, respectively, thus relieving the Company of the obligation to serve this portion of load. As the joint owners retain more capacity and energy from Catawba, or a third party, supplemental power sales are expected to decline. The agreements with each of the other joint owners include provisions that the Company will provide generating reserves to backstand the other joint owners' retained capacity in the Catawba plant at the system average cost of installed capacity. Additionally, the agreements include certain reliability exchanges designed to manage outage-related risks by exchanging energy entitlements between the Catawba Nuclear Station and the McGuire Nuclear Station, impacting the Company as well as all the other joint owners.
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 3. JOINT OWNERSHIP OF GENERATING FACILITIES -- Continued Purchased energy cost payments are based on variable operating costs and are a function of the generation output of Catawba. Purchased capacity payments are based on the fixed costs of the plant and include the capital costs and fixed operating and maintenance costs. Actual purchased capacity costs for 1996 and projected obligations for 1997 through 2001, including the impact of the 1995 settlement agreement with NCMPA and PMPA (See Note 13), are as follows (dollars in thousands):
Effective in its November 1991 rate order, the North Carolina Utilities Commission reaffirmed the Company's recovery, on a levelized basis, of the capital costs and fixed operating and maintenance costs of capacity purchased from the other joint owners. The Public Service Commission of South Carolina in its November 1991 rate order reaffirmed the Company's recovery on a levelized basis of the capital costs of capacity purchased from the other joint owners. Levelization was reaffirmed through inclusion in rates approved in March 1992 by the Federal Energy Regulatory Commission (FERC). The portion of purchased capacity subject to levelization not currently recovered in rates is being deferred, and the Company is recording a deferred return on the accumulated balance. The Company recovers the accumulated balance, including the deferred return, when the sum of the declining purchased capacity payments and accrual of deferred returns for the current period drops below the levelized revenues. Jurisdictional levelizations are intended to recover total costs, including deferred returns, and are subject to adjustments, including final true-ups. The Company recovers the costs of purchased energy and the non-levelized portion of purchased capacity on a current basis. The current levelized revenues approved in the Company's last general rate proceedings are $211,423,000, $94,137,000 and $6,815,000 for North Carolina retail, South Carolina retail and Other Wholesale (FERC), respectively. Purchased power costs, subject to levelization, are deferred based on allocation factors of approximately 62 percent, 26 percent and 2 percent for North Carolina retail, South Carolina retail and Other Wholesale (FERC), respectively. The PSCSC, on May 7, 1996, ordered a rate reduction in the form of a decrement rider for an interim true-up adjustment. (See Note 2.) The Company also recovers an allocated amount of purchased power costs in the pricing of supplemental sales made to the other joint owners on a current basis. During 1996, in the North Carolina retail and FERC wholesale jurisdictions, annual levelized revenues exceeded purchased capacity payments and the accrual of deferred returns for the first time. In the South Carolina retail jurisdiction, cumulative levelized revenues have exceeded purchased capacity payments and accrual of deferred returns. For the years ended December 31, 1996, 1995 and 1994, the Company recorded purchased capacity and energy costs from the other joint owners of $151,174,000, $388,246,000 and $604,505,000, respectively. These amounts, after adjustments for the costs of capacity purchased not reflected in current rates, are included in "Net interchange and purchased power" in the Consolidated Statements of Income. As of December 31, 1996 and 1995, $892,000,000 and $965,473,000, respectively, associated with the cost of capacity purchased but not reflected in current rates have been accumulated in the Consolidated Balance Sheets as "Purchased capacity costs."
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 4. INCOME TAX EXPENSE Accumulated deferred income taxes consist primarily of the following (dollars in thousands):
* The net regulatory asset related to income taxes is $488,936,000 for 1996 and $490,676,000 for 1995. Total deferred income tax liability was $2,932,260,000 as of December 31, 1996, and $2,946,711,000 as of December 31, 1995. Total deferred income tax asset was $556,248,000 as of December 31, 1996, and $564,507,000 as of December 31, 1995. Income tax expense for the years ended December 31, 1996, 1995 and 1994 consisted of the following (dollars in thousands):
Income taxes differ from amounts computed by applying the statutory tax rate to pre-tax income for the years ended December 31, 1996, 1995 and 1994 as follows (dollars in thousands):
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 5. SHORT-TERM BORROWINGS AND CREDIT FACILITIES The following credit facilities were available to the Company at December 31, 1996 and 1995:
(a) The Company had $40,000,000 in pollution control bonds, included in long-term debt, outstanding throughout 1996 and 1995 backed by these facilities. (b) The outstanding balances of $42,000,000 in 1996 and $30,043,000 in 1995 are included in long-term debt. (c) The Company had $130,000,000 in commercial paper, included in long-term debt, outstanding throughout 1996 and 1995 backed by these facilities. Cash balances maintained at the banks on deposit were $11,336,000 as of December 31, 1996, and $17,120,000 as of December 31, 1995. Cash balances and fees compensate banks for their services, even though the Company has no formal compensating-balance arrangements. To compensate certain banks for credit facilities, the Company maintained balances of $45,000 as of December 31, 1996 and 1995. The Company retains the right of withdrawal with respect to the funds used for compensating-balance arrangements. A summary of short-term borrowings is as follows (dollars in thousands):
NOTE 6. COMMON STOCK AND RETAINED EARNINGS COMMON STOCK As of December 31, 1996, a total of 9,004,659 shares was reserved for issuance for stock plans. On February 27, 1996, the Board of Directors authorized the Company to repurchase up to $1 billion of its common stock over the next five years. As of December 31, 1996, approximately 3.3 million shares had been repurchased for $159 million. On January 28, 1997, the Board of Directors amended the program to expressly limit the number of shares authorized for repurchase under the program, from the initiation of the program through a date two years after the consummation of the proposed merger with PanEnergy Corp, to an amount not to exceed 15 million shares. (See Note 13.) RETAINED EARNINGS As of December 31, 1996, substantially all of the Company's retained earnings were unrestricted as to the declaration or payment of dividends.
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 7. PREFERRED AND PREFERENCE STOCK WITHOUT SINKING FUND REQUIREMENTS The following shares of stock were authorized with or without sinking fund requirements as of December 31, 1996 and 1995:
As of December 31, 1996 and 1995, there were no shares of preference stock outstanding. Preferred stock without sinking fund requirements as of December 31, 1996 and 1995, was as follows (dollars in thousands):
NOTE 8. PREFERRED AND PREFERENCE STOCK WITH SINKING FUND REQUIREMENTS The following shares of stock were authorized with or without sinking fund requirements as of December 31, 1996 and 1995:
As of December 31, 1996 and 1995, there were no shares of preference stock outstanding. Preferred stock with sinking fund requirements as of December 31, 1996 and 1995, was as follows (dollars in thousands):
The annual sinking fund requirements through 2001 are $0 in 1997, $4,250,000 in 1998, $24,250,000 in 1999, $37,250,000 in 2000 and $37,250,000 in 2001. Some additional redemptions are permitted at the Company's option. The call provisions for the outstanding preferred stock specify various redemption prices not exceeding 108 percent of par value, plus accumulated dividends to the redemption date.
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 9. LONG-TERM DEBT Long-term debt outstanding as of December 31, 1996 and 1995, was as follows (dollars in thousands):
(a) Substantially all of Duke Power's electric plant was mortgaged as of December 31, 1996. (b) Substantial amounts of Crescent Resources, Inc.'s real estate development projects, land and buildings are pledged as collateral.
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 9. LONG-TERM DEBT -- Continued As of December 31, 1996 and 1995, the Company had $40,000,000 in pollution control revenue bonds backed by an unused, two-year revolving credit facility of $40,000,000. In addition, the Company had $130,000,000 in commercial paper outstanding throughout 1996 and 1995 backed by unused five-year revolving credit facilities. These facilities are on a fee basis. Both the $40,000,000 in pollution control bonds and the $130,000,000 in commercial paper are included in long-term debt. As of December 31, 1996, Crescent Resources, Inc. had $45,428,000 in mortgage loans which mature through 1999 and $30,630,000 in mortgage loans maturing in 2000 or thereafter. Additionally, Crescent Resources, Inc. had $42,000,000 outstanding at December 31, 1996, included in long-term debt on a $75,000,000 four-year revolving credit facility. Interest rates are variable and at December 31, 1996, ranged from 5.95 percent to 7.10 percent. As of December 31, 1996, Nantahala Power and Light Company had $68,000,000 in senior notes maturing in 2011, 2012 and 2016. The notes carry fixed interest rates of 9.21 percent, 7.45 percent and 6.90 percent and require monthly payments of principal beginning in 1997, 1998 and 2002, respectively. The annual maturities of consolidated long-term debt, including capitalized lease principal payments through 2001, are $212,309,000 in 1997; $62,759,000 in 1998; $444,840,000 in 1999; $248,271,000 in 2000; and $154,541,000 in 2001. NOTE 10. FINANCIAL INSTRUMENTS The carrying amounts of "Cash," "Short-term investments," and "Notes payable" on the Consolidated Balance Sheets approximate fair value primarily because of the short maturities of these instruments. "Other investments" includes notes receivable issued at fixed rates with maturities up to 30 years for which there are no quoted market prices. The majority of estimated fair value amounts of long-term debt and preferred stock as disclosed below were obtained from independent parties. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 1996 and 1995, are not necessarily indicative of the amounts the Company could have realized in current market exchanges. External funds have been established, as required by the Nuclear Regulatory Commission, as a mechanism to fund certain costs of nuclear decommissioning. (See Note 14.) Currently, these nuclear decommissioning trust funds are invested in U.S. stocks, bonds and cash equivalents. "Nuclear decommissioning trust funds" are presented on the Consolidated Balance Sheets at amounts that approximate fair value. The carrying amounts and estimated fair values of long-term debt and preferred stock are as follows (dollars in thousands):
The Company has authority to issue up to $1 billion aggregate principal amount of debt securities under a shelf registration statement filed with the Securities and Exchange Commission (SEC). Such debt securities may be issued as First and Refunding Mortgage Bonds, Senior Notes or Subordinated Debentures. In order to obtain variable rate financing at an attractive cost, the Company entered into interest rate swap agreements associated with the November 1994, issuance of $200 million aggregate principal amount of its First and Refunding Mortgage Bonds, 8% Series B due 1999 and the August 1995, issuance of $100 million aggregate principal amount of its First and Refunding Mortgage Bonds, 7 1/2% Series B due 2025. The interest rate swaps are reset quarterly based upon the three-month London Interbank Offered Rate (LIBOR). As a result of the interest rate swap contracts, interest expense on the Consolidated
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 10. FINANCIAL INSTRUMENTS -- Continued Statements of Income is recognized at the weighted average rate for the year tied to the LIBOR rate. The weighted average rates are as follows (dollars in thousands):
Duke Energy Group, Inc. entered into a hedge transaction in 1995 to offset currency fluctuations between the U.S. dollar and the Chilean peso associated with expected equity contributions to an affiliate in 1995, 1996 and 1997. The hedge transaction has a notional amount of approximately $4.4 million at December 31, 1996. Duke Energy Group, Inc. records any realized gains or losses associated with the hedge as an adjustment to investments in affiliates. NOTE 11. INVESTMENTS IN AFFILIATES Certain investments, where the Company's ownership in domestic and international affiliates is 50 percent or less, are accounted for by the equity method. These investments include ownership interests in various power development projects; start-up personal communications services; marketing of natural gas, electric power, and development of other energy services; participation in various construction and support activities for fossil-fueled generating plants; and real-estate development projects. The Company's proportionate share of net income (loss) from these affiliates for the years ended December 31, 1996, 1995 and 1994 was $(6,133,000), $9,237,000 and $7,049,000, respectively. These amounts are reflected in "Operating revenues" on the Consolidated Statements of Income. A summary of assets and liabilities of these affiliates follows (dollars in thousands):
* The Company's exposure to these liabilities is mitigated through the use of project or limited recourse financing by the affiliates and capitalization of its subsidiaries investing in the affiliates. In addition, the Company had outstanding loans to certain affiliates of $2,900,000 and $23,170,000 at December 31, 1996 and 1995, respectively. In the normal course of business, some of these affiliates enter into contractual agreements to exchange natural gas, electric power, futures, swaps and options; and construction contracts which contain certain schedule and performance requirements. The affiliates use risk management procedures to control their exposure associated with the contracts. Certain subsidiaries of the Company have guaranteed performance of the affiliates under some of these contracts. Management is of the opinion that these guarantees will not have any material adverse effect on the results of operations or the financial position of the Company. NOTE 12. RETIREMENT BENEFITS A. RETIREMENT PLAN The Company and its operating subsidiaries, with the exception of Nantahala Power and Light Company, which maintains its own retirement plans, have a non-contributory, defined benefit retirement plan covering substantially all their employees. Through December 31, 1996, the benefit was based upon an age-related formula which took into account years of creditable service and the employee's average compensation based upon the highest compensation during a consecutive sixty-month period. The benefit was reduced by an adjustment which is based upon the employee's social security wages. Normal retirement age under the Plan was age 65; however, early retirement benefits were payable as early as age 55 with 10
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 12. RETIREMENT BENEFITS -- Continued years of creditable service or age 51 if the employee had at least 30 years of creditable service. The Company's policy is to fund pension costs as accrued. Effective January 1, 1997, the Plan was amended to be a Cash Balance Plan. Under the Cash Balance Plan, records are maintained on an individual participant basis with monthly credits based upon the participant's creditable compensation multiplied times a percentage that ranges from 3 percent to 7 percent depending upon the sum of the participant's age and years of service. An additional credit of 4 percent applies to creditable compensation in excess of the social security wage base. Additionally, monthly interest credits will be allocated based upon the yield of 30-year U.S. Treasury Bonds, subject to a 4 percent minimum and a 9 percent maximum yield. Normal retirement age will remain age 65. Employees who were participants in the Plan before January 1, 1997, remain eligible to receive certain transitional benefits under the provisions of the previous plan. After January 1, 1997, employees can receive early retirement benefits as early as age 55 with at least 5 years of vesting service. Net periodic pension cost for the years ended December 31, 1996, 1995 and 1994, include the following components (dollars in thousands):
A reconciliation of the funded status of the plan to the amounts recognized in the Consolidated Balance Sheets as of December 31, 1996 and 1995, is as follows (dollars in thousands):
Assumptions used in the Company's pension accounting include:
During 1995, the Company offered to certain employees an Enhanced Vested Benefits program (EVB). The Company recorded an additional one-time expense for special termination benefits associated with EVB of approximately $42,196,000, including $21,600,000 of additional retirement plan costs.
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 12. RETIREMENT BENEFITS -- Continued B. POSTRETIREMENT BENEFITS The Company and its operating subsidiaries, with the exception of Nantahala Power and Light Company (NP&L), which maintained its own postretirement benefit plans through December 1995, currently provide certain health care and life insurance benefits for retired employees. NP&L employees who retired after January 1, 1996, are covered by Duke Power Company's postretirement benefit plan. Through December 31, 1996, employees became eligible for these benefits if they retired at age 55 or greater with 10 years of service or if they retired as early as age 51 with 30 years or more of service. Effective January 1, 1997, employees who were participants in the Retirement Plan before January 1, 1997, become eligible for certain transitional postretirement benefits under the provisions of the previous plan. Employees who were not participants in the plan before January 1, 1997, become eligible as early as age 55 with at least 10 years of vesting service. All employees retiring after January 1, 1992, receive a fixed Company allowance, based on years of service, to be used to pay medical insurance premiums. The Company reserves the right to terminate, suspend, withdraw, amend or modify the plans in whole or in part at any time. In 1992, the Company commenced funding the maximum amount allowable under section 401(h) of the Internal Revenue Code, which provides for tax deductions for contributions and tax-free accumulation of investment income. Such amounts partially fund the Company's medical and dental postretirement benefits. The Company has also established a Retired Lives Reserve, which has tax attributes similar to 401(h) funding, to partially fund its postretirement life insurance obligation. The Company contributed $15,200,000 into these funding mechanisms in 1996 and $23,000,000 in 1995. Net periodic postretirement benefit cost for the years ended December 31, 1996, 1995 and 1994, include the following components (dollars in thousands):
A reconciliation of the funded status of the plan to the amounts recognized in the Consolidated Balance Sheets as of December 31, 1996 and 1995, is as follows (dollars in thousands):
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 12. RETIREMENT BENEFITS -- Continued Assumptions used in the Company's postretirement benefits accounting include:
The assumed medical inflation rate was approximately 9.5 percent in 1996. This rate decreases by 0.5 percent to 1.0 percent per year until a rate of 5.5 percent is achieved in the year 2001, which remains fixed thereafter. A 1.0 percent increase in the medical and dental trend rates produces a 7.0 percent ($2,940,971) increase in the aggregate service and interest cost. The increase in the APBO attributable to a 1.0 percent increase in the medical and dental trend rates is 7.8 percent ($31,462,000) as of December 31, 1996. NOTE 13. COMMITMENTS AND CONTINGENCIES A. CONSTRUCTION PROGRAM Projected construction and nuclear fuel costs for Duke Power's electric operations, both including allowance for funds used during construction, are $2.6 billion and $716 million, respectively, for 1997 through 2001. These projections are subject to periodic review and revisions. Actual construction and nuclear fuel costs and capital expenditures incurred may vary from such estimates. Cost variances are due to various factors, including revised load estimates, environmental matters and cost and availability of capital. Projected capital expenditures of subsidiaries and diversified activities are $1.5 billion for 1997 through 2001. These projections are subject to periodic review and revisions and may vary significantly as business plans evolve to meet the opportunities presented by their markets. B. NUCLEAR INSURANCE The Company maintains nuclear insurance coverage in three areas: liability coverage, property, decontamination and decommissioning coverage, and extended accidental outage coverage to cover increased generating costs and/or replacement power purchases. The Company is being reimbursed by the other joint owners of the Catawba Nuclear Station for certain expenses associated with nuclear insurance premiums paid by the Company. Pursuant to the Price-Anderson Act, the Company is required to insure against public liability claims resulting from nuclear incidents to the full limit of liability of approximately $8.9 billion. The maximum required private primary insurance of $200 million has been purchased along with a like amount to cover certain worker tort claims. The remaining amount, currently $8.7 billion, which will be increased by $79.3 million as each additional commercial nuclear reactor is licensed, has been provided through a mandatory industry-wide excess secondary insurance program of risk pooling. The $8.7 billion could also be reduced by $79.3 million for certain nuclear reactors that are no longer operational and may be exempted from the risk pooling insurance program. Under this program, licensees could be assessed retrospective premiums to compensate for damages in the event of a nuclear incident at any licensed facility in the nation. If such an incident occurs and public liability damages exceed primary insurances, licensees may be assessed up to $79.3 million for each of their licensed reactors, payable at a rate not to exceed $10 million a year per licensed reactor for each incident. The $79.3 million amount is subject to indexing for inflation and may be subject to state premium taxes. The $79.3 million includes a surcharge of 5 percent (which is also included in the above $8.7 billion figure) if funds are insufficient to pay claims and associated costs. If retrospective premiums were to be assessed, the other joint owners of the Catawba Nuclear Station are obligated to assume their pro rata share of such assessment. The Company is a member of Nuclear Mutual Limited (NML), which provides $500 million in primary property damage coverage for each of the Company's nuclear facilities. If NML's losses ever exceed its reserves, the Company will be liable, on a pro rata basis, for additional assessments of up to $34 million. This amount represents 5 times the Company's
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 13. COMMITMENTS AND CONTINGENCIES -- Continued annual premium to NML. The other joint owners of Catawba are obligated to assume their pro rata share of any liability for retrospective premiums and other premium assessments resulting from the NML policies applicable to Catawba. The Company is also a member of Nuclear Electric Insurance Limited (NEIL) and purchases insurance through NEIL's excess property, decontamination and decommissioning liability insurance program. NEIL provides excess insurance coverage of $2.25 billion for the Catawba Nuclear Station and $1.5 billion for each of the Oconee and McGuire Nuclear Stations. If losses ever exceed the accumulated funds available to NEIL for the excess property, decontamination and decommissioning liability program, the Company will be liable, on a pro rata basis, for additional assessments of up to $40 million. This amount is limited to 5 times the Company's annual premium to NEIL for excess property, decontamination and decommissioning liability insurance. The other joint owners of Catawba are obligated to assume their pro rata share of any liability for retrospective premiums and other premium assessments resulting from the NEIL policies applicable to Catawba. The Company participates in a NEIL program that provides insurance for the increased cost of generation and/or purchased power resulting from an accidental outage of a nuclear unit. Each unit of the McGuire and Catawba Nuclear Stations is insured for up to approximately $3.5 million per week, after a 21-week deductible period, with declining amounts per unit where more than one unit is involved in an accidental outage. The Oconee Nuclear Station units are insured for up to approximately $2.7 million, under like terms. Coverages continue at 100 percent for 52 weeks and 80 percent for the next 104 weeks. If NEIL's losses for this program ever exceed its reserves, the Company will be liable, on a pro rata basis, for additional assessments of up to $27 million. This amount represents 5 times the Company's annual premium to NEIL for insurance for the increased cost of generation and/or purchased power resulting from an accidental outage of a nuclear unit. The other joint owners of Catawba are obligated to assume their pro rata share of any liability for retrospective premiums and other premium assessments resulting from the NEIL policies applicable to the joint ownership agreements. C. PROPOSED MERGER WITH PANENERGY CORP On November 25, 1996, the Company and PanEnergy Corp announced a proposed stock-for-stock transaction creating an integrated energy company. Upon consummation of the merger, PanEnergy will be a wholly owned subsidiary of the Company, and the Company's name will be changed to Duke Energy Corporation. The transaction is expected to close by December 31, 1997, subject to approval of the shareholders of both companies and all applicable regulatory approvals. The shareholders of each company will vote on the proposed merger at their annual meetings, which are scheduled for April 24, 1997 for both companies. Applications for regulatory approval were filed with the NCUC and the PSCSC on December 19, 1996 and the FERC on February 3, 1997. Regulatory proceedings are expected to be successfully completed by year-end 1997. In connection with the transaction, each share of PanEnergy common stock will be converted into 1.0444 shares of common stock of the Company. The transaction will be accounted for as a pooling of interests. Further details about the proposed acquisition are provided in the Company's report on Form 8-K, filed with the Securities and Exchange Commission on December 9, 1996, and in the Joint Proxy Statement-Prospectus provided to shareholders in connection with the Company's annual meeting. Unless otherwise indicated, all information presented herein relates to the Company only and does not take into account the proposed merger with PanEnergy. D. OTHER The Company and North Carolina Municipal Power Agency Number 1 and Piedmont Municipal Power Agency, two of the four other joint owners of the Catawba Nuclear Station, entered into a settlement in September 1995 which resolved outstanding issues related to how certain calculations affecting bills under the Catawba joint ownership contractual agreements should be performed. The settlement was approved by the North Carolina Utilities Commission on January 16, 1996 and The Public Service Commission of South Carolina on January 23, 1996. As part of the settlement, the Company agreed to purchase additional megawatts (MW) of Catawba capacity during the period 1996 through 1999 and remove certain restrictions related to sales of surplus energy by these two joint owners. The additional capacity purchases are 215 MW in 1996, 165 MW in 1997, 120 MW in 1998 and 100 MW in 1999. The Company expects to recover the costs associated with this settlement as part of the purchased capacity levelization, consistent with prior orders of the retail regulatory commissions. Therefore, the Company believes these matters should not have a material adverse effect on the results of operations or the financial position of the Company.
DUKE POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- CONTINUED NOTE 13. COMMITMENTS AND CONTINGENCIES -- Continued The Company and all four of the other joint owners of the Catawba Nuclear Station entered into settlement agreements in 1994 which resolved all issues in contention in arbitration proceedings related to the Catawba joint ownership contractual agreements. The basic contention in each proceeding was that certain calculations affecting bills under these agreements should be performed differently. These items are covered by the agreements between the Company and the other Catawba joint owners which have been previously approved by the Company's retail regulatory commissions. (See Note 3.) In 1994, the Company settled its cumulative net obligation through 1993 of approximately $205 million related to these settlement agreements. Billings for 1994 and later years will conform to the settlement agreements, which have been approved by the Company's retail regulatory commissions. Because the Company expects the costs associated with these settlements to be recovered as part of the purchased capacity levelization, which has been approved by the Company's retail regulatory commissions, the Company included approximately $205 million as an increase to "Purchased capacity costs" on its Consolidated Balance Sheets in 1994. Therefore, the Company believes these matters should not have a material adverse effect on the results of operations or financial position of the Company. The Company is also involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business, some of which involve substantial amounts. Where appropriate, the Company has made accruals in accordance with Statement of Financial Accounting Standards No. 5, "Accounting for Contingencies," in order to provide for such matters. Management is of the opinion that the final disposition of these proceedings will not have a material adverse effect on the results of operations or financial position of the Company. NOTE 14. NUCLEAR DECOMMISSIONING COSTS Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $1.3 billion stated in 1994 dollars based on decommissioning studies completed in 1994. This amount includes the Company's 12.5 percent ownership in the Catawba Nuclear Station. The other joint owners of the Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. Both the North Carolina Utilities Commission and the Public Service Commission of South Carolina have granted the Company recovery of estimated decommissioning costs through retail rates over the expected remaining service periods of the Company's nuclear plants. Such estimates presume each unit will be decommissioned as soon as possible following the end of their license life. Although subject to extension, the current operating licenses for the Company's nuclear units expire as follows: Oconee 1 and 2 -- 2013, Oconee 3 -- 2014; McGuire 1 -- 2021, McGuire 2 -- 2023; and Catawba 1 -- 2024, Catawba 2 -- 2026. In accordance with a 1988 Nuclear Regulatory Commission order, during 1996, the Company expensed approximately $56,470,000 which was contributed to the external funds for decommissioning costs and accrued an additional $1,618,000 to the internal reserve. Nuclear units are depreciated at a rate of 4.70 percent, of which 1.61 percent is for decommissioning. The balance of the external funds as of December 31, 1996, was $362,627,000. The balance of the internal reserve as of December 31, 1996, was $207,774,000 and is reflected in accumulated depreciation and amortization on the Consolidated Balance Sheets. Management's opinion is that the decommissioning costs being recovered through rates, when coupled with assumed after-tax fund earnings of 5.5 percent to 5.9 percent, are currently sufficient to provide for the cost of decommissioning.
INDEPENDENT AUDITORS' REPORT DUKE POWER COMPANY: We have audited the consolidated financial statements of Duke Power Company and subsidiaries (the Company) listed in the accompanying index for Item 8. Our audits also included the consolidated financial statement schedule listed in the accompanying index. These financial statements and consolidated financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and consolidated financial statement schedule based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein. DELOITTE & TOUCHE LLP Charlotte, North Carolina February 7, 1997 RESPONSIBILITY FOR FINANCIAL STATEMENTS The financial statements of Duke Power Company are prepared by management, which is responsible for their integrity and objectivity. The statements are prepared in conformity with generally accepted accounting principles appropriate in the circumstances to reflect in all material respects the substance of events and transactions which should be included. The other information in the annual report is consistent with the financial statements. In preparing these statements, management makes informed judgments and estimates of the expected effects of events and transactions that are currently being reported. The Company's system of internal accounting control is designed to provide reasonable assurance that assets are safeguarded and transactions are executed according to management's authorization. Internal accounting controls also provide reasonable assurance that transactions are recorded properly, so that financial statements can be prepared according to generally accepted accounting principles. In addition, the Company's accounting controls provide reasonable assurance that errors or irregularities which could be material to the financial statements are prevented or are detected by employees within a timely period as they perform their assigned functions. The Company's accounting controls are continually reviewed for effectiveness. In addition, written policies, standards and procedures, and a strong internal audit program augment the Company's accounting controls. The Board of Directors pursues its oversight role for the financial statements through the audit committee, which is composed entirely of directors who are not employees of the Company. The audit committee meets with management and internal auditors periodically to review the work of each group and to monitor each group's discharge of its responsibilities. The audit committee also meets periodically with the Company's independent auditors, Deloitte & Touche LLP. The independent auditors have free access to the audit committee and the Board of Directors to discuss internal accounting control, auditing and financial reporting matters without the presence of management. JEFFREY L. BOYER CONTROLLER
QUARTERLY FINANCIAL DATA
Generally, quarterly earnings fluctuate with seasonal weather conditions and maintenance of electric generating units, especially nuclear units.
SUBSIDIARIES AND DIVERSIFIED ACTIVITIES HIGHLIGHTS The Company has organized all its subsidiaries and diversified activities into the Associated Enterprises Group (AEG). AEG includes the following: (Bullet) CHURCH STREET CAPITAL CORP. (CSCC) serves as the parent company and provides equity funding and credit enhancement services for the Company's non-electric operating subsidiaries. CSCC and one of its wholly-owned subsidiaries manage investment funds, highlights of which are as follows (dollars in thousands): SHORT-TERM INVESTMENTS AND MARKETABLE SECURITIES
INVESTMENT INCOME (AFTER TAX)
(Bullet) CRESCENT RESOURCES, INC. provides real estate management, forestry operation and high-quality commercial and residential real estate development services in the Southeast. (Bullet) DUKE ENERGY GROUP, INC. develops, owns, manages and operates energy facilities worldwide. (Bullet) DUKE ENGINEERING & SERVICES, INC. provides engineering, project management, quality assurances, construction management, operating and maintenance and environmental services for utilities, industry and government worldwide. (Bullet) DUKE/FLUOR DANIEL provides engineering, procurement, construction and operating and maintenance services for fossil-fueled electric generating stations worldwide. (Bullet) DUKE/LOUIS DREYFUS, LLC markets electric power, natural gas and energy-related services to utilities, municipalities and other large energy users in North America. (Bullet) DUKE MERCHANDISING sells and services home appliances, electronics and wireless communications devices. (Bullet) DUKENET COMMUNICATIONS, INC. develops and manages communications systems, including fiber optic and wireless digital network services. (Bullet) DUKE WATER OPERATIONS provides franchised water service to customers in parts of North and South Carolina. (Bullet) NANTAHALA POWER AND LIGHT COMPANY is a franchised electricity provider serving a five-county area in western North Carolina.
The following tables set forth operating results, financial position, cash flows and other information with respect to the Company's subsidiaries and diversified activities for the periods and as of the dates specified: OPERATING RESULTS
FINANCIAL POSITION
CASH FLOWS
OTHER INFORMATION
(a) Excludes operations and financial position of an affiliate, Duke/Fluor Daniel, which is included in All Other Business Units amounts. (b) All Other Business Units amounts include Associated Enterprises Group intercompany eliminations. (c) 1996 includes a provision for an investment in a power plant in Argentina. (d) 1994 includes a gain from the sale of preferred stock. (e) 1996 includes proceeds from sale of office building.
(f) 1996 includes proceeds from repayment of a loan by an affiliate. (See Note 11.) 1994 includes proceeds from the sale of preferred stock and debt securities. (g) 1996 and 1995 include the net change in short-term investments for the period of $3,588,000 and $56,392,000, respectively. Also, 1995 includes proceeds from the sale of a dividend capture program. (h) 1996 includes amounts paid relating to acquisition activities. (i) 1994 includes the net change in short-term investments for the period of $12,060,000. (j) Excludes capital infusion and return of capital transactions between parent, Church Street Capital Corp., and its subsidiaries. (k) 1996 and 1994 exclude net return of capital to parent, Church Street Capital Corp., of $4,724,000 and $12,100,000, respectively. 1995 excludes net capital infusions from Church Street Capital Corp. of $33,455,000. (l) 1996 excludes net capital infusions from parent, Church Street Capital Corp., of $35,900,000. (m) 1996 includes capital infusion from Duke Power to Church Street Capital Corp. of $65,000,000.
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
(1) Principally consists of Injuries and Damages reserves and Property Insurance reserve which are included in "Deferred Credits and Other Liabilities" in the Consolidated Balance Sheets.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. No events necessary to be disclosed by the Company under this item have occurred. PART III. ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. Information for this item concerning directors of the Company is set forth in the sections entitled "Election of Directors," "Information Regarding the Board of Directors" and "Common Stock Ownership of Certain Beneficial Owners and Management" under "The Duke Meeting -- Additional Matters" in the Joint Proxy Statement-Prospectus relating to the Company's 1997 annual meeting of shareholders, which are being incorporated herein by reference. Information concerning the executive officers of the Company is set forth in the section entitled "Executive Officers of the Company" in this annual report. ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION. Information for this item is set forth in the sections entitled "Executive Compensation" and "Directors' Fees" under "The Duke Meeting -- Additional Matters", and "Interests of Certain Persons in the Merger -- Duke Employment Agreements" under "The Merger" in the Joint Proxy Statement-Prospectus relating to the Company's 1997 annual meeting of shareholders, which are being incorporated herein by reference. ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. Information for this item is set forth in the section entitled "Common Stock Ownership of Certain Beneficial Owners and Management" under "The Duke Meeting -- Additional Matters" in the Joint Proxy Statement-Prospectus relating to the Company's 1997 annual meeting of shareholders, which is being incorporated herein by reference. ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. Information for this item is set forth in the sections entitled "Information Regarding the Board of Directors" and "Common Stock Ownership of Certain Beneficial Owners and Management" under "The Duke Meeting -- Additional Matters" in the Joint Proxy Statement-Prospectus relating to the Company's 1997 annual meeting of shareholders, which are being incorporated herein by reference.
PART IV. ITEM 14.
ITEM 14. EXHIBITS, CONSOLIDATED FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. (a) Consolidated Financial Statements, Supplemental Financial Data and Supplemental Schedules included in Part II of this annual report are as follows: Consolidated Financial Statements Consolidated Statements of Income for the Three Years Ended December 31, Consolidated Statements of Retained Earnings for the Three Years Ended December 31, 1996 Consolidated Statements of Cash Flows for the Three Years Ended December 31, 1996 Consolidated Balance Sheets -- December 31, 1996 and 1995 Notes to Consolidated Financial Statements Selected Quarterly Financial Data (unaudited) Consolidated Financial Statement Schedule Schedule II -- Valuation and Qualifying Accounts and Reserves for the Three Years Ended December 31, 1996 All other schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements or notes thereto. (b) Reports on Form 8-K A Report on Form 8-K was filed by the Company on December 9, 1996, in which it reported in Item 5 thereof the execution of an Agreement and Plan of Merger dated as of November 24, 1996, by and between the Company, Duke Transaction Corporation and PanEnergy Corp. (c) Exhibits -- See Exhibit Index immediately following signature page.
SIGNATURES Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Charlotte and State of North Carolina on the 24th day of March, 1997. DUKE POWER COMPANY (Registrant) By: W. H. GRIGG CHAIRMAN OF THE BOARD AND CHIEF EXECUTIVE OFFICER Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
ELLEN T. RUFF, by signing her name hereto, does hereby sign this document on behalf of the registrant and on behalf of each of the above-named persons pursuant to a power of attorney duly executed by the registrant and such persons, filed with the Securities and Exchange Commission as an exhibit hereto. /s/ ELLEN T. RUFF ELLEN T. RUFF, ATTORNEY-IN-FACT
EXHIBIT INDEX The following exhibits indicated by an asterisk preceding the exhibit number are filed herewith. The balance of the exhibits have heretofore been filed with the Securities and Exchange Commission and pursuant to Rule 12b- 32 are incorporated herein by reference.
+ Compensatory plan or arrangement filed with Form 10-K for the year ended December 31, 1992, File No. 1-4928, under the same exhibit number as listed herein. ++ Compensatory plan or arrangement filed with Form 10-K for the year ended December 31, 1993, File No. 1-4928, under the same exhibit number as listed herein. +++ Compensatory plan or arrangement filed with Form 10-K for the year ended December 31, 1994, File No. 1-4928, under the same exhibit number as listed herein.
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