-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, LWABFpo8shDlCn8HP9PCQuc893E3GMId0KMoXru91lQpXORjZaJoI0N2wWEg3c71 1ijT+eebDfeR9hX0+dtbuA== 0000017797-97-000009.txt : 19970329 0000017797-97-000009.hdr.sgml : 19970329 ACCESSION NUMBER: 0000017797-97-000009 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970328 SROS: NYSE SROS: PSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: CAROLINA POWER & LIGHT CO CENTRAL INDEX KEY: 0000017797 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 560165465 STATE OF INCORPORATION: NC FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03382 FILM NUMBER: 97566125 BUSINESS ADDRESS: STREET 1: 411 FAYETTEVILLE ST CITY: RALEIGH STATE: NC ZIP: 27601 BUSINESS PHONE: 9195466111 10-K 1 FORM 10-K OF CAROLINA POWER & LIGHT COMPANY UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1996 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _____ to _____ Commission file number 1-3382 CAROLINA POWER & LIGHT COMPANY (Exact name of registrant as specified in its charter) 411 Fayetteville Street North Carolina 56-0165465 Raleigh, North Carolina 27601 _______________________________________________________________________ (State or other (I.R.S. Employer (Address of principal (Zip Code) jurisdiction of Identification executive offices) incorporation or No.) organization) 919-546-6111 (Registrant's telephone number) SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Title of each class Name of each exchange on which registered ___________________ _______________________________ Common Stock (Without Par Value) New York Stock Exchange Pacific Stock Exchange Quarterly Income Capital Securities New York Stock Exchange SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: Preferred Stock (Without Par Value, Cumulative) (Title of Class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X . No . ___ ___ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] The aggregate market value of the voting stock held by non-affiliates at February 28, 1997, was $5,746,914,678. Shares of Common Stock (Without Par Value) outstanding at February 28,1997: 151,415,722. DOCUMENTS INCORPORATED BY REFERENCE: Portions of the Company's 1997 definitive proxy statement dated March 31, 1997, are incorporated into Part III, Items 10, 11, 12 and 13 hereof. TABLE OF CONTENTS Page ____ Safe Harbor for Forward-Looking Statements. . . . . . . . . . i PART I Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . 1 General . . . . . . . . . . . . . . . . . . . . . . . 1 Generating Capability . . . . . . . . . . . . . . . . 2 Interconnections with Other Systems . . . . . . . . . 5 Competition and Franchises. . . . . . . . . . . . . . 6 Construction Program . . . . . . . . . . . . . . . .10 Financing Program . . . . . . . . . . . . . . . . . .10 Retail Rate Matters . . . . . . . . . . . . . . . . .12 Wholesale Rate Matters . . . . . . . . . . . . . . .14 Environmental Matters . . . . . . . . . . . . . . . .15 Nuclear Matters . . . . . . . . . . . . . . . . . . .18 Fuel . . . . . . . . . . . . . . . . . . . . . . . .22 Other Matters . . . . . . . . . . . . . . . . . . . .24 Operating Statistics . . . . . . . . . . . . . . . .27 Item 2. Properties . . . . . . . . . . . . . . . . . . . . .28 Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . .28 Item 4. Submission of Matters to a Vote of Security Holders .29 Executive Officers of the Registrant . . . . . . . . 30 PART II Item 5. Market for the Registrant's Common Equity and Related Shareholder Matters . . . . . . . . . . . . . . . . 32 Item 6. Selected Consolidated Financial Data . . . . . . . .33 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . 34 Item 8. Consolidated Financial Statements and Supplementary Data. . . . . . . . . . . . . . . . . . . . . . . . .42 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. . . . . . . . . . . . . . .65 PART III Item 10. Directors and Executive Officers of the Registrant .65 Item 11. Executive Compensation. . . . . . . . . . . . . . . .65 Item 12. Security Ownership of Certain Beneficial Owners and Management. . . . . . . . . . . . . . . . . . . .65 Item 13. Certain Relationships and Related Transactions . . .65 PART IV Item 14. Exhibits, Consolidated Financial Statement Schedules and Reports on Form 8-K. . . . . . . . . . . . . . . .66-69 SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS This Form 10-K and other presentations made by the Company and its subsidiaries contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. The Company is including the following cautionary statement in this Form 10-K to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements, whether written or oral, made by or on behalf of the Company. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions, and any other statements which are not statements of historical fact. Such statements include without limitation those that are identified by the use of the words "anticipates," "estimates," "expects," "intends," "plans," "predicts" and similar expressions. Although the Company believes that in making any such statement its expectations are based on reasonable assumptions, any such statement involves uncertainties and is qualified in its entirety by reference to the following important factors that could cause the actual results of the Company to differ materially from those projected in such forward-looking statement: (i) prevailing governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission, the North Carolina Utilities Commission, the South Carolina Public Service Commission, and the Nuclear Regulatory Commission, with respect to allowed rates of return, industry and rate structure, purchased power costs and investment recovery, operations of nuclear generating facilities, acquisitions and disposal of assets and facilities, operation and construction of plant facilities, decommissioning costs, present or prospective wholesale and retail competition, changes in tax laws and policies and changes in and compliance with environmental and safety laws and policies, (ii) weather conditions and other natural phenomena, (iii) unanticipated population growth or decline, and changes in market demand and demographic pattern, (iv) competition for retail and wholesale customers, (v) pricing and transportation of fossil fuel and other commodities, (vi) unanticipated changes in interest rates or in rates of inflation, (vii) unanticipated changes in operating expenses and capital expenditures, (viii) capital market conditions, (ix) competition for new energy development opportunities, and (x) legal and administrative proceedings and settlements. Any forward-looking statement speaks only as of the date on which such statement is made, and the Company does not undertake any obligation to update any forward-looking statement to reflect events occurring or circumstances arising after the date on which such statement is made, or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for the Company to predict all of such factors, or to assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward looking statement. i PART I ITEM 1. BUSINESS _________________ GENERAL _______ 1. COMPANY. Carolina Power & Light Company (Company) is a public service corporation formed under the laws of North Carolina in 1926, and is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. The Company had 6,701 employees at December 31, 1996. The principal executive offices of the Company are located at 411 Fayetteville Street, Raleigh, North Carolina 27601, telephone number: 919-546-6111. 2. SERVICE. a. The territory served, an area of approximately 30,000 square miles, includes a substantial portion of the coastal plain of North Carolina extending to the Atlantic coast between the Pamlico River and the South Carolina border, the lower Piedmont section of North Carolina, an area in northeastern South Carolina, and an area in western North Carolina in and around the City of Asheville. The estimated total population of the territory served is approximately 3.75 million. b. The Company provides electricity at retail in 219 communities, each having an estimated population of 500 or more, and at wholesale to one joint municipal power agency, 3 municipalities and 2 electric membership corporations (North Carolina Electric Membership Corporation, which has 27 members, 17 of which are served by the Company's system, and French Broad Electric Membership Corporation). At December 31, 1996, the Company was furnishing electric service to approximately 1,121,000 customers. 3. SALES. During 1996, 34% of operating revenues was derived from residential sales, 21% from commercial sales, 25% from industrial sales, 18% from resale sales and 3% from other sources. Of such operating revenues, approximately 68% was derived from North Carolina retail customers, 14% from South Carolina retail customers, 14% from wholesale customers under contract and 4% from bulk power sales. 4. PEAK DEMAND. a. A 60-minute system peak demand record of 10,156 megawatts (MW) was reached on August 14, 1995. At the time of this peak demand, the Company's capacity margin based on installed capacity (less unavailable capacity) and scheduled firm purchases and sales was approximately 7.0%. b. Total system peak demand for 1994 increased by 5.8%, for 1995 increased by 0.12%, and for 1996 decreased by 3.4%, as compared with the preceding year. The Company currently projects that system peak demand will increase at an average annual growth rate of approximately 2.5% over the next ten years. The year-to-year change in actual peak demand is influenced by the specific weather conditions during those years and may not exhibit a consistent pattern. Total system load factors, expressed as the ratio of the average load supplied to the peak load demand, for the years 1994-1996 were 56.3%, 59.2%, and 60.8%, respectively. The Company forecasts capacity margins of 12.1% over anticipated system peak load for 1997 and 11.4% for 1998. This forecast assumes normal weather conditions in each year consistent with long-term experience, and is based upon the rated Maximum Dependable Capacity of generating units in commercial operation and scheduled firm purchases of power. See PART I, ITEM 1, "Generating Capability" and "Interconnections With Other Systems." However, some of the generating units included in arriving at these capacity margins may be 1 unavailable as a result of scheduled outages, environmental modifications or unplanned outages. See PART I, ITEM 1, "Environmental Matters" and "Nuclear Matters." The data contained in this paragraph includes North Carolina Eastern Municipal Power Agency's (Power Agency) load requirements and capability from its ownership interests in certain of the Company's generating facilities. See PART I, ITEM 1, "Generating Capability," paragraph 1. GENERATING CAPABILITY _____________________ 1. FACILITIES. The Company has a total system installed generating capability (including Power Agency's share) of 9,613 MW, with generating capacity provided primarily from the installed generating facilities listed in the table below. The remainder of the Company's generating capacity is composed of 53 coal, hydro and combustion turbine units ranging in size from a 2.5 MW hydro unit to a 78 MW coal-fired unit. Pursuant to certain agreements with the Company, Power Agency, which is comprised of former North Carolina municipal wholesale customers of the Company and Virginia Electric and Power Company (Virginia Power), has acquired undivided ownership interests of 18.33% in Brunswick Unit Nos. 1 and 2, 12.94% in Roxboro Unit No. 4, and 16.17% in Harris Unit No. 1 and Mayo Unit No. 1 (collectively, the Joint Facilities). Of the total system installed generating capability of 9,613 MW, 55% is coal, 32% is nuclear, 2 % is hydro and 11% is fired by other fuels including No. 2 oil, natural gas and propane. 2 MAJOR INSTALLED GENERATING FACILITIES Year Maximum Plant Unit Commercial Primary Dependable Location No. Operation Fuel Capacity ________ ____ __________ _______ _________ Asheville 1 1964 Coal 198 MW (Skyland, N.C.) 2 1971 Coal 194 MW Cape Fear 5 1956 Coal 143 MW (Moncure, N.C.) 6 1958 Coal 173 MW H. F. Lee 1 1952 Coal 79 MW (Goldsboro, N.C.) 2 1951 Coal 76 MW 3 1962 Coal 252 MW H. B. Robinson 1 1960 Coal 174 MW (Hartsville, S.C.) 2 1971 Nuclear 683 MW Roxboro 1 1966 Coal 385 MW (Roxboro, N.C.) 2 1968 Coal 670 MW 3 1973 Coal 707 MW 4 1980 Coal 700 MW* L. V. Sutton 1 1954 Coal 97 MW (Wilmington, N.C.) 2 1955 Coal 106 MW 3 1972 Coal 410 MW Brunswick 1 1977 Nuclear 767 MW* (Southport, N.C.) 2 1975 Nuclear 754 MW* Mayo 1 1983 Coal 745 MW* (Roxboro, N.C.) Harris 1 1987 Nuclear 860 MW* (New Hill, N.C.) _____________ * Facilities are jointly owned by the Company and Power Agency, and the capacity shown includes Power Agency's share. 2. MAINTENANCE OF PROPERTIES. The Company maintains all of its properties in good operating condition in accordance with sound management practices. The average life expectancy for rate-making and accounting purposes of the Company's generating facilities (excluding combustion turbine units and hydro units) is approximately 40 years from the date of commercial operation. 3 3. GENERATION ADDITIONS SCHEDULE. The Company's energy and load forecasts were revised in December 1996. Over the next ten years, system sales growth is forecasted to average approximately 2.6% per year and annual growth in system peak demand is projected to average approximately 2.5%. The Company's generation additions schedule, which is updated annually, provides for the addition of 3440 megawatts of combustion turbine capacity, 1800 megawatts of combined cycle capacity, and 500 megawatts of baseload coal capacity over the period 1997 to 2011. Additions planned through 1999 are discussed below. a. In 1997, two new combustion turbine generating units, construction of which began in 1995, are scheduled to commence commercial operation. These units, having a total generating capacity of approximately 240 MW, are located at the Company's Darlington County Electric Plant near Hartsville, South Carolina and are expected to cost an aggregate amount of approximately $61 million. b. The Company filed an Application for a Certificate of Public Convenience and Necessity with the North Carolina Utilities Commission (NCUC) on September 27, 1995 seeking permission to construct 500 MW of combustion turbine capacity adjacent to the Company's Lee Steam Electric Plant in Wayne County, North Carolina. The units will primarily be used during periods of summer and winter peak demands. The NCUC hearing in this matter was held on January 9, 1996, and by order issued March 21, 1996, the NCUC granted the Company a certificate to construct these combustion turbine units. The original schedule called for construction of the 500 MW of combustion turbine capacity to begin in 1996, and commercial operation anticipated to begin in 1998; however, the Company has delayed plans for construction of the 500 MW of combustion turbine capacity. Construction is now scheduled to begin in 1997, with commercial operation to begin in 1999 and the aggregate cost expected to approximate $120 million. In the interim, peaking requirements will be met with power purchases. c. The Company issued a Notice of Inquiry (NOI) on March 12, 1996 concerning short-term power purchases for the peak winter months of 1998-1999, and the peak summer months of 1998. The NOI was sent to a number of electric utilities, independent power producers and power marketers. The Company received a number of bids, which resulted in contract purchases for the summer of 1998. d. In June 1996, the Company issued a Request for Proposals (RFP) for purchased power of 700 to 1000 MW of capacity to meet the Company's future generation needs in its service territory and to replace contract purchases terminating in 1998-1999. The Company projected a need of approximately 200 to 350 MW in its western service territory, and approximately 350 to 650 MW in its eastern service territory. The capacity was requested to be available for delivery by June 1, 1999. Proposals were invited from all potential suppliers who were capable of meeting the conditions of the RFP. In January 1997 the Company decided, based on the proposals received, to purchase approximately one-third of the necessary peaking capacity. The other two-thirds of capacity will be supplied by a combination of power from the combustion turbine units to be constructed at the Wayne County site, described in paragraph 3.b. above, and the Buncombe County site, as described in paragraph 3.e. below. e. Due to increased economic activity and load growth in its western service territory, on September 4, 1996, the Company filed with the NCUC its preliminary plans to construct approximately 320 MW of combustion turbine generating capacity in Buncombe County, North Carolina at the Company's existing Asheville Steam Electric Plant, with an in-service date of the summer of 1999. Pursuant to those plans, on January 31, 1997, the Company filed with the NCUC an Application for a Certificate of Public Convenience and Necessity for one 160 MW combustion turbine at the Asheville Plant. (This turbine, along with certain power purchases described in paragraph 3.d. above, will satisfy the Company's anticipated future generation needs in its western service territory. As a result, plans to construct the additional 160 MW of combustion turbines in Buncombe County have been indefinitely postponed.) The Company cannot predict the outcome of this matter. 4 INTERCONNECTIONS WITH OTHER SYSTEMS ___________________________________ 1. INTERCONNECTIONS. The Company's facilities in Asheville and vicinity are integrated into the total system through the facilities of Duke Power Company (Duke) via interconnection agreements that permit transfer of power to and from the Asheville area. The Company also has major interconnections with the Tennessee Valley Authority (TVA), Appalachian Power Company (APCO), Virginia Power, South Carolina Electric and Gas Company (SCE&G), South Carolina Public Service Authority (SCPSA) and Yadkin, Inc. (Yadkin). Major interconnections include 115 kV and 230 kV ties with SCE&G and SCPSA; 115 kV, 230 kV and 500 kV ties with Duke and Virginia Power; a 115 kV tie with Yadkin; a 161 kV tie with TVA; and three 138 kV ties and one 230 kV tie with APCO. See paragraph 3.b. below. 2. INTERCHANGE AND POWER PURCHASE/SALE AGREEMENTS. a. The Company has interchange agreements with APCO, Duke, SCE&G, SCPSA, TVA, Virginia Power and Yadkin which provide for the purchase and sale of power for hourly, daily, weekly, monthly or longer periods. In addition to the interchange agreements, the Company has executed individual purchase agreements and sales agreements with more than 100 companies beyond the Virginia-Carolinas Subregion described in paragraph 2.b. below. Purchases and sales under these agreements may be made due to economic or reliability considerations. By letter dated May 24, 1996, the Company provided Duke with written notice that effective June 1, 1999, it will terminate Schedule G to the Interchange Agreement between the Company and Duke. Schedule G provides for the wheeling of electricity between the Company's eastern area and its western area. By letter dated December 30, 1996, Duke provided the Company with written notice that effective December 31, 1999, it will terminate the Standby Concurrent Exchange Agreement (Standby Agreement) between the Company and Duke. The Standby Agreement provides for the simultaneous exchange of up to 70 MW of electricity during periods of scheduled maintenance or breakdown. On December 31, 1996 pursuant to the Federal Energy Regulatory Commission (FERC) Order 888, which directs that no bundled economy energy coordination transactions occur after December 31, 1996, the Company submitted to the FERC a compliance filing to unbundle transmission charges from rate schedules that are applicable to the power sales agreements between the Company and others. See PART I, ITEM 1, "Competition and Franchises," paragraph 1.b. for further discussion of FERC Order 888. b. The Virginia-Carolinas Subregion of the Southeastern Electric Reliability Council is made up of the Company, Duke, Nantahala Power & Light Company, SCE&G, SCPSA and Virginia Power, plus the Southeastern Power Administration and Yadkin. Electric service reliability is promoted by arrangements among the members of electric reliability organizations at the subregional level. 3. LONG-TERM PURCHASE POWER CONTRACTS. a. In March 1987, the Company entered into a purchase power contract with Duke, whereby Duke would provide 400 MW of firm capacity to the Company's system over the period January 1, 1992, through December 31, 1997. Pursuant to an amendment of the contract, commencement of the purchase of power by the Company was delayed until July 1993 and termination was extended through June 1999. On January 20, 1995, the FERC issued an order accepting the purchase power contract. The estimated minimum annual payment for power purchases under the six-year agreement is approximately $43 million, which represents capital-related capacity costs. Other costs include fuel and energy-related operation and maintenance expenses. Purchases under this agreement, including transmission use charges, totaled $65.4 million in 1996. 5 b. The Company has entered into an agreement, which has been approved by the FERC, with APCO and Indiana Michigan Power Company (Indiana Michigan), operating subsidiaries of American Electric Power Company, to upgrade a transmission interconnection with APCO in the Company's western service area, establish a new interconnection in the Company's eastern service area, and purchase 250 MW of generating capacity from Indiana Michigan's Rockport Unit No. 2 through 2009. The upgrade to the transmission interconnection in the Company's western service area was completed in 1992, and the Company recently announced plans to upgrade an existing 138 kV transmission line between Person County, North Carolina and Danville, Virginia, rather than establishing a new interconnection in its eastern service area. The upgrade is currently expected to be completed by mid-1998. The estimated minimum annual payment for power purchases under the agreement is approximately $30 million, which represents capital-related capacity costs. Other costs associated with the agreement include demand-related production expenses, and fuel and energy-related operation and maintenance expenses. In 1996, purchases under this agreement, including transmission use charges, totaled $60.9 million. c. In 1996, the Company agreed with Cogentrix of North Carolina, Inc. and Cogentrix Eastern Carolina Corporation (collectively referred to as Cogentrix) to amend electric power purchase agreements related to five plants owned by Cogentrix. The amendments, which became effective on September 26, 1996, permit the Company to dispatch the output of the five plants. In return, the Company gave up its right to purchase two of the five plants in 1997. As a result of the amendments, the Company will save approximately $30 million per year in energy costs during the years 1997 through 2002. 4. POWER AGENCY. Pursuant to the terms of a 1981 Power Coordination Agreement, as amended, between the Company and Power Agency, the Company is obligated to purchase a percentage of Power Agency s ownership capacity of and energy from the Mayo Plant and the Harris Plant through 1997 and 2007, respectively. The estimated minimum annual payments for these purchases, which reflect capital-related capacity costs, total approximately $27 million. Other costs of such purchases are primarily demand-related production expenses, and fuel and energy-related operation and maintenance expenses. Purchases under the agreement with Power Agency totaled $36.7 million in 1996. COMPETITION AND FRANCHISES __________________________ 1. COMPETITION. a. Generally, in municipalities and other areas where the Company provides retail electric service, no other utility directly renders such service. In recent years, however, customers interested in building their own generation facilities, competition from unregulated energy suppliers and changing government regulations have fostered the development of alternative sources of electricity for certain of the Company's wholesale and industrial customers. The Public Utility Regulatory Policies Act (PURPA) has facilitated the entry of non-utility companies into the wholesale electric generation business. Under PURPA, non-utility companies are allowed to construct "qualifying facilities" for the production of electricity in connection with industrial steam supplies and, under certain circumstances, to compel a utility to purchase the electricity generated at prices reflecting the utility's avoided cost as set by state regulatory bodies. Over the near term, the purchase of power from qualifying facilities has increased the Company's total cost of power supply. b. In 1992, the National Energy Policy Act (Energy Act) changed certain underlying federal policies governing wholesale generation and the sale of electric power. In effect, the Energy Act partially deregulated the wholesale electric utility industry at the generation level by allowing non-utility generators to build and own generating plants for both cogeneration and sales to utilities. Provisions of the Energy Act that most affected the utility industry were the establishment of exempt wholesale generators, and the authority given the FERC to mandate wholesale transfer, or 6 wheeling, of power over the transmission lines of other utilities. Since the Energy Act was passed, competition in the wholesale electric utility industry has increased due to greater participation by traditional electricity suppliers and by non-traditional electricity suppliers, such as wholesale power marketers and brokers, and by the trading of energy futures contracts on commodities exchanges such as the New York Merchantile Exchange and the Kansas City Board of Trade. This increased competition could impact the Company's load forecasts, plans for power supply, and wholesale energy sales and related revenues. The impact could vary depending on the extent to which additional generation is built to compete in the wholesale market, new opportunities are created for the Company to expand its wholesale load, or current wholesale customers elect to purchase from other suppliers after existing contracts expire. If the Company is not able to recover lost revenues associated with any lost loads, there could be an adverse impact on the Company's financial condition. On April 24, 1996 the FERC issued final regulations for wholesale wheeling of electric power through its rules on open access transmission and stranded costs and on information systems and standards of conduct (Orders 888 and 889). The rules require all transmitting utilities to have on file an open access transmission tariff, which should contain provisions for the recovery of stranded costs. The rules also contain numerous other items that could impact the sale of electric energy at the wholesale level. These final rules became effective on July 9, 1996. FERC also issued a notice of proposed rulemaking (NOPR) on Capacity Reservation Open Access Transmission Tariffs. The Company filed comments on this new NOPR with the FERC on October 21, 1996. On May 24, 1996, the Company filed a Request for Clarification and Rehearing of Orders 888 and 889, as did many other entities. The Company filed its open access transmission tariff with the FERC on July 9, 1996. On August 7, 1996, Power Agency filed with the FERC a motion to intervene and protest concerning the Company's tariff. Other entities also filed protests. These protests challenged numerous aspects of the Company's tariff and requested that an evidentiary proceeding be held. The FERC set the matter for hearing and set a discovery and procedural schedule. The Company, the FERC staff and most of the parties have agreed on a settlement-in-principle, and by order dated January 16, 1997, the administrative law judge suspended the procedural schedule until April 17, 1997, pending a final settlement of the case. By order issued May 15, 1996, the NCUC established a new docket (Docket No. E-100, Sub 78) to address FERC Orders 888 and 889. In accordance with the NCUC's order, the Company filed its comments on July 16, 1996 regarding the implementation of the FERC's orders, their impact on North Carolina customers and what the NCUC can do to maximize the benefits of the wholesale market. In response to various rehearing requests, on March 4, 1997, the FERC issued Orders 888-A and 889-A. These Orders make minor clarifying adjustments to FERC Orders 888 and 889, and are intended to facilitate implementation of those Orders. The Company cannot predict the outcome of these matters or the impact of the new rules on its future financial condition. Although the Energy Act prohibits the FERC from ordering retail wheeling--transmitting power on behalf of another producer to an individual retail customer--some states have changed or are considering changing their laws or regulations, or instituting experimental programs to allow retail electric customers to buy power from suppliers other than the local utility. These changes or proposals elsewhere have taken differing forms and included disparate elements. The Company believes changes in existing laws in both North Carolina and South Carolina would be required to permit retail competition in the Company's retail jurisdictions. The South Carolina Public Service Commission (SCPSC) has ruled that it would be a violation of its past practice and of South Carolina's territorial assignment statute to require utilities to engage in retail competition. On February 8, 1995, the Carolina Utility Consumers Association, Inc., a group of industrial customers doing business in North Carolina, filed a petition with the NCUC requesting that the NCUC hold a generic hearing to investigate whether retail electric competition would be in the public interest, how it could be implemented in North Carolina and whether it could be implemented without changing state law. On July 21, 1995, the NCUC issued an order indicating that it would not convene a formal hearing to investigate these issues at that time. The NCUC's order noted that North Carolina's territorial assignment statute appears to prohibit retail competition, and the issue involves a number of jurisdictional uncertainties. Both the NCUC and the SCPSC indicated that they would monitor other states' activities regarding retail competition and would allow interested parties to submit information on the subject. 7 On September 19, 1995, the Company filed with the NCUC a list of specific issues it believes should be addressed prior to any form of retail competition being allowed in the state of North Carolina. On April 3, 1996, the NCUC issued an order seeking comments regarding the impact of retail competition on system reliability, obligation to serve, and stranded and ancillary costs. However, by order issued May 7, 1996, in Docket No. E-100, Sub 77, which concerns retail competition, the NCUC found that FERC Orders 888 and 889 essentially restructure the wholesale electric industry, and therefore may provide a new focus for NCUC proceedings with respect to competition in the electric industry. As a result, the NCUC concluded: (i) that all parties should concentrate their efforts on examining the impacts of the FERC orders, (ii) that the filing of comments requested by its order issued April 3, 1996 should be extended indefinitely, and (iii) that this docket should be held in abeyance pending further order. The Company cannot predict the outcome of the current debate regarding retail wheeling; however, the implications of retail competition on the Company's financial condition could be of a significantly greater magnitude than those associated with wholesale wheeling as discussed above. On January 29, 1997, representatives of both houses of the North Carolina General Assembly filed bills calling for the establishment of a commission, comprised of retail electric customers, electric companies, legislators and other interested parties, to study the future of the electric utility industry in North Carolina. The commission would be expected to file a report with the 1999 North Carolina General Assembly that would examine the numerous components of the electric industry and the implications of making changes. On February 6, 1997, representatives in the South Carolina General Assembly introduced a bill calling for a transition to full competition in the electric utility industry beginning in 1998. The Company cannot predict the outcome of these matters. Several pieces of legislation that concern the issue of retail competition were introduced in Congress in 1996. One bill (HR 3790), if enacted, would mandate retail wheeling in all 50 states no later than December 15, 2000. As proposed, this bill would require states to give all customers the right to choose their electric supplier. If this choice was not implemented by the states, the bill proposes that the FERC would be responsible for the implementation. The other bills had various provisions concerning retail competition and related topics. On January 30, 1997 a bill was introduced that would require states to allow all customers to choose their electric supplier by December 15, 2003. The bill has been referred to the Public Utility Subcommittee of the House Labor, Commerce and Industry Committee. The Company anticipates that this issue will continue to be debated by Congress during 1997. The Company cannot predict the outcome of these matters. The issues described above have created greater planning uncertainty and risks for the Company. The Company has been addressing these risks in the wholesale sector by securing long-term contracts with all of its wholesale customers, representing approximately 14% of the Company's 1996 operating revenue. These long-term contracts will allow the Company flexibility in managing its load and efficiently planning its future resource requirements. In the industrial sector, the Company is continuing to work to meet the energy needs of its customers. Other elements of the Company's strategy for responding to the changing market for electricity include promoting economic development, implementing new marketing strategies, improving customer satisfaction, increasing the focus on managing and reducing costs, and consequently, avoiding future rate increases. c. On December 2, 1996, the Company filed an application with the NCUC (Docket No. E-2, Sub 702) for approval of a self-generation deferral rate for General Electric Company's nuclear fuel and aircraft engine facility in North Carolina. In 1994, the NCUC adopted guidelines for self-generation deferral rates. The guidelines allow utilities to adjust rates to retain certain loads for which self-generation is feasible as long as they can demonstrate that doing so is in the best interest of all of their customers. The proposed rate, which is somewhat lower than the rate General Electric has been paying for electricity, will enable the Company to retain General Electric as a customer. On February 28, 1997, the Public Staff of the NCUC filed a response to the Company's application recommending that the Company's proposed self-generation deferral rate for General Electric be allowed. On March 10, 1997, the NCUC approved the proposed rate. 8 d. On December 16, 1996, the Company filed an application with the NCUC (Docket No. E-2, Sub 704) for approval of an experimental real-time pricing schedule for a limited number of non-residential customers. The proposed tariff offers hourly marginal cost-based prices for electricity consumption that exceeds the customer's baseline, which typically represents the hourly consumption during the previous year under existing tariffs. The proposed rate provides opportunities for some customers to control a part of their electricity costs and helps the Company make the best use of its existing generation resources. The tariff would be available to a limited number of participants with contract demand requirements of at least 1,000 kW. A similar application was filed with the SCPSC on February 6, 1997. On February 18, 1997, the proposed tariff was approved by both the NCUC and SCPSC. e. In June 1994, the FERC granted final approval of a Power Coordination Agreement (1994 PCA) and an Interchange Agreement, both dated August 27, 1993, which set forth explicitly the future relationship between the Company and North Carolina Electric Membership Corporation (NCEMC), and established a framework under which they will operate (Project Nos. 432-004 and 2748-000). The 1994 PCA allowed NCEMC to assume responsibility for up to 200 MW of its load from the Company's system between January 1, 1996 and December 31, 2000. Pursuant to this authority, NCEMC's board of directors awarded a power-supply contract for 200 MW to another supplier beginning on January 1, 1996. The contract, which has been accepted by the FERC, displaced 200 MW of baseload capacity that NCEMC previously purchased from the Company. On October 31, 1996, the Company and NCEMC entered into a revised power coordination agreement under which the Company will continue to serve a majority of NCEMC's power needs well past the year 2000. Under the terms of the revised agreement, NCEMC will receive discounted capacity in exchange for long-term commitments to the Company for its supplemental power. As a result of this new agreement, the Company will provide 225 MW of baseload power to NCEMC from 2000 to 2010, an additional block of 225 MW from 2001 to 2004, and a third block of 225 MW from 2002 to 2008. The remainder of the NCEMC load provided by the Company, not separately contracted for in the revised agreement, will be billed at a fixed price through the year 2004, rather than at the formula rates established in the 1994 PCA. The revised agreement, which represents an amendment to the 1994 PCA, was accepted for filing by the FERC on December 26, 1996, with an effective date of January 1, 1997. f. In late 1995, one of the Company's industrial customers in the City of Darlington, South Carolina ("City"), requested that the City become a municipal electric utility and provide retail electric service to the area. If it had become a municipal electric utility, the City would possibly have sought to purchase bulk power from a supplier other than the Company. The Company undertook efforts to educate the City's residents, businesses and industries regarding the many costs and legal issues associated with a municipalization effort. Both the Company and the City undertook studies to determine the feasibility of the municipalization proposal. The results of the Company's study, which was conducted by the consulting group Stone & Webster, found that municipalization would increase the cost of electricity to the City. The results of the City's study, conducted by the consulting group Strategic Energy Limited, found that municipalization would only benefit the City if the City were not required to pay the Company for any of its lost revenues or stranded costs. On September 3, 1996, the Darlington City Council voted against the proposal that the City become a municipal electric utility and will take no further action on the request at this time. g. On August 7, 1996, Power Agency notified the Company that it intends to discontinue certain contractual purchases of power from the Company effective September 1, 2001. Power Agency's notice indicated that it intends to replace these contractual obligations through purchases of capacity and energy related services in the open market and that the Company will be considered as a potential supplier for those purchases. The 1981 Power Coordination Agreement, as amended, between the parties requires that Power Agency give appropriate notice five years prior to reducing its purchases from the Company. The Company and Power Agency have agreed on a process for determining the sufficiency of the August 1996 notice. The Company cannot predict the outcome of this matter. 2. FRANCHISES. The Company is a regulated public utility and holds franchises to the extent necessary to operate in the municipalities and other areas it serves. 9 CONSTRUCTION PROGRAM ____________________ 1. CAPITAL REQUIREMENTS. During 1996 the Company expended approximately $555 million for capital requirements. The Company revised its capital program in 1996 as part of its annual business planning process. Estimated capital requirements for the years 1997 through 1999, which primarily reflect construction expenditures that will be made to meet customer growth by adding generating, transmission and distribution facilities as well as upgrading existing facilities, are set forth below. These estimates include Clean Air Act compliance expenditures of approximately $56 million, and generating facility addition expenditures of approximately $317 million. The generating facility addition expenditures will primarily be used to construct new combustion turbine units, which are intended for use during periods of high demand. The units are scheduled to be placed in service in 1997 through 2002. See PART I, ITEM 1, "Environmental Matters," paragraph 2 and "Generating Capability," paragraph 3, for further discussion of the impact of the Clean Air Act on the Company and planned generation additions, respectively. Estimated Capital Requirements ______________________________ (In millions) 1997 1998 1999 TOTAL ____ ____ ____ _____ Construction Expenditures $365 $489 $401 $1,255 Nuclear Fuel Expenditures 78 104 104 286 AFUDC (12) (20) (23) (55) ____ ____ ____ _____ Net Expenditures (a) 431 573 482 1,486 Mandatory Redemptions of Long-Term Debt 103 208 53 364 ____ ____ ____ _____ TOTAL $534 $781 $535 $1,850 ==== ==== ==== ===== ____________ (a) Reflects reductions of approximately $7 million, $11 million and $7 million for 1997, 1998 and 1999, respectively, in net capital requirements resulting from Power Agency's projected payment of its ownership share of capital expenditures related to the Joint Facilities. FINANCING PROGRAM _________________ 1. CAPITAL REQUIREMENTS. Based on the Company's most recent estimate of capital requirements, external funding requirements, which do not include early redemptions of long-term debt or redemptions of preferred stock, are expected to approximate $161 million in 1998. These funds will be required for construction, mandatory redemptions of long-term debt and general corporate purposes, including the repayment of short-term debt. The Company does not expect to have external funding requirements in 1997 or 1999. The Company may from time to time sell additional securities beyond the amount needed to meet capital requirements in order to allow for the early redemption of outstanding issues of long-term debt, the redemption of preferred stock, the reduction of short-term debt or for other corporate purposes. The amounts and timing of the sales of securities will depend upon market conditions and the specific needs of the Company. See PART II, ITEM 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," for further analysis and discussion of the Company's financing plans and capital resources and liquidity. 10 2. SEC FILINGS. a. The Company has on file with the Securities and Exchange Commission (SEC) a shelf registration statement (File No. 33-57835), under which an aggregate of $450 million principal amount of First Mortgage Bonds, and an additional $125 million combined aggregate principal amount of First Mortgage Bonds and/or unsecured debt securities of the Company remain available for issuance. b. The Company has on file with the SEC a shelf registration statement (File No. 33-5134) enabling the Company to issue up to $180 million of Serial Preferred Stock. 3. ISSUANCES OF BONDS, PREFERRED STOCK AND DEBENTURES. No bonds, preferred stock or debentures were issued by the Company during 1996; however, see PART I, ITEM 1, "Financing Program," paragraph 5 below for discussion of the Company's credit facility borrowings. 4. REDEMPTIONS/RETIREMENTS OF BONDS, PREFERRED STOCK AND DEBENTURES. Redemptions and retirements during 1996 and early 1997 included: - The redemption on February 27, 1996, of $125 million principal amount of First Mortgage Bonds, 8 7/8% Series due February 15, 2021, at 105.69% of the principal amount of such bonds plus accrued interest to the date of redemption. - The redemption on March 26, 1996, of $22.6 million principal amount of First Mortgage Bonds, 8 1/8% Series due November 1, 2003, at 100.52% of the principal amount of such bonds plus accrued interest to the date of redemption. - The redemption on March 26, 1996, of $100 million principal amount of First Mortgage Bonds, 7 3/4% Series due 2003, at 100.18% of the principal amount of such bonds plus accrued interest to the date of redemption. - The retirement on April 1, 1996, of $30 million principal amount of First Mortgage Bonds, 5 1/8% Series, which matured on that date. - The redemption on April 1, 1996, of $100 million principal amount of First Mortgage Bonds, 9% Series due April 1, 2022, at 105.89% of the principal amount of such bonds plus accrued interest to the date of redemption. - The retirement on December 2, 1996, of $25 million principal amount of First Mortgage Bonds, 4.85% Secured Medium-Term Notes, Series C, which matured on that date. - The retirement on December 27, 1996, of $50 million principal amount of First Mortgage Bonds, 7.90% Secured Medium-Term Notes, Series C, which matured on that date. - The retirement on January 24, 1997, of $60 million principal amount of First Mortgage Bonds, 7.75% Secured Medium-Term Notes, Series C, which matured on that date. 5. CREDIT FACILITIES. The Company's credit facilities presently total $685 million. This amount includes two new long-term revolving credit facilities totaling $350 million, which the Company entered in 1996 to support its commercial paper borrowings. In addition to these new facilities, the Company has other long-term revolving credit agreements totaling $235 million, and a $100 million short-term revolving credit agreement. The Company is required to pay minimal annual commitment fees to maintain certain credit facilities. Consistent with management's intent to maintain up to $350 million of its commercial paper on a long-term basis, and as supported by its long-term revolving credit facilities, the Company has included in its long-term debt $350 million of commercial paper outstanding as of December 31, 1996. See PART II, ITEM 8, Consolidated Financial Statements and Supplementary Data, Note 3, for a more detailed discussion of the Company's revolving credit facilities. 11 RETAIL RATE MATTERS ___________________ 1. GENERAL. The Company is subject to regulation in North Carolina by the NCUC and in South Carolina by the SCPSC with respect to, among other things, rates and service for electric energy sold at retail, retail service territory and issuances of securities. 2. CURRENT RETAIL RATES. The rates of return granted to the Company in its most recent general rate cases are as follows: 1988 North Carolina Utilities Commission Order (test year ended March 31, 1987) _____________________________________________ Capital Weighted Weighted Capital Structure Ratio Cost Rate Cost _________________ _______ _________ _______ Long-Term Debt 48.57% 8.62% 4.19% Preferred Stock 7.43 8.75 .65 Common Equity 44.00 12.75 5.61 Rate of Return _____ 10.45% ===== 1988 South Carolina Public Service Commission Order (test year ended September 30, 1987) ___________________________________________________ Capital Weighted Weighted Capital Structure Ratio Cost Rate Cost _________________ _______ _________ ________ Long-Term Debt 47.82% 8.62% 4.12% Preferred Stock 7.46 8.75 .65 Common Equity 44.72 12.75 5.71 Rate of Return _____ 10.48% ===== A petition was filed on July 19, 1996 by the Carolina Industrial Group for Fair Utility Rates (CIGFUR) with the NCUC requesting that the NCUC conduct an investigation of the Company's base rates or treat its petition as a complaint against the Company (Docket No. E-2, Sub. 699). The petition alleged that the Company's return on equity (which was authorized by the NCUC in the Company's last general rate proceeding in 1988), and earnings are too high. The Company filed a response to the petition and motion to dismiss on July 29, 1996, in which it argued that the petition was without merit. By letter dated August 2, 1996, the Company notified the NCUC that the Company intended to seek NCUC approval of certain accounting adjustments that would impact the Company's earnings. On August 6, 1996, the NCUC issued an order allowing the Company until September 16, 1996 to submit these adjustments, and stating that it would take no further action in this docket until the filing was made by the Company. On September 13, 1996, the Company (i) filed for approval to accelerate the amortization of certain regulatory assets, and to defer and amortize hurricane damage expenses, (ii) requested NCUC approval to implement these adjustments, effective January 1, 1997, and (iii) renewed its motion to dismiss CIGFUR's petition. On October 28, 1996, the Public Staff of the NCUC filed its comments on the Company's proposal. Those 12 comments included recommendations that the NCUC issue an order allowing the adjustments proposed by the Company, subject to certain minor modifications. By Order dated December 6, 1996, the NCUC approved the Company's proposal to accelerate amortization of certain regulatory assets over a three-year period beginning January 1, 1997. The accelerated amortization of these regulatory assets will reduce income by approximately $43 million, after tax, in each of the next three years. The NCUC also authorized the Company to defer operation and maintenance expenses associated with Hurricane Fran. See PART I, ITEM 1, "Other Matters," paragraph 8 for further discussion of hurricane damage. On December 27, 1996, the NCUC issued an order denying CIGFUR's petition and stating that it tentatively found no reasonable grounds to proceed with CIGFUR's petition as a complaint. On January 10, 1997, CIGFUR filed a motion for reconsideration with the NCUC, to which the Company responded on January 23, 1997. On February 6, 1997, the NCUC issued an order denying CIGFUR's motion for reconsideration. On February 25, 1997, CIGFUR filed a Notice of Appeal of the NCUC's decision with the North Carolina Court of Appeals. The Company cannot predict the outcome of this matter. With regard to South Carolina retail jurisdiction, on December 9, 1996, the Company filed for approval of a similar proposal to accelerate amortization of certain regulatory assets, including plant abandonment costs related to the Harris Plant, over a three-year period beginning January 1, 1997, with the SCPSC (Docket No. 96-381-E). This accelerated amortization will reduce income by approximately $13 million, after tax, in each of the next three years. In anticipation of approval of the proposal in 1997, the unamortized balance of plant abandonment costs related to the Harris Plant was adjusted in 1996 to reflect the present value impact of the shorter recovery period. This adjustment resulted in an increase in income of approximately $14 million, after tax, in 1996. On March 4, 1997, the SCPSC approved the implementation of the proposed accounting adjustments. 3. INTEGRATED RESOURCE PLANNING. Integrated resource planning is a process that systematically compares all reasonably available resources, both demand-side and supply-side, in order to develop that mix of resources that allows a utility to meet customer demand in a cost-effective manner, giving due regard to system reliability, safety and the environment. Utilities are required to file their Integrated Resource Plans (IRP) with the NCUC and the SCPSC once every three years. The Company regularly reviews its IRP in light of changing conditions and evaluates the impact these changes have on its resource plans, including purchases and other resource options. The Company filed its 1995 IRP with the NCUC on April 28, 1995, and with the SCPSC on July 3, 1995. By order dated February 20, 1996, the NCUC approved the Company's 1995 IRP as filed. The SCPSC established April 8, 1996 as the deadline for parties to intervene and/or submit comments regarding the Company's 1995 IRP. The South Carolina Consumer Advocate and Nucor Corporation intervened in the proceeding, but the SCPSC has not yet issued an order in this matter. The Company cannot predict the outcome of this matter. 4. FUEL COST RECOVERY. In the North Carolina retail jurisdiction, the NCUC establishes base fuel costs in general rate cases and holds hearings annually to determine whether a rider should be added to base fuel rates to reflect increases or decreases in the cost of fuel and the fuel cost component of purchased power as well as changes in the fuel cost component of sales to other utilities. The NCUC considers the changes in the Company's cost of fuel during a historic test period ending March 31 of each year and corrects any past over- or under-recovery. On June 7, 1996, the Company filed its 1996 application proposing no change in its net fuel factor. The hearing was held on August 14, 1996, and by order issued September 10, 1996, the NCUC approved the Company's request for no change in its net fuel factor. In the South Carolina retail jurisdiction, fuel rates are set by the SCPSC. At the fuel hearings, any past over- or under-recovery of fuel costs is taken into account in establishing the new rate. During the 1996 legislative session, the South Carolina General Assembly made several modifications to SC Code Ann. Section 58-27-865, which is the statute that governs the recovery of fuel cost by electric utilities. The modifications include: changing the test period from a six-month period to a twelve-month period, which will result in the frequency of fuel cost hearings being changed from every six months to every twelve months; allowing utilities to recover the cost of Clean Air Act allowances through the fuel factor; and establishing a rebuttable presumption of prudent operation of a utility's nuclear generating facilities if the utility achieves a 13 nuclear system capacity factor of 92.5%, exclusive of refueling and maintenance outages. On February 19, 1997, the Company filed a proposal with the SCPSC to reduce its fuel factor from its current level of 1.34 cents/kWh to 1.122 cents/kWh. In accordance with the modified fuel cost recovery statute, the Company's South Carolina fuel proceeding was held on March 19, 1997, and on March 25, 1997, the SCPSC approved the Company's proposed fuel factor. The new fuel factor will be effective for the period April 1, 1997 through March 31, 1998. 5. AVOIDED COST PROCEEDINGS. a. The NCUC opened Docket No. E-100, Sub 79 for its biennial proceeding to establish the avoided cost rates for all electric utilities in North Carolina. Avoided cost rates are intended to reflect the costs that utilities are able to "avoid" by purchasing power from qualifying facilities. The Company's initial filing in this docket was made on November 4, 1996. Intervenor comments on the utilities' filings were made on January 10, 1997. On February 4, 1997, the NCUC received non-expert public testimony and further written comments by the parties. On March 4, 1997, all parties filed proposed orders with the NCUC. The Company cannot predict the outcome of this matter. b. The SCPSC opened Docket No. 95-1192-E to establish avoided cost rates for all electric utilities in South Carolina. Hearings were held on August 8, 1996, and on August 28, 1996, the SCPSC issued an order approving the Company's proposed avoided cost rates. WHOLESALE RATE MATTERS ______________________ 1. GENERAL. The Company is subject to regulation by the FERC with respect to rates for transmission and sale of electric energy at wholesale, the interconnection of facilities in interstate commerce (other than interconnections for use in the event of certain emergency situations), the licensing and operation of hydroelectric projects and, to the extent the FERC determines, accounting policies and practices. The Company and its wholesale customers last agreed to a general increase in wholesale rates in 1988; however, wholesale rates have been adjusted since that time through contractual negotiations. 2. FERC MATTERS. a. By letter dated May 31, 1995, the Company requested that the FERC (Docket No. 95-1139) establish a return on equity (ROE) in connection with the formula rates provided in the PCA dated August 27, 1993 between the Company and NCEMC. The requested ROE is consistent with the rate of return on common equity approved by the NCUC in the Company's 1988 rate case. On February 6, 1996, the Company filed an offer of settlement with the FERC to set the ROE at 10.75 percent. The FERC staff filed comments supporting the settlement on February 14, 1996. On April 11, 1996 the FERC issued an order approving the 10.75 percent ROE and ordered refunds of excess revenues collected since January 1, 1996. These refunds are not material to the results of operations of the Company. b. On May 31, 1995, the Company filed a petition with the FERC (Docket No. EL95-50) seeking to recover certain fuel costs from the Company's wholesale customers. These costs are related to the Company's $6.8 million buyout of its contractual agreement with The Arch Coal Sales Company (Arch Coal). As a result of this buyout, the Company will purchase less coal from Arch Coal in the future and will pay a lower purchase price for that coal. The Company cannot predict the outcome of this matter. c. On July 7, 1995, Smithfield Foods, Inc., doing business as Carolina Foods Processors, Inc. (Carolina Foods), filed a Complaint with the FERC (Docket No. EL95-60) alleging that certain charges imposed upon NCEMC under the PCA between the Company and NCEMC are unreasonable. These charges are related to generation installed by Carolina 14 Foods, which receives electric service from Four County EMC (a customer of NCEMC). The Company filed its response to the Complaint on August 10, 1995. The Company cannot predict the outcome of this matter. d. On March 1, 1996, the Company and Power Agency entered into a contractual agreement which provides that Power Agency will delay construction and startup of its 183.7 MW combustion turbine generating project until 2004. (That project was scheduled to begin commercial operation in June 1998.) Pursuant to a 1981 Power Coordination Agreement, as amended, between Power Agency and the Company, Power Agency is obligated to purchase this electricity from the Company from 1995 through May 31, 1998. As a result of the new agreement, Power Agency will purchase peaking capacity from the Company as follows: 110 MW from June 1, 1998 through December 31, 1998, 116 MW in 1999 and 183.7 MW from 2000 through 2003. The new agreement must be submitted to the FERC for approval. The Company cannot predict the outcome of this matter. ENVIRONMENTAL MATTERS _____________________ 1. GENERAL. In the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes and other environmental matters, the Company is subject to regulation by various federal, state and local authorities. The Company considers itself to be in substantial compliance with those environmental regulations currently applicable to its business and operations and believes it has all necessary permits to conduct such operations. The Company does not currently anticipate that its potential capital expenditures for environmental pollution control purposes will be material. Environmental laws and regulations, however, are constantly evolving and the character, scope and ultimate costs for compliance with such evolving laws and regulations cannot now be accurately estimated. The costs associated with compliance with pollution control laws and regulations at the Company's existing facilities that the Company expects to incur from 1997 through 1999 are included in the estimates of capital requirements under PART I, ITEM 1, "Construction Program." 2. CLEAN AIR LEGISLATION. The 1990 amendments to the Clean Air Act (Act) require substantial reductions in sulfur dioxide and nitrogen oxides emissions from fossil-fueled electric generating plants. The Company was not required to take action to comply with the Act's Phase I requirements for these emissions, which had to be met by January 1, 1995. The Act's Phase II requirements, which contain more stringent provisions, will become effective January 1, 2000. The Act required that a Title IV permit application , including certifications regarding compliance with the Phase II sulfur dioxide and nitrogen oxides emissions requirements, be submitted to the appropriate permitting authority for each of the Company's plants by January 1, 1996. The Company submitted its Title IV permit applications in late 1995. The Company plans to meet the Phase II sulfur dioxide emissions requirements by utilizing the most economical combination of fuel-switching and sulfur dioxide emission allowances. Each sulfur dioxide emission allowance allows a utility to emit one ton of sulfur dioxide. The Company has purchased emission allowances under the Environmental Protection Agency's (EPA) emission allowance trading program in order to supplement the allowances the EPA granted to the Company. Installation of additional equipment will be necessary to reduce nitrogen oxide emissions. The Company estimates that future capital costs necessary to comply with Phase II of the Act will approximate $160 million. Increased operation and maintenance costs, including emission allowance expense, and increased fuel costs are not expected to be material to the results of operations of the Company. The EPA has recently proposed revisions to existing air quality standards for ozone and particulate matters. If these standards are eventually finalized as proposed, additional compliance costs will be incurred. As the Company's plans for compliance with the Act's requirements are subject to change, the amount required for capital expenditures and for increased operation, and maintenance and fuel expenditures cannot be determined with certainty at this time. The Company cannot predict the outcome of this matter. 3. SUPERFUND. The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA and, indirectly, the states, to require generators and certain transporters of certain hazardous substances released from or at a site, and the owners and operators of such site, to clean up the site or reimburse the costs therefor. In most instances, this statute has been interpreted to impose retroactive joint and several 15 liability on responsible parties. There are presently several sites with respect to which the Company has been notified by the EPA or the State of North Carolina of its potential liability, as described below in greater detail. a. On December 2, 1986, the EPA notified the Company of its potential liability pursuant to CERCLA for the investigation and cleanup activities associated with the Maxey Flats Nuclear Disposal Site, a low-level nuclear waste disposal site located in Fleming County, Kentucky. The EPA indicated that the site was operated from 1963 to 1977 under the management of Nuclear Engineering Company (now U. S. Ecology). The EPA estimated that the Company sent 304,459 cubic feet of low-level radioactive waste to the disposal site. In response to the EPA's notice, the Company and several other potentially responsible parties (PRPs) formed a steering committee (the Maxey Flats Steering Committee) to undertake a remedial investigation/feasibility study pursuant to CERCLA. As a result of this study, the EPA has selected a remedial action which is currently estimated to have a present value cost of between $57 million and $78 million. Subsequent analysis of waste volume sent to the site performed by the Maxey Flats Steering Committee established that the Company contributed only approximately 1% of the total waste volume. It is expected that the Company's share of remediation costs will be based on the ratio of the Company's waste volume to that of other participating PRPs. The Company is currently ranked twenty-fourth on the waste-in list. On June 30, 1992, the EPA sent the Company, along with a number of other companies, agencies and organizations, a notice demanding reimbursement of response costs of approximately $5.8 million that have been incurred at the site and seeking to initiate formal negotiations regarding performance of the remedial design and remedial action for the site. On July 20, 1992, the Company responded that it would negotiate these matters through the Maxey Flats Steering Committee. In December 1992, the EPA rejected the offer the Maxey Flats Steering Committee filed regarding the performance of the remedial design and remedial action for this site. The Maxey Flats Steering Committee submitted amended offers to the EPA in 1993. The EPA has engaged in settlement negotiations with the Maxey Flats Steering Committee, the Commonwealth of Kentucky, which owns the site, and the federal agencies in an effort to reach global settlement. On June 5, 1995, a De Maximus Consent Decree (Consent Decree) was filed on behalf of the Maxey Flats Steering Committee in the United States District Court for the Eastern District of Kentucky (Civil Action No. 95-58). The Consent Decree provides for the performance of the Initial Remediation Phase and the Balance of Remediation Phase, and for the reimbursement of certain response costs incurred by the EPA. The Consent Decree has been approved by the court, and the work it requires is in progress. Although the Company cannot predict the outcome of this matter, it does not anticipate that costs associated with this site will be material to the results of operations of the Company. b. By letter dated May 21, 1991, the EPA notified the Company that it is a PRP with respect to the disposal of hazardous substances at the Benton Salvage site in Little Rock, Arkansas. The Company has been unable to identify any records of shipments by the Company to that site. Until any such documentation can be produced, the Company does not intend to participate in cleanup activities at the site. The Company cannot predict the outcome of this matter. c. On April 15, 1991, the North Carolina Department of Environment, Health, and Natural Resources (DEHNR) notified the Company that it is a PRP with respect to the disposal of hazardous waste at the Seaboard Chemical Corporation (Seaboard) site in Jamestown, North Carolina. Seaboard is in bankruptcy. The wastes sent from the Company's facilities to the Seaboard site consisted primarily of cleaning and degreasing solvents, solvent contaminated oils and paint-related waste. DEHNR has indicated that it is offering PRPs the opportunity to perform voluntary site cleanup. Seaboard records indicate that there are over 1,300 PRPs for the site and that the Company's contribution to waste disposal is less than 1% of the total waste disposed. On May 29, 1992, the Company entered into an Administrative Order of Consent (AOC) with DEHNR, Division of Solid Waste Management, to undertake and perform a Work Plan for Surface Removal (Removal Work Plan). The Company estimates that to date its costs associated with completion of the Removal Work Plan total approximately $12,000. On July 28, 1993, DEHNR determined that the Removal Work Plan had been substantially completed. DEHNR further recommended that the Seaboard Group (a group of PRPs with respect to the Seaboard site) undertake additional remedial activities at the Seaboard site. The Company has joined the Seaboard Group II (a group of PRPs formed to conduct additional work at the Seaboard site). The Seaboard Group II, the City of High Point, North Carolina and the DEHNR have negotiated an AOC that requires the Seaboard Group II and the City of High Point to conduct a joint 16 Remedial Investigation (RI). The Company has executed that AOC. The City of High Point operated a landfill that bounds the Seaboard site on three sides. The City of High Point has conducted studies of groundwater on its site and those studies have indicated that a joint RI is appropriate. Cost estimates for the additional work are not available. Although the Company cannot predict the outcome of this matter, it does not anticipate that costs associated with this site would be material to the results of operations of the Company. On April 13, 1994, Crown Cork & Seal Company, Inc. and Clark Equipment Co. filed a motion to add the Company as a defendant in an ongoing lawsuit concerning the Macon-Dockery site, located near Cordova, North Carolina. The lawsuit was filed in the United States District Court for the Middle District of North Carolina in Greensboro, North Carolina (Civil Action No. 3:92CV00744) on December 4, 1992. The lawsuit seeks to recover costs incurred in undertaking the Remedial Investigation Feasibility Study and the Remedial Design for the Macon-Dockery site. (The EPA first notified the Company in 1992 that it is a PRP with respect to the additional remediation of hazardous wastes at the site.) Wastes disposed of at the Macon-Dockery site include antifreeze, used oils, metals, paint, solvent wastes and waste acids and bases. The Company made arrangements in the past for the transportation and sale of some petroleum products to C & M Oil Distributors, a company that operated an oil reprocessing facility at the Macon-Dockery site. However, the information available to the Company indicates that no CERCLA hazardous wastes from Company facilities were sent to the site. On July 6, 1994, the United States District Court for the Middle District of North Carolina granted the motion Crown Cork & Seal Company and Clark Equipment Co. filed seeking to name the Company as a defendant in the lawsuit. On September 30, 1994, the Company filed an Answer denying any liability to Crown Cork & Seal Company and Clark Equipment Co. Discovery in this matter is currently underway. Although the Company cannot predict the outcome of this matter, it does not anticipate that costs associated with this site, if any, would be material to the results of operations of the Company. e. Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under various federal and state laws. The production of manufactured gas was commonplace from the late 1800s until the 1950s. There are several manufactured gas plant (MGP) sites to which the Company and certain entities which were later merged into the Company had some connection. In this regard, the Company, along with other entities alleged to be former owners and operators of MGP sites in North Carolina, is participating in a cooperative effort with the North Carolina Department of Environment, Health and Natural Resources, Division of Waste Management (DWM), formerly the Division of Solid Waste Management, to establish a uniform framework for addressing these MGP sites. The investigation and remediation of specific MGP sites will be addressed pursuant to one or more Administrative Orders on Consent between the DWM and individual PRPs. The Company continues to investigate the identities of parties connected to individual MGP sites , the relative relationships of the Company and other parties to those sites, and the degree to which the Company will undertake shared voluntary efforts with others at individual sites. Due to uncertainty regarding the extent of remedial action that will be required and questions of liability, the cost of remedial activities at certain MGP sites is not currently determinable. The Company cannot predict the outcome of these matters. f. By letter dated March 7, 1996, the EPA notified the Company that it is a PRP with respect to the disposal of hazardous substances at the Cherokee Oil Company (Cherokee) sites in Charlotte, North Carolina. The materials sent from the Company's facilities to the Cherokee sites were associated with tank cleanings at the Company's former Wilmington Oil Terminal. The EPA has performed removal actions at the sites and is now seeking cost recovery. Although the Company cannot predict the outcome of this matter, it does not anticipate costs associated with this site will be material to the results of operations of the Company. 4. OTHER ENVIRONMENTAL MATTERS. On April 21, 1989, the North Carolina Department of Environment, Health and Natural Resources, Division of Water Quality (DWQ), formerly the Division of Environmental Management, requested that, in response to a 1979 spill of No. 2 fuel oil, the Company install a groundwater compliance monitoring system at the 17 Company's Wilmington Oil Terminal located in New Hanover County, North Carolina. During the second half of 1989, six groundwater monitoring wells were installed. One of the six wells indicated gasoline contamination and samples from a second well indicated No. 2 fuel oil contamination. In February 1993, the DWQ approved a corrective action plan (CAP) for addressing gasoline and No. 2 fuel oil contamination. In 1995, the Company confirmed the presence of off-site gasoline contamination; however, it is not clear that the Company is responsible for off-site gasoline contamination. The Company is proceeding to seek approval to modify the CAP so that on and off-site contamination will be remediated by natural attenuation and degradation factors. The Company sold the Wilmington Oil Terminal on March 1, 1996, but will continue to address existing on- and off-site gasoline and No. 2 fuel oil contamination solely associated with its prior years of ownership. Although the Company cannot predict the outcome of this matter, it does not anticipate that costs associated with this site will be material to the results of operations of the Company. 5. ENVIRONMENTAL ACCRUAL. As noted above, the Company has been notified by regulators of its involvement or potential involvement in several sites, other than MGP sites, that require remedial action. Although the Company cannot predict the outcome of these matters, it does not expect costs associated with these sites to be material to the results of operations of the Company. The Company continues to carry a liability for the estimated costs associated with certain remedial activities at several MGP and other sites. This liability is not material to the financial position of the Company. NUCLEAR MATTERS _______________ 1. GENERAL. Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, as amended, operation of nuclear plants is intensively regulated by the Nuclear Regulatory Commission (NRC), which has broad power to impose nuclear safety and security requirements. In the event of noncompliance, the NRC has the authority to impose fines, set license conditions, or shut down a nuclear unit, or some combination of these, depending upon its assessment of the severity of the situation, until compliance is achieved. The electric utility industry in general has experienced challenges in a number of areas relating to the operation of nuclear plants, including substantially increased capital outlays for modifications; the effects of inflation upon the cost of operations; increased costs related to compliance with changing regulatory requirements; renewed emphasis on achieving excellence in all phases of operations; unscheduled outages; outage durations; and uncertainties regarding both disposal facilities for low-level radioactive waste and storage facilities for spent nuclear fuel. See paragraphs 2 and 3 below. The Company experiences these challenges to varying degrees. Capital expenditures for modifications at the Company's nuclear units, excluding Power Agency's ownership interests, during 1997, 1998 and 1999 are expected to total approximately $37 million, $44 million, and $37 million respectively (including AFUDC). 2. SPENT FUEL AND OTHER HIGH-LEVEL RADIOACTIVE WASTE. The Nuclear Waste Policy Act of 1982 (Nuclear Waste Act) provides the framework for development by the federal government of interim storage and permanent disposal facilities for high-level radioactive waste materials. The Nuclear Waste Act promotes increased usage of interim storage of spent nuclear fuel at existing nuclear plants. The Company will continue to maximize the use of spent fuel storage capability within its own facilities for as long as feasible. Pursuant to the Nuclear Waste Act, the Company, through a joint agreement with the U. S. Department of Energy (DOE) and the Electric Power Research Institute, has built a demonstration facility at the Robinson Plant that allows for the dry storage of 56 spent nuclear fuel assemblies. As of December 31, 1996, sufficient on-site spent nuclear fuel storage capability is available for the full-core discharge of Brunswick Unit No. 1 through 1999, Brunswick Unit No. 2 through 1998, and Robinson Unit No. 2 through 2000 assuming normal operating and refueling schedules. The Harris Plant spent fuel storage facilities, with certain modifications, together with the spent fuel storage facilities at the Brunswick and Robinson Units, are sufficient to provide storage space for spent fuel generated on the Company's system through the expiration of the current operating licenses for all of the Company's nuclear generating units. Subsequent to the expiration of the licenses, dry storage may be necessary in conjunction with the decommissioning of the units. The Company is maintaining full-core discharge capability for the Brunswick Units and Robinson Unit No. 2 by 18 transferring spent nuclear fuel by rail to the Harris Plant. As a contingency to the shipment by rail of spent nuclear fuel, on April 27, 1989, the Company filed an application with the NRC for the issuance of a license to construct and operate an independent spent fuel storage facility for the dry storage of spent nuclear fuel at the Brunswick Plant. Due to the success of the Company's shipping efforts to date, however, at the Company's request, the NRC suspended review of the Company's license application pending notification by the Company of its desire to continue the application process. The Company cannot predict the outcome of this matter. As required by the Nuclear Waste Act, the Company entered into a contract with the DOE in June 1983 under which the DOE agreed to dispose of the Company's spent nuclear fuel. The contract includes a provision requiring the Company to pay the DOE for disposal costs. Disposal costs of fuel burned are based upon actual nuclear generation and are paid on a quarterly basis. Disposal costs, excluding waste disposal credits, are approximately $20 million annually based on the expected level of operations and the present disposal fee per kWh of nuclear generation, and are currently recovered through the Company's fuel adjustment clauses. To date, the Company has paid $306 million (including Power Agency's share), to the DOE. See PART I, ITEM 1, "Retail Rate Matters," paragraph 4. By letter dated December 17, 1996, the DOE notified the Company and other similarly situated utilities that the agency anticipates that it will be unable to begin acceptance of spent nuclear fuel by January 31, 1998. On January 31, 1997, the Company, together with 35 other utilities, filed a Joint Petition for Review with the United States Court of Appeals requesting the Court review the final decision of the DOE and the DOE's failure to meet its unconditional obligation under the Nuclear Waste Act. The petition requests the Court, among other things, to issue a declaration stating that the petitioners are relieved of their reciprocal obligation to pay fees into the Nuclear Waste Fund and, instead, may deposit those funds into escrow until the DOE commences disposing of spent nuclear fuel. The Company cannot predict at this time whether the DOE will be able to perform its contract and provide interim storage or permanent disposal repositories for spent fuel and/or high-level radioactive waste materials on a timely basis. 3. LOW-LEVEL RADIOACTIVE WASTE. Disposal costs for low-level radioactive waste that results from normal operation of nuclear units have increased significantly in recent years and are expected to continue to rise. Pursuant to the Low-Level Radioactive Waste Policy Act of 1980, as amended in 1985, each state is responsible for disposal of low-level waste generated in that state. States that do not have existing sites may join in regional compacts. The States of North Carolina and South Carolina were participants in the Southeast regional compact and disposed of waste at a disposal site in South Carolina along with other members of the compact. Effective July 1, 1995, South Carolina withdrew from the Southeast regional compact and excluded North Carolina waste generators from the existing disposal site in South Carolina. As a result, the State of North Carolina does not have access to a low-level radioactive waste disposal facility. The North Carolina Low-Level Radioactive Waste Management Authority, which is responsible for siting and operating a new low-level radioactive waste disposal facility for the Southeast regional compact, has submitted a license application for the site it selected in Wake County, North Carolina to the North Carolina Division of Radiation Protection. Although the Company does not control the future availability of low-level waste disposal facilities, the cost of waste disposal or the development process, it is actively supporting the development of new facilities and is committed to a timely and cost-effective solution to low-level waste disposal. The Company's nuclear plants in North Carolina are currently storing low-level waste on site and are developing additional storage capacity to accommodate future needs. The Company's nuclear plant in South Carolina has access to the existing disposal site in South Carolina. Although the Company cannot predict the outcome of this matter, it does not expect the cost of providing additional on-site storage capacity for low-level radioactive waste to be material to the results of operations or financial position of the Company. 4. DECOMMISSIONING. a. Pursuant to an NRC rule, licensees of nuclear facilities are required to submit decommissioning funding plans to the NRC for approval to provide reasonable assurance that the licensee will have the financial ability to implement its decommissioning plan for each facility. The rule requires licensees to do one of the following: prepay at least an NRC-prescribed minimum amount immediately; set up an external sinking fund for accumulation of at least that minimum amount 19 over the operating life of the facility; or provide a surety to guarantee financial performance in the event of the licensee's financial inability to perform actual decommissioning. On July 26, 1990, the Company submitted its decommissioning funding plans to the NRC. In this regard, the Company entered into a Master Decommissioning Trust Agreement dated July 19, 1990 (Trust), with Wachovia Bank of North Carolina, N.A., as Trustee, as a vehicle to achieve such decommissioning funding. In June 1991, the Company began depositing funds into the Trust. With regard to the Company's recovery through rates of nuclear decommissioning costs, in the Company's retail jurisdictions, provisions for nuclear decommissioning costs were approved by the NCUC and the SCPSC in the Company's 1988 general rate cases, and were based on site-specific estimates that included the costs for removal of all radioactive and other structures at the site. In the wholesale jurisdiction, the provisions for nuclear decommissioning costs are based on amounts agreed upon in applicable rate agreements. Decommissioning cost provisions, which are included in depreciation and amortization, were $33.1 million in 1996, $31.2 million in 1995, and $29.5 million in 1994. Accumulated decommissioning costs, which are included in accumulated depreciation, were $326 million at December 31, 1996 and $288.4 million at December 31, 1995. These costs include amounts retained internally and amounts funded in the Trust. The balance of the Trust, which is included in miscellaneous other property and investments, was $145.3 million at December 31, 1996 and $110.2 million at December 31, 1995. Trust earnings, which increase the trust balance with a corresponding increase in accumulated decommissioning, were $4.5 million in both 1996 and 1995 and $1.5 million in 1994. Based on the site-specific estimates discussed below and using an assumed after-tax earnings rate of 8.5% and an assumed cost escalation rate of 4%, current levels of rate recovery for nuclear decommissioning costs are adequate to provide for decommissioning of the Company's nuclear facilities. b. The Company's most recent site-specific estimates of decommissioning costs were developed in 1993 using 1993 cost factors, and are based on prompt dismantlement decommissioning, which reflects the cost of removal of all radioactive and other structures currently at the site, with such removal occurring shortly after operating license expiration. See paragraph 5 below for expiration dates of operating licenses. These estimates, in 1993 dollars, are as follows: $257.7 million for Robinson Unit No. 2; $235.4 million for Brunswick Unit No. 1; $221.4 million for Brunswick Unit No. 2; and $284.3 million for the Harris Plant. These estimates are subject to change based on a variety of factors, including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning, and changes in federal, state or local regulations. The cost estimates exclude the portion attributable to Power Agency, which holds an undivided ownership interest in the Brunswick and Harris nuclear generating facilities. To the extent of its ownership interests, Power Agency is responsible for satisfying the NRC's financial assurance requirements for decommissioning costs. See PART I, ITEM 1, "Generating Capabilities," paragraph 1. c. The Financial Accounting Standards Board (the Board) has reached several tentative conclusions with respect to its project regarding accounting practices related to closure and removal of long-lived assets. The primary conclusions as they relate to nuclear decommissioning are: 1) the cost of decommissioning should be accounted for as a liability and accrued as the obligation is incurred; 2) recognition of a liability for decommissioning results in recognition of an increase to the cost of the plant; 3) the decommissioning liability should be measured based on discounted cash flows using a risk-free rate; and 4) decommissioning trust funds should not be offset against the decommissioning liability. It is uncertain what impacts the final statement may ultimately have on the Company's accounting for nuclear decommissioning and other closure and removal costs. The Board has announced that the effective date would be no earlier than 1998. 5. OPERATING LICENSES. Facility Operating Licenses, issued by the NRC, for the Company's nuclear facilities allow for a full 40 years of operation. Expiration dates for these licenses are set forth in the following table. 20 Facility Operating License Facility Expiration Date ________ ___________________________ Robinson Unit No. 2 July 31, 2010 Brunswick Unit No. 1 September 8, 2016 Brunswick Unit No. 2 December 27, 2014 Harris Plant October 24, 2026 6. OTHER NUCLEAR MATTERS a. In 1991, the NRC issued a final rule on nuclear plant maintenance that became effective on July 10, 1996. In general terms, the new maintenance rule prescribes the establishment of performance criteria for each safety system based on the significance of that system. The rule also requires monitoring of safety system performance against the established acceptance criteria, and provides that remedial action be taken when performance falls below the established criteria. The Company has been working closely with the Nuclear Energy Institute (formerly the Nuclear Management and Resources Council) and with other utilities to develop its compliance approach and to minimize the financial and operational impacts of the new rule. The Company anticipates its compliance will be on schedule and is evaluating the magnitude of the financial and operational impacts of this new rule. Although the Company cannot predict the outcome of this matter, it does not expect the impacts of the new rule to be material to the Company's results of operations. b. On November 23, 1988, the NRC requested in Generic Letter 88-20 that utilities perform Individual Plant Examinations (IPEs) to determine potential vulnerabilities to severe accidents beyond the design basis accidents for which the plants are designed. These are considered to be very low probability events. The Company submitted the results of the first phase (for internally initiated events) in August 1992 for the Brunswick and Robinson Plants. Based on those results, potential enhancements for the Robinson Plant were evaluated and several enhancements were made to the Robinson Plant. These changes had insignificant financial and operational impacts. For the Brunswick Plant, no modifications were required to meet the guidelines of the IPE. On August 20, 1993, the Company submitted the results of the Harris Plant IPE. While some Harris Plant procedural changes were made due to the IPE results, the IPE did not reveal any significant financial or operational impacts or identify any need for plant modifications. In June 1995, the Company completed and submitted the results of the second phase of the IPEs (for externally initiated events) for the Company's three nuclear plants. The results of the IPEs indicated that some procedural changes may be required for the Harris and Brunswick Plants. Those results also indicated that both minor procedural changes and minor plant modifications will be required for the Robinson Plant. The Company has filed an implementation plan with the NRC which calls for all IPE actions to be implemented by 1998. Although the Company cannot predict at this time the exact magnitude of the financial and operational impacts of the second phase of the IPEs, it does not expect those impacts to be material to the results of operations or financial position of the Company. c. Degradation of tubing internal to steam generators in pressurized water reactor power plants (PARS) due to intergranular stress corrosion cracking has been an on-going industry phenomenon. The Company has determined that the steam generators at the Harris Plant are subject to steam generator degradation and the Company is closely monitoring the steam generator performance. Experience and testing conducted to date indicate that the Harris Plant steam generators will not require replacement before 2000. The steam generators at the H.B. Robinson plant were replaced in 1982 and are expected to perform until the plant's operating license expires. Although the Company cannot predict the outcome of this matter, it does not expect the cost of replacing the steam generators at the Harris Plant to be material to the results of operations or financial position of the Company. 21 d. The Company is insured against public liability for a nuclear incident up to $8.9 billion per occurrence, which is the maximum limit on public liability claims pursuant to the Price-Anderson Act. The $8.9 billion coverage includes $200 million primary coverage and $8.7 billion secondary financial protection through assessments on nuclear reactor owners. In the event that public liability claims from an insured nuclear incident exceed $200 million, the Company would be subject to a pro rata assessment, for each reactor it owns, of up to $75.5 million, plus a 5% surcharge, for each incident. Payment of such assessment would be made over time as necessary to limit the payment in any one year to no more than $10 million per reactor owned. Power Agency would be responsible for its ownership share of the assessment on jointly-owned nuclear units. For a more detailed discussion of nuclear liability insurance, see PART II, ITEM 8, Consolidated Financial Statements and Supplementary Data Note 11 B. FUEL ____ 1. SOURCES OF GENERATION. Total system generation (including Power Agency's share) by primary energy source, along with purchased power, for the years 1993 through 1997 is set forth below: 1993 1994 1995 1996 1997 ____ ____ ____ ____ ____ (estimated) Fossil 54% 43% 44% 45% 48% Nuclear 31 42 42 41 42 Purchased Power 13 13 13 12 9 Hydro 2 2 1 2 1 2. COAL. a. The Company has intermediate and long-term agreements from which it expects to receive approximately 63% of its coal burn requirements in 1997. During 1995 and 1996, the Company obtained approximately 77% (7,531,171 tons), and 68% (7,181,257 tons), respectively, of its coal burn requirements from intermediate and long-term agreements. Over the next ten years, the Company expects to receive approximately 75% of its coal burn requirements from intermediate and long-term agreements. Existing agreements have expiration dates ranging from 1998 to 2006. During 1996, the Company maintained from 29 to 52 days' supply of coal, based on anticipated burn rate. All of the coal that the Company is currently purchasing under intermediate and long-term agreements is considered to be low sulfur coal by industry standards. Recent amendments to the Clean Air Act may result in increases in the price of low sulfur coal which continue beyond the effective date of the second phase of the Act. See PART I, ITEM 1, "Environmental Matters," paragraph 2. The Company purchased approximately 1,286,000 tons of coal in the spot market during 1995 and 3,340,000 tons in 1996. The Company's contract coal purchase prices during 1996 ranged from approximately $29.90 to $38.45 per ton (F.O.B. mine adjusted to 12,000 Btu/lb.). The average cost (including transportation costs) to the Company of coal delivered for the past five years is as follows: Year $/Ton Cents/Million BTU ____ _____ _________________ 1992 43.25 174 1993 43.10 172 1994 43.36 174 1995 44.46 179 1996 42.21 170 b. The Company and certain subsidiaries of Zeigler Coal Holding Company (Zeigler) have renegotiated their existing contract. Under the revised agreement, which expires in 2006, the Company will continue to purchase 22 approximately 2.75 million tons of coal annually from Zeigler's Marrowbone mine, and will purchase approximately 6 million tons of additional, lower cost coal from Zeigler over a period of several years under a new contract. The coal will be required to meet the same technical specifications for sulfur and thermal content as the coal supplied from the Marrowbone mine, and is expected to save the Company more than $100 million over the life of the contract. 3. OIL. The Company uses No. 2 oil primarily for its combustion turbine units, which are used for emergency backup and peaking purposes, and for boiler start-up and flame stabilization. The Company burned approximately 8.8 million gallons and 12.1 million gallons of No. 2 oil during 1995 and 1996, respectively. The Company has a No. 2 oil supply contract for its normal requirements. In the event base-load capacity is unavailable during periods of high demand, the Company may increase the use of its combustion turbine units, thereby increasing No. 2 oil consumption. The Company intends to meet any additional requirements for No. 2 oil through additional contract purchases or purchases in the spot market. There can be no assurance that adequate supplies of No. 2 oil will be available to meet the Company's requirements. To reduce the Company's vulnerability to dislocations in the oil market, seven combustion turbine units with a total generating capacity of 364 MW have been converted to burn either propane or No. 2 oil. In addition, twelve combustion turbine units with a total generating capacity of 425 MW can burn natural gas when available. Two additional units will be added in 1997 increasing gas-fired capacity by 240 MW. Over the last five years, No. 2 oil, natural gas and propane accounted for 1.7% of the Company's total burned fuel cost. In 1996, No. 2 oil, natural gas and propane accounted for 1.6% of the Company's total burned fuel cost. The availability and cost of fuel oil could be adversely affected by energy legislation enacted by Congress, disruption of oil or gas supplies, labor unrest and the production, pricing and embargo policies of foreign countries. 4. NUCLEAR. The nuclear fuel cycle requires the mining and milling of uranium ore to provide uranium oxide concentrate (U3O8), the conversion of U3O8 to uranium hexafluoride (UF6), the enrichment of the UF6 and the fabrication of the enriched uranium into fuel assemblies. Existing uranium contracts are expected to supply the necessary nuclear fuel to operate Robinson Unit No. 2 through 1998, Brunswick Unit No. 1 through 1998, Brunswick Unit No. 2 through 1998, and the Harris Plant through 1999. The Company expects to meet its future U3O8 requirements from inventory on hand and amounts received under contract. Although the Company cannot predict the future availability of uranium and nuclear fuel services, the Company does not currently expect to have difficulty obtaining U3O8 and the services necessary for its conversion, enrichment and fabrication into nuclear fuel. For a discussion of the Company's plans with respect to spent fuel storage, see PART I, ITEM 1, "Nuclear Matters," paragraph 2. 5. DOE ENRICHMENT FACILITIES DECONTAMINATION AND DECOMMISSIONING FUND. Under Title XI of the Energy Policy Act of 1992, Public Law 102-486, Congress established a decontamination and decommissioning (D&D) fund for the DOE's gaseous diffusion enrichment plants. Contributions to this fund are being made by U.S. domestic utilities who have purchased enrichment services from DOE since it began sales to non-Department of Defense customers. Each utility's share of the contributions will be based on that utility's past purchases of services as a percentage of all purchases of services by U.S. utilities, with total annual contributions capped at $150 million per year, indexed to inflation, and an overall cap of $2.25 billion over 15 years, also indexed to inflation. The Company has paid approximately $27 million in D&D fees, and expects to pay a cumulative total of approximately $85 million during the period 1992 through 2007. As of December 31, 1996, the Company had a recorded liability of $56.1 million representing the balance of its estimated share of the contributions. The Company is recovering these costs as a component of fuel cost. On or about March 4, 1997, the Company filed a claim with the DOE seeking a refund of part of the price paid by the Company for enrichment services purchased from the DOE in 1993. It is the Company's position that the contract price it paid to DOE in 1993 for uranium purchases included the cost of D&D, and that DOE's collection of 23 additional D&D fees pursuant to the Energy Act resulted in an overpayment of fees by the Company totaling approximately $1.4 million. The Company cannot predict the outcome of this matter. Additionally, on or about March 21, 1997, the Company, along with other entities, filed an administrative claim with the DOE, and a Complaint against the DOE in the United States Court of Federal Claims, Carolina Power & Light Company v. United States, seeking the recovery of approximately $27 million representing D&D assessments paid by the Company, and the elimination of future D&D fund assessments. It is the Company's position that the D&D assessments constitute a breach of contract, a taking of vested contract rights, a violation of property rights, illegal exaction, and a violation of the Fifth Amendment of the United States Constitution. In a similar case, Yankee Atomic Electric Company v, United States (33 Fed.Cl. 580 (Cl.Ct. 1995) the United States Court of Claims found that a portion of the D&D assessments made against Yankee Atomic were unlawful. The government has appealed that case to the District of Columbia Circuit Court of Appeals. The Company cannot predict the outcome of these matters. 6. PURCHASED POWER. The Company purchased 6,792,340 MWh in 1996, 6,974,597 MWh in 1995 and 6,710,346 MWh in 1994 or approximately 12%, 13% and 13%, respectively, of its system energy requirements (including Power Agency) and had available 1,536 MW in 1996, 1,596 MW in 1995 and 2,840 MW in 1994 of firm purchased capacity under contract at the time of peak load. The Company may acquire purchased power capacity in the future to accommodate a portion of its system load needs. OTHER MATTERS _____________ 1. SAFETY INSPECTION REPORTS. On April 3, 1990, the FERC sent a letter to the Company providing comments on its review of the Company's Fifth (1987) Independent Consultant's Safety Inspection Report (required every five years under FERC Regulation 18 CFR Part 12) for the Walters Hydroelectric Project and requesting the Company to undertake certain supplemental analyses and investigations regarding the stability of the dam under extreme and improbable loading conditions. Similar letters were sent by the FERC on May 30, 1990, with respect to the Company's Blewett and Tillery Hydroelectric Plants. With the independent consultant, the Company has begun addressing the issues raised by the FERC and is working with the FERC to complete investigations and analyses with respect to each of these matters. On November 30, 1994, the Company submitted the independent consultant's report to the FERC regarding the stability of the dam at the Walters Project. The independent consultant concluded that the Walters dam has adequate structural stability and reserve capacity to resist both usual and unusual loading conditions without failure and that structural remediation is neither warranted nor recommended. While the Company does not believe that there are any stability concerns that would be cause for any imminent safety concerns, the FERC's review and analysis of the consultant's report are pending. The consultant's final reports regarding the Blewett and Tillery Hydroelectric Plants are not yet completed. Depending on the outcome of these matters, the Company could be required to undertake efforts to enhance the stability of the dams. The cost and need for such efforts have not been determined. The Company cannot predict the outcome of these matters. 2. MARSHALL HYDROELECTRIC PROJECT. On November 21, 1991, the FERC notified the Company that the 5 MW Marshall Hydroelectric Project is no longer exempt from 18 CFR Part 12, Subpart C and D, dam safety regulations and that the plant's regulatory jurisdiction was being transferred from the NCUC to the FERC. This change resulted from updated dambreak flood studies which identified the potential impact on new downstream development, thus indicating the need to reclassify the project from a low hazard to a high hazard classification. In accordance with the change in regulatory jurisdiction, the Company developed an emergency action plan which meets FERC guidelines and engaged its independent consultant to perform a safety inspection. On April 6, 1992 the consultant's safety inspection report was submitted to the FERC for approval. In March 1995 the Company received comments on the report from the FERC. As a result of these comments, and a meeting with FERC officials, the Company was requested to perform further analyses and submit its findings to the FERC. The Company subsequently submitted the first phase of the requested analyses to the FERC by letter dated September 15, 1995. Depending on the outcome of the FERC's review, the Company could be required to undertake 24 efforts to enhance the stability of the Marshall dam and/or powerhouse. The cost and need for such efforts have not been determined. The Company cannot predict the outcome of this matter. 3. STONE CONTAINER DISPUTE. On April 20, 1994, the Company filed a Complaint with the FERC (Docket No. EL-94-62-000 and QF85-102-005) and in the United States District Court for the Eastern District of North Carolina in Raleigh, North Carolina (Civil Action No. 5:94-CV-285-DI) claiming that the rate the Company pays for power it purchases from Stone Container Corporation (Stone Container) is invalid. The Company entered into a twenty-year purchase power agreement with Stone Container in 1984, and in 1987 began receiving power from a cogeneration facility operated by Stone Container in Florence, South Carolina. It is the Company's position that when Stone Container elected to sell the facility's gross output under a "buy all/sell all" option in 1991, the facility lost its status as a "qualified facility" under PURPA and became a public utility. As a result, the contract rate the Company pays for power purchased from the facility is no longer valid, and a just and reasonable rate should be established by the FERC under the Federal Power Act. The Company will continue to purchase electricity from Stone Container at the current contract rate pending the outcome of this dispute. The District Court action has been stayed pending a decision by the FERC. Both parties have submitted briefs in the FERC matter and are awaiting the FERC's decision. The Company cannot predict the outcome of this matter. 4. TAX REFUND DISPUTE. On April 28, 1994, the Company filed a Complaint against the U.S. Government in the United States District Court for the Eastern District of North Carolina in Raleigh, North Carolina (Civil Action No. 5:94-CV-313-BR3) seeking a refund of approximately $188 million representing tax and interest related to depreciation deductions the Internal Revenue Service (IRS) previously disallowed for the years 1986 and 1987 on the Company's Harris Plant. The Company maintains that under applicable laws and regulations the Harris Plant was ready and available for operation in 1986. The IRS has previously denied some of the depreciation deductions on the Company's tax returns for the years in question on the ground that in its view the plant was not placed in service until 1987. On December 19, 1995, the jury returned a verdict in favor of the U. S. Government. The Company has filed an appeal of the jury's verdict. The Company cannot predict the outcome of this matter. 5. CARONET, LLC. On November 29, 1994, the Company established a wholly-owned subsidiary, CaroNet, Inc., (CaroNet), which was reorganized as CaroNet, LLC in 1996. CaroNet owns a ten-percent interest in a regional limited partnership, BellSouth Carolinas PCS, L.P. (Partnership), led by BellSouth Personal Communications, Inc. (BellSouth). On March 14, 1995 BellSouth won its bid for a Federal Communications Commission (FCC) license for the Partnership to operate a Personal Communications Services (PCS) system covering most of North and South Carolina, as well as a small portion of Georgia. PCS, a wireless communications technology, provides high-quality mobile communications. BellSouth is the general partner and handles day-to-day management of the business. In anticipation of infrastructure construction, the Company invested $50 million in CaroNet on April 28, 1995. Construction of the PCS system infrastructure began during the summer of 1995 and by the end of 1996, service was available in all major cities in the Carolinas. The bulk of the infrastructure construction is expected to be completed within two years. CaroNet participates on the Partnership's executive committee. In addition to participating in the Partnership, CaroNet is providing fiber optic network capacity to telecommunications carriers in North and South Carolina. On November 14, 1995, the SCPSC issued an order granting CaroNet permission to provide wholesale services in South Carolina. CaroNet filed an application to provide competing local telephone service and an application to provide intrastate long distance service in North Carolina with the NCUC on September 19, 1996 and September 26, 1996, respectively. 6. CAROHOME, LLC. In 1995, the Company established CaroHome, LLC (CaroHome), a limited-liability company, to further the Company's investments in affordable housing. These investments are designed to earn tax credits while helping communities meet their needs for affordable housing. The Company, primarily through CaroHome, has committed to invest $47 million in affordable housing and anticipates investing up to a total of $125 million in affordable housing by the year 2000. 25 7. CAROCAPITAL, INC. On January 22, 1996, the Company established a wholly-owned subsidiary, CaroCapital, Inc., (CaroCapital), which purchased a minority equity interest in Knowledge Builders, Inc. (KBI), an energy-management software and control systems company. Investments in KBI amounted to $9 million in 1996, with total investment through 2001 anticipated to reach $12 million, subject to the terms and conditions of a Stock Purchase Agreement, which includes certain sales and profitability targets. Although KBI and its subsidiaries will continue to operate independently, CaroCapital has designated two directors who are currently serving on the KBIs' board of directors. 8. HURRICANE DAMAGE. On July 12, 1996, Hurricane Bertha struck the North Carolina coast. Restoration of the Company's system from hurricane-related damage resulted in operation and maintenance expenses of approximately $4 million and capital expenditures of approximately $7 million, which did not have a material impact on the results of operations or financial position of the Company. On September 5, 1996, Hurricane Fran struck significant portions of the Company's service territory. Restoration of the Company's system from hurricane-related damage resulted in operation and maintenance expenses of approximately $40 million and capital expenditures of approximately $55 million. The capital expenditures are related to labor and materials used in replacing destroyed poles, lines and other equipment. The operation and maintenance expenditures are related to repairs of damaged equipment. The Company did not seek a general rate increase to recover the restoration costs. Instead, on September 13, 1996, the Company proposed to the NCUC (Docket No. E-2, Sub 699) a plan that would defer operation and maintenance expenses associated with Hurricane Fran, with amortization over the next three years. By Order dated December 6, 1996, the NCUC authorized the Company to defer operation and maintenance expenses associated with Hurricane Fran, with amortization over a 40-month period beginning in September 1996. See PART I, ITEM 1, "Retail Rate Matters," paragraph 2 for further discussion of the approved plan. 26
OPERATING STATISTICS -------------------- Years Ended December 31 ----------------------- 1996 1995 1994 1993 1992 ---- ---- ---- ---- ---- Energy supply (millions of kWh) Generated - coal 24,859 23,517 21,001 25,807 25,196 nuclear 20,284 19,949 18,511 13,691 11,108 hydro 882 824 884 784 881 combustion turbines 68 56 67 84 54 Purchased 7,292 7,433 7,039 7,110 7,343 ----------- ----------- ----------- ----------- ----------- Total energy supply (Company share) 53,385 51,779 47,502 47,476 44,582 Power Agency share (a) 3,616 3,828 3,236 2,402 2,232 ----------- ----------- ----------- ----------- ----------- Total system energy supply 57,001 55,607 50,738 49,878 46,814 =========== =========== =========== =========== =========== Average fuel cost (per million BTU) Fossil $ 1.75 $ 1.83 $ 1.78 $ 1.75 $ 1.83 Nuclear fuel 0.45 0.46 0.47 0.46 0.45 All fuels 1.14 1.17 1.14 1.28 1.38 Energy sales (millions of kWh) Residential 12,611 12,074 11,147 11,398 10,490 Commercial 9,615 9,276 8,690 8,548 8,060 Industrial 14,456 14,312 14,030 13,557 13,134 Government and municipal 1,263 1,288 1,263 1,248 1,213 Power Agency contract requirements 2,523 2,338 2,589 3,505 3,304 NCEMC 3,947 5,454 4,885 4,778 4,372 Other wholesale 2,014 1,915 1,983 2,144 2,042 Other utilities 4,899 3,233 985 327 214 ----------- ----------- ----------- ----------- ----------- Total energy sales 51,328 49,890 45,572 45,505 42,829 Company uses and losses 2,057 1,889 1,930 1,971 1,753 ----------- ----------- ----------- ----------- ----------- Total energy requirements 53,385 51,779 47,502 47,476 44,582 =========== =========== =========== =========== =========== Customers billed Residential 945,703 920,495 894,616 873,377 856,130 Commercial 167,151 159,064 155,349 151,242 146,858 Industrial 5,066 4,863 4,845 4,825 4,763 Government and municipal 2,774 2,328 2,302 2,214 2,262 Resale 27 17 12 26 26 ----------- ----------- ----------- ----------- ----------- Total customers billed 1,120,721 1,086,767 1,057,124 1,031,684 1,010,039 =========== =========== =========== =========== =========== Operating revenues (in thousands) Residential $ 992,152 $ 969,112 $ 915,986 $ 943,697 $ 871,469 Commercial 627,880 618,394 595,573 592,973 560,560 Industrial 721,588 733,448 741,662 744,016 720,413 Government and municipal 75,391 78,400 78,317 78,616 76,838 Power Agency contract requirements 96,795 100,951 115,262 134,258 140,623 NCEMC 234,653 299,171 266,733 253,859 252,744 Other wholesale 87,463 82,407 84,775 100,062 99,749 Other utilities 105,077 78,147 33,789 11,232 4,834 Miscellaneous revenue 54,716 46,523 44,492 36,670 39,591 ----------- ----------- ----------- ----------- ----------- Total operating revenues $2,995,715 $ 3,006,553 $ 2,876,589 $ 2,895,383 $ 2,766,821 =========== =========== =========== =========== =========== Peak demand of firm load (thousands of kW) System 9,812 10,156 10,144 9,589 9,236 Company 9,264 9,500 9,642 9,107 8,745 Total capability at year-end (thousands of kW) (b) Fossil plants 6,331 6,331 6,331 6,331 6,331 Nuclear plants 3,064 3,064 3,064 3,064 3,064 Hydro plants 218 218 218 218 218 Purchased 1,603 1,592 1,596 1,289 890 ----------- ----------- ----------- ----------- ----------- Total system capability 11,216 11,205 11,209 10,902 10,503 Less Power Agency-owned portion (a) 686 682 654 627 647 ----------- ----------- ----------- ----------- ----------- Total Company capability 10,530 10,523 10,555 10,275 9,856 =========== =========== =========== =========== =========== __________ (a) Net of the Company's purchases from Power Agency. (b) Represents peak generating capability, based on summer peak conditions assuming all generating units are available for operation. Amounts include capacity under contract with cogenerators, small power producers and other utilities. 27
ITEM 2. PROPERTIES __________________ In addition to the major generating facilities listed in PART I, ITEM 1, "Generating Capability," the Company also operates the following plants: Plant Location _____ ________ 1. Walters North Carolina 2. Marshall North Carolina 3. Tillery North Carolina 4. Blewett North Carolina 5. Darlington South Carolina 6. Weatherspoon North Carolina 7. Morehead City North Carolina The Company's sixteen power plants represent a flexible mix of fossil, nuclear and hydroelectric resources, with a total generating capacity (including Power Agency's share) of 9,613 MW. The Company's strategic geographic location facilitates purchases and sales of power with many other electric utilities, allowing the Company to serve its customers more economically and reliably. Major industries in the Company's service area include textiles, chemicals, metals, paper, automotive components and electronic machinery and equipment. At December 31, 1996, the Company had 5,860 pole miles of transmission lines including 292 miles of 500 kV lines and 2,827 miles of 230 kV lines, and distribution lines of approximately 44,312 pole miles of overhead lines and approximately 6,791 miles of underground lines. Distribution and transmission substations in service had a transformer capacity of approximately 36,091 kVA in 2,248 transformers. Distribution line transformers numbered 408,047 with an aggregate 16,697,000 kVA capacity. Power Agency has acquired undivided ownership interests of 18.33% in Brunswick Unit Nos. 1 and 2, 12.94% in Roxboro Unit No. 4, and 16.17% in Harris Unit No. 1 and Mayo Unit No. 1. Otherwise, the Company has good and marketable title to its principal plants and important units, subject to the lien of its Mortgage and Deed of Trust, with minor exceptions, restrictions, and reservations in conveyances, as well as minor defects of the nature ordinarily found in properties of similar character and magnitude. The Company also owns certain easements over private property on which transmission and distribution lines are located. The Company believes that its generating facilities are suitable, adequate, well-maintained, and in good operating condition. Plant Accounts (including nuclear fuel) - During the period January 1, 1992 through December 31, 1996, there was added to the Company's utility plant accounts $1,998,819,677, there was retired $568,063,316 of property and there were transfers to other accounts and adjustments for a net decrease of $21,547,650 resulting in net additions during the period of $1,409,208,711 an increase of approximately 15.66%. ITEM 3. LEGAL PROCEEDINGS _________________________ Legal and regulatory proceedings are included in the discussion of the Company's business in PART I, ITEM 1 and incorporated by reference herein. 28 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ___________________________________________________________ No matters were submitted to a vote of security holders in the fourth quarter of 1996. 29 EXECUTIVE OFFICERS OF THE REGISTRANT ____________________________________ Name Age Recent Business Experience ____ ___ __________________________ Sherwood H. Smith, Jr. 62 Chairman of the Board of Directors, October 1996 to present; Chairman and Chief Executive Officer, September 1992 to October 1996; Chairman/President and Chief Executive Officer, May 1980 to September 1992. Member of the Board of Directors of the Company since 1971. William Cavanaugh III 58 President and Chief Executive Officer, October 1996 to present; President and Chief Operating Officer, September 1992 to October 1996; Group President - Energy Supply, Entergy Corporation, July 1992; Chairman and Chief Executive Officer, System Energy Resources, Inc., April 1992; Chairman and Chief Executive Officer, Entergy Operations, Inc., April 1992; Senior Vice President, System Executive - Nuclear, Entergy Corporation and Entergy Services, Inc., 1987-August 1992; Executive Vice President and Chief Nuclear Officer, Arkansas Power & Light Company and Louisiana Power & Light Company, January 1990-August 1992; President and Chief Executive Officer, System Energy Resources,Inc., 1986-August 1992; President and Chief Executive Officer, Entergy Operations, Inc., June 1990- April 1992. Member of Board of Directors of Arkansas Power & Light Company and Louisiana Power & Light Company, January 1990-August 1992; Member of Board of Directors of System Fuels, Inc., August 1992; Member of Board of Directors of System Energy Resources, Inc., 1986-August 1992; Member of Board of Directors of Entergy Operations, Inc., 1990-August 1992; Member of Board of Directors of Entergy Services, Inc., 1987-August 1992. Before joining the Company, Mr. Cavanaugh held various senior management and executive positions during a 23-year career with Entergy Corporation, an electric utility holding company with operations in Arkansas, Louisiana and Mississippi. Member of the Board of Directors of the Company since 1993. Glenn E. Harder 46 Executive Vice President and Chief Financial Officer, Financial Services, August 1995 to present; Senior Vice President, Group Executive - Financial Services, October 1994 to August 1995; Vice President - Financial Strategies and Treasurer, Entergy Corporation, September 1991 to October 1994; Vice President - Administrative Services & Regulatory Affairs, Entergy Operations, Inc., May 1991 to August 1991; Vice President, Accounting and Treasurer, System Energy Resources, Inc., October 1986 to May 1991. Before joining the Company, Mr. Harder held various senior management and executive positions with Entergy Corporation, an electric utility holding company with operations in Arkansas, Louisiana and Mississippi, and related entities. William S. Orser 52 Executive Vice President and Chief Nuclear Officer, Energy Supply, December 1996 to present; Executive Vice President - Nuclear Generation, April 1993 to December 1996; Executive Vice President - Nuclear 30 Generation, Detroit Edison Company, April 1993; Senior Vice President - Nuclear Generation, Detroit Edison Company, 1990-1992; Vice President - Nuclear Operations, Detroit Edison Company, 1987-1990. Prior to 1987, Mr. Orser held various other positions with Detroit Edison, and with Portland General Electric Company, Southern California Edison, and the U. S. Navy. Roy A. Anderson 48 Senior Vice President, Customer Services, 1996-January 1997(Resigned); Vice President, Fossil Generation, 1995-1996; Vice President, Brunswick Nuclear Power Plant, 1992-1995. James M. Davis, Jr. 60 Senior Vice President, Group Executive - Power Operations, June 1986 to present; Senior Vice President - Operations Support Group, August 1983. Norris L. Edge 65 Senior Vice President, Group Executive - Customer and Operating Services, May 1990 to October 1996 (Retired); Vice President - Rates and Energy Services, September 1989; Vice President - Rates and Service Practices, December 1980. Cecil L. Goodnight 54 Senior Vice President and Chief Administrative Officer, Administrative Services, December 1996 to present; Senior Vice President, Human Resources and Support Services, March 1995- December 1996; Vice President - Human Resources (formerly Employee Relations Department), May 1983 to March 1995. Richard E. Jones 59 Senior Vice President, General Counsel and Secretary, Group Executive - Public and Corporate Relations, November 1990 to April 1996 (Resigned); Vice President, General Counsel and Secretary, November 1989 to November 1990; Vice President and General Counsel, July 1987 to November 1989; Vice President, Senior Counsel and Manager - Legal Department, May 1982. Mark F. Mulhern 37 Vice President and Treasurer, February 1997 to present; Vice President and Controller, March 1996 to February 1997; Vice President of Finance and Treasurer, HYDRA-CO Enterprises, Inc., a subsidiary of Niagara Mohawk Power Corporation, 1994-1996; Director of Finance and Accounting, HYDRA-CO Enterprises, Inc., 1992-1994; Controller, HYDRA-CO Enterprises, Inc., 1991-1992. Prior to 1991, Mr. Mulhern held various positions with the accounting firm of Price Waterhouse & Co. Bonnie V. Hancock 35 Vice President and Controller, February 1997 to present; Manager, Tax Department, September 1995 to February 1997; Director, Corporate Income Tax, Treasury Department, September 1993 to September 1995. Before joining the Company, Ms. Hancock held various management positions in the Tax Department at Potomac Electric Power Company. 31 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS _____________________________________________________________ The Company's Common Stock is listed on the New York and Pacific Stock Exchanges. The high and low sales prices per share, as reported as composite transactions in The Wall Street Journal, and dividends paid are as follows: 1995 High Low Dividends Paid First Quarter $ 28 5/8 $ 26 3/8 $ .440 Second Quarter 30 3/4 26 3/4 .440 Third Quarter 34 29 1/2 .440 Fourth Quarter 34 1/2 32 3/8 .440 1996 High Low Dividends Paid First Quarter $ 38 3/8 $ 34 1/2 $.455 Second Quarter 38 34 7/8 .455 Third Quarter 38 1/4 34 1/8 .455 Fourth Quarter 37 34 1/4 .455 The December 31 closing price of the Company's Common Stock was $34 1/2 in 1995 and $36 1/2 in 1996. As of February 28, 1997, the Company had 76,189 holders of record of Common Stock. On July 13, 1994, the Board of Directors of the Company authorized the repurchase of up to 10 million shares of the Company's Common Stock on the open market. Under this stock repurchase program, the Company purchased approximately 0.7 million shares in 1996, 4.2 million shares in 1995 and 4.4 million shares in 1994. 32
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA - ------- ------------------------------------ The selected consolidated financial data should be read in conjunction with the consolidated financial statements and the notes thereto included elsewhere in this report. Years Ended December 31 ----------------------- 1996 1995 1994 1993 1992 ---- ---- ---- ---- ---- (in thousands except per share data) Operating results Operating revenues $ 2,995,715 $ 3,006,553 $ 2,876,589 $ 2,895,383 $ 2,766,821 Net income $ 391,277 $ 372,604 $ 313,167 $ 346,496 $ 379,635 Earnings for common stock $ 381,668 $ 362,995 $ 303,558 $ 336,887 $ 379,045 Ratio of earnings to fixed charges 4.12 3.67 3.31 3.23 3.34 Per share data Earnings per common share $ 2.66 $ 2.48 $ 2.03 $ 2.10 $ 2.36 Dividends declared per common share $ 1.835 $ 1.775 $ 1.715 $ 1.655 $ 1.595 Financial position Total assets $ 8,369,201 $ 8,227,150 $ 8,211,163 $ 8,194,018 $ 7,706,201 Capitalization Common stock equity $ 2,690,454 $ 2,574,743 $ 2,586,179 $ 2,632,116 $ 2,534,025 Preferred stock - redemption not required 143,801 143,801 143,801 143,801 143,801 Long-term debt, net 2,525,607 2,610,343 2,530,773 2,584,903 2,674,823 ---------- ---------- ---------- ---------- ---------- Total capitalization $ 5,359,862 $ 5,328,887 $ 5,260,753 $ 5,360,820 $ 5,352,649 ========== ========== ========== ========== ========== 33
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS __________________________________________________________ RESULTS OF OPERATIONS _____________________ Revenues ________ Revenue fluctuations as compared to the prior year are due to the following factors (in millions): 1996 1995 Increase Increase (Decrease) (Decrease) Customer growth/changes in usage patterns $ 87 $ 85 Sales to other utilities 34 46 Weather 4 75 NCEMC load loss (96) - Price (36) (62) Sales to Power Agency (4) (14) ____ _____ $(11) $130 ===== ===== Sales to other utilities increased in both comparison periods as a result of the Company's active pursuit of opportunities in the wholesale market. A return of more normal weather in 1995 generated a $75 million increase in revenues as compared to 1994 when the Company's service territory experienced unusually mild weather. Beginning in January 1996, the Company lost 200 megawatts of load from North Carolina Electric Membership Corporation (NCEMC), resulting in a $96 million decrease in revenues. The price-related decrease in 1996 is primarily attributable to a decrease in the fuel cost component of revenue. For 1995 as compared to 1994, approximately half of the price-related decrease was due to a decrease in the fuel cost component of customer rates and approximately half was due to the expiration in July 1994 of a North Carolina rate rider under which the Company was allowed to recover certain abandoned plant costs. The reduction in revenue due to the expiration of the rate rider did not significantly affect net income due to a corresponding decrease in amortization expense. For 1995 as compared to 1994, sales to North Carolina Eastern Municipal Power Agency (Power Agency) decreased due to the increased availability of generating units owned jointly by the Company and Power Agency. Operating Expenses __________________ Fuel expense decreased in 1996 due to renegotiated coal contracts, increased spot market coal purchases and the refunding of over-recovered fuel costs. This decrease more than offset the increase in fuel expense related to a 3.9% increase in generation during 1996. Fuel expense increased in 1995 over 1994 primarily as a result of a 9.6% increase in generation. Purchased power decreased in 1995 as compared to 1994 as a result of a 1993 agreement with Power Agency. Pursuant to this agreement, the Company's buyback percentage of capacity and energy from Power Agency's ownership interest in the Harris Plant decreased from 50% in 1994 to 33% in 1995. This change in buyback percentage reduced purchased power in 1995 by $20 million as compared to 1994. Partially offsetting this decrease in 1995 were increases in purchases from other utilities and cogenerators. Operation and maintenance expenses decreased in 1996 as compared to 1995, continuing a downward trend as a result of the Company's ongoing cost reduction efforts. Partially offsetting this decrease were storm-related expenses of approximately $6 million incurred as a result of severe ice storms experienced in early 1996 and the impact of Hurricane Bertha striking the Company's service territory in July 1996. 34 Operation and maintenance expenses decreased in 1995 primarily due to lower nuclear outage-related expenses. Partially offsetting this decrease was an increase of $13 million in severance-related costs and a 1994 insurance reserve adjustment of $23 million, which reduced expenses in that year. Hurricane Fran struck significant portions of the Company's service territory in September 1996. In December 1996, the North Carolina Utilities Commission (NCUC) authorized the Company to defer operation and maintenance expenses associated with Hurricane Fran. See discussion of Hurricane Fran in Other Matters. The increase in depreciation and amortization expense in 1996 includes amortization of deferred Hurricane Fran costs of approximately $4 million. Depreciation and amortization expense decreased from 1994 to 1995 due to the completion in July 1994 of the amortization of certain abandoned plant costs associated with a North Carolina rate rider and the completion of the amortization of abandoned plant costs for Harris Unit No. 2 in October 1994. Other Income ____________ Other income, net, increased in 1996 primarily due to an adjustment of $22.9 million to the unamortized balance of abandonment costs related to the Harris Plant. See additional discussion of the abandonment adjustment in the Retail Rate Matters section of Other Matters. In 1995, other income, net, decreased due to an increase in charitable contributions of approximately $7 million and decreases in various income items, none of which was individually significant. Interest Charges ________________ Interest charges on long-term debt decreased from 1995 to 1996 primarily due to reductions of long-term debt in 1996. Also contributing to the decrease were refinancings of long-term debt with lower interest cost commercial paper borrowings which are backed by the Company's long-term revolving credit facilities. See discussion of credit facilities in Liquidity and Capital Resources. Other interest charges increased in 1995 primarily due to a $6 million interest accrual recorded in 1995 related to the 1995 NCUC Fuel Order. LIQUIDITY AND CAPITAL RESOURCES _______________________________ Cash Flow and Financing _______________________ The net cash requirements of the Company arise primarily from operational needs and support for investing activities, including replacement or expansion of existing facilities and construction to comply with pollution control laws and regulations. The Company has on file with the Securities and Exchange Commission (SEC) a shelf registration statement under which an aggregate of $450 million principal amount of first mortgage bonds and an additional $125 million combined aggregate principal amount of first mortgage bonds and/or unsecured debt securities of the Company remain available for issuance. The Company can also issue up to $180 million of additional preferred stock under a shelf registration statement on file with the SEC. The Company's ability to issue first mortgage bonds and preferred stock is subject to earnings and other tests as stated in certain provisions of its mortgage, as supplemented, and charter. The Company has the ability to issue an additional $4.3 billion in first mortgage bonds and an additional 29 million shares of preferred stock at an assumed price of $100 per share and a $6.63 annual dividend rate. The Company also has 10 million authorized preference stock shares available for issuance that are not subject to an earnings test. In 1996, the Company entered into two new long-term revolving credit facilities totaling $350 million, which support the Company's commercial paper borrowings. In addition to these new facilities, the Company has other long-term revolving credit agreements totaling $235 million and a $100 million short-term revolving credit agreement. The Company is required to pay minimal annual commitment fees to maintain certain credit facilities. Consistent with management's intent to maintain up to $350 million of its commercial paper on a long-term basis, and as supported by its long-term revolving credit 35 facilities, the Company has included in long-term debt $350 million of commercial paper outstanding as of December 31, 1996. The proceeds from the issuance of commercial paper related to the credit facilities mentioned above, and/or internally generated funds, financed the redemption or retirement of long-term debt totaling $453 million in 1996. External funding requirements, which do not include early redemptions of long-term debt or redemptions of preferred stock, are expected to approximate $161 million in 1998. These funds will be required for construction, mandatory redemptions of long-term debt and general corporate purposes, including the repayment of short-term debt. The Company does not expect to have external funding requirements in 1997 or 1999. The Company's access to outside capital depends on its ability to maintain its credit ratings. The Company's first mortgage bonds are currently rated A2 by Moody's Investors Service, A by Standard & Poor's and A+ by Duff & Phelps. The Company's commercial paper is currently rated P-1, A-1 and D-1 with Moody's Investors Service, Standard & Poor's and Duff & Phelps, respectively. The amount and timing of future sales of Company securities will depend upon market conditions and the specific needs of the Company. The Company may from time to time sell securities beyond the amount needed to meet capital requirements in order to allow for the early redemption of outstanding issues of long-term debt, the redemption of preferred stock, the reduction of short-term debt or for other corporate purposes. In 1994, the Board of Directors of the Company authorized the repurchase of up to 10 million shares of the Company's common stock on the open market. Under this stock repurchase program, the Company purchased approximately 0.7 million shares in 1996, 4.2 million shares in 1995 and 4.4 million shares in 1994. Capital Requirements ____________________ Estimated capital requirements for the period 1997 through 1999 primarily reflect construction expenditures that will be made to meet customer growth by adding generating, transmission and distribution facilities as well as upgrading existing facilities. The Company's capital requirements for those years are reflected in the following table (in millions). 1997 1998 1999 ____ ____ ____ Construction expenditures $ 365 $ 489 $ 401 Nuclear fuel expenditures 78 104 104 AFUDC (12) (20) (23) Mandatory redemptions of long-term debt 103 208 53 ___ ___ ___ Total $ 534 $ 781 $ 535 === === === This table includes Clean Air Act expenditures of approximately $56 million and generating facility addition expenditures of approximately $317 million. The generating facility addition expenditures will primarily be used to construct new combustion turbine units, which are intended for use during periods of high demand. The units are scheduled to be placed in service in 1997 through 2002. The Company has two long-term agreements for the purchase of power from other utilities. The first agreement provides for the purchase of 250 megawatts of capacity through 2009 from Indiana Michigan Power Company's Rockport Unit No. 2. The estimated minimum annual payment for power purchases under this agreement is approximately $30 million, which represents capital-related capacity costs. Other costs include demand-related production expenses, fuel and energy-related operation and maintenance expenses. In 1996, purchases under this agreement totaled $60.9 million, including transmission use charges. The second agreement is with Duke Power Company for the purchase of 400 megawatts of firm capacity through mid-1999. The estimated minimum annual payment for power purchases under this agreement is approximately $43 million, which represents capital-related capacity costs. Other costs include fuel and energy-related operation and maintenance expenses. Purchases under this agreement, including transmission use charges, totaled $65.4 million in 1996. 36 In addition, pursuant to the terms of the 1981 Power Coordination Agreement, as amended, between the Company and Power Agency, the Company is obligated to purchase a percentage of Power Agency's ownership capacity of, and energy from, the Mayo Plant and the Harris Plant through 1997 and 2007, respectively. The estimated minimum annual payments for these purchases, which reflect capital-related capacity costs, total approximately $27 million. Other costs of such purchases are primarily demand-related production expenses and fuel and energy-related operation and maintenance expenses. Purchases under the agreement with Power Agency totaled $36.7 million in 1996. OTHER MATTERS _____________ Retail Rate Matters ____________________ A petition was filed in July 1996 by the Carolina Industrial Group for Fair Utility Rates (CIGFUR) with the NCUC, requesting that the NCUC conduct an investigation of the Company's base rates or treat its petition as a complaint against the Company. This petition alleged that the Company's return on equity, which was authorized by the NCUC in the Company's last general rate proceeding in 1988, and earnings are too high. The Company filed a response to the petition and Motion to Dismiss in July 1996, in which it argued that the petition was without merit. As part of this docket, the Company filed a proposal to accelerate amortization of certain regulatory assets. In addition to proposing accelerated amortization of the regulatory assets, the Company requested approval to defer storm-related operation and maintenance expenses associated with Hurricane Fran. In December 1996, the NCUC approved the Company's proposal to accelerate amortization of certain regulatory assets over a three-year period beginning January 1, 1997. The accelerated amortization of these regulatory assets will reduce income by approximately $43 million, after tax, in each of the next three years. The NCUC also authorized the Company to defer operation and maintenance expenses associated with Hurricane Fran. See discussion of Hurricane Fran below. Additionally, the Company has filed for approval from the South Carolina Public Service Commission (SCPSC) to accelerate amortization of certain regulatory assets, including plant abandonment costs related to the Harris Plant, over a three-year period beginning January 1, 1997. This accelerated amortization will reduce income by approximately $13 million, after tax, in each of the next three years. In anticipation of the approval in 1997, the unamortized balance of plant abandonment costs related to the Harris Plant was adjusted in 1996 to reflect the present value impact of the shorter recovery period. This adjustment resulted in an increase in income of approximately $14 million, after tax, in 1996. On March 4, 1997, the SCPSC approved the implementation of the proposed accounting adjustments. In December 1996, the NCUC issued an order denying CIGFUR's petition and stating that it tentatively finds no reasonable grounds to proceed with CIGFUR's petition as a complaint. On January 10, 1997, CIGFUR filed its Comments and Motion for Reconsideration. On January 23, 1997, the Company filed its response in opposition to CIGFUR's Comments and Motion for Reconsideration. On February 6, 1997, the NCUC issued an order denying CIGFUR's motion for reconsideration. On February 25, 1997, CIGFUR filed a Notice of Appeal of the NCUC's decision with the North Carolina Court of Appeals. The Company cannot predict the outcome of this matter. Hurricane Fran ______________ Hurricane Fran struck significant portions of the Company's service territory on September 5, 1996. Restoration of the Company's system from hurricane-related damage resulted in operation and maintenance expenses of approximately $40 million and capital expenditures of approximately $55 million. In December 1996, the NCUC authorized the Company to defer operation and maintenance expenses associated with Hurricane Fran, with amortization over a 40-month period. Environmental _____________ The Company is subject to federal, state and local regulations addressing air and water quality, hazardous and solid waste management and other environmental matters. Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under various federal and state laws. There are several manufactured gas plant (MGP) sites to which the Company and certain entities that were later merged into the Company had some connection. In this regard, the Company, along with 37 other entities alleged to be former owners and operators of MGP sites in North Carolina, is participating in a cooperative effort with the North Carolina Department of Environment, Health and Natural Resources, Division of Waste Management (DWM), formerly the Division of Solid Waste Management, to establish a uniform framework for addressing these MGP sites. The investigation and remediation of specific MGP sites will be addressed pursuant to one or more Administrative Orders on Consent between the DWM and individual potentially responsible party or parties. The Company continues to investigate the identities of parties connected to individual MGP sites, the relative relationships of the Company and other parties to those sites and the degree to which the Company will undertake shared voluntary efforts with others at individual sites. The Company has been notified by regulators of its involvement or potential involvement in several sites, other than MGP sites, that require remedial action. Although the Company cannot predict the outcome of these matters, it does not expect costs associated with these sites to be material to the results of operations of the Company. The Company continues to carry a liability for the estimated costs associated with certain remedial activities at several MGP and other sites. This liability is not material to the financial position of the Company. Due to uncertainty regarding the extent of remedial action that will be required and questions of liability, the cost of remedial activities at certain MGP sites is not currently determinable. The Company cannot predict the outcome of these matters. The 1990 amendments to the Clean Air Act (Act) require substantial reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fueled electric generating plants. The Company was not required to take action to comply with the Act's Phase I requirements for these emissions, which had to be met by January 1, 1995. Phase II of the Act, which contains more stringent provisions, will become effective January 1, 2000. The Company plans to meet the Phase II sulfur dioxide emissions requirements by the most economical combination of fuel-switching and utilization of sulfur dioxide emission allowances. Each sulfur dioxide emission allowance allows a utility to emit one ton of sulfur dioxide. The Company has purchased emission allowances under the Environmental Protection Agency's (EPA) emission allowance trading program in order to supplement the allowances the EPA has granted to the Company. Installation of additional equipment will be necessary to reduce nitrogen oxide emissions. The Company estimates that future capital costs necessary to comply with Phase II of the Act will approximate $160 million. Increased operation and maintenance costs, including emission allowance expense, and increased fuel costs are not expected to be material to the results of operations of the Company. The EPA has recently proposed revisions to existing air quality standards for Ozone and Particulate Matter. If these standards are finalized as proposed, additional compliance costs will be incurred. As plans for compliance with the Act's requirements are subject to change, the amount required for capital expenditures and for increased operation and maintenance and fuel expenditures cannot be determined with certainty at this time. Nuclear _______ In the Company's retail jurisdictions, provisions for nuclear decommissioning costs are approved by the NCUC and the SCPSC and are based on site-specific estimates that include the costs for removal of all radioactive and other structures at the site. In the wholesale jurisdiction, the provisions for nuclear decommissioning costs are based on amounts agreed upon in applicable rate agreements. Based on the site-specific estimates discussed below, and using an assumed after-tax earnings rate of 8.5% and an assumed cost escalation rate of 4%, current levels of rate recovery for nuclear decommissioning costs are adequate to provide for decommissioning of the Company's nuclear facilities. The Company's most recent site-specific estimates of decommissioning costs were developed in 1993, using 1993 cost factors, and are based on prompt dismantlement decommissioning, which reflects the cost of removal of all radioactive and other structures currently at the site, with such removal occurring shortly after operating license expiration. These estimates, in 1993 dollars, are $257.7 million for Robinson Unit No. 2, $235.4 million for Brunswick Unit No. 1, $221.4 million for Brunswick Unit No. 2 and $284.3 million for the Harris Plant. The estimates are subject to change based on a variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning, and changes in federal, state or local regulations. The cost estimates exclude the portion attributable to Power Agency, which holds an undivided ownership interest in the Brunswick and Harris nuclear generating facilities. Operating licenses for the Company's nuclear units expire in the year 2010 for Robinson Unit No. 2, 2016 for Brunswick Unit No. 1, 2014 for Brunswick Unit No. 2 and 2026 for the Harris Plant. 38 The Financial Accounting Standards Board (the Board) has reached several tentative conclusions with respect to its project regarding accounting practices related to closure and removal of long-lived assets. The primary conclusions as they relate to nuclear decommissioning are: 1) the cost of decommissioning should be accounted for as a liability and accrued as the obligation is incurred; 2) recognition of a liability for decommissioning results in recognition of an increase to the cost of the plant; 3) the decommissioning liability should be measured based on discounted cash flows using a risk-free rate; and 4) decommissioning trust funds should not be offset against the decommissioning liability. It is uncertain what impacts the final statement may ultimately have on the Company's accounting for nuclear decommissioning and other closure and removal costs. The Board has announced that the effective date would be no earlier than 1998. 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. In December of 1996, the DOE notified the Company and other similarly situated utilities that the agency anticipates that it will be unable to begin acceptance of spent nuclear fuel by January 31, 1998. In January of 1997, the Company, together with 35 other utilities, filed a Joint Petition for Review with the United States Court of Appeals requesting that the Court review the final decision of the DOE and the DOE's failure to meet its unconditional obligation under the Nuclear Waste Act.The Company cannot predict whether the DOE will be able to perform its contractual obligations and provide interim storage or permanent disposal repositories for spent nuclear fuel and/or high-level radioactive waste materials on a timely basis. With certain modifications, the Company's spent fuel storage facilities are sufficient to provide storage space for spent fuel generated on the Company's system through the expiration of the current operating licenses for all of the Company's nuclear generating units. Subsequent to the expiration of these licenses, dry storage may be necessary. Other Business ______________ The Company amended electric purchase power agreements related to five plants owned by Cogentrix of North Carolina, Inc., and Cogentrix Eastern Carolina Corporation (collectively referred to as Cogentrix) in 1996. The amendments became effective in late 1996 and permit the Company to dispatch the output of these plants. In return, the Company gave up its right to purchase two of Cogentrix's plants in 1997. As a result of the amended agreements, the Company will save approximately $30 million per year in energy costs during 1997 through 2002. In 1994, the Company established CaroNet, Inc., which was reorganized into CaroNet, LLC in 1996. CaroNet, LLC owns a ten percent interest in BellSouth Carolinas PCS, L.P., a limited partnership led by BellSouth Personal Communications, Inc. (BellSouth). In 1995, BellSouth won its bid for a Federal Communications Commission license for the limited partnership to operate a personal communications services (PCS) system covering most of North Carolina and South Carolina, as well as a small portion of Georgia. PCS, a wireless communications technology, provides high-quality mobile communications. BellSouth is the general partner and handles day-to-day management of the business. The Company invested $50 million in CaroNet, LLC in anticipation of infrastructure construction by BellSouth. Construction began in 1995 and by the end of 1996, service was available in all major cities in the Carolinas. The bulk of infrastructure construction is expected to be completed within two years. In addition to participating in the limited partnership, CaroNet, LLC is providing fiber optic network capacity to telecommunications carriers in North Carolina and South Carolina. In 1995, the Company established CaroHome, LLC, a limited-liability company, to further the Company's investments in affordable housing. These investments are designed to earn tax credits while helping communities meet the needs for affordable housing. The Company, principally through CaroHome, LLC, has committed to invest $47 million in affordable housing and anticipates investing up to a total of $125 million in affordable housing by the year 2000. In 1996, the Company established a wholly owned subsidiary, CaroCapital, Inc., which purchased a minority equity interest in Knowledge Builders, Inc. (KBI), an energy-management software and control systems company. Investments in KBI amounted to $9 million in 1996 with anticipation of total investment through 2001 reaching $12 million, subject to the terms and conditions of a Stock Purchase Agreement, which includes certain sales and profitability targets. Competition ___________ In 1992, the National Energy Policy Act (Energy Act) changed certain underlying federal policies governing wholesale generation and the sale of electric power. In effect, the Energy Act partially deregulated the wholesale electric utility 39 industry at the generation level by allowing non-utility generators to build and own generating plants for both cogeneration and sales to utilities. Provisions of the Energy Act that most affected the utility industry were the establishment of exempt wholesale generators, and the authority given the Federal Energy Regulatory Commission (FERC) to mandate wholesale transfer, or wheeling, of power over the transmission lines of other utilities. Since the Energy Act was passed, competition in the wholesale electric utility industry has increased due to greater participation by traditional electricity suppliers and by non-traditional electricity suppliers, such as wholesale power marketers and brokers, and by the trading of energy futures contracts on commodities exchanges such as the New York Mercantile Exchange and the Kansas City Board of Trade. This increased competition could impact the Company's load forecasts, plans for power supply and wholesale energy sales and related revenues. The impact could vary depending on the extent to which additional generation is built to compete in the wholesale market, new opportunities are created for the Company to expand its wholesale load or current wholesale customers elect to purchase from other suppliers after existing contracts expire. If the Company is not able to recover lost revenues associated with any lost loads, there could be an adverse impact on the Company's financial condition. In early 1996, the FERC issued regulations for wholesale wheeling of electric power through its rules on open access transmission and stranded costs and on information systems and standards of conduct (Orders 888 and 889). The rules require all transmitting utilities to have on file an open access transmission tariff, which should contain provisions for the recovery of stranded costs. The rules also contain numerous other items that could impact the sale of electric energy at the wholesale level. The Company filed its open access transmission tariff with the FERC in mid-1996. Shortly thereafter, Power Agency filed with the FERC a Motion to Intervene and Protest concerning the Company's tariff. Other entities also filed protests. These protests challenge numerous aspects of the Company's tariff and request that an evidentiary proceeding be held. The FERC set the matter for hearing and set a discovery and procedural schedule. The Company, the FERC staff and most of the parties have agreed on a settlement-in-principle, and by order dated January 16, 1997, the administrative law judge suspended the procedural schedule until April 17, 1997, pending a final settlement of the case. The Energy Act prohibits the FERC from ordering retail wheeling transmitting power on behalf of another producer to an individual retail customer. Some states have changed or are considering changing their laws or regulations, or instituting experimental programs, to allow retail electric customers to buy power from suppliers other than the local utility. These changes or proposals elsewhere have taken differing forms and included disparate elements. The Company believes changes in existing laws in both North Carolina and South Carolina would be required to permit retail competition in the Company's retail jurisdictions. In 1995, the Carolina Utility Consumers Association, Inc., a group of industrial customers conducting business in North Carolina, filed a petition with the NCUC requesting that the NCUC hold a generic hearing to investigate retail electric competition. The NCUC ruled that it would not convene a formal hearing to investigate the issue at that time. The NCUC's order noted that North Carolina's territorial assignment statute appears to prohibit retail competition, and the issue involves a number of jurisdictional uncertainties. Both the NCUC and the SCPSC indicated that they would monitor other states' activities regarding generation competition and allow interested parties to submit information on the subject. In April 1996, the NCUC issued an order seeking comments regarding the impact of retail competition on system reliability, obligation to serve and stranded and ancillary costs. However, in May 1996, the NCUC issued an order which stated that FERC Orders 888 and 889 essentially restructure the wholesale electric utility industry, and therefore may provide a new focus for NCUC proceedings with respect to competition in the electric industry. As a result, the NCUC concluded that all parties should concentrate their efforts on examining the impacts of the FERC orders and that the filing of comments requested by the NCUC's April 1996 order should be extended indefinitely. The NCUC also concluded that this docket should be held in abeyance pending further order. The Company cannot predict the outcome of the current debate regarding retail wheeling; however, the implications of retail wheeling on competition and the Company's financial condition could be of a significantly greater magnitude than those associated with wholesale wheeling, as discussed above. On January 29, 1997, representatives of both houses of the North Carolina General Assembly filed bills calling for the establishment of a commission, comprised of representatives from retail customers, electric companies and other interested parties. The commission would be expected to file a report with the 1999 North Carolina General Assembly that would examine the numerous components of the electric industry and the implications of making changes. On February 6, 1997, representatives in the South Carolina General Assembly introduced a bill calling for a transition to full competition in the electric utility industry beginning in 1998. The Company cannot predict the outcome of these matters. Several pieces of legislation that concern the issue of retail competition were introduced in Congress in 1996. One bill mandated retail wheeling in all 50 states no later than December 15, 2000. As proposed, this bill would require states to give all customers the right to choose their electric supplier. If this choice were not implemented by the states, the bill 40 proposes that the FERC would be responsible for the implementation. The other bills had various provisions concerning retail competition and related topics. The Company anticipates that this issue will continue to be debated by Congress during 1997. The Company cannot predict the outcome of these matters. The issues described above have created greater planning uncertainty and risks for the Company. The Company has been addressing these risks in the wholesale sector by securing long-term contracts with all of its wholesale customers, representing approximately 14% of the Company's 1996 operating revenue. These long-term contracts will allow the Company flexibility in managing its load and efficiently planning its future resource requirements. In the industrial sector, the Company is continuing to work to meet the energy needs of its customers. Other elements of the Company's strategy to respond to the changing market for electricity include promoting economic development, implementing new marketing strategies, improving customer satisfaction, increasing the focus on managing and reducing costs and, consequently, avoiding future rate increases. In 1994, NCEMC issued two requests for proposals (RFPs) to provide up to 675 MW of baseload power, which was being purchased from the Company under the existing 1994 Power Coordination Agreement (PCA), in blocks of up to 225 MW (for a minimum of ten years each) beginning in 2001, 2002 and 2003. The Company responded to the RFPs and negotiations the parties concerning power supply options continued for several months. As a result of these negotiations, in late 1996, the Company and NCEMC entered into a revised PCA under which NCEMC will receive discounted capacity in exchange for long-term commitments to the Company for its supplemental power. As a result of this revised agreement, the Company has extended beyond 2000 the terms of existing capacity agreements to supply 225 MW from 2000 through 2010, an additional block of 225 MW from 2001 through 2004, and a third block of 225 MW from 2002 through 2008. The remainder of the NCEMC capacity provided by the Company, not separately contracted for in the revised agreement, will be billed at fixed rates through the year 2003, rather than at the formula rates established in the original PCA. The FERC has accepted the revised PCA. When NCEMC seeks future supplies, the Company will respond and expects to remain competitive in the pursuit and retention of wholesale load. In August 1996, Power Agency notified the Company of its intention to discontinue certain contractual purchases of power from the Company effective September 1, 2001. Power Agency's notice indicated that it intends to replace these contractual obligations through purchases of capacity and energy and related services in the open market, and that the Company will be considered as a potential supplier for those purchases. Under the 1981 Power Coordination Agreement, as amended, between the Company and Power Agency, Power Agency can reduce its purchases from the Company with an appropriate five-year notice. The Company and Power Agency are currently discussing the sufficiency of the August 1996 notice. The Company cannot predict the outcome of this matter. Under Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation," (SFAS-71), a utility defers certain costs of providing services if the rates established by its regulators are designed to recover those costs and the economic environment gives reasonable assurance that those rates can be charged and collected from customers. The continued applicability of SFAS-71 will require further evaluation as competitive forces, deregulation and restructuring take effect in the electric utility industry. In the event the Company discontinued the application of SFAS-71, amounts recorded under SFAS-71 as regulatory assets and liabilities, would be eliminated. Additionally, the factors discussed above could also result in an impairment of electric utility plant assets as determined pursuant to Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." 41 ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA _________________________________________________________________ The following consolidated financial statements, supplementary data and consolidated financial statement schedules are included herein: Page(s) Independent Auditors' Report 43 Consolidated Financial Statements: Consolidated Statements of Income for the Years Ended December 31, 1996, 1995 and 1994 44 Consolidated Statements of Cash Flows for the Years Ended December 31, 1996, 1995 and 1994 45 Consolidated Balance Sheets as of December 31, 1996 and 1995 46-47 Consolidated Schedules of Capitalization as of December 31, 1996 and 1995 48 Consolidated Statements of Retained Earnings for the Years Ended December 31, 1996, 1995 and 1994 49 Consolidated Quarterly Financial Data (Unaudited) 49 Notes to Consolidated Financial Statements 50-61 Consolidated Financial Statement Schedules for the Years Ended December 31, 1996, 1995 and 1994: II- Valuation and Qualifying Accounts 52-64 All other schedules have been omitted as not applicable or not required or because the information required to be shown is included in the Consolidated Financial Statements or the accompanying Notes to Consolidated Financial Statements. 42 INDEPENDENT AUDITORS' REPORT To the Board of Directors and Shareholders of Carolina Power & Light Company We have audited the accompanying consolidated balance sheets and schedules of capitalization of Carolina Power & Light Company and subsidiaries as of December 31, 1996 and 1995, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1996. Our audits also included the financial statement schedules listed in the Index at Item 8. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Carolina Power & Light Company and subsidiaries at December 31, 1996 and 1995, and the results of their operations and their 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 financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein. We have also previously audited, in accordance with generally accepted auditing standards, the consolidated balance sheets and schedules of capitalization as of December 31, 1994, 1993 and 1992, and the related consolidated statements of income, retained earnings and cash flows for the years ended December 31, 1996 and 1992 (none of which are presented herein); and we expressed unqualified opinions on those financial statements. In our opinion, the information set forth in the selected financial data for each of the five years in the period ended December 31, 1996, appearing at Item 6, is fairly presented in all material respects in relation to the consolidated financial statements from which it has been derived. \s\ DELOITTE & TOUCHE LLP Raleigh, North Carolina February 10, 1997 43
CONSOLIDATED STATEMENTS OF INCOME Years ended December 31 (In thousands except per share data) 1996 1995 1994 - -------------------------------------------------------------------------------------------------------------------------------- Operating revenues $ 2,995,715 $ 3,006,553 $2,876,589 - -------------------------------------------------------------------------------------------------------------------------------- Operating expenses Fuel 515,050 529,812 510,138 Purchased Power 412,554 409,940 414,300 Other operation and maintenance 730,140 738,031 746,692 Depreciation and amortization 386,927 364,527 397,735 Taxes other than on income 140,479 144,043 138,540 Income tax expense 269,763 259,224 198,535 Harris Plant deferred costs, net 26,715 28,128 26,329 - -------------------------------------------------------------------------------------------------------------------------------- Total operating expenses 2,481,628 2,473,705 2,432,269 - -------------------------------------------------------------------------------------------------------------------------------- Operating income 514,087 532,848 444,320 - -------------------------------------------------------------------------------------------------------------------------------- Other income Allowance for equity funds used during construction 11 3,350 6,074 Income tax credit 13,847 18,541 9,425 Harris Plant carrying costs 7,299 8,297 9,754 Interest income 4,063 8,680 14,569 Other income, net (Note 6) 37,340 9,063 25,592 - -------------------------------------------------------------------------------------------------------------------------------- Total other income 62,560 47,931 65,414 - -------------------------------------------------------------------------------------------------------------------------------- Income before interest charges 576,647 580,779 509,734 - -------------------------------------------------------------------------------------------------------------------------------- Interest charges Long-term debt 172,622 187,397 183,891 Other interest charges 19,155 25,896 16,119 Allowance for borrowed funds used during construction (6,407) (5,118) (3,443) - --------------------------------------------------------------------------------------------------------------------------------- Total interest charges, net 185,370 208,175 196,567 - --------------------------------------------------------------------------------------------------------------------------------- Net income 391,277 372,604 313,167 - --------------------------------------------------------------------------------------------------------------------------------- Preferred stock dividend requirements (9,609) (9,609) (9,609) - --------------------------------------------------------------------------------------------------------------------------------- Earnings for common stock $ 381,668 $ 362,995 $ 303,558 - --------------------------------------------------------------------------------------------------------------------------------- Average common shares outstanding (Notes 5 and 7) 143,621 146,232 149,614 - --------------------------------------------------------------------------------------------------------------------------------- Earnings per common share $ 2.66 $ 2.48 $ 2.03 - --------------------------------------------------------------------------------------------------------------------------------- Dividends declared per common share $ 1.835 $ 1.775 $ 1.715 - --------------------------------------------------------------------------------------------------------------------------------- 44
CONSOLIDATED STATEMENT OF CASH FLOWS Years ended December 31 (In thousands) 1996 1995 1994 - --------------------------------------------------------------------------------------------------------- Operating activities Net income $ 391,277 $ 372,604 $ 313,167 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 446,508 446,662 473,481 Harris Plant deferred costs 19,416 19,831 16,575 Deferred income taxes 130,818 89,681 37,240 Investment tax credit (10,445) (9,344) (11,537) Allowance for equity funds used during construction (11) (3,350) (6,074) Deferred fuel cost (credit) (23,156) (849) 38,171 Net increase in receivables,inventories and prepaid expens (64,793) (77,849) (73,891) Net increase(decrease)in payables and accrued expenses 8,365 (39,592) (46,771) Miscellaneous 64,852 35,629 (4,935) - --------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 962,831 833,423 735,426 - --------------------------------------------------------------------------------------------------------- Investing activities Gross property additions (369,308) (266,400) (274,777) Nuclear fuel additions (87,265) (77,346) (25,849) Contributions to external decommissioning trust (30,683) (38,075) (21,625) Contributions to retiree benefit trusts (24,700) (2,400) (18,917) Allowance for equity funds used during construction 11 3,350 6,074 Miscellaneous (28,046) (28,515) (6,094) - --------------------------------------------------------------------------------------------------------- Net cash used in investing activities (539,991) (409,386) (341,188) - --------------------------------------------------------------------------------------------------------- Financing activities Proceeds from issuance of long-term debt (Note 3) 350,000 180,713 318,211 Net increase (decrease) in short-term notes payable (8,858) 5,643 (7,900) Retirement of long-term debt (467,810) (276,144) (268,380) Purchase of Company common stock (Note 5) (28,902) (132,439) (114,717) Dividends paid on common stock (261,204) (257,937) (255,206) Dividends paid on preferred stock (9,614) (9,623) (9,614) - --------------------------------------------------------------------------------------------------------- Net cash used in financing activities (426,388) (489,787) (337,606) - --------------------------------------------------------------------------------------------------------- Net increase (decrease) in cash and cash equivalents (3,548) (65,750) 56,632 - --------------------------------------------------------------------------------------------------------- Cash and cash equivalents at beginning of year 14,489 80,239 23,607 - --------------------------------------------------------------------------------------------------------- Cash and cash equivalents at end of year $ 10,941 $ 14,489 $ 80,239 ========================================================================================================= Supplemental disclosures of cash flow information Cash paid during the year - interest $ 194,391 $ 203,296 $ 188,754 income taxes $ 141,350 $ 177,163 $ 180,759 45
CONSOLIDATED BALANCE SHEETS Assets December 31 (In thousands) 1996 1995 - ------------------------------------------------------------------------------------- Electric utility plant Electric utility plant in service $ 9,783,442 $ 9,440,442 Accumulated depreciation (3,796,645) (3,493,153) - ------------------------------------------------------------------------------------- Electric utility plant in service, net 5,986,797 5,947,289 Held for future use 12,127 13,304 Construction work in progress 196,623 179,260 Nuclear fuel, net of amortization 204,372 188,655 - ------------------------------------------------------------------------------------- Total electric utility plant, net 6,399,919 6,328,508 - ------------------------------------------------------------------------------------- Current assets Cash and cash equivalents 10,941 14,489 Accounts receivable 384,318 364,536 Fuel 60,369 53,654 Materials and supplies 122,809 121,227 Prepayments 65,794 59,918 Other current assets 27,808 27,834 - ------------------------------------------------------------------------------------- Total current assets 672,039 641,658 - ------------------------------------------------------------------------------------- Deferred debits and other assets (Note 6) Income taxes recoverable through future rates 384,336 387,150 Abandonment costs 65,863 57,120 Harris Plant deferred costs 83,397 107,992 Unamortized debt expense 69,956 58,404 Miscellaneous other property and investments 489,334 475,564 Other assets and deferred debits 204,357 170,754 - ------------------------------------------------------------------------------------- Total deferred debits and other assets 1,297,243 1,256,984 - ------------------------------------------------------------------------------------- Total assets $ 8,369,201 $ 8,227,150 - ------------------------------------------------------------------------------------- See notes to consolidated financial statements. 46
CONSOLIDATED BALANCE SHEETS (continued) Capitalization and liabilities December 31 (In thousands) 1996 1995 - -------------------------------------------------------------------------------------- Capitalization (see consolidated schedules of capitalization) Common stock equity $ 2,690,454 $ 2,574,743 Preferred stock - redemption not required 143,801 143,801 Long-term debt, net 2,525,607 2,610,343 - -------------------------------------------------------------------------------------- Total capitalization 5,359,862 5,328,887 - -------------------------------------------------------------------------------------- Current liabilities Current portion of long-term debt 103,345 105,755 Notes payable (principally commercial paper) 64,885 73,743 Accounts payable 375,216 309,294 Interest accrued 39,436 48,441 Dividends declared 73,469 71,285 Deferred fuel credit 4,339 27,495 Other current liabilities 74,668 81,676 - -------------------------------------------------------------------------------------- Total current liabilities 735,358 717,689 - -------------------------------------------------------------------------------------- Deferred credits and other liabilities Accumulated deferred income taxes 1,827,693 1,716,835 Accumulated deferred investment tax credits 232,262 242,707 Other liabilities and deferred credits 214,026 221,032 - -------------------------------------------------------------------------------------- Total deferred credits and other liabilities 2,273,981 2,180,574 - -------------------------------------------------------------------------------------- Commitments and contingencies (Note 11) Total capitalization and liabilities $ 8,369,201 $ 8,227,150 - -------------------------------------------------------------------------------------- See notes to consolidated financial statements. 47
CONSOLIDATED SCHEDULES OF CAPITALIZATION December 31 (Dollars in thousands except per share data) 1996 1995 - --------------------------------------------------------------------------------------------------------------------------------- Common stock equity Common stock without par value, 200,000,000 shares authorized; outstanding, 151,415,722 shares at December 31, 1996 and 152,102,922 at December 31, 1995 (Note 5) $ 1,366,100 $ 1,381,496 Unearned ESOP common stock (Note 7) (178,514) (191,341) Capital stock issuance expense (790) (790) Retained earnings (Note 5) 1,503,658 1,385,378 - --------------------------------------------------------------------------------------------------------------------------------- Total common stock equity $ 2,690,454 $ 2,574,743 - --------------------------------------------------------------------------------------------------------------------------------- Cumulative preferred stock, without par value (entitled to $100 a share plus accumulated dividends in the event of liquidation; outstanding shares are as of December 31, 1996) Preferred stock - redemption not required: Authorized - 300,000 shares $5.00 Preferred Stock; 20,000,000 shares Serial Preferred Stock $ 5.00 Preferred - 237,259 shares outstanding (redemption price $110.00) $ 24,376 $ 24,376 4.20 Serial Preferred - 100,000 shares outstanding (redemption price $102.00) 10,000 10,000 5.44 Serial Preferred - 250,000 shares outstanding (redemption price $101.00) 25,000 25,000 7.95 Serial Preferred - 350,000 shares outstanding (redemption price $101.00) 35,000 35,000 7.72 Serial Preferred - 500,000 shares outstanding (redemption price $101.00) 49,425 49,425 - --------------------------------------------------------------------------------------------------------------------------------- Total preferred stock - redemption not required $ 143,801 $ 143,801 - --------------------------------------------------------------------------------------------------------------------------------- Long-term debt (interest rates are as of December 31, 1996) First mortgage bonds: 5.125% due 1996 $ - $ 30,000 6.375% due 1997 40,000 40,000 5.375% and 6.875% due 1998 140,000 140,000 6.125% due 2000 150,000 150,000 6.750% due 2002 100,000 100,000 7.750% to 8.125% due 2003 - 122,626 5.875% and 7.875% due 2004 300,000 300,000 6.875% to 9.00% due 2021 - 2023 500,000 725,000 First mortgage bonds - secured medium-term notes: 4.85% and 7.90% due 1996 - 75,000 7.75% due 1997 60,000 60,000 5.00% and 5.06% due 1998 65,000 65,000 7.15% due 1999 50,000 50,000 First mortgage bonds - pollution control series: 6.30% to 6.90% due 2009 - 2014 93,530 93,530 3.60% due 2024 122,600 122,600 - --------------------------------------------------------------------------------------------------------------------------------- Total first mortgage bonds 1,621,130 2,073,756 - --------------------------------------------------------------------------------------------------------------------------------- Other long-term debt: Pollution control obligations backed by letter of credit, 3.57% to 5.05% due 2014 - 2017 442,000 442,000 Other pollution control obligations, 4.25% due 2019 55,640 55,640 Unsecured subordinated debentures, 8.55% due 2025 125,000 125,000 Commercial paper reclassified to long-term debt (Note 3) 350,000 - Miscellaneous notes 56,858 48,157 - --------------------------------------------------------------------------------------------------------------------------------- Total other long-term debt 1,029,498 670,797 - --------------------------------------------------------------------------------------------------------------------------------- Unamortized premium and discount, net (21,675) (28,455) Current portion of long-term debt (103,346) (105,755) - --------------------------------------------------------------------------------------------------------------------------------- Total long-term debt, net $ 2,525,607 $ 2,610,343 - --------------------------------------------------------------------------------------------------------------------------------- Total capitalization $ 5,359,862 $ 5,328,887 - --------------------------------------------------------------------------------------------------------------------------------- See notes to consolidated financial statements. 48
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS Years ended December 31 (In thousands) 1996 1995 1994 - ------------------------------------------------------------------------------------------------------------------------------- Retained earnings at beginning of year $ 1,385,378 $ 1,280,960 $ 1,231,354 Net income 391,277 372,604 313,167 Preferred stock dividends at stated rates (9,609) (9,609) (9,609) Common stock dividends at annual rate of $1.835 per share in 1996, $1.775 in 1995 and $1.715 in 1994 (Note 5) (263,388) (258,577) (256,021) Other adjustments - - 2,069 - ------------------------------------------------------------------------------------------------------------------------------- Retained earnings at end of year $ 1,503,658 $ 1,385,378 $ 1,280,960 - -------------------------------------------------------------------------------------------------------------------------------
CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED) First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands except per share data) 1996 1995 1996 1995 1996 1995 1996 1995 - ------------------------------------------------------------------------------------------------------------------------------- Operating revenues $ 783,585 $ 728,238 $ 685,968 $ 681,965 $ 831,590 $ 875,500 $ 694,572 $ 720,850 Operating income $ 154,428 $ 136,259 $ 94,966 $ 93,426 $ 164,125 $ 194,440 $ 100,568 $ 108,723 Net income $ 118,346 $ 98,033 $ 62,656 $ 55,962 $ 129,159 $ 151,905 $ 81,116 $ 66,704 Common stock data: Earnings per common share $ .81 $ .65 $ .42 $ .36 $ .88 $ 1.02 $ .55 $ .45 Dividend paid per common share $ .455 $ .440 $ .455 $ .440 $ .455 $ .440 $ .455 $ .440 Price per share - high $ 38 3/8 $ 28 5/8 $ 38 $ 30 3/4 $ 38 1/4 $ 34 $ 37 $ 34 1/2 low $ 34 1/2 $ 26 3/8 $ 34 7/8 $ 26 3/4 $ 34 1/8 $ 29 1/2 $ 34 1/4 $ 32 3/8 See notes to consolidated financial statements. 49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION The Company is a public service corporation primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. The accounting records of the Company are maintained in accordance with uniform systems of accounts prescribed by the Federal Energy Regulatory Commission (FERC), the North Carolina Utilities Commission (NCUC) and the South Carolina Public Service Commission (SCPSC). Certain amounts for 1995 and 1994 have been reclassified to conform to the 1996 presentation, with no effect on previously reported net income or common stock equity. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. Principles of Consolidation The consolidated financial statements include the activities of the Company's wholly owned subsidiaries. These subsidiaries have investments in areas such as communications technology, energy-management software and affordable housing. Significant intercompany balances and transactions have been eliminated. B. Use of Estimates and Assumptions In preparing financial statements that conform with generally accepted accounting principles, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and amounts of revenues and expenses reflected during the reporting period. Actual results could differ from those estimates. C. Electric Utility Plant The cost of additions, including betterments and replacements of units of property, is charged to electric utility plant. Maintenance and repairs of property, and replacements and renewals of items determined to be less than units of property, are charged to maintenance expense. The cost of units of property replaced, renewed or retired, plus removal or disposal costs, less salvage, is charged to accumulated depreciation. Generally, electric utility plant other than nuclear fuel is subject to the lien of the Company's mortgage. The balances of electric utility plant in service at December 31 are listed below (in millions). 1996 1995 --------- --------- Production plant $ 6,161.4 $ 6,014.1 Transmission plant 940.0 912.7 Distribution plant 2,178.6 2,037.6 General plant and other 503.4 476.0 --------- --------- Electric utility plant in service $ 9,783.4 $ 9,440.4 ========= ========= As prescribed in regulatory uniform systems of accounts, an allowance for the cost of borrowed and equity funds used to finance electric utility plant construction (AFUDC) is charged to the cost of plant. Regulatory authorities consider AFUDC an appropriate charge for inclusion in the Company's utility rates to customers over the service life of the property. The equity funds portion of AFUDC is credited to other income and the borrowed funds portion is credited to interest charges. The composite AFUDC rate was 5.8% in 1996, 8.0% in 1995 and 8.4% in 1994. 50 D. Depreciation and Amortization For financial reporting purposes, depreciation of utility plant other than nuclear fuel is computed on the straight-line method based on the estimated remaining useful life of the property, adjusted for estimated net salvage. Depreciation provisions, including decommissioning costs (see Note 1E), as a percent of average depreciable property other than nuclear fuel, were approximately 3.9% in 1996 and 3.8% in 1995 and 1994. Depreciation expense totaled $363.2 million in 1996, $344.0 million in 1995 and $335.1 million in 1994. Depreciation and amortization expense also includes amortization of plant abandonment costs (see Note 6C) and amortization of hurricane-related deferred costs (see Note 6D). Amortization of nuclear fuel costs, including disposal costs associated with obligations to the U.S. Department of Energy (DOE), is computed primarily on the unit-of-production method and charged to fuel expense. Costs related to obligations to the DOE for the decommissioning and decontamination of enrichment facilities are also charged to fuel expense. E. Nuclear Decommissioning In the Company's retail jurisdictions, provisions for nuclear decommissioning costs are approved by the NCUC and the SCPSC and are based on site-specific estimates that include the costs for removal of all radioactive and other structures at the site. In the wholesale jurisdiction, the provisions for nuclear decommissioning costs are based on amounts agreed upon in applicable rate agreements. Decommissioning cost provisions, which are included in depreciation and amortization, were $33.1 million in 1996, $31.2 million in 1995 and $29.5 million in 1994. Accumulated decommissioning costs, which are included in accumulated depreciation, were $326.0 million at December 31, 1996, and $288.4 million at December 31, 1995. These costs include amounts retained internally and amounts funded in an external decommissioning trust. The balance of the external decommissioning trust, which is included in miscellaneous other property and investments, totaled $145.3 million at December 31, 1996, and $110.2 million at December 31, 1995. Trust earnings, which increase the trust balance with a corresponding increase in accumulated decommissioning, were $4.5 million in 1996 and 1995 and $1.5 million in 1994. Based on the site-specific estimates discussed below, and using an assumed after-tax earnings rate of 8.5% and an assumed cost escalation rate of 4%, current levels of rate recovery for nuclear decommissioning costs are adequate to provide for decommissioning of the Company's nuclear facilities. The Company's most recent site-specific estimates of decommissioning costs were developed in 1993, using 1993 cost factors, and are based on prompt dismantlement decommissioning, which reflects the cost of removal of all radioactive and other structures currently at the site, with such removal occurring shortly after operating license expiration. These estimates, in 1993 dollars, are $257.7 million for Robinson Unit No. 2, $235.4 million for Brunswick Unit No. 1, $221.4 million for Brunswick Unit No. 2 and $284.3 million for the Harris Plant. The estimates are subject to change based on a variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning, and changes in federal, state or local regulations. The cost estimates exclude the portion attributable to North Carolina Eastern Municipal Power Agency (Power Agency), which holds an undivided ownership interest in the Brunswick and Harris nuclear generating facilities. Operating licenses for the Company's nuclear units expire in the year 2010 for Robinson Unit No. 2, 2016 for Brunswick Unit No. 1, 2014 for Brunswick Unit No. 2 and 2026 for the Harris Plant. The Financial Accounting Standards Board (the Board) has reached several tentative conclusions with respect to its project regarding accounting practices related to closure and removal of long-lived assets. The primary conclusions as they relate to nuclear decommissioning are: 1) the cost of decommissioning should be accounted for as a liability and accrued as the obligation is incurred; 2) recognition of a liability for decommissioning results in recognition of an increase to the cost of the plant; 3) the decommissioning liability should be measured based on discounted cash flows using a risk-free rate; and 4) decommissioning trust funds should not be offset against the decommissioning liability. It is uncertain what impacts the 51 final statement may ultimately have on the Company's accounting for nuclear decommissioning and other closure and removal costs. The Board has announced that the effective date would be no earlier than 1998. F. Other Policies Customers' meters are read and bills are rendered on a cycle basis. Revenues are accrued for services rendered but unbilled at the end of each accounting period. Fuel expense includes fuel costs or recoveries that are deferred through fuel clauses established by the Company's regulators. These clauses allow the Company to recover fuel costs and the fuel component of purchased power costs through the fuel component of customer rates. Other property and investments are stated principally at cost. The Company maintains an allowance for doubtful accounts receivable, which totaled $3.7 million at December 31, 1996, and $2.3 million at December 31, 1995. Fuel inventory and materials and supplies inventory are carried on a first-in, first-out or average cost basis. Long-term debt premiums, discounts and issuance expenses are amortized over the life of the related debt using the straight-line method. Any expenses or call premiums associated with the reacquisition of debt obligations are amortized over the remaining life of the original debt using the straight-line method (see Note 6B). For purposes of the Consolidated Statements of Cash Flows, the Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. 3. SHORT-TERM NOTES AND REVOLVING CREDIT FACILITIES At December 31, 1996, and 1995, the Company's short-term debt balances were $64.9 million and $73.7 million, respectively. Additionally, at December 31, 1996, the Company had $350 million of commercial paper classified as long-term debt (see below). The weighted-average interest rates of these borrowings were 5.41% at December 31, 1996, and 5.86% at December 31, 1995. In 1996, the Company entered into two new long-term revolving credit facilities totaling $350 million, which support the Company's commercial paper borrowings. In addition to these new facilities, the Company has other long-term revolving credit agreements totaling $235 million and a $100 million short-term revolving credit agreement. The Company is required to pay minimal annual commitment fees to maintain certain credit facilities. Consistent with management's intent to maintain up to $350 million of its commercial paper on a long-term basis, and as supported by its long-term revolving credit facilities, the Company has included in long-term debt $350 million of commercial paper outstanding as of December 31, 1996. 4. FAIR VALUE OF FINANCIAL INSTRUMENTS The carrying amounts of cash and cash equivalents and notes payable approximate fair value due to the short maturities of these instruments. The carrying amount of the Company's long-term debt was $2.67 billion at December 31, 1996, and $2.76 billion at December 31, 1995. The estimated fair value of this debt, which was obtained from an independent pricing service, was $2.67 billion at December 31, 1996, and $2.85 billion at December 31, 1995. There are inherent limitations in any estimation technique, and these estimates are not necessarily indicative of the amount the Company could realize in current transactions. 5. CAPITALIZATION In 1994, the Board of Directors of the Company authorized the repurchase of up to 10 million shares of the Company's common stock on the open market. Under this stock repurchase program, the Company purchased approximately 0.7 million shares in 1996, 4.2 million shares in 1995 and 4.4 million shares in 1994. 52 At December 31, 1996, the Company had 14,767,052 shares of authorized but unissued common stock reserved and available for issuance to satisfy the requirements of the Company's stock plans. The Company intends, however, to meet the requirements of these stock plans with issued and outstanding shares presently held by the Trustee of the Stock Purchase- Savings Plan or with open market purchases of common stock shares, as appropriate. The Company's mortgage, as supplemented, and charter contain provisions limiting the use of retained earnings for the payment of dividends under certain circumstances. At December 31, 1996, there were no significant restrictions on the use of retained earnings. As of December 31, 1996, long-term debt maturities for the years 1997 through 2000 are $103 million, $208 million, $53 million and $197 million, respectively. There are no long-term debt maturities scheduled for the year 2001. Person County Pollution Control Revenue Refunding Bonds Series 1992A totaling $56 million have interest rates that must be negotiated on a weekly basis. At the time of interest rate renegotiation, holders of these bonds may require the Company to repurchase their bonds. Consistent with the Company's intention to maintain the debt as long- term, and to the extent this intention is supported by the Company's long-term revolving credit agreements, these bonds are classified as long-term debt in the Consolidated Balance Sheets. 6. REGULATORY MATTERS A. Regulatory Assets As a regulated entity, the Company is subject to the provisions of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation," (SFAS-71). Accordingly, the Company records certain assets resulting from the effects of the ratemaking process, which would not be recorded under generally accepted accounting principles for non-regulated entities. At December 31, 1996, the balances of the Company's regulatory assets were as follows (in millions): Income taxes recoverable through future rates $ 384.3 Harris Plant deferred costs 83.4 Abandonment costs 65.9 Loss on reacquired debt (included in unamortized debt expense) 63.0 Items included in other assets and deferred debits: Deferred DOE enrichment facilities-related costs 54.7 Deferred hurricane-related costs 35.1 Emission allowance carrying costs 11.8 Deferred purchased capacity costs - Mayo Plant 1.9 ------- Total $ 700.1 ======= See Note 11C for additional discussion of SFAS-71. B. Retail Rate Matters A petition was filed in July 1996 by the Carolina Industrial Group for Fair Utility Rates (CIGFUR) with the NCUC requesting that the NCUC conduct an investigation of the Company's base rates or treat its petition as a complaint against the Company. This petition alleged that the Company's return on equity, which was authorized by the NCUC in the Company's last general rate proceeding in 1988, and earnings are too high. The Company filed a response to the petition and Motion to Dismiss in July 1996, in which it argued that the petition was without merit. As part of this docket, the Company 53 filed a proposal to accelerate amortization of certain regulatory assets. In addition to proposing accelerated amortization of the regulatory assets, the Company requested approval to defer storm-related operation and maintenance expenses associated with Hurricane Fran. (See discussion of Hurricane Fran in Note 6D.) In December 1996, the NCUC approved the Company's proposal to accelerate amortization of certain regulatory assets over a three-year period beginning January 1, 1997. The accelerated amortization of these regulatory assets will reduce income by approximately $43 million, after tax, in each of the next three years. The NCUC also authorized the Company to defer operation and maintenance expenses associated with Hurricane Fran. Additionally, the Company has filed for, and expects to receive, approval from the SCPSC to accelerate amortization of certain regulatory assets, including plant abandonment costs related to the Harris Plant, over a three-year period beginning January 1, 1997. This accelerated amortization will reduce income by approximately $13 million, after tax, in each of the next three years. In anticipation of the approval in 1997, the unamortized balance of plant abandonment costs related to the Harris Plant was adjusted in 1996 to reflect the present value impact of the shorter recovery period. This adjustment resulted in an increase in income of approximately $14 million, after tax, in 1996. The North Carolina retail and South Carolina retail jurisdictional balances at December 31, 1996, for the regulatory assets subject to accelerated amortization, include loss on reacquired debt of $50 million, emission allowance carrying costs of $12 million, certain income taxes recoverable through future rates of $101 million and plant abandonment costs of $45 million. In December 1996, the NCUC issued an order denying CIGFUR's petition and stating that it tentatively finds no reasonable grounds to proceed with CIGFUR's petition as a complaint. On January 10, 1997, CIGFUR filed its Comments and Motion for Reconsideration. On January 23, 1997, the Company filed its response in opposition to CIGFUR's Comments and Motion for Reconsideration. The Company cannot predict the outcome of this matter. C. Plant-Related Deferred Costs The Company abandoned efforts to complete Harris Unit No. 2 in December 1983 and Mayo Unit No. 2 in March 1987. The NCUC and SCPSC each allowed the Company to recover the cost of these abandoned units over a ten-year period without a return on the unamortized balances. The amortization of Harris Unit No. 2 costs was completed in 1994. In the 1988 rate orders and a 1990 NCUC Order on Remand, the Company was ordered to remove from rate base and treat as abandoned plant certain costs related to the Harris Plant. Amortization related to abandoned plant costs associated with the 1990 NCUC Order on Remand was completed in 1994. Abandoned plant amortization related to the 1988 rate orders will be completed in 1998 for the North Carolina retail and wholesale jurisdictions and in 1999 for the South Carolina retail jurisdiction, assuming SCPSC approval of accelerated amortization as discussed in Note 6B. Amortization of plant abandonment costs is included in depreciation and amortization expense and totaled $17.6 million in 1996, $18.3 million in 1995 and $60.5 million in 1994. The unamortized balances of plant abandonment costs are reported at the present value of future recoveries of these costs. The associated accretion of the present value was $26.4 million in 1996 (which includes a $22.9 million adjustment to the unamortized balance - see Note 6B), $4.3 million in 1995 and $6.6 million in 1994, and is reported in other income, net. In 1988, the Company began recovering certain Harris Plant deferred costs over ten years from the date of deferral, with carrying costs accruing on the unamortized balance. Excluding deferred purchased capacity costs (see Note 11A), the unamortized balance of Harris Plant deferred costs was $15.6 million at December 31, 1996, and $38.4 million at December 31, 1995. 54 D. Hurricane-Related Deferred Costs Hurricane Fran struck significant portions of the Company's service territory on September 5, 1996. Restoration of the Company's system from hurricane-related damage resulted in operation and maintenance expenses of approximately $40 million and capital expenditures of approximately $55 million. In December 1996, the NCUC authorized the Company to defer operation and maintenance expenses associated with Hurricane Fran, with amortization over a 40-month period. Amortization of deferred hurricane costs is included in depreciation and amortization expense and totaled approximately $4 million in 1996. 7. EMPLOYEE STOCK OWNERSHIP PLAN The Company sponsors the Stock Purchase-Savings Plan (SPSP) for which all full-time employees and certain part-time employees are eligible. The SPSP, which has Company match and incentive goal features, encourages systematic savings by employees and provides a method of acquiring Company common stock and other diverse investments. The SPSP, as amended in 1989, is an employee stock ownership plan (ESOP) that can enter into acquisition loans to acquire Company common stock to satisfy SPSP common share needs. Qualification as an ESOP did not change the level of benefits received by employees under the SPSP. Common stock acquired with the proceeds of an ESOP loan is held by the SPSP Trustee in a suspense account. The common stock is released from the suspense account and made available for allocation to participants as the ESOP loan is repaid. Such allocations are used to partially meet common stock needs related to participant contributions, Company matching and incentive contributions and/or reinvested dividends. Dividends paid on ESOP suspense shares and on ESOP shares allocated to participants, as well as certain Company contributions, are used to repay ESOP acquisition loans. Such dividends are deductible for income tax purposes. There were 8,114,328 ESOP suspense shares at December 31, 1996, with a fair value of $296.2 million. ESOP shares allocated to plan participants totaled 14,861,249 at December 31, 1996. The Company has a long-term note receivable from the SPSP Trustee related to the purchase of common stock from the Company in 1989. The balance of the note receivable from the SPSP Trustee is included in the determination of unearned ESOP common stock, which reduces common stock equity. ESOP shares that have not been committed to be released to participants' accounts are not considered outstanding for the determination of earnings per common share. Interest income on the note receivable and dividends on unallocated ESOP shares are not recognized for financial statement purposes. 8. POSTRETIREMENT BENEFIT PLANS The Company has a noncontributory defined benefit retirement (pension) plan for all full-time employees and funds the pension plan in amounts that comply with contribution limits imposed by law. Pension plan benefits reflect an employee's compensation, years of service and age at retirement. The components of net periodic pension cost are (in thousands): 1996 1995 1994 ----------- ----------- --------- Actual return on plan assets $ (76,347) $ (103,381) $ 4,897 Variance from expected return, deferred 27,056 59,425 (47,219) ----------- ----------- --------- Expected return on plan assets (49,291) (43,956) (42,322) Service cost 19,257 16,344 19,686 Interest cost on projected benefit obligation 39,505 35,592 35,108 Net amortization 466 (3,580) 831 ----------- ----------- --------- Net periodic pension cost $ 9,937 $ 4,400 $ 13,303 =========== =========== ========= 55 Reconciliations of the funded status of the pension plan at December 31 are (in thousands): 1996 1995 --------- --------- Actuarial present value of benefits for services rendered to date: Accumulated benefits based on salaries to date, including vested benefits of $415.1 million for 1996 and $345.1 million for 1995 $ 452,552 $ 392,768 Additional benefits based on estimated future salary levels 106,136 130,167 --------- --------- Projected benefit obligation 558,688 522,935 Fair market value of plan assets, invested primarily in equity and fixed-income securities 683,508 610,278 --------- --------- Funded status 124,820 87,343 Unrecognized prior service costs 8,023 8,747 Unrecognized actuarial gain (155,145) (124,383) Unrecognized transition obligation, amortized over 18.5 years beginning January 1, 1987 899 1,005 --------- --------- Accrued pension costs recognized in the Consolidated Balance Sheets $ (21,403) $ (27,288) ========= ========= The assumptions used to measure the projected benefit obligation are: 1996 1995 ------ ------ Weighted-average discount rate 7.75% 7.75% Assumed rate of increase in future compensation 4.20% 4.20% The expected long-term rate of return on pension plan assets used in determining the net periodic pension cost was 9.25% in 1996 and 9.00% in 1995 and 1994. In addition to pension benefits, the Company provides contributory postretirement benefits (OPEB), including certain health care and life insurance benefits, for substantially all retired employees. The components of net periodic OPEB cost are (in thousands): 1996 1995 1994 --------- --------- ------- Actual return on plan assets $ (2,656) $ (2,514) $ 42 Variance from expected return, deferred 726 1,420 (682) --------- --------- ------- Expected return on plan assets (1,930) (1,094) (640) Service cost 8,412 7,498 8,039 Interest cost on accumulated benefit obligation 10,629 10,595 9,463 Net amortization 5,889 5,530 5,966 --------- --------- ------- Net periodic OPEB cost $ 23,000 $ 22,529 $ 22,828 ========= ========= ======= 56 Reconciliations of the funded status of the OPEB plans at December 31 are (in thousands): 1996 1995 ---------- ---------- Actuarial present value of benefits for services rendered to date: Current retires $ 60,534 $ 59,809 Active employees eligible to retire 19,607 17,942 Active employees not eligible to retire 84,346 68,819 ---------- ---------- Accumulated postretirement benefit obligation 164,487 146,570 Fair market value of plan assets, invested primarily in equity and fixed-income securities 28,799 20,869 --------- ---------- Funded status (135,688) (125,701) Unrecognized actuarial gain (11,339) (15,132) Unrecognized transition obligation, amortized over 20 years beginning January 1, 1993 94,225 101,414 ---------- ---------- Accrued OPEB costs recognized in the Consolidated Balance Sheets $ (52,802) $ (39,419) ========== ========== The assumptions used to measure the accumulated postretirement benefit obligation are: 1996 1995 ----- ----- Weighted-average discount rate 7.75% 7.75% Initial medical cost trend rate for pre-Medicare benefits 7.70% 8.40% Initial medical cost trend rate for post-Medicare benefits 7.50% 8.20% Ultimate medical cost trend rate 5.25% 5.25% Year ultimate medical cost trend rate is achieved 2005 2005 The expected long-term rate of return on plan assets used in determining the net periodic OPEB cost was 9.25% in 1996 and 9.00% in 1995 and 1994. Assuming a one percent increase in the medical cost trend rates, the aggregate of the service and interest cost components of the net periodic OPEB cost for 1996 would increase by $2.8 million, and the accumulated postretirement benefit obligation at December 31, 1996, would increase by $18.6 million. In general, OPEB costs are paid as claims are incurred and premiums are paid; however, the Company is partially funding retiree health care benefits in a trust created pursuant to Section 401(h) of the Internal Revenue Code. 57 9. INCOME TAXES Deferred income taxes are provided for temporary differences between book and tax bases of assets and liabilities. Income taxes are allocated between operating income and other income based on the source of the income that generated the tax. Investment tax credits related to operating income are amortized over the service life of the related property. Net accumulated deferred income tax liabilities at December 31 are (in thousands): 1996 1995 ------------ ------------ Accelerated depreciation and property cost differences $ 1,734,001 $ 1,613,752 Deferred costs, net 122,580 133,139 Miscellaneous other temporary differences, net 23 (12,487) ------------ ------------ Net accumulated deferred income tax liability $ 1,856,604 $ 1,734,404 ============ ============ Total deferred income tax liabilities were $2.30 billion and $2.17 billion at December 31, 1996, and 1995, respectively. Total deferred income tax assets were $439 million at December 31, 1996, and $434 million at December 31, 1995. A reconciliation of the Company's effective income tax rate to the statutory federal income tax rate is as follows: 1996 1995 1994 ----- ----- ----- Effective income tax rate 39.5% 39.2% 37.6% State income taxes, net of federal income tax benefit (4.9) (5.0) (5.5) Investment tax credit amortization 1.6 1.6 2.4 Other differences, net (1.2) (0.8) 0.5 ----- ----- ----- Statutory federal income tax rate 35.0% 35.0% 35.0% ===== ===== ===== The provisions for income tax expense are comprised of (in thousands): 1996 1995 1994 ----------- ----------- ----------- Included in Operating Expenses Income tax expense (credit) Current - federal $ 132,570 $ 143,440 $ 143,461 state 29,380 41,826 39,185 Deferred - federal 97,303 75,442 23,926 state 20,955 7,860 3,500 Investment tax credit (10,445) (9,344) (11,537) ----------- ----------- ----------- Subtotal 269,763 259,224 198,535 Harris Plant deferred costs Investment tax credit (286) (297) (297) ----------- ----------- ----------- Total included in operating expenses 269,477 258,927 198,238 ----------- ----------- ----------- Included in Other Income Income tax expense (credit) Current - federal (22,382) (20,669) (15,732) state (4,025) (4,251) (3,507) Deferred - federal 10,286 5,254 8,065 state 2,274 1,125 1,749 ----------- ----------- ----------- Total included in other income (13,847) (18,541) (9,425) ----------- ----------- ----------- Total income tax expense $ 255,630 $ 240,386 $ 188,813 =========== =========== =========== 58 10. JOINT OWNERSHIP OF GENERATING FACILITIES Power Agency holds undivided ownership interests in certain generating facilities of the Company. The Company and Power Agency are entitled to shares of the generating capability and output of each unit equal to their respective ownership interests. Each also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. The Company's share of expenses for the jointly owned units is included in the appropriate expense category in the Consolidated Statements of Income. The Company's share of the jointly owned generating facilities is listed below with related information as of December 31, 1996 (dollars in millions): Company Megawatt Ownership Plant Accumulated Under Facility Capability Interest Investment Depreciation Construction - ------------ ---------- --------- ---------- ------------ ------------ Mayo Plant 745 83.83% $ 451.3 169.1 $ 0.3 Harris Plant 860 83.83% $ 3,011.1 $ 840.3 $ 12.3 Brunswick Plant 1,521 81.67% $ 1,395.2 $ 814.2 $ 23.0 Roxboro Unit No.4 700 87.06% $ 230.4 $ 97.1 $ 1.4 In the table above, plant investment and accumulated depreciation, which includes accumulated nuclear decommissioning, are not reduced by the regulatory disallowances related to the Harris Plant. 11. COMMITMENTS AND CONTINGENCIES A. Purchased Power Pursuant to the terms of the 1981 Power Coordination Agreement, as amended, between the Company and Power Agency, the Company is obligated to purchase a percentage of Power Agency's ownership capacity and energy from the Mayo and Harris plants. For Mayo, the percentage purchased declines ratably over a 15-year period that ends in 1997. In 1993, the Company and Power Agency entered into an agreement to restructure portions of their contracts covering power supplies and interests in jointly owned units. Under the terms of the 1993 agreement, the Company increased the amount of capacity and energy purchased from Power Agency's ownership interest in the Harris Plant, and the buyback period was extended six years through 2007. The estimated minimum annual payments for these purchases, which reflect capital-related capacity costs, total approximately $27 million. Other costs of such purchases are primarily demand-related production expenses, fuel and energy- related operation and maintenance expenses. Contractual purchases from the Mayo and Harris plants totaled $36.7 million for 1996, $39.4 million for 1995 and $60.4 million for 1994. In 1987, the NCUC ordered the Company to reflect the recovery of the capacity portion of these costs on a levelized basis over the original 15-year buyback period, thereby deferring for future recovery the difference between such costs and amounts collected through rates. In 1988, the SCPSC ordered similar treatment, but with a ten-year levelization period. At December 31, 1996, and 1995, the Company had deferred purchased capacity costs, including carrying costs accrued on the deferred balances, of $69.7 million and $72.7 million, respectively. Increased purchases resulting from the 1993 agreement with Power Agency, which were approximately $13 million for 1996, $10 million for 1995 and $21 million for 1994, are not being deferred for future recovery. The Company purchases 250 megawatts of generating capacity from Indiana Michigan Power Company's Rockport Unit No. 2 (Rockport) and 400 megawatts of generating capacity from Duke Power Company (Duke). The estimated minimum annual payment for power under these contracts is approximately $30 million for Rockport and $43 million for 59 Duke, representing capital-related capacity costs. Other costs include demand-related production expenses, fuel and energy-related operation and maintenance expenses for Rockport and fuel and energy-related operation and maintenance expenses for Duke. Purchases, including transmission use charges, from Rockport and Duke, respectively, totaled $60.9 million and $65.4 million for 1996, $61.8 million and $63.8 million for 1995 and $61.9 million and $62.9 million for 1994. The Rockport agreement expires in late-2009 and the Duke agreement expires in mid-1999. B. Insurance The Company is a member of Nuclear Mutual Limited (NML), which provides primary insurance coverage against property damage to members' nuclear generating facilities. The Company is insured thereunder for $500 million for each of its nuclear generating facilities. For the current policy period, the Company is subject to maximum retrospective premium assessments of approximately $17 million in the event that losses at insured facilities exceed premiums, reserves, reinsurance and other NML resources, which are at present more than $857 million. The Company is also a member of Nuclear Electric Insurance Limited (NEIL), which provides insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages of members' nuclear generating units. The Company is insured thereunder for the first 52 weeks (starting 21 weeks after the outage begins) in weekly amounts of $1.4 million at Brunswick Unit No. 1, $1.3 million at Brunswick Unit No. 2, $1.5 million at the Harris Plant and $1.3 million at Robinson Unit No. 2. The Company is insured for the next 104 weeks for 80% of the above amounts. NEIL also provides decontamination, decommissioning and excess property insurance for nuclear generating facilities. The Company is insured under this coverage for $1.4 billion per incident. This is in addition to the $500 million coverage provided by NML. For the current policy period, the Company is subject to retrospective premium assessments of up to approximately $6.2 million with respect to the incremental replacement power costs coverage and $26.4 million with respect to the decontamination, decommissioning and excess property coverage in the event covered expenses at insured facilities exceed premiums, reserves, reinsurance and other NEIL resources. These resources are at present more than $2.5 billion. Pursuant to regulations of the Nuclear Regulatory Commission, the Company's property damage insurance policies provide that all proceeds from such insurance be applied, first, to place a plant in safe and stable condition after an accident and, second, to decontaminate it before any proceeds can be used for plant repair or restoration. The Company is responsible to the extent losses may exceed limits of the coverage described above. Power Agency would be responsible for its ownership share of such losses and for certain retrospective premium assessments on jointly owned nuclear units. The Company is insured against public liability for a nuclear incident up to $8.9 billion per occurrence, which is the maximum limit on public liability claims pursuant to the Price-Anderson Act. In the event that public liability claims from an insured nuclear incident exceed $200 million, the Company would be subject to a pro rata assessment of up to $75.5 million, plus a 5% surcharge, for each reactor owned for each incident. Payment of such assessment would be made over time as necessary to limit the payment in any one year to no more than $10 million per reactor owned. Power Agency would be responsible for its ownership share of the assessment on jointly owned nuclear units. C. Applicability of SFAS-71 The continued applicability of SFAS-71 (see Note 6A) will require further evaluation as competitive forces, deregulation and restructuring take effect in the electric utility industry. In the event the Company discontinued the application of SFAS-71, amounts recorded under SFAS-71 as regulatory assets and liabilities, would be eliminated. Additionally, the factors discussed above could also result in an impairment of electric utility plant assets as determined pursuant to Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." 60 D. Claims and Uncertainties (1) The Company is subject to federal, state and local regulations addressing air and water quality, hazardous and solid waste management and other environmental matters. Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under various federal and state laws. There are several manufactured gas plant (MGP) sites to which the Company and certain entities that were later merged into the Company had some connection. In this regard, the Company, along with other entities alleged to be former owners and operators of MGP sites in North Carolina, is participating in a cooperative effort with the North Carolina Department of Environment, Health and Natural Resources, Division of Waste Management (DWM), formerly the Division of Solid Waste Management, to establish a uniform framework for addressing these MGP sites. The investigation and remediation of specific MGP sites will be addressed pursuant to one or more Administrative Orders on Consent between the DWM and individual potentially responsible party or parties. The Company continues to investigate the identities of parties connected to individual MGP sites, the relative relationships of the Company and other parties to those sites and the degree to which the Company will undertake shared voluntary efforts with others at individual sites. The Company has been notified by regulators of its involvement or potential involvement in several sites, other than MGP sites, that require remedial action. Although the Company cannot predict the outcome of these matters, it does not expect costs associated with these sites to be material to the results of operations of the Company. The Company continues to carry a liability for the estimated costs associated with certain remedial activities at several MGP and other sites. This liability is not material to the financial position of the Company. Due to uncertainty regarding the extent of remedial action that will be required and questions of liability, the cost of remedial activities at certain MGP sites is not currently determinable. The Company cannot predict the outcome of these matters. (2) As required under the Nuclear Waste Policy Act of 1982, the Company entered into a contract with the DOE under which the DOE agreed to dispose of the Company's spent nuclear fuel. The Company cannot predict whether the DOE will be able to perform its contractual obligations and provide interim storage or permanent disposal repositories for spent nuclear fuel and/or high-level radioactive waste materials on a timely basis. With certain modifications, the Company's spent fuel storage facilities are sufficient to provide storage space for spent fuel generated on the Company's system through the expiration of the current operating licenses for all of the Company's nuclear generating units. Subsequent to the expiration of the licenses, dry storage may be necessary. (3) In the opinion of management, liabilities, if any, arising under other pending claims would not have a material effect on the financial position, results of operations or cash flows of the Company. 61
CAROLINA POWER & LIGHT COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Year Ended December 31, 1996 - ----------------------------------------------------------------------------------------------------------- COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - ----------------------------------------------------------------------------------------------------------- Additions Balance at (1) (2) Deductions Balance at Beginning Charged to Charged to from Close of Description of Period Income Other Account Reserves Period - ----------------------------------------------------------------------------------------------------------- Reserves deducted from related assets on the balance sheet: Uncollectible accounts $ 2,323,808 $ 8,525,513 $ - $ 7,159,538 $ 3,689,783 =========== =========== ============ ========== =========== Reserves other than those deducted from assets on the balance sheet: Injuries and damages $ 1,270,881 $ 1,033,504 $ - $ 1,026,497 $ 1,277,888 =========== =========== ============ ========== =========== Reserve for possible coal mine investment losses $ 7,797,250 $ - $ - $ 172,242 $ 7,625,008 =========== =========== ============ ========== =========== Reserve for employee retirement and compensation plans $ 91,779,866 $ 41,816,846 $ - $ 26,027,305 $ 107,569,407 =========== =========== ============ ========== =========== Reserve for environmental investigation and remediation costs $ 1,906,730 $ - $ - $ 90,821 1,815,909 =========== =========== ============ ========== =========== 62
CAROLINA POWER & LIGHT COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Year Ended December 31, 1995 - ----------------------------------------------------------------------------------------------------------- COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - ----------------------------------------------------------------------------------------------------------- Additions Balance at (1) (2) Deductions Balance at Beginning Charged to Charged to from Close of Description of Period Income Other Account Reserves Period - ----------------------------------------------------------------------------------------------------------- Reserves deducted from related assets on the balance sheet: Uncollectible accounts $ 2,520,785 $ 4,622,288 $ - $ 4,819,265 $ 2,323,808 =========== ========== ============ ========== ========== Reserves other than those deducted from assets on the balance sheet: Injuries and damages $ 2,212,161 $ 566,718 $ - $ 1,507,998 $ 1,270,881 =========== ========== ============ ========== ========== Reserve for possible coal mine investment losses $ 8,004,970 $ - $ - $ 207,720 $ 7,797,250 =========== ========== ============ ========== ========== Reserve for employee retirement and compensation plans $ 88,015,413 $ 36,288,787 $ - $ 32,524,334 $ 91,779,866 =========== ========== ============ ========== ========== Reserve for environmental investigation and remediation costs $ 1,976,716 $ - $ - $ 69,986 $ 1,906,730 =========== ========== ============ ========== ========== 63
CAROLINA POWER & LIGHT COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Year Ended December 31, 1994 - ----------------------------------------------------------------------------------------------------------- COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - ----------------------------------------------------------------------------------------------------------- Additions Balance at (1) (2) Deductions Balance at Beginning Charged to Charged to from Close of Description of Period Income Other Account Reserves Period - ----------------------------------------------------------------------------------------------------------- Reserves deducted from related assets on the balance sheet: Uncollectible accounts $ 2,305,141 $ 5,151,386 $ - $ 4,935,742 $ 2,520,785 =========== =========== ============ ========== ========== Reserves other than those deducted from assets on the balance sheet: Injuries and damages $ 2,094,006 $ 980,440 $ - $ 862,285 $ 2,212,161 =========== =========== ============ ========== ========== Property insurance reserve $ 23,217,772 $ (23,217,772 $ - $ - $ - =========== =========== ============ ========== ========== Reserve for possible coal mine investment losses $ 8,406,753 $ - $ - $ 401,783 $ 8,004,970 =========== =========== ============ ========== ========== Reserve for employee retirement and compensation plans $ 65,626,193 $ 46,044,119 $ - $ 23,654,899 $ 88,015,413 =========== =========== ============ ========== ========== Reserve for environmental investigation and remediation costs $ - $ 1,976,716 $ - $ - $ 1,976,716 =========== =========== ============ ========== ========== 64
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE __________________________________________________________ None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ___________________________________________________________ a) Information on the Company's directors is set forth in the Company's 1997 definitive proxy statement dated March 31, 1997, and incorporated by reference herein. b) Information on the Company's executive officers is set forth in Part I and incorporated by reference herein. ITEM 11. EXECUTIVE COMPENSATION _______________________________ Information on executive compensation is set forth in the Company's 1997 definitive proxy statement dated March 31, 1997, and incorporated by reference herein. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT _______________________________________________________________________ a) The Company knows of no person who is a beneficial owner of more than five (5%) percent of any class of the Company's voting securities except for (i) Wachovia Bank of North Carolina, N.A., Post Office Box 3099, Winston-Salem, North Carolina 27102 which as of December 31, 1996, owned 8,791,601 shares of Common Stock (5.8% of Class) as Trustee of the Company's Stock Purchase-Savings Plan and (ii) The Colonial Group, Inc., One Financial Center, Boston, MA 02111, which as of December 31, 1996, owned 30,000 shares of the Company's Serial Preferred Stock, $7.72 Series (6% of Class). b) Information on security ownership of the Company's management is set forth in the Company's 1997 definitive proxy statement dated March 31, 1997, and incorporated by reference herein. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS _______________________________________________________ Information on certain relationships and related transactions is set forth in the Company's 1997 definitive proxy statement dated March 31, 1997, and incorporated by reference herein. 65 PART IV ITEM 14. EXHIBITS, CONSOLIDATED FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. a) 1. Consolidated Financial Statements Filed: See ITEM 8 - Consolidated Financial Statements and ______ Supplementary Data. 2. Consolidated Financial Statement Schedules Filed: See ITEM 8 - Consolidated Financial Statements and ______ Supplementary Data. 3. Exhibits Filed: ______________ Exhibit No. *3a(1) Restated Charter of the Company, as amended May 10, 1995 (filed as Exhibit No. 3(i) to quarterly report on Form 10-Q for the quarterly period ended June 30, 1995, File No. 1-3382). Exhibit No. *3a(2) By-laws of the Company, as amended May 10, 1995 (filed as Exhibit No. 3(ii) to quarterly report on Form 10-Q for the quarterly period ended June 30, 1995, File No. 1-3382). Exhibit No. *4a(1) Resolution of Board of Directors, dated December 8, 1954, authorizing the issuance of, and establishing the series designation, dividend rate and redemption prices for the Company's Serial Preferred Stock, $4.20 Series (filed as Exhibit 3(c), File No. 33-25560). Exhibit No. *4a(2) Resolution of Board of Directors, dated January 17, 1967, authorizing the issuance of, and establishing the series designation, dividend rate and redemption prices for the Company's Serial Preferred Stock, $5.44 Series (filed as Exhibit 3(d), File No. 33-25560). Exhibit No. *4a(3) Statement of Classification of Shares dated January 13, 1971, relating to the authorization of, and establishing the series designation, dividend rate and redemption prices for the Company's Serial Preferred Stock, $7.95 Series (filed as Exhibit 3(f), File No. 33-25560). Exhibit No. *4a(4) Statement of Classification of Shares dated September 7, 1972, relating to the authorization of, and establishing the series designation, dividend rate and redemption prices for the Company's Serial Preferred Stock, $7.72 Series (filed as Exhibit 3(g), File No. 33-25560). Exhibit No. *4b Mortgage and Deed of Trust dated as of May 1, 1940 between the Company and The Bank of New York (formerly, Irving Trust Company) and Frederick G. Herbst (W.T. Cunningham, Successor), Trustees and the First through Fifth Supplemental Indentures thereto (Exhibit 2(b), File No. 2-64189); and the Sixth through Sixty-third Supplemental Indentures (Exhibit 2(b)-5, File No. 2-16210; Exhibit 2(b)-6, File No. 2-16210; Exhibit 4(b)-8, File No. 2-19118; 66 Exhibit 4(b)-2, File No. 2-22439; Exhibit 4(b)-2, File No. 2-24624; Exhibit 2(c), File No. 2-27297; Exhibit 2(c), File No. 2-30172; Exhibit 2(c), File No. 2-35694; Exhibit 2(c), File No. 2-37505; Exhibit 2(c), File No. 2-39002; Exhibit 2(c), File No. 2-41738; Exhibit 2(c), File No. 2-43439; Exhibit 2(c), File No. 2-47751; Exhibit 2(c), File No. 2-49347; Exhibit 2(c), File No. 2-53113; Exhibit 2(d), File No. 2-53113; Exhibit 2(c), File No. 2-59511; Exhibit 2(c), File No. 2-61611; Exhibit 2(d), File No. 2-64189; Exhibit 2(c), File No. 2-65514; Exhibits 2 and 2(d), File No. 2-66851; Exhibits 4(b)-1, 4(b)-2, and 4(b)-3, File No. 2-81299; Exhibits 4(c)-1 through 4(c)-8, File No. 2-95505; Exhibits 4(b) through 4(h), File No. 33-25560; Exhibits 4(b) and 4(c), File No. 33-33431; Exhibits 4(b) and 4(c), File No. 33-38298; Exhibits 4(h) and 4(I), File No. 33-42869; Exhibits 4(e)-(g), File No. 33-48607; Exhibits 4(e) and 4(f), File No. 33-55060; Exhibits 4(e) and 4(f), File No. 33-60014; Exhibits 4(a) and 4(b), File No. 33-38349; Exhibit 4(e), File No. 33-50597; and Exhibit 4(e) and 4(f), File No. 33-57835). Exhibit No. *4c(1) Indenture, dated as of March 1, 1995, between the Company and Bankers Trust Company, as Trustee, with respect to Unsecured Subordinated Debt Securities (filed as Exhibit No.4 to Current Report on Form 8-K dated April 13, 1995, File No. 1-3382). Exhibit No. *4c(2) Resolutions adopted by the Executive Committee of the Board of Directors at a meeting held on April 13, 1995, establishing the terms of the 8.55% Quarterly Income Capital Securities (Series A Subordinated Deferrable Interest Debentures) (filed as Exhibit 4(b) to Current Report on Form 8-K dated April 13, 1995, File No. 1-3382). Exhibit No. *10a(1) Purchase, Construction and Ownership Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency, amending letter dated February 18, 1982, and amendment dated February 24, 1982 (filed as Exhibit 10(a), File No. 33-25560). Exhibit No. *10a(2) Operating and Fuel Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency, amending letters dated August 21, 1981 and December 15, 1981, and amendment dated February 24, 1982 (filed as Exhibit 10(b), File No. 33-25560). Exhibit No. *10a(3) Power Coordination Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency and amending letter dated January 29, 1982 (filed as Exhibit 10(c), File No. 33-25560). Exhibit No. *10a(4) Amendment dated December 16, 1982 to Purchase, Construction and Ownership Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Eastern Municipal Power Agency (filed as Exhibit 10(d), File No. 33-25560). 67 Exhibit No. *10a(5) Agreement Regarding New Resources and Interim Capacity between Carolina Power & Light Company and North Carolina Eastern Municipal Power Agency dated October 13, 1987 (filed as Exhibit 10(e), File No. 33-25560). Exhibit No. *10a(6) Power Coordination Agreement - 1987A between North Carolina Eastern Municipal Power Agency and Carolina Power & Light Company for Contract Power From New Resources Period 1987-1993 dated October 13, 1987 (filed as Exhibit 10(f), File No. 33-25560). +Exhibit No. *10b(1) Directors Deferred Compensation Plan effective January 1, 1982 as amended (filed as Exhibit 10(g), File No. 33-25560). +Exhibit No. *10b(2) Supplemental Executive Retirement Plan effective January 1, 1984 (filed as Exhibit 10(h), File No. 33-25560). +Exhibit No. *10b(3) Retirement Plan for Outside Directors (filed as Exhibit 10) (I), File No. 33-25560). +Exhibit No. *10b(4) Executive Deferred Compensation Plan effective May 1, 1982 as amended (filed as Exhibit 10(j), File No. 33-25560). +Exhibit No. *10b(5) Key Management Deferred Compensation Plan (filed as Exhibit 10(k), File No. 33-25560). +Exhibit No. *10b(6) Resolutions of the Board of Directors, dated March 15, 1989, amending the Key Management Deferred Compensation Plan (filed as Exhibit 10(a), File No. 33-48607). +Exhibit No. *10b(7) Resolutions of the Board of Directors dated May 8, 1991, amending the Directors Deferred Compensation Plan (filed as Exhibit 10(b), File No. 33-48607). +Exhibit No. *10b(8) Resolutions of the Board of Directors dated May 8, 1991, amending the Executive Deferred Compensation Plan (filed as Exhibit 10(c), File No. 33-48607). Exhibit No. 12 Computation of Ratio of Earnings to Fixed Charges and Preferred Dividends Combined and Ratio of Earnings to Fixed Charges. Exhibit No. 18 Letter re: Change in Accounting Principles Exhibit No. 23(a) Consent of Deloitte & Touche LLP Exhibit No. 23(b) Consent of William D. Johnson Exhibit No. 27 Financial Data Schedule *Incorporated herein by reference as indicated. +Management contract or compensation plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14 (c) of Form 10-K. 68 b) Reports on Form 8-K filed during or with respect to the last quarter of 1996 and the portion of the first quarter of 1997 prior to the filing of this 10-K: Date of Report Item Reported ______________ _____________ NONE 69 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, on the 26th day of March, 1997. CAROLINA POWER & LIGHT COMPANY (Registrant) By: /s/ Glenn E. Harder Executive Vice President and Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. Signature Title Date _________ _____ ____ /s/ William Cavanaugh III _____________________________ Principal Executive (William Cavanaugh III, Officer and Director President and Chief Executive Officer) /s/ Glenn E. Harder _____________________________ Principal Financial (Glenn E. Harder Officer Executive Vice President and Chief Financial Officer) /s/ Bonnie V. Hancock _____________________________ Principal Accounting (Bonnie V. Hancock Officer Vice President and Controller) /s/ Sherwood H. Smith, Jr. _____________________________ Director March 26, 1997 (Sherwood H. Smith, Jr., Chairman) /s/ Edwin B. Borden _____________________________ Director (Edwin B. Borden) /s/ Felton J. Capel _____________________________ Director (Felton J. Capel) /s/ Charles W. Coker _____________________________ Director (Charles W. Coker) 70 Signature Title Date _________ _____ ____ /s/ Richard L. Daugherty _____________________________ Director (Richard L. Daugherty) /s/ Robert L. Jones _____________________________ Director (Robert L. Jones) /s/ Estell C. Lee Director _____________________________ March 26, 1997 (Estell C. Lee) /s/ William O. McCoy _____________________________ Director (William O. McCoy) /s/ J. Tylee Wilson _____________________________ Director (J. Tylee Wilson) 71 EX-12 2 COMPUTATION OF RATIO OF EARNINGS
EXHIBIT 12 CAROLINA POWER & LIGHT COMPANY COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED DIVIDENDS COMBINED AND RATIO OF EARNINGS TO FIXED CHARGES -------------------------------------------- Twelve Months Ended December 31, -------------------------------------------- 1996 1995 1994 1993 1992 ---- ---- ---- ---- ---- (Thousands of Dollars) Earnings, as defined: Net income......................................$ 391,277 $ 372,604 $ 313,167 $ 346,496 $ 379,635 Fixed charges, as below......................... 204,593 226,833 213,821 237,098 253,215 Income taxes, as below.......................... 247,405 232,046 180,518 181,653 211,717 -------------- -------------- -------------- -------------- ----------- Total earnings, as defined....................$ 843,275 $ 831,483 $ 707,506 $ 765,247 $ 844,567 ============== ============== ============== ============== =========== Fixed Charges, as defined: Interest on long-term debt......................$ 172,622 $ 187,397 $ 183,891 $ 205,182 $ 223,158 Other interest.................................. 19,155 25,896 16,119 16,419 15,717 Imputed interest factor in rentals-charged principally to operating expenses............. 12,816 13,540 13,811 15,497 14,340 -------------- -------------- -------------- -------------- ----------- Total fixed charges, as defined...............$ 204,593 $ 226,833 $ 213,821 $ 237,098 $ 253,215 ============== ============== ============== ============== =========== Earnings Before Income Taxes......................$ 638,682 $ 604,650 $ 493,685 $ 528,149 $ 591,352 ============== ============== ============== ============== =========== Ratio of Earnings Before Income Taxes to Net Income...... 1.63 1.62 1.58 1.52 1.56 Income Taxes: Included in operating expenses..................$ 269,477 $ 258,927 $ 198,238 $ 189,535 $ 210,266 Included in other income: Income tax expense (credit)................... (13,847) (18,541) (9,425) 392 5,885 Harris Plant carrying costs................... - - - - 1,969 Other income, net............................. - - - - 58 Included in AFUDC - borrowed funds.............. - - - - 2,060 Included in AFUDC - deferred taxes in nuclear fuel amortization and book depreciation....... (8,225) (8,340) (8,295) (8,274) (8,521) -------------- -------------- -------------- -------------- ----------- Total income taxes............................$ 247,405 $ 232,046 $ 180,518 $ 181,653 $ 211,717 ============== ============== ============== ============== =========== Fixed Charges and Preferred Dividends Combined: Preferred dividend requirements.................$ 9,609 $ 9,609 $ 9,609 $ 9,609 $ 14,798 Portion deductible for income tax purposes...... (312) (312) (312) (312) (321) -------------- -------------- -------------- -------------- ----------- Preferred dividend requirements not deductible..$ 9,297 $ 9,297 $ 9,297 $ 9,297 $ 14,477 ============== ============== ============== ============== =========== Preferred dividend factor: Preferred dividends not deductible times ratio of earnings before income taxes to net income................................ .$ 15,154 $ 15,061 $ 14,689 $ 14,131 $ 22,584 Preferred dividends deductible for income taxes............................. . 312 312 312 312 321 Fixed charges, as above...................... 204,593 226,833 13,821 237,098 253,215 Total fixed charges and preferred dividends -------------- -------------- -------------- -------------- ----------- combined..................................$ 220,059 $ 242,206 $ 228,822 $ 251,541 $ 276,120 ============== ============== ============== ============== =========== Ratio of Earnings to Fixed Charges and Preferred Dividends Combined............................. 3.83 3.43 3.09 3.04 3.06 Ratio of Earnings to Fixed Charges............... 4.12 3.67 3.31 3.23 3.34
EX-18 3 LETTER RE: CHANGE IN ACCOUNTING PRINCIPLES [CP&L Logo Appears Here] Carolina Power & Light Company Bonnie V. Hancock P.O. Box 1551 Vice President - Accounting Raleigh, NC 27602 and Controller March 19, 1997 Securities and Exchange Commission 450 5th Street, NW Judiciary Plaza Washington, DC 20549 Gentlemen: Pursuant to the General Instructions to Form 10-K, please be advised that the financial statements contained in the 1996 Form 10-K of Carolina Power & Light Company do not reflect any changes from the preceding year in accounting principles or practices or in the method of applying any such principles or practices. Sincerely yours, /s/ Bonnie V. Hancock EX-23.A 4 CONSENT OF EXPERT AND COUNSEL Exhibit No. 23(a) INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement No. 33-33520 on Form S-8, Registration Statement No. 33-5134 on Form S-3, Post-Effective Amendment No. 1 to Registration Statement No. 33-38349 on Form S-3, Registration Statement No. 33-50597 on Form S-3 and Registration Statement No. 33-57835 on Form S-3 of Carolina Power & Light Company, of our report dated February 10, 1997, appearing in this Annual Report on Form 10-K of Carolina Power & Light Company for the year ended December 31, 1996. \s\ DELOITTE & TOUCHE LLP Raleigh, North Carolina March 26, 1997 EX-23.B 5 CONSENT OF EXPERT AND COUNSEL CONSENT OF EXPERT AND COUNSEL Carolina Power & Light Company: The statements of law and legal conclusions under Item 1. Business and Item 3. Legal Proceedings in the Company's Annual Report on Form 10-K for the year ended December 31, 1996 have been reviewed by me and are set forth therein in reliance upon my opinion as an expert. I hereby consent to the incorporation by reference of such statements of law and legal conclusions in Registration Statement No. 33-33520 on Form S-8, Registration Statement No. 33-5134 on Form S-3, Post-Effective Amendment No. 1 to Registration Statement No. 33-38349 on Form S-3, Registration Statement No. 33-50597 on Form S-3 and Registration Statement No. 33-57835 on Form S-3 and the related Prospectuses, which are a part of such Registration Statements. /s/ William D. Johnson, Vice President and Senior Counsel March 26, 1997 EX-27 6 FINANCIAL DATA SCHEDULE
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM (INTERIM FINANCIAL STATEMENTS AS OF DECEMBER 31, 1996) AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000017797 CAROLINA POWER & LIGHT COMPANY
YEAR DEC-31-1996 DEC-31-1996 PER-BOOK $6,399,919 $489,334 $672,039 $603,552 $204,357 $8,369,201 $1,187,586 ($790) $1,503,658 $2,690,454 $0 $143,801 $2,525,607 $0 $0 $0 $103,345 $0 $0 $0 $2,905,994 $8,369,201 $2,995,715 $269,763 $2,211,865 $2,481,628 $514,087 $62,560 $576,647 $185,370 $391,277 $9,609 $381,668 $263,388 $172,622 $962,831 $2.66 $2.66 -----END PRIVACY-ENHANCED MESSAGE-----