-----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, AWFR1aLBIXg+9xAuPADKnjpKqWyI0Gq9zor7Yn5/MPaOOzGej378UHJhRaVAeiVD p+Vqyd2uY/Aqe04grPMWJg== 0000950168-00-000708.txt : 20000328 0000950168-00-000708.hdr.sgml : 20000328 ACCESSION NUMBER: 0000950168-00-000708 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 11 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000327 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-K405 SEC ACT: SEC FILE NUMBER: 001-03382 FILM NUMBER: 578788 BUSINESS ADDRESS: STREET 1: 411 FAYETTEVILLE ST CITY: RALEIGH STATE: NC ZIP: 27601 BUSINESS PHONE: 9195466111 10-K405 1 FORM 10-K 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, 1999 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 jurisdiction of (I.R.S. Employer (Address of principal executive offices) (Zip Code) incorporation or organization) Identification No.)
919-546-6111 ------------ (Registrant's telephone number, including area code) SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: -----------------------------------------------------------
Title of each class Name of each exchange on which registered ------------------- ----------------------------------------- Common Stock (Without Par Value) New York Stock Exchange 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 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. [X] The aggregate market value of the voting and non-voting common stock held by non-affiliates at February 29, 2000 was $4,748,799,423. Shares of Common Stock (Without Par Value) outstanding at February 29, 2000: 159,623,510. DOCUMENTS INCORPORATED BY REFERENCE ----------------------------------- Portions of the Company's 2000 definitive proxy statement dated March 31, 2000 are incorporated into PART III, ITEMS 10, 11, 12 and 13 hereof. 1
TABLE OF CONTENTS Page ---- SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS 3 PART I ITEM 1. BUSINESS 4 General 4 Company 4 Significant Transactions 4 Financial Information 5 Business Activities 5 Generating Capability 5 Interconnections with Other Systems 8 Competition 9 Capital Requirements 13 Financing Requirements 13 Retail Rate Matters 15 Wholesale Rate Matters 18 Environmental Matters 18 Nuclear Matters 20 Fuel 24 Natural Gas Supply 26 Diversified Businesses 27 Other Matters 27 Employees 29 Operating Statistics - Electric 30 Operating Statistics - Natural Gas 31 ITEM 2. PROPERTIES 32 ITEM 3. LEGAL PROCEEDINGS 34 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 34 EXECUTIVE OFFICERS OF THE REGISTRANT 35 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS 37 ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA 38 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 39 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 51 ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 52 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 81 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 81 ITEM 11. EXECUTIVE COMPENSATION 81 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 81 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 81 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 81
2 SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS - ------------------------------------------ The matters discussed throughout this Form 10-K that are not historical facts are forward-looking and, accordingly, involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Examples of forward-looking statements discussed in this Form 10-K, PART I, ITEM 1, "BUSINESS," include, but are not limited to, statements under the following headings: 1) "General" relating to the Amended and Restated Agreement and Plan of Exchange with Florida Progress Corporation; 2) "Business Activities" regarding changes at the Company; 3) "Generating Capability" regarding the forecasted system sales growth, planned generation additions schedule, and forecasted capacity margins over anticipated system peak loads; 4) "Interconnections with Other Systems" relating to future energy cost savings resulting from amendments to agreements with Cogentrix, future purchases from the Broad River Energy project and relating to estimated minimum annual payments for long-term purchase contracts; 5) "Competition" regarding the effect on the Company of increased competition at the wholesale level and the likelihood of additional industry restructuring-related bills being introduced in Congress in 2000; 6) "Capital Requirements" relating to estimated capital requirements for 2000-2002; 7) "Financing Requirements" relating to expected external funding requirements; 8) "Environmental Matters" relating to future capital expenditures to meet nitrogen oxide emission requirements, emerging regulatory requirements and the materiality of future costs related to environmental matters; 9) "Nuclear Matters" relating to future capital expenditures for modifications at the Company's nuclear units, future increase in low-level radioactive waste disposal costs, materiality of various nuclear-related matters; and 10) "Fuel" regarding the percentages of future coal burn requirements from intermediate and long-term agreements, effect of amendments to the Clean Air Act on the price of low sulfur coal, sufficiency of existing uranium contracts and regarding total decontamination and decommissioning fund fees expected to be paid. In addition, examples of forward-looking statements discussed in this Form 10-K, PART II, ITEM 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" include, but are not limited to, statements under the following headings: 1) "Liquidity and Capital Resources" about estimated capital requirements through the year 2002 and 2) "Other Matters" about the effects of new environmental regulations, nuclear decommissioning costs, and the effect of electric utility industry restructuring. Any forward-looking statement speaks only as of the date on which such statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made. Examples of factors that should be considered with respect to any forward-looking statements made throughout this document include, but are not limited to, the following: Governmental policies and regulatory actions (including those of the Federal Energy Regulatory Commission, the Environmental Protection Agency, the Nuclear Regulatory Commission, the Department of Energy, the North Carolina Utilities Commission and the Public Service Commission of South Carolina); general industry trends; operation of nuclear power facilities; availability of nuclear waste storage facilities; nuclear decommissioning costs; changes in the economy of areas served by the Company; legislative and regulatory initiatives that impact the speed and degree of industry restructuring; ability to obtain adequate and timely rate recovery of costs, including potential stranded costs arising from industry restructuring; competition from other energy suppliers; the success of the Company's subsidiaries; weather conditions and catastrophic weather-related damage; market demand for energy; inflation; capital market conditions; the proposed share exchange with Florida Progress Corporation; failure of the potential benefits of the Company's conversion to a holding company structure to materialize, unanticipated changes in operating expenses and capital expenditures; and legal and administrative proceedings. All such factors are difficult to predict, contain uncertainties that may materially affect actual results, and may be beyond the control of the Company. New factors emerge from time to time and it is not possible for management to predict all of such factors, nor can it assess the effect of each such factor on the Company. 3 PART I ITEM 1. BUSINESS - ------- -------- GENERAL - ------- COMPANY - ------- Carolina Power & Light Company (the Company), whose principal executive offices are located at 411 Fayetteville Street, Raleigh, North Carolina is a full service energy provider formed under the laws of North Carolina in 1926 and is an exempt holding company as defined by the Public Utility Holding Company Act of 1935. The Company is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North and South Carolina, and the transmission, distribution and sale of natural gas in portions of North Carolina. The Company provides these and other services through its business segments: electric, natural gas and other. The electric segment generates, transmits, distributes and sells electricity to 56 of the 100 counties in North Carolina, and 14 counties in northeastern South Carolina. The territory served is an area of 33,667 square miles, including 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 an around the city of Asheville. The estimated total population of the territory served is approximately 4.2 million. At December 31, 1999, the electric segment was providing electric services, retail and wholesale, to 1.2 million customers. The electric segment is subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC), the North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (SCPSC). The natural gas segment transmits, distributes and sells gas to approximately 167,000 thousand customers in 110 towns and cities and four municipal gas distribution systems. The area served includes substantial portions of south-central and eastern North Carolina. The natural gas segment also purchases and transports natural gas under long-term contracts with Transcontinental Gas Pipe Line Corporation (Transco), Columbia Gas Transmission Corporation (Columbia) and several major oil and gas producers. Natural gas operations are subject to the rules and regulations of the NCUC. The other segment primarily includes telecommunication services, energy management services, propane and miscellaneous non-regulated activities. These services are primarily provided through two of the Company's subsidiaries, Strategic Resource Solutions Corp. (SRS) and Interpath Communications, Inc. (Interpath). SRS specializes in facilities and energy management software, systems and services for educational, commercial, industrial and governmental markets nationwide. Interpath is a telecommunications company primarily engaged in providing comprehensive network services. The Company holds franchises to the extent necessary to operate its regulated electric and natural gas operations in the municipalities and other areas it serves. SIGNIFICANT TRANSACTIONS - ------------------------ On July 15, 1999, the Company completed the acquisition of North Carolina Natural Gas Corporation (NCNG), now operating as a wholly owned subsidiary. Each outstanding share of NCNG common stock was converted into the right to receive 0.8054 shares of Company common stock, resulting in the issuance of approximately 8.3 million shares. The acquisition was accounted for as a purchase and, accordingly, the operating results of NCNG have been included in the Company's consolidated financial statements since the date of acquisition. See PART II, ITEM 7, "Other Matters." The Company, Florida Progress Corporation (FPC), a Florida corporation, and CP&L Energy, Inc. (CP&L Energy), a North Carolina corporation and wholly owned subsidiary of the Company formerly known as CP&L Holdings, Inc. 4 entered into an Amended and Restated Agreement and Plan of Share Exchange dated as of August 22, 1999, amended and restated as of March 3, 2000 (the "Amended Agreement"). The transaction is expected to be completed in the fall of 2000. See PART II, ITEM 7, "Other Matters." The Company is in the process of converting to a holding company structure, in which the Company would become a subsidiary of a newly formed holding company. The holding company structure will allow for greater organizational flexibility, and will provide the ability to conduct financing activities at the holding company level. See PART II, ITEM 7, "Other Matters." FINANCIAL INFORMATION - --------------------- During 1999, the Company's operating revenues totaled $3.4 billion of which $3.1 billion was related to the electric segment, $98.9 million to the natural gas segment and $119.9 million to the other segment. During 1999, 34% of electric revenues were derived from residential sales, 22% from commercial sales, 22% from industrial sales, 13% from wholesale sales and 9% from other sources. Of such operating revenues, approximately 67% were derived from North Carolina retail customers, 13% from South Carolina retail customers, 13% from North Carolina wholesale customers, less than 0.5% from South Carolina wholesale customers and 7% from sales to other utilities and other customers. For the revenues related to the natural gas segment, 50% of the revenues were derived from industrial sales while the remaining sales were evenly distributed among residential, commercial, electric utilities and wholesale customers, all in North Carolina. The operating revenues for the other segment primarily include revenues of two of the Company's subsidiaries, SRS and Interpath. For additional information see PART II, ITEM 7, "Results of Operations" and PART II, ITEM 8, "Note 5." BUSINESS ACTIVITIES - ------------------- GENERATING CAPABILITY - --------------------- 1. FACILITIES. At December 31, 1999, the Company had a total system installed generating capability (including the North Carolina Eastern Municipal Power Agency's (Power Agency) share) of 10,128 megawatts (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 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. Of the total system installed generating capability of 10,128 MW, 53% is coal, 31% is nuclear, 2% is hydro and 14% is fired by other fuels including No. 2 oil, natural gas and propane. 5
MAJOR INSTALLED GENERATING FACILITIES ------------------------------------- AT DECEMBER 31, 1999 -------------------- Year Maximum Commercial Dependable Plant Location Unit No. Operation Primary Fuel Capacity -------------- -------- --------- ------------ -------- Asheville 1 1964 Coal 198 MW (Skyland, N.C.) 2 1971 Coal 194 MW 3 1999 Gas/Oil 165 MW 4 2000 Gas/Oil 165 MW Cape Fear 5 1956 Coal 143 MW (Moncure, N.C.) 6 1958 Coal 173 MW Darlington County Plant 12 1997 Gas/Oil 120 MW (Hartsville, S.C.) 13 1997 Gas/Oil 120 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 820 MW* (Southport, N.C.) 2 1975 Nuclear 811 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.
6 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 ratemaking 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. GENERATION ADDITIONS SCHEDULE The Company's energy and load forecasts were revised in December 1999. Over the next ten years, system internal sales growth is forecasted to average approximately 2.8% per year and annual growth in system internal peak demand is projected to average approximately 2.8%. The Company's generation additions schedule provides for the addition of approximately 2,872 MW of combustion turbine capacity and 2,406 MW of combined cycle capacity over the period 2000 to 2009 in order to meet the needs of its growing customer base and increase its ability to participate in the wholesale power market. The Company may alter its long-term plans based on changes in load forecasts, market conditions, and other factors. In addition, see PART I, ITEM 1 "Interconnections with Other Systems" and PART I, ITEM 1, "Competition" for discussion of the Company's long-term purchase power contracts. On August 18, 1998 the Company filed with the NCUC an application for a Certificate of Public Convenience and Necessity to construct an additional 177 MW of combustion turbine capacity adjacent to the Company's Lee Steam Electric Plant in Wayne County, North Carolina and a second 160 MW combustion turbine unit at the Company's Asheville Steam Electric Plant in Buncombe County, North Carolina. The Wayne County Turbine is in addition to the 500 MW of combustion turbine capacity for which the Company received a Certificate of Public Convenience and Necessity on March 21, 1996. These units will primarily be used during periods of summer and winter peak demands. By order issued December 17, 1998, the NCUC granted the Company a Certificate to construct both units. Construction of the combustion turbines began during the first quarter of 1999. Commercial operation was anticipated to begin in June 2000 for both units; however, the Asheville combustion turbine became operational in February 2000, three months ahead of schedule. On March 19, 1999, the Company filed with the NCUC an application for a Certificate of Public Convenience and Necessity to construct 1600 MW of combustion turbine generating capacity between two sites, one in Rowan County and a site in Richmond County. The NCUC granted the certificate on November 11, 1999. Construction of the combustion turbine in Rowan county began November 15, 1999 and the construction of the combustion turbine in Richmond county began February 1, 2000. During 1999, the Company invested approximately $47.5 million in new generating plant facilities. 4. PEAK DEMAND. An instantaneous system peak demand record of 10,948 MW was reached on August 11, 1999. 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 5.22%. Total system peak demand increased for 1997 by 2.2%, for 1998 by 5.0% and for 1999 by 4.0% as compared with the preceding year. The Company currently projects that system peak demand will increase at an average annual growth rate of approximately 2.8% 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, were 60.6% for 1997, 60.1% for 1998, and 58.2% for 1999. The Company forecasts capacity margins of 10.5% over anticipated system peak load for 2000 and 10.6% for 2001. 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 7 purchases of power. However, some of the generating units included in arriving at these capacity margins may be unavailable as a result of scheduled and unplanned outages. INTERCONNECTIONS WITH OTHER SYSTEMS - ----------------------------------- 1. INTERCONNECTIONS. 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). In addition, the Company, on occasion, will reserve daily to hourly transmission on Duke Energy's (Duke) system under the transmission tariff in order to accommodate the peak demand in the western control area. 2. INTERCHANGE AND POWER PURCHASE/SALE AGREEMENTS. ----------------------------------------------- a) The Company has interchange agreements with APCO, 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 2b below. Purchases and sales under these agreements may be made due to economic or reliability considerations. In June 1999, the Company terminated Schedule G to the Interchange Agreement between the Company and Duke. Schedule G provided for the wheeling of electricity between the Company's eastern area and its western area. On December 31, 1999, the Company terminated the Standby Concurrent Exchange Agreement (Standby Agreement) between the Company and Duke. The Standby Agreement provided 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," for further discussion of the FERC Order 888. b) The Virginia-Carolinas Subregion of the Southeastern Electric Reliability Council is principally made up of the Company, Duke, Nantahala Power & Light Company, SCE&G, SCPSA, Virginia Power, 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) From July 1993 through June 1999, Duke provided 400 MW of firm capacity to the Company's system. The Company terminated this contract in 1999. Purchases under this agreement, including transmission use charges, totaled $33.8 million in 1999. b) The Company has 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 transmission interconnections in the Company's western and eastern service areas 8 and purchase 250 MW of generating capacity from Indiana Michigan's Rockport Unit No. 2 through 2009. Upgrades to the transmission interconnections in the Company's western and eastern service area were completed in 1992 and 1998, respectively. The estimated minimum annual payment for power purchases under the agreement is approximately $31 million, representing capital-related capacity costs. In 1999, purchases under this agreement, including transmission use charges, totaled $59.5 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 expects to realize energy cost savings through the expiration of the agreement in 2002. d) In December 1998, the Company entered into an agreement to purchase all of the output of a combustion turbine project to be built, owned, and operated by Broad River Energy, LLC, in Cherokee County, South Carolina. The project is scheduled to be in service on or before June 1, 2001 and is expected to have a net dependable capacity of approximately 500 MW. The agreement is for an initial period of 15 years, with an option for the Company to extend the agreement for two additional five-year terms. During the term of the agreement, the Company will have full rights to the output of the project as well as control over the scheduling of the units. 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 Harris Plant through 2007. The estimated minimum annual payments for these purchases, which reflect capital-related capacity costs, total approximately $26 million. Purchases under this agreement totaled $36.5 million in 1999. COMPETITION - ----------- 1. GENERAL. In recent years, the electric utility industry has experienced a substantial increase in competition at the wholesale level, caused by changes in federal law and regulatory policy. Several states have also decided to restructure aspects of retail electric service. The issue of retail restructuring and competition is being reviewed by a number of states and bills have been introduced in Congress that seek to introduce such restructuring in all states. Allowing increased competition in the generation and sale of electric power will require resolution of many complex issues. One of the major issues to be resolved is who will pay for stranded costs. Stranded costs are those costs and investments made by utilities in order to meet their statutory obligation to provide electric service, but which could not be recovered through the market price for electricity following industry restructuring. The amount of such stranded costs that the Company might experience would depend on the timing of, and the extent to which, direct competition is introduced, and the then-existing market price of energy. If electric utilities were no longer subject to cost-based regulation and it were not possible to recover stranded costs, the financial position and results of operations of the Company could be adversely affected. 2. WHOLESALE COMPETITION. Since passage of the National Energy Act of 1992 (Energy Act), competition in the wholesale electric utility industry has significantly increased due to a greater participation by traditional 9 electricity suppliers, wholesale power marketers and brokers, and due to the trading of energy futures contracts on various commodities exchanges. This increased competition could affect 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. To assist in the development of wholesale competition, the FERC, in 1996, issued standards 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 contains provisions for the recovery of stranded costs and numerous other provisions that could affect 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 and other entities filed protests challenging numerous aspects of the Company's tariff and requesting that an evidentiary proceeding be held. The FERC set the matter for hearing and set a discovery and procedural schedule. In July 1997, the Company filed an offer of settlement in this matter. The administrative law judge certified the offer to the full FERC in September 1997. The offer is pending before the FERC. The Company cannot predict the outcome of this matter. On December 20, 1999, the FERC issued a rule on Regional Transmission Organizations (RTO) that sets forth four minimum characteristics and eight functions for transmission entities, including independent system operators and transmission companies, to become FERC-approved RTOs. The rule states that public utilities that own, operate or control interstate transmission facilities must file by October 15, 2000, either a proposal to participate in an RTO or an alternative filing describing efforts and plans to participate in an RTO. The Company plans to participate in an RTO and anticipates complying with this filing requirement. 3. RETAIL COMPETITION. The Energy Act prohibits the FERC from ordering retail wheeling - transmitting power on behalf of another producer to an individual retail customer. Several states have changed their laws and regulations to allow full retail competition. Other states are considering changes to allow retail competition. These changes and proposals have taken differing forms and included disparate elements. The Company believes changes in existing laws in both North and South Carolina would be required to permit competition in the Company's retail jurisdictions. 4. NORTH CAROLINA ACTIVITIES. In April 1997, the North Carolina General Assembly approved legislation establishing a 23-member study commission to evaluate the future of electric service in the state. During 1998, the study commission met and held public hearings around the state. The study commission also retained consultants to conduct analyses and studies concerning various restructuring issues, including stranded costs, state and local tax implications and electric rate comparisons. In June 1998, the study commission issued an interim report to the 1998 North Carolina General Assembly, summarizing the numerous fact-finding and educational activities and analytical projects the study commission had initiated or completed. That report offered no judgments or recommendations. In May 1999, the North Carolina General Assembly approved legislation that expanded the study commission from 23 to 29 members. All 29 study commission members were appointed by August 1999. The study commission conducted several meetings during August through November to discuss the reports regarding deregulation issues prepared by the Research Triangle Institute at the request of the study commission. During those meetings, several entities, including the Company and Duke, presented proposals for addressing the nearly $6 billion debt of North Carolina's Municipal Power Agencies. The study commission resumed meeting in January 2000. On 10 March 8, 2000, the commission co-chairs presented draft recommendations regarding electric industry restructuring to the full study commission for its consideration in preparing its report to the North Carolina General Assembly. Key recommendations in the draft include (i) electric retail competition should begin in North Carolina no later than June 30, 2006; (ii) recovery of utilities' stranded costs should not be extended beyond June 30, 2006; and (iii) the generation and distribution of assets of the municipal power agencies (including Power Agency) should be sold no later than June 30, 2002, and the funds from those sales should be used to pay off a portion of the municipal power agencies' debt. The draft recommendations also address issues related to the legislative timetable, consumer protection measures, environmental concerns, tax laws, and transmission and distribution. Implicit in recommendation is a rate freeze through the year 2006. Initial comments on the draft recommendations were due on March 10, 2000. The Company and other interested parties submitted comments. The draft recommendations will serve as a starting point for preparation of the study commission's report addressing industry restructuring in the State of North Carolina. The recommendations and related issues will be debated and discussed at future study commission meetings. The commission is expected to make a final report to the North Carolina General Assembly in the spring of 2000. The Company cannot predict the outcome of this matter. 5. SOUTH CAROLINA ACTIVITIES. The 1999 session of the South Carolina General Assembly adjourned in June 1999 without approving any legislation regarding electric industry restructuring. On October 29, 1998, the South Carolina Senate Judiciary Committee appointed a 13-member task force to study the restructuring issue and make a report to the Senate. The task force was subsequently expanded to 18 members, including the Company. The task force, including its various committees, has conducted several meetings to receive input from various experts and interested parties and to discuss issues related to restructuring. The House Public Utility Subcommittee is expected to continue considering the electric industry restructuring bills that were introduced in 1999, and the Senate task force is expected to continue to consider the issue of restructuring during the South Carolina General Assembly's 2000 legislative session. The Company cannot predict the outcome of these matters. 6. FEDERAL ACTIVITIES. During 1999, over 20 bills were introduced in Congress regarding electric industry restructuring. A draft bill passed the House Commerce Subcommittee on October 27, 1999. This bill will proceed to full Commerce Committee consideration in the first quarter of 2000 where it is expected to be changed significantly. The Company cannot predict the outcome of this matter. 7. COMPANY ACTIVITIES. The developments described above have created changing markets for energy. As a strategy for competing in these changing markets, the Company is becoming a total energy provider in the region by providing a full array of energy-related services to its current customers and expanding its market reach. The Company took a major step towards implementing this strategy, by entering into the Amended Agreement with FPC. In December 1998, the Company entered into an agreement to purchase all of the output of a combustion turbine project to be built, owned and operated by Broad River Energy, LLC (BRE), in Cherokee County, South Carolina. In conjunction with this agreement, the Company agreed to provide bridge financing to BRE under a Financing Term Sheet. This financing will be used by BRE to (i) make payments to Duke Energy in connection with certain electrical interconnection agreements, (ii) purchase two generator step up transformers and (iii) acquire land for the Broad River Energy Center Project. Under the terms of this agreement, the Company agreed to loan BRE up to $20.5 million that will be due on July 1, 2000. In 11 addition, in August of 1999 the Company agreed to loan Broad River Investors, LLC up to $84.5 million that will be due on July 1, 2000 to finance the purchase of the combustion turbines for the project. Interest on each of the loans is calculated based on the London Inter-Bank Offer Rate, LIBOR, plus a spread of 1%. In August 1999, the Company signed a five-year agreement with Municipal Electric Authority of Georgia (MEAG) pursuant to which MEAG will receive the full output of a 160 MW combustion turbine owned and operated by Monroe Power Company, a wholly owned subsidiary of the Company. Headquartered in Atlanta, Georgia, MEAG represents 48 municipal electric utilities in Georgia and is part owner of four generating facilities and the Georgia Integrated Transmission System. In August 1999, the Company signed an off-system wholesale peaking power sales agreement with Santee Cooper. The Company will provide up to 150 MW of additional peaking power for a one-year term from June 2001 to May 2002, to help meet the increasing demand in Santee Cooper's fast-growing service area. In October 1999, the Company and the Albemarle-Pamlico Economic Development Corporation (APEC) announced their intention to build an 850-mile natural gas transmission and distribution system to 14 currently unserved counties in eastern North Carolina. The Company will operate both the transmission and distribution systems and APEC will help ensure that the new facilities are built in the most advantageous locations to promote development of the economic base in the region. In conjunction with this proposal, the Company and APEC filed a joint request with the NCUC for $186 million of a $200 million state bond package established for clean water and natural gas infrastructure. If granted, these funds will be used to pay for the portion of the project that likely could not be recovered from future gas customers through rates. The Company plans to invest an additional $11.5 million, thus bringing the total cost of the project to $197.5 million. As proposed, the project is scheduled to be developed in phases through 2003. The NCUC has established a procedural schedule with hearings regarding the first phase of the project to be conducted in April 2000. An order is expected mid-2000. The Company cannot predict the outcome of this matter. In December 1999, the Company announced plans to build a 30-inch natural gas pipeline in North Carolina that will extend approximately 82 miles from Williams Energy's Transcontinental interstate pipeline in Iredell County to Richmond County. The pipeline will provide gas for the Company's planned new power plant in Richmond County and is scheduled to be completed during the spring of 2001. The pipeline is expected to cost approximately $100 million and will accommodate extension of natural gas service to future Company power plants and normal load growth on NCNG's system. This pipeline plan replaces a plan for a 175-mile pipeline, the Palmetto Pipeline that the Company and Southern Natural Gas Company, a subsidiary of El Paso Energy, had been assessing. 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 and liabilities resulting from the effects of the ratemaking process, which would not be recorded under generally accepted accounting principles for unregulated entities. The Company's ability to continue to meet the criteria for application of SFAS-71 may be affected in the future by competitive forces and restructuring in the electric utility industry. In the event that SFAS-71 no longer applied to a separable portion of the Company's operations, related regulatory assets and liabilities would be eliminated unless an appropriate regulatory recovery mechanism is provided. Additionally, these factors could 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." 12 CAPITAL REQUIREMENTS - -------------------- CAPITAL REQUIREMENTS. During 1999, the Company expended approximately $862 million for capital requirements. Estimated capital requirements for 2000 through 2002 primarily reflect construction expenditures to add generation, transmission and distribution facilities, as well as upgrade existing facilities. Those capital requirements are reflected in the following table (in millions):
2000 2001 2002 ------- ------- ------- Construction Expenditures $ 851 $ 876 $ 912 Nuclear Fuel Expenditures 64 94 66 AFUDC (21) (32) (38) Mandatory Retirements of Long-Term Debt 201 5 251 ------- ------- ------- TOTAL $ 1,095 $ 943 $ 1,191 ======= ======== =======
The table includes expenditures of approximately $311 million expected to be incurred at fossil-fueled electric generating facilities to comply with the Clean Air Act. In addition, the Company has total projected cash requirements of approximately $565 million over the years 2000 through 2002 relating to expenditures in other areas such as affordable housing investments and merchant generation. These projections are periodically reviewed and may change significantly. FINANCING REQUIREMENTS - ---------------------- 1. FINANCING REQUIREMENTS. The proceeds from the issuance of commercial paper and/or internally generated funds financed the retirement of long-term debt totaling $113 million in 1999. In addition, the issuance of $500 million extendible notes in October 1999, financed the retirement of $100 million of extendible commercial notes and reduced the outstanding commercial paper balance. External funding requirements, which do not include early redemptions of long-term debt, redemption of preferred stock or issuances in conjunction with acquisitions, are expected to approximate $490 million, $580 million and $640 million in 2000, 2001 and 2002, respectively. These funds will be required for construction, mandatory retirements of long-term debt and general corporate purposes. 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 long-term debt, the redemption of preferred stock, the reduction of short-term debt or for other general corporate purposes. 2. SEC FILINGS. i) The Company has on file with the Securities and Exchange Commission (SEC) a shelf registration statement (File No. 333-69237) under which first mortgage bonds, senior notes and other debt securities are available for issuance by the Company. As of December 31, 1999, the Company had $600 million available under this shelf registration. ii) 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. 13 3. ISSUANCES OF BONDS, PREFERRED STOCK AND DEBENTURES. --------------------------------------------------- External financings during 1999 included: i) The issuance on March 5, 1999 of $400 million principal amount of Senior Notes, 5.95% Series due on March 1, 2009. The net proceeds were used to reduce the outstanding balance of commercial paper and for other general corporate purposes. ii) In October 1999, the Company issued $500 million of unsecured Extendible Notes with a final maturity of October 28, 2009, and an initial reset period from October 28, 1999 to July 28, 2000 at an interest rate to be reset and payable on a monthly basis at a rate equal to the one month LIBOR plus a spread of 0.33%. The net proceeds from this issuance were used to reduce commercial paper borrowings and other short-term indebtedness. 4. REDEMPTIONS/RETIREMENTS OF BONDS, PREFERRED STOCK AND DEBENTURES. ---------------------------------------------------------------- Redemptions and retirements during 1999 included: i) The retirement on July 1, 1999 of $50 million principal amount of First Mortgage Bonds, Medium Term Notes, 7.15% Series B, which matured on that date. ii) The redemption on August 9, 1999 of $25 million principal amount of, 9.21% Debentures Series C, due November 15, 2011 on behalf of NCNG. iii) The redemption on August 13, 1999 of $30 million principal amount of, 7.15% Debentures Series, due November 15, 2015 on behalf of NCNG. 5. CREDIT FACILITIES. As of December 31, 1999, the Company's revolving credit facilities totaled $750 million, all of which are long-term agreements. The Company is required to pay minimal annual commitment fees to maintain its credit facilities. Consistent with management's intent to maintain its commercial paper, pollution control revenue refunding bonds (pollution control bonds) and other short-term indebtedness on a long-term basis, and as supported by its long-term revolving credit facilities, the Company included in long-term debt commercial paper, pollution control bonds and other short-term indebtedness outstanding of approximately $363 million, $56 million and $331 million, respectively, as of December 31, 1999. Commercial paper and pollution control bonds outstanding of approximately $488 million and $56 million, respectively, were reclassified as long-term debt as of December 31, 1998. See PART II, ITEM 8, "Consolidated Financial Statements and Supplementary Data," Note 6, for a more detailed discussion of the Company's revolving credit facilities. 6. COMMERCIAL NOTES. In September 1999, the Company established a $150 million extendible commercial notes program. As of December 31, 1999, there were no extendible commercial notes outstanding. 7. CREDIT RATINGS. The Company's access to outside capital depends on its ability to maintain its credit ratings. The Company's credit ratings are as follows: 14
Moody's Duff and Phelps Investors Service Standard and Poor's --------------- ----------------- ------------------- First Mortgage Bonds A+ A2 A Commercial Paper D-1 P-1 A-1 Extendible Commercial Notes N/A P-1 A-1 Extendible Notes D-1 P-1 A-1
The following is a summary of the meanings of the ratings shown above and the relative rank of the Company's rating within each agency's classification system. Duff and Phelps' top four bond ratings (AAA, AA, A and BBB) are considered "investment grade." Debt that is rated "A" is considered upper grade securities which possess adequate protection factors but risk factors that are more variable in periods of economic stress. Duff and Phelps may use a plus (+) or minus (-) sign to designate the relative position of a credit within the rating category. Moody's top four bond ratings (Aaa, Aa, A and Baa) are generally considered "investment grade." Obligations that are rated "A" possess many favorable investment attributes and are considered as upper medium grade obligations. Factors giving security to principal and interest are considered adequate but elements may be present which suggest a susceptibility to impairment sometime in the future. A numerical modifier ranks the security within the category with a "2" indicating the mid-range. Standard & Poor's top four bond ratings (AAA, AA, A and BBB) are considered "investment grade." Debt rated "A" has a strong capacity to pay interest and repay principal although it is somewhat more susceptible to the adverse effects of changes in economic conditions than debt in higher rated categories. Standard & Poor's may use a plus (+) or minus (-) sign after ratings to designate the relative position of a credit within the rating category. Duff and Phelps' top three commercial paper ratings (D-1, D-2 and D-3) are generally considered "investment grade." Issuers rated "D-1" have a very high certainty of timely payment, liquidity factors are excellent and risk factors are minor. Moody's top three commercial paper ratings (P-1, P-2 and P-3) are generally considered "investment grade." Issuers rated "P-1" have a superior ability for repayment of senior short-term debt obligations and repayment ability is often evidenced by a conservative structure, broad margins in earnings coverage of fixed financial charges and well established access to a range of financial markets and assured sources of alternate liquidity. Standard & Poor's commercial paper ratings are a current assessment of the likelihood of timely payment of debt having an original maturity less than 365 days. The top three Standard & Poor's commercial paper ratings (A-1, A-2 and A-3) are considered "investment grade." Issues rated "A-1" indicate that the degree of safety regarding timely payment is either overwhelming or very strong. Those issues determined to possess overwhelming safety are denoted with a plus (+) sign designation. 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. The Company is also subject to regulation in North Carolina by the NCUC with respect to rates and service for the transmission, distribution, and sale of natural gas in portions of North Carolina. 2. ELECTRIC RETAIL RATES. The rates of return granted to the Company in its most recent general rate cases are as follows: 15
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% 0.65% 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% 0.65% Common Equity 44.72% 12.75% 5.71% ------- Rate of Return 10.48% =======
3. NATURAL GAS RATES. On October 27, 1995, the NCUC issued its Order granting a general rate increase amounting to $4.2 million in annual revenues effective November 1, 1995. The Commission's Order approved, in all material respects, the Stipulation of Settlement reached among NCNG, the NCUC Public Staff, which represents the using and consuming public, the Carolina Utility Customers Association, Inc. (CUCA) and other intervenors in the rate case. The Order provides for a rate of return on net investment of 10.09% but, pursuant to the Stipulation of Settlement, did not state separately the rate of return on common equity nor the capital structure used to calculate revenue requirements. 4. OTHER RETAIL RATE MATTERS. Pursuant to authorizations from the NCUC and the SCPSC, the Company began to accelerate the amortization of certain regulatory assets over a three-year period beginning January 1997 and expiring December 1999. The accelerated amortization of these regulatory assets resulted in additional depreciation and amortization expenses of approximately $68 million in each year of the three-year period. In 1996, the NCUC also authorized the Company to defer operation and maintenance expenses of approximately $40 million associated with Hurricane Fran, with amortization over a 40-month period, which expired December 1999. In late 1998 and early 1999, the Company filed, and the respective commissions subsequently approved, proposals in the North and South Carolina retail jurisdictions to accelerate cost recovery of its nuclear generating assets beginning January 1, 2000 and continuing through 2004. The accelerated cost recovery begins immediately after the 1999 expiration of the accelerated amortization of certain regulatory assets, which began in January 1997. Pursuant to the orders, the Company's depreciation expense for nuclear generating assets will increase by a minimum of $106 million up to a maximum of $150 million per year. Recovering the costs of the nuclear generating assets on an accelerated basis will better position the Company for the uncertainties associated with potential restructuring of the electric utility industry. In conjunction with the acquisition, the Company and NCNG signed a joint stipulation agreement with the Public Staff of the NCUC in which the Company agreed to cap base retail electric rates, exclusive of fuel 16 costs, with limited exceptions, through December 2004, and NCNG agreed to cap margin rates for gas sales and transportation services, with limited exceptions, through November 1, 2003. Management is of the opinion that this agreement will not have a material effect on the consolidated results of operations or financial position of the Company. 5. 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. In the past, utilities were 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. During 1998, the NCUC and SCPSC substantially altered their IRP rules. Both the NCUC and SCPSC reduced the amount of information that must be included in the Company's IRP. The NCUC also eliminated the triennial IRP and now requires an annual filing. 6. FUEL COST RECOVERY. ------------------ a) 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 3, 1999, the Company filed its 1999 fuel cost recovery application. The NCUC issued a final order approving the Company's proposed billing fuel factor of 1.057 cents/kWh on September 9, 1999. This new factor became effective on September 15, 1999. On October 8, 1999, CUCA appealed the Commission's decision. b) 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. The Company's fuel hearing was held on March 24, 1999 and by order issued April 1, 1999, the SCPSC approved the Company's proposed continuation of the existing fuel factor of 1.122 cents/kWh. 7. AVOIDED COST PROCEEDINGS. In 1998, the NCUC opened Docket No. E-100, Sub 81 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 6, 1998. Intervenor comments on the utilities' filings were filed January 15, 1999, and a hearing for non-expert public witnesses was held on February 2, 1999. By order issued July 16, 1999, the NCUC approved the Company's proposed avoided cost rates. WHOLESALE RATE MATTERS - ---------------------- 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 17 adjusted since that time through contractual negotiations. 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. Environmental laws and regulations constantly evolve and the ultimate costs of compliance cannot always be accurately estimated. The capital costs associated with compliance with pollution control laws and regulations at the Company's existing fossil facilities that the Company expects to incur from 2000 through 2002 are included in the estimates under PART I, ITEM 1, "Capital Requirements." 2. CLEAN AIR LEGISLATION. The 1990 amendments to the Clean Air Act require substantial reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fueled electric generating plants. The Clean Air Act required the Company to meet more stringent provisions effective January 1, 2000. The Company will meet the sulfur dioxide emissions requirements by maintaining sufficient sulfur dioxide emission allowances. Installation of additional equipment was necessary to reduce nitrogen oxide emissions. Increased operation and maintenance costs, including emission allowance expense, installation of additional equipment and increased fuel costs are not expected to be material to the consolidated financial position or results of operations of the Company. The EPA has been conducting an enforcement initiative related to a number of coal-fired utility power plants in an effort to determine whether modifications at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The Company has recently been asked to provide information to the EPA as part of this initiative and has cooperated in providing the requested information. The EPA has initiated enforcement actions which may have potentially significant penalties against other companies that have been subject to this initiative. The Company cannot predict the outcome of this matter. On October 27, 1998, the EPA published a final rule addressing the issue of regional transport of ozone. This rule is commonly known as the NOx SIP call. The EPA's rule requires 22 states, including North and South Carolina, to further reduce nitrogen oxide emissions in order to attain a pre-set state NOx emission level by May 2003. The EPA's rule also suggests to the states that these additional nitrogen oxide emission reductions be obtained from the utility sector. The Company is evaluating necessary measures to comply with the rule and estimates its related capital expenditures through 2003 could be approximately $327 million, a portion of which is reflected in the "Capital Requirements" discussion under PART II, ITEM 7, "Liquidity and Capital Resources." Increased operation and maintenance costs relating to the NOx SIP call are not expected to be material to the Company's results of operations. The Company and the states of North and South Carolina have been participating in litigation challenging the NOx SIP call. On March 3, 2000, a three-judge panel of the District of Columbia Circuit Court of Appeals upheld the EPA's NOx SIP call. Further appeals are being considered. The Company cannot predict the outcome of this matter. The EPA published a final rule approving certain petitions under the Clean Air Act that requires certain sources to make reductions in nitrogen oxide emissions by 2003. The Company's fossil-fueled electric 18 generating plants in North Carolina are included in these petitions. The Company and other states are participating in litigation challenging the EPA's actions. 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 to require the clean up of hazardous waste sites. This statute imposes retroactive joint and several liability. Some states, including North and South Carolina, have similar types of legislation. 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. 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 both the electric utility and the gas utility have some connection. In this regard, the electric utility and the gas utility, along with others, are participating in a cooperative effort with the North Carolina Department of Environment and Natural Resources, Division of Waste Management (DWM), which has established a uniform framework to address MGP sites. The investigation and remediation of specific MGP sites will be addressed pursuant to one or more Administrative Orders on Consent (AOC) between the DWM and the potentially responsible party or parties. Both the electric utility and the gas utility have signed AOCs to investigate certain sites. Both the electric utility and the gas utility continue to identify parties connected to individual MGP sites, and to determine their relationships to other parties at those sites and the degree to which the Company will undertake efforts with others at individual sites. The Company does not expect the costs associated with these sites to be material to the consolidated financial position or results of operations of the Company. The Company is periodically notified by regulators such as the North Carolina Department of Environment and Natural Resources, the South Carolina Department of Health and Environmental Control, and the U.S. Environmental Protection Agency (EPA) of its involvement or potential involvement in sites, other than MGP sites, that may require investigation and/or remediation. Although the Company may incur costs at these sites about which it has been notified, based upon current status of these sites, the Company does not expect those costs to be material to the consolidated financial position or results of operations of the Company. 4. OTHER ENVIRONMENTAL MATTERS. The Company has filed claims with its general liability insurance carriers to recover costs arising out of actual or potential environmental liabilities. Some claims have been settled, and others are still being pursued. The Company cannot predict the outcome of these matters. 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 19 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 disposal facilities for low-level radioactive waste and storage facilities for spent nuclear fuel. See paragraphs 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 2000, 2001 and 2002 are expected to total approximately $41 million, $80 million and $29 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. As of December 31, 1999, sufficient on-site spent nuclear fuel storage capability is available for the full-core discharge of Brunswick Unit No. 1 through 2001, Brunswick Unit No. 2 through 2000, Robinson Unit No. 2 through 2000 and Harris through 2002 assuming normal operating and refueling schedules. The spent fuel storage facilities at the Brunswick and Robinson Units along with the Harris Plant spent fuel storage facilities are sufficient to provide storage space for spent fuel generated by all of the Company's nuclear generating units through the expiration of their current operating licenses, provided that currently idle storage space at the Harris Plant can be activated. On December 23, 1998, the Company submitted a license amendment application to the NRC requesting approval to activate and begin using the additional spent fuel storage at the Harris Plant. The Company is maintaining full-core discharge capability for the Brunswick Units and Robinson Unit No. 2 by transferring spent nuclear fuel by rail to the Harris Plant. As a contingency to the shipment by rail of spent nuclear fuel, during April 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. At the Company's request, the NRC suspended review of the Company's license application based on the success of the Company's shipping efforts. The NRC will resume review of the license upon notification by the Company of its desire to continue the application process. Subsequent to the expiration of the licenses, dry storage may be necessary in conjunction with the decommissioning of the units. 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. The Company cannot predict the outcome of these matters. 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 begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract. In April 1995, the DOE issued a final interpretation that it did not have an unconditional obligation to take spent nuclear fuel by January 31, 1998. In Indiana & Michigan Power v. DOE, the U.S. Court of Appeals vacated the DOE's final interpretation and ruled that the DOE had an unconditional obligation to begin taking spent nuclear fuel. The Court did not specify a remedy because the DOE was not yet in default. After the DOE failed to comply with the decision in Indiana & Michigan Power v. DOE, a group of utilities (including the Company) petitioned the U.S. Court of Appeals in Northern States Power (NSP) v. DOE, seeking an order requiring the DOE to begin taking spent nuclear fuel by January 31, 1998. The DOE took the position that their delay was unavoidable, and the DOE was excused from performance under the terms 20 and conditions of the contract. The Court of Appeals issued an order that precluded the DOE from treating the delay as an unavoidable delay. However, the Court of Appeals did not order the DOE to begin taking spent nuclear fuel, stating that the utilities had a potentially adequate remedy by filing a claim for damages under the contract. After the DOE failed to begin taking spent nuclear fuel by January 31, 1998, a group of utilities (including the Company) filed a motion with the U.S. Court of Appeals to enforce the mandate in NSP v. DOE. Specifically, the utilities asked the Court to permit the utilities to escrow their waste fee payments, to order the DOE not to use the waste fund to pay damages to the utilities, and to order the DOE to establish a schedule for disposal of spent nuclear fuel. The Court denied this motion based primarily on the grounds that a review of the matter was premature and that some of the requested remedies fell outside of the mandate in NSP v. DOE. Subsequently, a number of utilities each filed an action for damages in the Court of Claims and before the Court of Appeals. The Company is in the process of evaluating whether it should file a similar action for damages. In NSP v. United States, the United States Court of Claims decided that NSP must pursue its administrative remedies instead of filing an action in the Court of Claims. NSP has filed an interlocutory appeal to the U.S. Court of Appeals based on NSP's position that the Court of Claims has jurisdiction to decide the matter. A group of utilities (including the Company) has submitted an amicus brief in support of NSP's position. The Company also continues to monitor legislation that has been introduced in Congress which might provide some limited relief. The Company cannot predict the outcome of this matter. With certain modifications and additional approval by the NRC, the Company's spent nuclear fuel storage facilities will be 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. The Company has initiated the process of obtaining the additional NRC approval. 3. LOW-LEVEL RADIOACTIVE WASTE. Disposal costs for low-level radioactive waste that result 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 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. In December 1997, the Southeast Regional Compact Commission suspended funding for the proposed low-level radioactive waste facility in Wake County. The future funding for this project remains uncertain. Although the Company does not control the future 21 availability of low-level waste disposal facilities, the cost of waste disposal or the development process, it supports 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 consolidated financial position or results of operations 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 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 June 1991, the Company began depositing funds into an external trust as a vehicle to achieve such decommissioning funding. 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 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 expense, were $33.3 million, $33.3 million, and $33.2 million in 1999, 1998, and 1997, respectively. Accumulated decommissioning costs, which are included in accumulated depreciation, were $568.0 million and $496.3 million at December 31, 1999 and 1998, respectively. These costs include amounts retained internally and amounts funded in an external decommissioning trust. The balance of the nuclear decommissioning trust was $379.9 million and $310.7 million at December 31, 1999 and 1998, respectively. Trust earnings increase the trust balance with a corresponding increase in the accumulated decommissioning balance. These balances are adjusted for net unrealized gains and losses related to changes in the fair value of trust assets. Based on the site-specific estimates discussed below, and using an assumed after-tax earnings rate of 7.75% 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 1998, using 1998 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 1998 dollars, are $279.8 million for Robinson Unit No. 2, $299.3 million for Brunswick Unit No. 1, $298.5 million for Brunswick Unit No. 2, and 22 $328.1 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. 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 Capability," paragraph 1. c) The Financial Accounting Standards Board is proceeding with its project regarding accounting practices related to obligations associated with the retirement of long-lived assets, and an exposure draft of a proposed accounting standard was issued during the first quarter of 2000. It is uncertain what effects it may ultimately have on the Company's accounting for nuclear decommissioning and other retirement costs. 5. OPERATING LICENSES. Facility Operating Licenses, issued by the NRC, for the Company's nuclear units allow for a full 40 years of operation. Expiration dates for these licenses are set forth in the following table. 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. In March 1998, the Company's Maintenance Rule Program was found acceptable by the NRC during baseline inspections. b) Degradation of tubing internal to steam generators in pressurized water reactor power plants 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 degradation and plans to replace the steam generators in 2001. The steam generators at the Robinson plant were replaced in 1984 and are expected to perform until the plant's operating license expires. The Company does not expect the costs associated with replacing the steam generators at the Harris Plant to be material to the consolidated financial position or results of operations of the Company. c) The Company is insured against public liability for a nuclear incident up to $9.7 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, 23 the Company would be subject to a pro rata assessment of up to $83.9 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. For a more detailed discussion of nuclear liability insurance, see PART II, ITEM 8, "Consolidated Financial Statements and Supplementary Data," Note 16b. FUEL - ---- 1. SOURCES OF GENERATION. Total system generation (including Power Agency's share) by primary energy source, along with purchased power, for the years 1996 through 2000 is set forth below: 1996 1997 1998 1999 2000 ---- ---- ---- ---- ---- (estimated) Fossil 45% 46% 47% 48% 48% Nuclear 41 43 42 42 41 Purchased Power 12 10 9 8 8 Hydro 2 1 1 1 1 Combustion Turbine -- -- 1 1 2 2. COAL. The Company has intermediate and long-term agreements from which it expects to receive approximately 80% of its coal burn requirements in 2000. These agreements have expiration dates ranging from 2000 to 2006. 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. See PART I, ITEM 1, "Environmental Matters," paragraph 2. The average cost (including transportation costs) to the Company of coal delivered for 1999 was $41.98 per ton. 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 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 the lack of No. 2 oil availability, twelve combustion turbine units with a total generating capacity of 766 MW can also burn natural gas. Over the last five years, No. 2 oil, natural gas and propane accounted for 2.89% of the Company's total burned fuel cost. In 1999, No. 2 oil, natural gas and propane accounted for 4.37% 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), and 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 all of the Company's nuclear generating facilities through 2001. 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 24 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." 5. DOE ENRICHMENT FACILITIES DECONTAMINATION AND DECOMMISSIONING (D&D) 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 which have purchased enrichment services from DOE since it began sales to non-Department of Defense customers. Each utility's share of the contributions is based on that utility's past purchases of services as a percentage of all purchases of services by U.S. utilities. Total annual contributions are capped at $150 million per year with an overall cap of $2.25 billion over 15 years both indexed to inflation. The Company has paid approximately $40 million in D&D fees through 1999, and expects to pay a cumulative total of approximately $82 million over the 15 year period ending September 30, 2007 (excluding Power Agency's ownership share). The Company is recovering these costs as a component of fuel cost. During March 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, seeking a refund of part of the price paid by the Company for enrichment services purchased from the DOE. It is the Company's position that the contract price it paid to the DOE for uranium purchases included the cost of D&D, and that the DOE's collection of additional D&D fees pursuant to the Energy Act resulted in an overpayment of fees by the Company. In addition, the claim requested the elimination of future D&D fund assessments. It was 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. The Company's action was stayed pending the outcome of a similar case, Yankee Atomic Electric Company (Yankee Atomic) v. United States (33 Fed.Cl. 580 (Cl.Ct. 1995)), in which the United States Court of Claims found that a portion of the D&D assessments made against Yankee Atomic were unlawful. The government appealed that case to the District of Columbia Circuit Court of Appeals, which subsequently overturned the favorable Court of Claims decision. After the Circuit Court of Appeals refused to rehear the matter, Yankee Atomic filed a petition for a certiorari to seek a review by the United States Supreme Court, which was denied. During February 1999, the Company amended its complaint for various reasons, and the government subsequently filed a motion to dismiss. The total refund demanded in the Company's amended complaint through the date of the complaint filing (including Power Agency's ownership share) is approximately $39 million. The Company cannot predict the outcome of this matter. 6. PURCHASED POWER. The Company purchased 4,730,657 MWh in 1999, 5,336,867 MWh in 1998, and 5,886,722 MWh in 1997 or approximately 8%, 9%, and 10%, respectively, of its system energy requirements (including Power Agency) and had available 1,489 MW in 1999, 1,438 MW in 1998, and 1,839 MW in 1997 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. NATURAL GAS SUPPLY - ------------------ During 1999, the Company purchased 7,647,462 dekatherms (dt) of natural gas under its firm sales contracts on the pipeline/utility. It purchased 20,023,674 dt in the spot market or from other nontraditional sources, including long-term contracts with producers or national gas marketers. The Company also transported 6,961,187 dt of customer-owned gas in 1999. The outlook for natural gas supplies in the Company's service area remains favorable and the Company has many sources of gas available on a firm basis. Nationally, gas supplies are adequate and no supply curtailments are anticipated. 25 The following table summarizes the supply sources which are under contract or otherwise available to the Company as of December 31, 1999.
Maximum Contract Daily Annual Expiration Deliverability (a) Quantity (a) Date Dt dt Transco - Firm Transportation (FT) 145,935 (b) 53,266,275 2013 Firm Sales (FS) 55,935 20,416,275 2001 General Storage (GSS) 2,070 98,790 2013 Washington Storage (WSS) 32,154 (c) 2,734,180 Liquefied Gas Storage (LG-A) 5,320 26,600 2016 Southern Expansion (FT) 16,871 (b) (d) 2,444,553 2005 Eminence Storage (ESS) 39,373 (g) 316,914 2013 Columbia Gas Transmission - Firm Transportation (FT) 19,801 (b) 7,227,365 2004 Firm Storage Services (FSS) 5,199 223,238 2004 Amerada Hess - Firm Sales 15,000 (e) (f) 3,732,750 2004 Firm Sales 25,000 (f) 9,125,000 2001 Conoco, Inc. - Firm Sales 10,000 (e) (f) 2,580,000 2001 Coral Energy Resources - Firm Sales 25,000 (e) (f) 6,450,000 2000 Amoco Energy Trading Corp. - Firm Sales 25,000 (f) 9,125,000 2001 Columbia Energy - Firm Sales 25,000 (f) 9,125,000 2001 PanCanadian Energy - Firm Sales 25,000 (f) 9,125,000 2001 Exxon Company, U.S.A. - Firm Sales 14,888 (f) 5,434,120 2003 Southern Company Energy Marketing - Firm Sales 25,000 (f) 9,125,000 2001 MEG Marketing - Firm Sales 5,000 (d) (f) 755,000 2001 LNG Plant (Company Owned) - 97,200 (h) 1,000,000 N/A
26 (a) Quantities are shown in dekatherms (dt) (one dt equals 1,000,000 Btu or one Mcf at Btu/cu. ft.). (b) Firm Transportation (FT) contracts are for pipeline capacity only. The Company is responsible for acquiring its own gas supplies to be transported on a firm basis under the FT contracts. Gas supplies are available under the Transco Firm Sales (FS) Agreement, other long-term agreements (See f below), multi-month term agreements or agreements of one month or less for supplies purchased in the spot market. (c) Washington Storage volumes may be withdrawn to the extent that the basic contract gas from Transco or other suppliers is unavailable on any day or if the Company elects to take such gas instead of other supplies. Service has continued subsequent to contract expiration under provisions of Transco's FERC tariff. FERC approval of abandonment would be required to terminate service. (d) Winter months only (November through March). (e) Provides for a lower daily deliverability volume in the summer period (April through October). (f) Contracts are for gas supply only - no pipeline capacity is included. Supplies purchased from these suppliers flow on the Company's FT contracts with Transco (See b above). (g) Transco salt dome storage capacity allocated to customers of Transco FS sales service by mandate of FERC order 636. Transco schedules injections and withdrawals of gas from Eminence storage capacity under agency agreements with the Company and the other FS sales service customers. (h) Deliverability of Company's transmission pipeline capacity to distribute supplies withdrawn from storage at the Company's LNG plant under normal operating conditions. DIVERSIFIED BUSINESSES - ---------------------- In 1999, the Company formed Monroe Power Company (Monroe), a wholly owned subsidiary. Monroe is a North Carolina corporation, authorized to do business in Georgia where it owns and operates a combustion turbine, which became operational in December 1999. In 1999, the Company completed the sale of Parke, a division of SRS that performed lighting retrofit services. In 1998, the Company formed Powerhouse Square, LLC, to facilitate the renovation of several historic buildings in North Carolina. OTHER MATTERS - ------------- 1. SAFETY INSPECTION REPORTS. In April 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, which is required every five years under the FERC Regulation 18 CFR Part 12, for the Walters Hydroelectric Project and requested the Company to undertake certain supplemental analyses and investigations regarding the stability of the dam under extreme and improbable loading conditions. In November 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. In February 1997, the Company received a letter from 27 the FERC pertaining to the Company's inspection report filed in November 1994. The FERC submitted comments on the inspection report and requested that further analysis be conducted. The Company filed a response in April 1997. In its response, the Company agreed with some of the FERC's comments and took exception to others. In November 1998, the Company received a letter from the FERC pertaining to the Company's April 1997 letter. The Company filed a response in December 1998, which provided information on a plan to further investigate the dam abutments and which addresses FERC's revised dynamic evaluation criteria. 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 this matter. Similar letters were sent by the FERC during May 1990 with respect to the Company's Blewett and Tillery Hydroelectric Plants. The matters raised in the May 1990 letters from the FERC are still under investigation. 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 filed the Seventh (1998) Part 12 Report for the Tillery Hydroelectric Plant in November 1998 in accordance with a request from the FERC. The Tillery report does not indicate any deficiencies that would endanger the integrity of the dam. The consultant's Seventh Part 12 Report regarding the Blewett Hydroelectric Plant has been developed but, as requested by the FERC, has not been filed. The FERC is developing comments on earlier filings from the Company and has indicated that additional investigation and analyses may be required. The Company has agreed to await the comments from the FERC and incorporate the consultant's responses into the Seventh Part 12 Report. A review of the draft of the Seventh Part 12 Report for Blewett reveals that the consultant did not identify any critical dam safety deficiencies. The Company cannot predict the outcome of this matter. 2. MARSHALL HYDROELECTRIC PROJECT. In November 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 the FERC guidelines and engaged its independent consultant to perform a safety inspection. In April 1992 the inspection report was submitted to the FERC for approval. In March 1995 the Company received comments on the inspection report from the FERC. As a result of these comments, and a meeting with the 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 in September 1995. Depending on the outcome of the FERC's review, the Company could be required to undertake 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. TAX REFUND DISPUTE. In April 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. During December 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. 28 4. YEAR 2000. The Company's critical systems, devices and applications successfully made the transition to the Year 2000. It is possible, however, that the Company, its vendors, distributors, suppliers or customers may encounter future Year 2000-related problems. If this should occur, we do not expect to experience any material adverse effects on our business, financial condition or results of operations. As of January 31, 2000, the Company had incurred and expensed approximately $18 million related to the inventory, assessment and remediation of non-compliant systems, equipment and applications. The Company does not expect additional costs related to the Year 2000 Project to be material to the consolidated financial position or results of operations of the Company. EMPLOYEES - --------- At December 31, 1999, the Company had 7,752 full-time employees. The Company has a noncontributory defined benefit retirement plan for substantially all full-time employees and an employee stock purchase plan among other employee benefits. The Company also provides contributory postretirement benefits, including certain health care and life insurance benefits, for substantially all retired employees. 29
OPERATING STATISTICS-ELECTRIC - ----------------------------- Years Ended December 31 1999 1998 1997 1996 1995 ---------- ---------- ---------- ---------- ---------- Energy supply (millions of kWh) Generated - coal 28,260 27,576 25,545 24,859 23,517 nuclear 22,451 22,014 21,690 20,284 19,949 hydro 520 790 799 882 824 combustion turbines 435 386 189 68 56 Purchased 5,132 5,675 6,318 7,292 7,433 ---------- ---------- ---------- ---------- ---------- Total energy supply (Company share) 56,798 56,441 54,541 53,385 51,779 Power Agency share (c) 4,353 4,349 4,101 3,616 3,828 ---------- ---------- ---------- ---------- ---------- Total system energy supply 61,151 60,790 58,642 57,001 55,607 ========== ========== ========== ========== ========== Average fuel cost (per million BTU) Fossil $ 1.75 $ 1.71 $ 1.75 $ 1.75 $ 1.83 Nuclear fuel $ .46 $ 0.46 $ 0.46 $ 0.45 $ 0.46 All fuels $ 1.16 $ 1.14 $ 1.14 $ 1.14 $ 1.17 Energy sales (millions of kWh) Retail Residential 13,318 13,117 12,488 12,611 12,074 Commercial 11,074 10,664 10,010 9,615 9,276 Industrial 14,473 14,911 15,073 14,456 14,312 Other Retail 1,352 1,357 1,294 1,263 1,288 Wholesale 14,542 14,427 13,900 13,383 12,940 ---------- ---------- ---------- ---------- ---------- Total energy sales 54,759 54,476 52,765 51,328 49,890 Company uses and losses 2,039 1,964 1,776 2,057 1,889 ---------- ---------- ---------- ---------- ---------- Total energy requirements 56,798 56,440 54,541 53,385 51,779 ========== ========== ========== ========== ========== Electric customers billed Residential 1,020,864 996,398 972,385 945,703 920,495 Commercial 183,914 178,588 172,821 167,151 159,064 Industrial 5,045 5,056 5,072 5,066 4,863 Government and municipal 2,731 2,757 2,785 2,774 2,328 Resale 39 35 43 27 17 ---------- ---------- ---------- ---------- ---------- Total electric customers billed 1,212,593 1,182,834 1,153,106 1,120,721 1,086,767 ========== ========== ========== ========== ========== Electric revenues (in thousands) Retail $2,519,348 $2,532,234 $2,450,509 $2,417,011 $2,399,354 Wholesale 549,870 528,253 507,720 512,579 560,676 Miscellaneous revenue 69,628 69,558 65,860 66,125 46,523 ---------- ---------- ---------- ---------- ---------- Total electric revenues $3,138,846 $3,130,045 $3,024,089 $2,995,715 $3,006,553 ========== ========== ========== ========== ========== Peak demand of firm load (thousands of kW) System 10,948 10,529 10,030 9,812 10,156 Company 10,344 9,875 9,344 9,264 9,500 Total capability at year-end (thousands of kW) (a) Fossil plants 6,736 6,571 6,571 6,331 6,331 Nuclear plants 3,174 3,174 3,064 3,064 3,064 Hydro plants 218 218 218 218 218 Purchased 1,088 1,538 1,588 1,603 1,592 ---------- ---------- ---------- ---------- ---------- Total system capability 11,216 11,501 11,441 11,216 11,205 Less Power Agency-owned portion (b) 593 593 690 686 682 ---------- ---------- ---------- ---------- ---------- Total Company capability 10,623 10,908 10,751 10,530 10,523 ========== ========== ========== ========== ==========
(a) Represents maximum dependable capacity of installed generating units plus other resources, including firm purchases. For 1999, total system capability during the summer was higher by 800 MW for term purchase contracts in place at time of summer peak. (b) Net of the Company's purchases from Power Agency. (c) Represents Power Agency's share of the energy supplied from the four generating facilities that are jointly owned. 30
OPERATING STATISTICS-NATURAL GAS* --------------------------------- Year Ended December 31, 1999 --------------- Natural gas sales and transportation revenues (in thousands) Residential $ 14,259 Commercial 12,433 Industrial 49,317 Electric Utilities 10,395 Wholesale 12,464 Other 35 --------------- Total natural gas sales and transportation revenues $ 98,903 =============== Natural gas sales (in thousands of dt) Residential 1,601 Commercial 2,165 Industrial 17,755 Electric Utilities 1,960 Wholesale 4,083 --------------- Total natural gas sales 27,564 =============== Gas sold 20,711 Gas transported 6,853 --------------- Total natural gas sales 27,564 =============== Customers billed (peak month) Residential 102,579 Commercial 13,856 Industrial and electric utilities 473 Wholesale 50,345 Propane 10,747 --------------- Total gas customers billed 178,000 ===============
*Statistics reflect natural gas operations since the acquisition of NCNG by the Company. 31 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. Weatherspoon North Carolina 6. Morehead North Carolina The Company's sixteen power plants represent a flexible mix of fossil, nuclear and hydroelectric resources in addition to combustion turbines, with a total generating capacity (including Power Agency's share) of 10,128 megawatts (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, food, rubber and plastics, wood products, and electronic machinery and equipment. The Company, through Monroe, a wholly owned subsidiary, owns and operates a combustion turbine in Georgia. The full output of 160 MW is received by MEAG, which represents 48 municipal electric utilities located in Georgia. At December 31, 1999, the Company had 5,585 pole miles of transmission lines including 292 miles of 500 kilovolt (kV) lines and 2,857 miles of 230 kV lines, and distribution lines of approximately 44,294 pole miles of overhead lines and approximately 13,842 miles of underground lines. Distribution and transmission substations in service had a transformer capacity of approximately 34,654 kilovolt-ampere (kVA) in 2,028 transformers. Distribution line transformers numbered 436,334 with an aggregate 18,599,000 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 owns and operates a liquefied natural gas storage plant which provides 120,000 dekatherms (dt) per day to the Company's peak-day delivery capability. The Company owns approximately 1,128 miles of transmission pipelines of two to 16 inches in diameter which connect its distribution systems with the Texas-to-New York transmission system of Transco and the southern end of Columbia's transmission system. Transco delivers gas to the Company at various points conveniently located with respect to the Company's distribution area. Columbia delivers gas to one delivery point near the North Carolina - Virginia border. Gas is distributed by the Company through 2,865 miles of distribution mains. These transmission pipelines and distribution mains are located primarily on rights-of-way held under easement, license or permit on lands owned by others. The Company believes that all of its facilities are suitable, adequate, well-maintained and in good operating condition. 32 Plant Accounts (including nuclear fuel) - During the period January 1, 1995 through December 31, 1999, there were $2,614,194,099 additions to the Company's electric utility plant accounts, $762,069,536 retirements and ($11,995,118) transfers and adjustments resulting in net additions of $1,840,129,445 to the electric utility plant. These net additions represent an increase of approximately 18.89%. During 1999, the Company acquired North Carolina Natural Gas Corporation resulting in a December 31, 1999 gas utility balance of $354,772,562. 33 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. ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - ------- --------------------------------------------------- (a) A special shareholder meeting was held on October 20, 1999. (b) The meeting was held to approve the Agreement and Plan of Share Exchange between the Company and CP&L Energy, Inc. (c) The total votes were as follows: Total Shareholder Accounts Voting 39,010 Total Votes Cast 123,640,874
Votes For Votes Against Votes Withheld --------- ------------- -------------- 104,960,978 - 65.5%* 16,998,911 - 10.6%* 1,680,985 - 1.0%*
*percentages represent portion of total available votes not total votes cast. 34
EXECUTIVE OFFICERS OF THE REGISTRANT ------------------------------------ Name Age Recent Business Experience - ---- --- -------------------------- William Cavanaugh III 61 CHAIRMAN, PRESIDENT AND CHIEF EXECUTIVE OFFICER, May 1999 to present; President and Chief Executive Officer, October 1996 to May 1999; President and Chief Operating Officer, September 1992 to October 1996. 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. Robert B. McGehee 57 EXECUTIVE VICE PRESIDENT, GENERAL COUNSEL, CHIEF ADMINISTRATIVE OFFICER AND INTERIM CHIEF FINANCIAL OFFICER, Administrative Services, Corporate Relations and Financial Services, March 3, 2000 to present; Executive Vice President, General Counsel and Chief Administrative Officer, Administrative Services and Corporate Relations, March 1999 to present; Senior Vice President and General Counsel, Public and Corporate Relations, May 1997 to March 1999. From 1974 to May 1997, Mr. McGehee was a practicing attorney with Wise Carter Child & Caraway, a law firm in Jackson, Mississippi. He primarily handled corporate, contract, nuclear regulatory and employment matters. From 1987 to 1997 he managed the firm, serving as chairman of its Board from 1992 to May 1997. William S. Orser 55 EXECUTIVE VICE PRESIDENT, Energy Supply, June 1998 to present; Executive Vice President and Chief Nuclear Officer, December 1996 to June 1998; Executive Vice President - Nuclear Generation, April 1993 to December 1996. Prior to April 1993, Mr. Orser held various senior management and executive positions with Detroit Edison Company, and positions with Portland General Electric Company, Southern California Edison, and the U. S. Navy. Fred N. Day, IV 56 SENIOR VICE PRESIDENT, Energy Delivery, July 1997 to present; Vice President, Western Region, 1995 to July 1997; Manager, Total Quality Performance, 1993 to 1995. Cecil L. Goodnight 56 SENIOR VICE PRESIDENT, Retail Sales and Services (CEO of Strategic Resource Solutions Corp., a wholly owned subsidiary of the Company), December 1998 to present; Senior Vice President and Chief Administrative Officer, Administrative Services, December 1996- December 1998; Senior Vice President, Human Resources and Support Services, March 1995 to December 1996; Vice President, Human Resources (formerly Employee Relations Department), May 1983 to March 1995. C.S. Hinnant 55 SENIOR VICE PRESIDENT AND CHIEF NUCLEAR OFFICER, Nuclear Generation, June 1998 to present; Vice President, Brunswick Nuclear Plant, April 1997 to May 1998; Vice President, Robinson Nuclear Plant, March 1994 to March 1997. 35 William D. Johnson 46 SENIOR VICE PRESIDENT AND CORPORATE SECRETARY, Legal and Risk Management, March 1999 to present; Vice President-Legal Department and Corporate Secretary, 1997 to 1999; Vice President, Senior Counsel and Manager-Legal Department, 1995 to 1997; Interim Manager-Legal Department 1994 to 1995; Associate General Counsel and Practice Group Leader, 1992 to 1994. Before joining the company, Mr. Johnson was a practicing attorney and partner with Hunton & Williams, a law firm in Raleigh, North Carolina. Tom D. Kilgore 52 SENIOR VICE PRESIDENT, Power Operations, August 1998 to present; President and Chief Executive Officer, Oglethorpe Power Corporation, Georgia Transmission Corporation and Georgia Operations Corporation, July 1991 to August 1998. These three companies provide power generation, transmission and system operations services, respectively, to 39 of Georgia's 42 customer-owned Electric Membership Corporations. From 1984 to July 1991, Mr. Kilgore held numerous management positions at Oglethorpe. Calvin B Wells 64 SENIOR VICE PRESIDENT, (President and Chief Executive Officer - NCNG, a wholly owned subsidiary of the Company), July 1999 to present. Before joining the company, Mr. Wells held the position of Chairman, President and Chief Executive Officer of North Carolina Natural Gas Corporation from December 1973 to July 1999. Larry M. Smith 44 VICE PRESIDENT AND CONTROLLER, August 1999 to present. Before joining the Company, Mr. Smith held the position of Vice President and Controller for MidAmerican Energy Company from November 1996 to August 1999 and Controller of that company from 1990 to 1996.
36 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS 1. 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 declared per share are as follows:
1998 High Low Dividends Declared - ----- ---- --- ------------------ First Quarter $45 3/4 $40 5/8 $ .485 Second Quarter 45 1/2 39 1/2 .485 Third Quarter 46 5/8 39 15/16 .485 Fourth Quarter 49 1/16 45 1/16 .500 1999 High Low Dividends Declared - ---- ---- --- ------------------ First Quarter $47 7/8 $37 5/8 $ .500 Second Quarter 45 36 5/8 .500 Third Quarter 43 1/4 34 1/8 .500 Fourth Quarter 36 13/16 29 1/4 .515
The December 31 closing price of the Company's Common Stock was $47 1/16 in 1998 and $30 7/16 in 1999. As of February 29, 2000, the Company had 66,791 holders of record of Common Stock. 2. Installment Payment of Consideration for Acquisition of Parke Industries, Incorporated: a) Securities Delivered. On February 5, 1999, and on February 11, 2000, 10,418 and 14,294 shares, respectively, of the Company's Common Shares were delivered to a former shareholder of Parke Industries, Incorporated (Parke) pursuant to an asset purchase agreement, dated January 30, 1998, by and between SRS and Parke. The asset purchase agreement provides that on each of the first three anniversaries of the closing of the above transaction, SRS is obligated to deliver Parke additional common shares having a market value of $450,000. The Common Shares delivered by SRS were acquired in market transactions and do not represent newly issued shares of the Company. b) Underwriters and Other Purchases. No underwriters were used in connection with this issuance of Common Shares. The Common Shares were received by one individual. c) Consideration. The consideration for the Common Shares was the delivery of certain assets of Parke. d) Exemption from Registration Claimed. The Common Shares described in this Item were issued on the basis of an exemption from registration under Section 4(2) of the Securities Act of 1933. The Common Shares were received by one individual and are subject to restrictions on resale appropriate for private placement. Appropriate disclosure was made to the recipient of the Common Shares. 37 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 1999 1998 1997 1996 1995 ---------- ---------- ---------- ---------- ---------- (dollars in thousands except per share data) Operating results Operating revenues $3,357,615 $3,191,668 $3,036,587 $2,999,273 $3,006,553 Net income $ 382,255 $ 399,238 $ 388,317 $ 391,277 $ 372,604 Earnings for common stock $ 379,288 $ 396,271 $ 382,265 $ 381,668 $ 362,995 Ratio of earnings to fixed charges 4.12 4.38 4.17 4.12 3.67 Ratio of earnings to fixed charges and preferred stock dividends 4.03 4.28 3.98 3.83 3.43 Per share data Basic earnings per Common share $ 2.56 $ 2.75 $ 2.66 $ 2.66 $ 2.48 Diluted earnings per Common share $ 2.55 $ 2.75 $ 2.66 $ 2.66 $ 2.48 Dividends declared per common Share $ 2.015 $ 1.955 $ 1.895 $ 1.835 $ 1.775 Assets $9,494,019 $8,401,406 $8,220,728 $8,364,862 $8,199,655 Capitalization Common stock equity $3,412,647 $2,949,305 $2,818,807 $2,690,454 $2,574,743 Preferred stock - redemption Not required 59,376 59,376 59,376 143,801 143,801 Long-term debt, net 3,028,561 2,614,414 2,415,656 2,525,607 2,610,343 ---------- ---------- ---------- ---------- ---------- Total capitalization $6,500,584 $5,623,095 $5,293,839 $5,359,862 $5,328,887 ========== ========== ========== ========== ==========
38 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS - --------------------- FOR 1999 AS COMPARED TO 1998 AND 1998 AS COMPARED TO 1997 In this section, earnings and the factors affecting them are discussed. The discussion begins with a general overview, then separately discusses earnings by business segment. In 1999, earnings available for common shareholders of Carolina Power & Light Company (the Company) were $379.3 million, a 4.3% decrease from $396.3 million in 1998. Earnings per share decreased from $2.75 per share in 1998 to $2.56 per share in 1999. Earnings were negatively affected by a decline in electric sales to industrial customers, a decline in electric revenues due to increased utilization of the real-time pricing tariff, and the effects of Hurricanes Dennis and Floyd. Continued customer growth and the addition of North Carolina Natural Gas Corporation (NCNG) positively affected earnings available for common shareholders. The Company issued common stock in connection with the acquisition of NCNG, which resulted in a dilution of earnings per common share. In 1998, earnings available for common shareholders were $396.3 million, a 3.7% increase from $382.3 million in 1997. Earnings per share increased from $2.66 per share in 1997 to $2.75 per share in 1998. Contributing to the increase were continued growth in the Company's service area in the commercial and residential sectors as well as a more favorable cooling season. Earnings were negatively affected by increased losses at two of the Company's subsidiaries, Interpath Communications, Inc. and Strategic Resource Solutions Corp. ELECTRIC - -------- The electric segment is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North and South Carolina. The territory served 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. Electric revenue fluctuations as compared to the prior year are due to the following factors (in millions):
1999 1998 ----- ---- Customer growth/changes in usage patterns* $ 72 $ 90 Industrial sales (22) (8) Price (31) (31) Weather (14) 27 Sales to Power Agency - 25 Sales to other utilities 4 - Other - 3 ----- ------- Total $ 9 $ 106 ===== =======
*CUSTOMER GROWTH/CHANGES IN USAGE PATTERNS EXCLUDES INDUSTRIAL CUSTOMERS. The increase in the customer growth/changes in usage patterns component of revenue for both comparison periods reflects continued growth in the number of customers served by the Company. While residential and commercial sales increased in both periods, industrial sales have decreased resulting from a decline in the chemical and textile industries. For the 1999 comparison period, the price-related decrease is due to increased utilization of the real-time pricing tariff. The price-related decrease for the 1998 comparison period is attributable to changes in the Power Coordination Agreement between the Company and North Carolina Electric Membership Corporation (NCEMC), as well as decreases in the fuel cost component of revenue. The decrease in the weather component for 1999 reflects overall milder-than- 39 normal weather conditions. The weather component and sales to North Carolina Eastern Municipal Power Agency (Power Agency) increased during 1998 due to a more favorable summer cooling season. The change in fuel expense for 1999 primarily reflects changes in the Company's generation mix. For 1998, the increase is attributable to a 5.3% increase in generation. For the 1999 comparison period, purchased power decreased due to the expiration in mid-1999 of the Company's long-term purchase power agreement with Duke Energy. The decrease in 1998 is attributable to a 9.4% reduction in kilowatt hours (kWh) purchased, which was partially offset by an increase in the average cost per kWh. In 1999, other operation and maintenance expense was negatively affected by $28.6 million of storm restoration expenses incurred as a result of Hurricanes Dennis and Floyd. The current year was also negatively affected by an increase in general and administrative expenses. For 1998, a decrease in the general and administrative expenses portion of other operation and maintenance expense was partially offset by expenses related to Hurricane Bonnie. Harris Plant deferred cost, net, decreased in 1998 due to the completion, in late 1997, of the amortization of the Harris Plant phase-in costs related to the North Carolina retail jurisdiction. NATURAL GAS - ----------- On July 15, 1999, the Company completed its acquisition of NCNG, now a wholly owned subsidiary. See "NCNG Acquisition" discussion under PART II, ITEM 7, "Other Matters." NCNG, headquartered in North Carolina, is a natural gas distribution utility. NCNG sells and transports natural gas to residential, commercial, industrial and electric power generation customers. NCNG provides natural gas, propane and related services to approximately 178,000 customers in 110 towns and cities and to four municipal gas distribution systems in south-central and eastern North Carolina. Much of that area is also part of the Company's electric service franchise. The ability to offer natural gas to customers is a priority for the Company as part of its strategy to become a total energy provider while securing fuel supplies for planned gas-fired electric generation. The results of NCNG are included in the Company's financial results since the date of the acquisition. Natural gas revenues for the six-month period totaled $98.9 million, while gas purchased for resale totaled $67.5 million and other operation and maintenance expenses totaled $13.8 million. NCNG's operations contributed $6.8 million of operating income. OTHER - ----- The other segment primarily includes the financial results of two of the Company's subsidiaries, Strategic Resource Solutions Corp. (SRS) and Interpath Communications, Inc. (Interpath), which are included in the caption Diversified businesses on the Consolidated Statements of Income. SRS, a wholly owned subsidiary, specializes in facilities and energy management software, systems and services for educational, commercial, industrial and governmental markets nationwide. SRS's operating losses were $9.9 million in 1999, down from a $34.7 million loss in 1998. Revenues for SRS in 1999 increased $27.8 million or 61% as compared to the prior year. Of this increase, unaffiliated revenues represented $25.2 million. This growth is primarily attributable to large performance contracts in the education and federal markets. Also contributing to the growth are strong sales in commercial and industrial building automation and HVAC controls. Even with this growth in revenues, operating expenses remained relatively flat in 1999 as compared to 1998 due to cost-cutting measures. Interpath, a wholly owned subsidiary, is an application service provider offering a full range of managed application services, Internet protocol-based applications and Internet consulting to businesses. Revenues for Interpath increased dramatically during 1999 to $73.2 million as compared to $37.6 million in 1998 and $3.8 million in 1997. Of these amounts, unaffiliated revenues represented $45.2 million, $15.7 million and $3.8 million in 1999, 1998 and 1997, respectively. This increase is primarily due to an increase in Interpath's customer base. Operating expenses increased significantly for all years due to the growth and business expansion of Interpath. This expansion contributed to 40 Interpath's operating losses of $44.8 million and $15.3 million in 1999 and 1998, respectively. In 1997, prior to the acquisition of Capitol Information Services, Inc., Interpath's operating income was $1.1 million. Other Income (Expense) - ---------------------- In 1997, interest income included $11 million related to an income tax refund. For 1999, other, net was negatively affected by a $4.1 million loss incurred on the sale of SRS's lighting division. The $21.1 million change in other, net for 1998 included a $6.0 million non-recurring charge related to an investment write-off by SRS and various other items, none of which are individually significant. Income Taxes - ------------ In general, income taxes fluctuate with changes in the Company's income before income taxes. In addition, 1997 income tax expense was negatively affected by tax provision adjustments of $10 million recorded in 1997 for potential audit issues related to the in-service date of the Harris Plant. Preferred Stock Dividend Requirements - ------------------------------------- The decrease in the preferred stock dividend requirements for 1998 is the result of the redemption of two preferred stock series in July 1997. 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, construction to comply with pollution control laws and regulations and investments in diversified businesses. The Company has on file with the Securities and Exchange Commission (SEC) a shelf registration statement under which first mortgage bonds, senior notes and other debt securities are available for issuance by the Company. As of December 31, 1999, the Company had $600 million available under this shelf registration. 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 $4.5 billion in first mortgage bonds and an additional 18 million shares of preferred stock at an assumed price of $100 per share and a $7.40 annual dividend rate. The Company also has 10 million authorized preference stock shares available for issuance that are not subject to an earnings test. As of December 31, 1999, the Company's revolving credit facilities totaled $750 million, all of which are long-term agreements supporting its commercial paper borrowings and other short-term indebtedness. The Company is required to pay minimal annual commitment fees to maintain its credit facilities. Consistent with management's intent to maintain its commercial paper and other short-term indebtedness on a long-term basis, and as supported by its long-term revolving credit facilities, the Company included in long-term debt commercial paper and other short-term indebtedness of $750 million and $488 million at December 31, 1999 and 1998, respectively. In September 1999, the Company established a $150 million extendible commercial notes program. As of December 31, 1999, there were no extendible commercial notes outstanding. The proceeds from the issuance of commercial paper related to the credit facilities mentioned above and/or internally generated funds financed the retirement of long-term debt totaling $113 million in 1999. In addition, the issuance of $500 million extendible notes in October 1999, financed the retirement of $100 million of extendible commercial notes and reduced the outstanding commercial paper balance. External funding requirements, which do not include early 41 redemption of long-term debt, redemption of preferred stock or issuances in conjunction with acquisitions, are expected to approximate $490 million, $580 million and $640 million in 2000, 2001 and 2002, respectively. These funds will be required for construction, mandatory retirements of long-term debt and general corporate purposes. The Company's access to outside capital depends on its ability to maintain its credit ratings. The Company's debt ratings are as follows:
Moody's Duff and Phelps Investors Service Standard and Poor's --------------- ----------------- ------------------- First Mortgage Bonds A+ A2 A Commercial Paper D-1 P-1 A-1 Extendible Commercial Notes N/A P-1 A-1 Extendible Notes D-1 P-1 A-1
The amount and timing of future sales of Company securities will depend on 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 long-term debt, the redemption of preferred stock, the reduction of short-term debt or for other general corporate purposes. In addition to the above, an anticipated issuance of common stock and debt is discussed in the "Florida Progress Corporation" discussion under PART II, ITEM 7, "Other Matters." Capital Requirements - -------------------- Estimated capital requirements for 2000 through 2002 primarily reflect construction expenditures to add generation, transmission and distribution facilities, as well as to upgrade existing facilities. Those capital requirements are reflected in the following table (in millions):
2000 2001 2002 ---- ---- ---- Construction expenditures $ 851 $ 876 $912 Nuclear fuel expenditures 64 94 66 AFUDC (21) (32) (38) Mandatory retirements of long-term debt 201 5 251 ------- ----- ------- Total $ 1,095 $ 943 $ 1,191 ======= ===== =======
The table includes expenditures of approximately $311 million expected to be incurred at fossil-fueled electric generating facilities to comply with the Clean Air Act. In addition, the Company has total projected cash requirements of approximately $565 million for the years 2000 through 2002 relating to expenditures in other areas such as affordable housing investments and merchant generation plants. These projections are periodically reviewed and may change significantly. During 1999, the Company had two long-term agreements for the purchase of power and related transmission services 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 (Rockport). The second agreement, which expired mid-1999, was with Duke Energy for the purchase of 400 megawatts of firm capacity. The estimated minimum annual payment for power purchases under the Rockport agreement is approximately $31 million, representing capital-related capacity costs. In 1999, total purchases (including transmission use charges) under the Rockport and Duke Energy agreements amounted to $59.5 million and $33.8 million, respectively. 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 Harris Plant through 2007. The estimated minimum annual payments for these purchases, representing capital- 42 related capacity costs, total approximately $26 million. Purchases under the agreement with Power Agency totaled $36.5 million in 1999. OTHER MATTERS - ------------- Florida Progress Corporation - ---------------------------- The Company, Florida Progress Corporation (FPC), a Florida corporation, and CP&L Energy, Inc. (CP&L Energy), a North Carolina corporation and wholly owned subsidiary of the Company, formerly known as CP&L Holdings, Inc. entered into an Amended and Restated Agreement and Plan of Share Exchange dated as of August 22, 1999, amended and restated as of March 3, 2000 (the "Amended Agreement"). Under the terms of the Agreement, all outstanding shares of common stock, no par value, of FPC common stock would be acquired by CP&L Energy in a statutory share exchange with an approximate value of $5.3 billion. Each share of FPC common stock, at the election of the holder, will be exchanged for (i) $54.00 in cash and one contingent value obligation (CVO), or (ii) the number of shares of common stock, no par value, of CP&L Energy equal to the ratio determined by dividing $54.00 by the average of the closing sale price per share of CP&L Energy common stock (Final Stock Price) as reported on the New York Stock Exchange composite tape for the twenty consecutive trading days ending with the fifth trading day immediately preceding the closing date for the exchange, and one CVO or (iii) a combination of cash and CP&L Energy common stock, and one CVO; provided, however, that shareholder elections shall be subject to allocation and proration to achieve a mix of the aggregate exchange consideration that is 65% cash and 35% common stock. The number of shares of CP&L Energy common stock that will be issued as stock consideration will vary if the Final Stock Price is within a range of $37.13 to $45.39, but not outside that range. Thus, the maximum number of shares of CP&L Energy common stock into which one share of FPC common stock could be exchanged would be 1.4543, and the minimum would be 1.1897. In addition, FPC shareholders will receive one contingent value obligation for each share of FPC stock owned. Each contingent value obligation will represent the right to receive contingent payments that may be made by CP&L Energy based on certain cash flows that may be derived from future operations of four synthetic fuel plants currently owned by FPC. In conjunction with this proposed share exchange, CP&L Energy plans to issue debt to fund the cash portion of the exchange. The transaction has been approved by the Boards of Directors of FPC, the Company and CP&L Energy. Consummation of the exchange is subject to the satisfaction or waiver of certain closing conditions including, among others, the approval by the shareholders of FPC and the approval of the issuance of CP&L Energy common stock in the exchange by the shareholders of the Company or CP&L Energy; the approval or regulatory review by the Federal Energy Regulatory Commission (FERC), the SEC, the Nuclear Regulatory Commission (NRC), the North Carolina Utilities Commission (NCUC), and certain other federal and state regulatory bodies; the expiration or early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976; and other customary closing conditions. In addition, FPC's obligation to consummate the exchange is conditioned upon the Final Stock Price being not less than $30.00. Both the Company and FPC have agreed to certain undertakings and limitations regarding the conduct of their respective businesses prior to the closing of the transaction. The transaction is expected to be completed in the fall of 2000. Either party may terminate the Agreement under certain circumstances, including if the exchange has not been consummated on or before December 31, 2000; provided that if certain conditions have not been satisfied on December 31, 2000, but all other conditions have been satisfied or waived then such date shall be June 30, 2001. In the event that FPC or the Company terminate the Agreement in certain limited circumstances, FPC would be required to pay the Company a termination fee of $150 million, plus the Company's reasonable out-of-pocket expenses which are not to exceed $25 million in the aggregate. On January 31, 2000, applications were filed with the NRC seeking approval of the change in control of FPC that will result from the share exchange. On February 3, 2000, CP&L Energy filed an application with the NCUC for authorization of the share exchange with FPC and the issuance of common stock in connection with the transaction. On February 3, 2000, CP&L Energy and FPC filed a joint application with the FERC requesting approval of the share exchange. The Company cannot predict the outcome of these matters. On March 14, 2000, CP&L Energy and FPC filed an application with the SEC requesting approval of the share exchange under the Public Utility Holding Company Act. 43 NCNG Acquisition - ---------------- On July 15, 1999, the Company completed the previously announced acquisition of NCNG for an aggregate purchase price of approximately $364 million. Each outstanding share of NCNG common stock was converted into the right to receive 0.8054 shares of Company common stock, resulting in the issuance of approximately 8.3 million shares. The acquisition has been accounted for as a purchase and, accordingly, the operating results of NCNG have been included in the Company's consolidated financial statements since the date of acquisition. The excess of the aggregate purchase price over the fair value of net assets acquired, approximately $240 million, has been recorded as goodwill of the acquired business and is being amortized primarily over a period of 40 years. NCNG, operating as a wholly owned subsidiary of the Company, is engaged in the transmission and distribution of natural gas. These gas services are provided under regulated rates to approximately 178,000 customers in eastern and south-central North Carolina. In conjunction with the acquisition, the Company and NCNG signed a joint stipulation agreement with the Public Staff of the NCUC in which the Company agreed to cap base retail electric rates, exclusive of fuel costs, with limited exceptions, through December 2004, and NCNG agreed to cap margin rates for gas sales and transportation services, with limited exceptions, through November 1, 2003. Management is of the opinion that this agreement will not have a material effect on the consolidated results of operations or financial position of the Company. Diversified Businesses - ---------------------- In addition to Interpath and SRS, whose results were previously discussed, the following subsidiaries represent diversified businesses of the Company. In 1999, the Company formed Monroe Power Company (Monroe), a wholly owned subsidiary. Monroe is a North Carolina corporation, authorized to do business in Georgia where it owns and operates a combustion turbine, which became operational in December 1999. In 1998, the Company formed Powerhouse Square, LLC, to facilitate the renovation of several historic buildings in North Carolina. Retail Rate Matters - ------------------- In late 1998 and early 1999, the Company filed, and the respective commissions subsequently approved, proposals in the North and South Carolina retail jurisdictions to accelerate cost recovery of its nuclear generating assets beginning January 1, 2000, and continuing through 2004. The accelerated cost recovery began immediately after the 1999 expiration of the accelerated amortization of certain regulatory assets, which began in January 1997. Pursuant to the orders, the Company's depreciation expense for nuclear generating assets will increase by a minimum of $106 million to a maximum of $150 million per year. Recovering the costs of the nuclear generating assets on an accelerated basis will better position the Company for the uncertainties associated with potential restructuring of the electric utility industry. 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 federal and state laws. There are several manufactured gas plant (MGP) sites to which both the electric utility and the gas utility have some connection. In this regard, the electric utility and the gas utility, along with others, are participating in a cooperative effort with the North Carolina Department of Environment and Natural Resources, Division of Waste Management (DWM). The DWM has established a uniform framework to address MGP sites. The investigation and remediation of specific MGP sites will be addressed pursuant to one or more Administrative Orders on Consent (AOC) between the DWM and the potentially responsible party or parties. Both the electric utility and the gas 44 utility have signed AOCs to investigate certain sites at which investigation includes the completion of interim remedial measures where appropriate and anticipate signing AOCs to remediate sites as well. Both the electric utility and the gas utility continue to identify parties connected to individual MGP sites, and to determine their relative relationship to other parties at those sites and the degree to which they will undertake efforts with others at individual sites. The Company does not expect the costs associated with these sites to be material to the consolidated financial position or results of operations of the Company. The Company is periodically notified by regulators such as the North Carolina Department of Environment and Natural Resources, the South Carolina Department of Health and Environmental Control, and the U.S. Environmental Protection Agency (EPA) of its involvement or potential involvement in sites, other than MGP sites, that may require investigation and/or remediation. Although the Company may incur costs at the sites about which it has been notified, based upon the current status of these sites, the Company does not expect those costs to be material to the consolidated financial position or results of operations of the Company. The EPA has been conducting an enforcement initiative related to a number of coal-fired utility power plants in an effort to determine whether modifications at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The Company has recently been asked to provide information to the EPA as part of this initiative and has cooperated in providing the requested information. The EPA has initiated enforcement actions which may have potentially significant penalties against other companies that have been subject to this initiative. The Company cannot predict the outcome of this matter. The 1990 amendments to the Clean Air Act require substantial reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fueled electric generating plants. The Clean Air Act required the Company to meet more stringent provisions effective January 1, 2000. The Company will meet the sulfur dioxide emissions requirements by maintaining sufficient sulfur dioxide emission allowances. Installation of additional equipment was necessary to reduce nitrogen oxide emissions. Increased operation and maintenance costs, including emission allowance expense, installation of additional equipment and increased fuel costs are not expected to be material to the consolidated financial position or results of operations of the Company. On October 27, 1998, the EPA published a final rule addressing the issue of regional transport of ozone. This rule is commonly known as the NOx SIP call. The EPA's rule requires 22 states, including North and South Carolina, to further reduce nitrogen oxide emissions in order to attain a pre-set state NOx emission level by May 2003. The EPA's rule also suggests to the states that these additional nitrogen oxide emission reductions be obtained from the utility sector. The Company is evaluating necessary measures to comply with the rule and estimates its related capital expenditures through 2003 could be approximately $327 million, a portion of which is reflected in the "Capital Requirements" discussion under PART II, ITEM 7, "Liquidity and Capital Resources." Increased operation and maintenance costs relating to the NOx SIP call are not expected to be material to the Company's results of operations. The Company and the states of North and South Carolina have been participating in litigation challenging the NOx SIP call. On March 3, 2000, a three-judge panel of the District of Columbia Circuit Court of Appeals upheld the EPA's NOx SIP call. Further appeals are being considered. The Company cannot predict the outcome of this matter. The EPA published a final rule approving petitions under section 126 of the Clean Air Act that requires certain sources to make reductions in nitrogen oxide emissions by 2003. The Company's fossil-fueled electric generating plants are included in these petitions. The Company and other states are participating in litigation challenging the EPA's actions. The Company cannot predict the outcome of this matter. Nuclear - ------- In the Company's retail jurisdictions, provisions for nuclear decommissioning costs are approved by the NCUC and the Public Service Commission of South Carolina (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 7.75% 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 1998, using 1998 cost 45 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 1998 dollars, are $279.8 million for Robinson Unit No. 2, $299.3 million for Brunswick Unit No. 1, $298.5 million for Brunswick Unit No. 2 and $328.1 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. The Financial Accounting Standards Board (FASB) is proceeding with its project regarding accounting practices related to obligations associated with the retirement of long-lived assets, and an exposure draft of a proposed accounting standard was issued during the first quarter of 2000. It is uncertain what effects it may ultimately have on the Company's accounting for nuclear decommissioning and other retirement costs. 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 begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract. In April 1995, the DOE issued a final interpretation that it did not have an unconditional obligation to take spent nuclear fuel by January 31, 1998. In Indiana & Michigan Power v. DOE, the Court of Appeals vacated the DOE's final interpretation and ruled that the DOE had an unconditional obligation to begin taking spent nuclear fuel. The Court did not specify a remedy because the DOE was not yet in default. After the DOE failed to comply with the decision in Indiana & Michigan Power v. DOE, a group of utilities (including the Company) petitioned the Court of Appeals in Northern States Power (NSP) v. DOE, seeking an order requiring the DOE to begin taking spent nuclear fuel by January 31, 1998. The DOE took the position that their delay was unavoidable, and the DOE was excused from performance under the terms and conditions of the contract. The Court of Appeals issued an order which precluded the DOE from treating the delay as an unavoidable delay. However, the Court of Appeals did not order the DOE to begin taking spent nuclear fuel, stating that the utilities had a potentially adequate remedy by filing a claim for damages under the contract. After the DOE failed to begin taking spent nuclear fuel by January 31, 1998, a group of utilities (including the Company) filed a motion with the Court of Appeals to enforce the mandate in NSP v. DOE. Specifically, the utilities asked the Court to permit the utilities to escrow their waste fee payments, to order the DOE not to use the waste fund to pay damages to the utilities, and to order the DOE to establish a schedule for disposal of spent nuclear fuel. The Court denied this motion based primarily on the grounds that a review of the matter was premature and that some of the requested remedies fell outside of the mandate in NSP v. DOE. Subsequently, a number of utilities each filed an action for damages in the Court of Claims and before the Court of Appeals. The Company is in the process of evaluating whether it should file a similar action for damages. In NSP v. U.S., the Court of Claims decided that NSP must pursue its administrative remedies instead of filing an action in the Court of Claims. NSP has filed an interlocutory appeal to the Court of Appeals based on NSP's position that the Court of Claims has jurisdiction to decide the matter. A group of utilities (including the Company) has submitted an amicus brief in support of NSP's position. The Company also continues to monitor legislation that has been introduced in Congress which might provide some limited relief. The Company cannot predict the outcome of this matter. With certain modifications and additional approval by the NRC, the Company's spent nuclear fuel storage facilities will be 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. The Company has initiated the process of obtaining the additional NRC approval. 46 Competition - ----------- GENERAL - ------- In recent years, the electric utility industry has experienced a substantial increase in competition at the wholesale level, caused by changes in federal law and regulatory policy. Several states have also decided to restructure aspects of retail electric service. The issue of retail restructuring and competition is being reviewed by a number of states and bills have been introduced in Congress that seek to introduce such restructuring in all states. Allowing increased competition in the generation and sale of electric power will require resolution of many complex issues. One of the major issues to be resolved is who will pay for stranded costs. Stranded costs are those costs and investments made by utilities in order to meet their statutory obligation to provide electric service, but which could not be recovered through the market price for electricity following industry restructuring. The amount of such stranded costs that the Company might experience would depend on the timing of, and the extent to which, direct competition is introduced, and the then-existing market price of energy. If electric utilities were no longer subject to cost-based regulation and it were not possible to recover stranded costs, the financial position and results of operations of the Company could be adversely affected. WHOLESALE COMPETITION - --------------------- Since passage of the National Energy Act of 1992 (Energy Act), competition in the wholesale electric utility industry has significantly increased due to a greater participation by traditional electricity suppliers, wholesale power marketers and brokers, and due to the trading of energy futures contracts on various commodities exchanges. This increased competition could affect 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. To assist in the development of wholesale competition, the FERC, in 1996, issued standards 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 contains provisions for the recovery of stranded costs and numerous other provisions that could affect 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 and other entities filed protests challenging numerous aspects of the Company's tariff and requesting that an evidentiary proceeding be held. The FERC set the matter for hearing and set a discovery and procedural schedule. In July 1997, the Company filed an offer of settlement in this matter. The administrative law judge certified the offer to the full FERC in September 1997. The offer is pending before the FERC. The Company cannot predict the outcome of this matter. On December 20, 1999, the FERC issued a rule on Regional Transmission Organizations (RTO) that sets forth four minimum characteristics and eight functions for transmission entities, including independent system operators and transmission companies, to become FERC-approved RTOs. The rule states that public utilities that own, operate or control interstate transmission facilities must file by October 15, 2000, either a proposal to participate in an RTO or an alternative filing describing efforts and plans to participate in an RTO. The Company plans to participate in an RTO and anticipates complying with this filing requirement. RETAIL COMPETITION - ------------------ The Energy Act prohibits the FERC from ordering retail wheeling - transmitting power on behalf of another producer to an individual retail customer. Several states have changed their laws and regulations to allow full retail competition. Other states are considering changes to allow retail competition. These changes and proposals have taken differing forms and included disparate elements. The Company believes changes in existing laws in both North and South Carolina would be required to permit competition in the Company's retail jurisdictions. 47 NORTH CAROLINA ACTIVITIES - ------------------------- In April 1997, the North Carolina General Assembly approved legislation establishing a 23-member study commission to evaluate the future of electric service in the state. During 1998, the study commission met and held public hearings around the state. The study commission also retained consultants to conduct analyses and studies concerning various restructuring issues, including stranded costs, state and local tax implications and electric rate comparisons. In June 1998, the study commission issued an interim report to the 1998 North Carolina General Assembly, summarizing the numerous fact-finding and educational activities and analytical projects the study commission had initiated or completed. That report offered no judgments or recommendations. In May 1999, the North Carolina General Assembly approved legislation that expanded the study commission from 23 to 29 members. All 29 study commission members were appointed by August 1999. The study commission conducted several meetings during August through November to discuss the reports regarding deregulation issues prepared by the Research Triangle Institute at the request of the study commission. During those meetings, several entities, including the Company and Duke Energy, presented proposals for addressing the nearly $6 billion debt of North Carolina's Municipal Power Agencies. The study commission resumed meeting in January 2000. On March 8, 2000, the commission co-chairs presented draft recommendations regarding electric industry restructuring to the full study commission for its consideration in preparing its report to the North Carolina General Assembly. Key recommendations in the draft include (i) electric retail competition should begin in North Carolina no later than June 30, 2006; (ii) recovery of utilities' stranded costs should not be extended beyond June 30, 2006; and (iii) the generation and distribution of assets of the municipal power agencies (including Power Agency) should be sold no later than June 30, 2002, and the funds from those sales should be used to pay off a portion of the municipal power agencies' debt. The draft recommendations also address issues related to the legislative timetable, consumer protection measures, environmental concerns, tax laws, and transmission and distribution. Implicit in recommendation is a rate freeze through the year 2006. Initial comments on the draft recommendations were due on March 10, 2000. The Company and other interested parties submitted comments. The draft recommendations will serve as a starting point for preparation of the study commission's report addressing industry restructuring in the State of North Carolina. The recommendations and related issues will be debated and discussed at future study commission meetings. The commission is expected to make a final report to the North Carolina General Assembly in the spring of 2000. The Company cannot predict the outcome of this matter. SOUTH CAROLINA ACTIVITIES - ------------------------- The 1999 session of the South Carolina General Assembly adjourned in June 1999 without approving any legislation regarding electric industry restructuring. On October 29, 1998, the South Carolina Senate Judiciary Committee appointed a 13-member task force to study the restructuring issue and make a report to the Senate. The task force was subsequently expanded to 18 members, including the Company. The task force, including its various committees, has conducted several meetings to receive input from experts and interested parties and to discuss issues related to restructuring. The House Public Utility Subcommittee is expected to continue considering the electric industry restructuring bills that were introduced in 1999, and the Senate task force is expected to continue to consider the issue of restructuring during the South Carolina General Assembly's 2000 legislative session. The Company cannot predict the outcome of these matters. FEDERAL ACTIVITIES - ------------------ During 1999, over 20 bills were introduced in Congress regarding electric industry restructuring. A draft bill passed the House Commerce Subcommittee on October 27, 1999. This bill will proceed to full Commerce Committee consideration in the first quarter of 2000 where it is expected to be changed significantly. The Company cannot predict the outcome of this matter. 48 COMPANY ACTIVITIES - ------------------ In December 1998, the Company entered into an agreement to purchase all of the output of a combustion turbine project to be built, owned and operated by Broad River Energy, LLC (BRE), in Cherokee County, South Carolina. In conjunction with this agreement, the Company agreed to provide bridge financing to BRE under a Financing Term Sheet. This financing will be used by BRE to (i) make payments to Duke Energy in connection with certain electrical interconnection agreements, (ii) purchase two generator step up transformers and (iii) acquire land for the Broad River Energy Center Project. Under the terms of this agreement, the Company agreed to loan BRE up to $20.5 million that will be due on July 1, 2000. In addition, in August 1999 the Company agreed to loan Broad River Investors, LLC up to $84.5 million that will be due on July 1, 2000 to finance the purchase of the combustion turbines for the project. Interest on each of the loans is calculated based on the London Inter-Bank Offer Rate, LIBOR, plus a spread of 1%. In August 1999, the Company signed a five-year agreement with Municipal Electric Authority of Georgia (MEAG) pursuant to which MEAG will receive the full output of a 160 MW combustion turbine owned and operated by Monroe Power Company, a wholly owned subsidiary of the Company. Headquartered in Atlanta, MEAG represents 48 municipal electric utilities in Georgia and is part owner of four generating facilities and the Georgia Integrated Transmission System. In August 1999, the Company signed an off-system wholesale peaking power sales agreement with Santee Cooper. The Company will provide up to 150 MW of additional peaking power for a one-year term from June 2001 to May 2002, to help meet the increasing demand in Santee Cooper's fast-growing service area. In October 1999, the Company and the Albemarle-Pamlico Economic Development Corporation (APEC) announced their intention to build an 850-mile natural gas transmission and distribution system to 14 currently unserved counties in eastern North Carolina. The Company will operate both the transmission and distribution systems and APEC will help ensure that the new facilities are built in the most advantageous locations to promote development of the economic base in the region. In conjunction with this proposal, the Company and APEC filed a joint request with the NCUC for $186 million of a $200 million state bond package established for clean water and natural gas infrastructure. If granted, these funds will be used to pay for the portion of the project that likely could not be recovered from future gas customers through rates. The Company plans to invest an additional $11.5 million, thus bringing the total cost of the project to $197.5 million. As proposed, the project is scheduled to be developed in phases through 2003. The NCUC has established a procedural schedule with hearings regarding the first phase of the project to be conducted in April 2000. An order is expected mid-2000. The Company cannot predict the outcome of this matter. In December 1999, the Company announced plans to build a 30-inch natural gas pipeline in North Carolina that will extend approximately 82 miles from Williams Energy's Transcontinental interstate pipeline in Iredell County to Richmond County. The pipeline will provide gas for the Company's planned new power plant in Richmond County and is scheduled to be completed during the spring of 2001. The pipeline is expected to cost approximately $100 million and will accommodate extension of natural gas service to future Company power plants. This pipeline replaces a plan for a 175-mile pipeline, the Palmetto Pipeline, that the Company and Southern Natural Gas Company, a subsidiary of El Paso Energy, had been assessing. As a regulated entity, the Company is subject to the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." Accordingly, the Company records certain assets and liabilities resulting from the effects of the ratemaking process, which would not be recorded under generally accepted accounting principles for unregulated entities. The Company's ability to continue to meet the criteria for application of SFAS No. 71 may be affected in the future by competitive forces and restructuring in the electric utility industry. In the event that SFAS No. 71 no longer applied to a separable portion of the Company's operations, related regulatory assets and liabilities would be eliminated unless an appropriate regulatory recovery mechanism is provided. Additionally, these factors could result in an impairment of electric utility plant assets as determined pursuant to SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." 49 Transition to Holding Company Structure - --------------------------------------- The Company is in the process of converting to a holding company structure, in which the Company would become a subsidiary of a newly formed holding company. This conversion will offer certain advantages as the Company continues to confront the rapidly changing environment facing electric utilities. The holding company structure would allow greater organizational flexibility, including a clearer separation of regulated businesses from each other and from unregulated businesses such as energy services, telecommunications and electric generation projects for wholesale markets. The ability to conduct financing activities at the holding company level without the need for state regulatory approvals will enable the Company to satisfy financing needs more quickly and efficiently. The Company's shareholders approved the contemplated holding company structure on October 20, 1999. The necessary approvals from various regulatory authorities are expected by the end of the first quarter of 2000. Upon conversion to a holding company structure, each share of the Company's common stock will automatically be exchanged for one share of common stock of the new holding company. On September 15, 1999, the Company filed an application with the NRC for consent to indirectly transfer control of its nuclear plant operating licenses to the newly formed holding company. This application was approved on December 31, 1999. On October 15, 1999, the Company filed an application with the NCUC to approve the transfer of ownership of the Company, Interpath and NCNG to the newly formed holding company. The Company cannot predict the outcome of this proceeding. On October 18, 1999, the Company filed an application with the SEC for approval which allows the holding company to acquire voting securities resulting in control over the Company and NCNG. The Company cannot predict the outcome of this matter. On October 20, 1999, the Company filed an application with the SCPSC to approve the transfer of the Company and Interpath to the newly formed holding company. The SCPSC issued an order approving the application on March 6, 2000. On October 25, 1999, the Company filed an application with the FERC for approval of the proposed reorganization of the Company related to the establishment of the new holding company. This application was approved on December 23, 1999. Year 2000 - --------- The Company's critical systems, devices and applications successfully made the transition to the Year 2000. It is possible, however, that the Company, its vendors, distributors, suppliers or customers may encounter future Year 2000-related problems. If this should occur, we do not expect to experience any material adverse effects on our business, financial condition or consolidated results of operations. As of January 31, 2000, the Company had incurred and expensed approximately $18 million related to the inventory, assessment and remediation of non-compliant systems, equipment and applications. The Company does not expect additional costs related to the Year 2000 Project to be material to the consolidated financial position or consolidated results of operations of the Company. New Accounting Standard - ----------------------- The FASB has delayed the effective date for SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The delay, published as SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133," changes the effective date to fiscal years beginning after June 15, 2000. The Company expects to determine any effects of SFAS No. 133 by mid-2000. 50 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK - -------- ---------------------------------------------------------- The Company is exposed to certain market risks that are inherent in the Company's financial instruments, which arise from transactions entered into in the normal course of business. The Company's primary exposures are changes in interest rates with respect to its long-term debt and commercial paper, and fluctuations in the return on marketable securities with respect to its nuclear decommissioning trust funds. These financial instruments are held for purposes other than trading. The risks discussed below do not include the price risks associated with nonfinancial instrument transactions and positions associated with the Company's operations, such as sales commitments and inventory. INTEREST RATE RISK The Company manages its interest rate risks through use of a combination of fixed and variable rate debt. Variable rate debt has rates that adjust in periods ranging from daily to monthly. Interest rate derivative instruments may be used to adjust interest rate exposures and to protect against adverse movements in rates. The table below presents principal cash flows and related weighted-average interest rates, by maturity date, for the Company's long-term debt, commercial paper and other short-term indebtedness at December 31, 1999, including current portions. In conjunction with the issuance of $400 million principal amount of Senior Notes on March 5, 1999, the Company settled its interest rate lock, receiving approximately $9.7 million which will reduce interest expense over the 10-year debt term.
Fair 2000 2001 2002 2003 2004 Thereafter Total Value -------- -------- -------- -------- -------- ---------- -------- -------- (Dollars in millions) Fixed rate long-term debt $ 197 - $ 100 $ 7 $ 300 $ 1,319 $ 1,923 $ 1,845 Average interest rate 6.15% - 7.17% 12.88% 6.88% 7.09% 7.01% - Variable rate long- term debt - - - - - $ 620 $ 620 $ 622 Average interest rate - - - - - 3.32% 3.32% - Commercial paper $ 363 - - - - - $ 363 $ 363 Average interest rate 6.07% - - - - - 6.07% - Extendible notes $ 500 - - - - - $ 500 $ 500 Average interest rate 5.88% - - - - - 5.88% -
The fixed and variable rate debt principal cash flows reflected in the table above are substantially the same as reported at December 31, 1998 for post-1999 debt, except for the issuance of $400 million principal amount of Senior Notes, 5.95% Series due March 1, 2009. Commercial paper outstanding at December 31, 1998 was approximately $488 million. There were no extendible notes outstanding at December 31, 1998. MARKETABLE SECURITIES RETURN RISK: The Company maintains trust funds, as required by the Nuclear Regulatory Commission, to fund certain costs of decommissioning. These funds are primarily invested in stocks, bonds and cash equivalents, which are exposed to price fluctuations in equity markets and to changes in interest rates. At December 31, 1999 and 1998, the fair values of these funds were approximately $380 million and $311 million, respectively. The Company actively monitors its portfolio by benchmarking the performance of its investments against certain indices and by maintaining, and periodically reviewing, target allocation percentages for various asset classes. The accounting for nuclear decommissioning recognizes the costs as recovered through the Company's regulated electric rates and; therefore, fluctuations in trust fund marketable security returns do not affect the earnings of the Company. 51 ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - ------- -------------------------------------------------------- The following consolidated financial statements, supplementary data and consolidated financial statement schedules are included herein:
Page ---- Independent Auditors' Report 53 Consolidated Financial Statements: Consolidated Statements of Income for the Years Ended December 31, 1999, 1998, and 1997 54 Consolidated Balance Sheets as of December 31, 1999 and 1998 55 Consolidated Statements of Cash Flow for the Years Ended December 31, 1999, 1998 and 1997 56 Consolidated Schedules of Capitalization as of December 31, 1999 and 1998 57 Consolidated Statements of Retained Earnings for the Years Ended December 31, 1999, 1998 and 1997 58 Consolidated Quarterly Financial Data (Unaudited) 58 Notes to Consolidated Financial Statements 59 Consolidated Financial Statement Schedules for the Years Ended December 31, 1999, 1998, and 1997: II-Valuation and Qualifying Accounts 78
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 the Consolidated Financial Statements. 52 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, 1999 and 1998, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1999. 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 these 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 the Company and subsidiaries at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, 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. /s/ DELOITTE & TOUCHE LLP Raleigh, North Carolina February 8, 2000, except for Note 2, as to which the date is March 3, 2000. 53
CONSOLIDATED STATEMENTS OF INCOME - --------------------------------- YEARS ENDED DECEMBER 31 (IN THOUSANDS EXCEPT PER SHARE DATA) 1999 1998 1997 - ----------------------------------------------------------------------------------------------------------------------- OPERATING REVENUES Electric $ 3,138,846 $ 3,130,045 $ 3,024,089 Natural gas 98,903 - - Diversified businesses 119,866 61,623 12,498 - ----------------------------------------------------------------------------------------------------------------------- Total Operating Revenues 3,357,615 3,191,668 3,036,587 - ----------------------------------------------------------------------------------------------------------------------- OPERATING EXPENSES Fuel used in electric generation 581,340 571,419 534,268 Purchased power 365,425 382,547 387,296 Gas purchased for resale 67,465 - - Other operation and maintenance 682,407 642,478 661,466 Depreciation and amortization 495,670 487,097 481,650 Taxes other than on income 142,741 141,504 139,478 Harris Plant deferred costs, net 7,435 7,489 24,296 Diversified businesses 174,589 111,584 22,156 - ----------------------------------------------------------------------------------------------------------------------- Total Operating Expenses 2,517,072 2,344,118 2,250,610 - ----------------------------------------------------------------------------------------------------------------------- OPERATING INCOME 840,543 847,550 785,977 - ----------------------------------------------------------------------------------------------------------------------- OTHER INCOME (EXPENSE) Interest income 10,336 9,526 18,335 Other, net (30,739) (26,108) (4,991) - ----------------------------------------------------------------------------------------------------------------------- Total Other Income (Expense) (20,403) (16,582) 13,344 - ----------------------------------------------------------------------------------------------------------------------- INCOME BEFORE INTEREST CHARGES AND INCOME TAXES 820,140 830,968 799,321 - ----------------------------------------------------------------------------------------------------------------------- INTEREST CHARGES Long-term debt 180,676 169,901 163,468 Other interest charges 10,298 11,156 18,743 Allowance for borrowed funds used during construction (11,510) (6,821) (4,923) - ----------------------------------------------------------------------------------------------------------------------- Total Interest Charges, Net 179,464 174,236 177,288 - ----------------------------------------------------------------------------------------------------------------------- INCOME BEFORE INCOME TAXES 640,676 656,732 622,033 INCOME TAXES 258,421 257,494 233,716 - ----------------------------------------------------------------------------------------------------------------------- NET INCOME $ 382,255 $ 399,238 $388,317 - ----------------------------------------------------------------------------------------------------------------------- PREFERRED STOCK DIVIDEND REQUIREMENTS (2,967) (2,967) (6,052) - ----------------------------------------------------------------------------------------------------------------------- EARNINGS FOR COMMON STOCK $ 379,288 $ 396,271 $382,265 - ----------------------------------------------------------------------------------------------------------------------- AVERAGE COMMON SHARES OUTSTANDING 148,344 143,941 143,645 - ----------------------------------------------------------------------------------------------------------------------- BASIC EARNINGS PER COMMON SHARE $ 2.56 $ 2.75 $ 2.66 - ----------------------------------------------------------------------------------------------------------------------- DILUTED EARNINGS PER COMMON SHARE $ 2.55 $ 2.75 $ 2.66 - ----------------------------------------------------------------------------------------------------------------------- DIVIDENDS DECLARED PER COMMON SHARE $ 2.015 $ 1.955 $ 1.895 - ----------------------------------------------------------------------------------------------------------------------- SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
54
CONSOLIDATED BALANCE SHEETS - --------------------------- (IN THOUSANDS) DECEMBER 31 ASSETS 1999 1998 - ------------------------------------------------------------------------------------------------------------ UTILITY PLANT Electric utility plant in service $10,633,823 $10,280,638 Gas utility plant in service 354,773 - Accumulated depreciation (4,975,405) (4,496,632) - ------------------------------------------------------------------------------------------------------------ Utility plant in service, net 6,013,191 5,784,006 Held for future use 11,282 11,984 Construction work in progress 536,017 306,866 Nuclear fuel, net of amortization 204,323 196,684 - ------------------------------------------------------------------------------------------------------------ Total Utility Plant, Net 6,764,813 6,299,540 - ------------------------------------------------------------------------------------------------------------ CURRENT ASSETS Cash and cash equivalents 79,871 28,872 Accounts receivable 446,367 406,418 Taxes receivable 3,770 21,000 Inventory 247,913 224,701 Deferred fuel cost 81,699 42,647 Prepayments 42,631 19,907 Other current assets 177,082 57,311 - ------------------------------------------------------------------------------------------------------------ Total Current Assets 1,079,333 800,856 - ------------------------------------------------------------------------------------------------------------ DEFERRED DEBITS AND OTHER ASSETS Income taxes recoverable through future rates 229,008 277,894 Abandonment costs 1,675 16,083 Harris Plant deferred costs 56,142 60,021 Unamortized debt expense 10,924 27,010 Nuclear decommissioning trust funds 379,949 310,702 Diversified businesses property, net 239,982 66,014 Miscellaneous other property and investments 252,454 282,664 Goodwill, net (Note 3E) 288,970 67,017 Other assets and deferred debits 190,769 193,605 - ------------------------------------------------------------------------------------------------------------ Total Deferred Debits and Other Assets 1,649,873 1,301,010 - ------------------------------------------------------------------------------------------------------------ Total Assets $9,494,019 $8,401,406 - ------------------------------------------------------------------------------------------------------------ CAPITALIZATION AND LIABILITIES - ------------------------------------------------------------------------------------------------------------ CAPITALIZATION (SEE CONSOLIDATED SCHEDULES OF CAPITALIZATION) - ------------------------------------------------------------------------------------------------------------ Common stock equity $3,412,647 $2,949,305 Preferred stock - redemption not required 59,376 59,376 Long-term debt, net 3,028,561 2,614,414 - ------------------------------------------------------------------------------------------------------------ Total Capitalization 6,500,584 5,623,095 - ------------------------------------------------------------------------------------------------------------ CURRENT LIABILITIES Current portion of long-term debt 197,250 53,172 Accounts payable 269,053 319,163 Interest accrued 47,607 39,941 Dividends declared 80,939 74,400 Notes payable 168,240 - Other current liabilities 130,036 108,824 - ------------------------------------------------------------------------------------------------------------ Total Current Liabilities 893,125 595,500 - ------------------------------------------------------------------------------------------------------------ DEFERRED CREDITS AND OTHER LIABILITIES Accumulated deferred income taxes 1,632,778 1,678,924 Accumulated deferred investment tax credits 203,704 211,822 Other liabilities and deferred credits 263,828 292,065 - ------------------------------------------------------------------------------------------------------------ Total Deferred Credits and Other Liabilities 2,100,310 2,182,811 - ------------------------------------------------------------------------------------------------------------ COMMITMENTS AND CONTINGENCIES (NOTE 16) - ------------------------------------------------------------------------------------------------------------ Total Capitalization and Liabilities $9,494,019 $8,401,406 - ------------------------------------------------------------------------------------------------------------ SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
55
CONSOLIDATED STATEMENTS OF CASH FLOWS - ------------------------------------- YEARS ENDED DECEMBER 31 (IN THOUSANDS) 1999 1998 1997 - --------------------------------------------------------------------------------------------------------------------------------- OPERATING ACTIVITIES Net income $ 382,255 $ 399,238 $ 388,317 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 588,123 578,348 565,212 Harris Plant deferred costs 3,878 3,704 19,670 Deferred income taxes (32,495) (38,517) (66,546) Investment tax credit (10,299) (10,206) (10,232) Deferred fuel credit (39,052) (22,017) (24,969) Net decrease in receivables, inventories, prepaid expenses and other current assets (168,148) (62,351) (111,216) Net increase in payables and accrued expenses 31,991 43,652 65,330 Other 75,867 2,330 59,191 - --------------------------------------------------------------------------------------------------------------------------------- Net Cash Provided by Operating Activities 832,120 894,181 884,757 - --------------------------------------------------------------------------------------------------------------------------------- INVESTING ACTIVITIES Gross property additions (689,054) (424,263) (322,205) Nuclear fuel additions (75,641) (102,511) (61,509) Contributions to nuclear decommissioning trust (30,825) (30,848) (30,726) Contributions to retiree benefit trusts - - (21,096) Net cash flow of company-owned life insurance program (6,542) (1,954) 138,508 Investments in non-utility activities (199,525) (103,543) (54,733) - --------------------------------------------------------------------------------------------------------------------------------- - --------------------------------------------------------------------------------------------------------------------------------- Net Cash Used in Investing Activities (1,001,587) (663,119) (351,761) - --------------------------------------------------------------------------------------------------------------------------------- FINANCING ACTIVITIES Proceeds from issuance of long-term debt 400,970 6,255 199,075 Net increase (decrease) in short-term indebtedness 339,100 242,100 (166,324) Net increase (decrease) in outstanding payments (117,643) 26,211 (71,744) Retirement of long-term debt (113,335) (208,050) (103,410) Redemption of preferred stock - - (85,850) Purchase of Company common stock - - (23,418) Dividends paid on common and preferred stock (296,671) (282,684) (277,840) Other 6,169 (448) - - --------------------------------------------------------------------------------------------------------------------------------- Net Cash Provided by (Used in) Financing Activities 218,590 (216,616) (529,511) - --------------------------------------------------------------------------------------------------------------------------------- NET INCREASE IN CASH AND CASH EQUIVALENTS 49,123 14,446 3,485 - --------------------------------------------------------------------------------------------------------------------------------- INCREASE IN CASH FROM ACQUISITION (SEE NONCASH ACTIVITIES) 1,876 - - CASH AND CASH EQUIVALENTS AT BEGINNING OF THE YEAR 28,872 14,426 10,941 - --------------------------------------------------------------------------------------------------------------------------------- CASH AND CASH EQUIVALENTS AT END OF YEAR $ 79,871 $ 28,872 $ 14,426 - --------------------------------------------------------------------------------------------------------------------------------- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Cash paid during the year - interest $180,395 $ 179,526 $171,511 income taxes $284,535 $ 329,739 $289,693
Noncash Activities - ------------------ In July 1999, the Company purchased all outstanding shares of North Carolina Natural Gas Corporation (NCNG). In conjunction with the purchase of NCNG, the Company issued approximately $360 million in common stock. SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. 56
CONSOLIDATED SCHEDULES OF CAPITALIZATION - ---------------------------------------- DECEMBER 31 (DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA) 1999 1998 - ------------------------------------------------------------------------------------------------------------------------- COMMON STOCK EQUITY Common stock without par value, authorized 200,000,000 shares, issued and outstanding 159,599,650 and 151,337,503 shares, respectively (Note 11) $1,746,249 $1,374,773 Unearned ESOP common stock (140,153) (152,979) Capital stock issuance expense (794) (790) Retained earnings (Note 8) 1,807,345 1,728,301 - ------------------------------------------------------------------------------------------------------------------------- Total Common Stock Equity $3,412,647 $2,949,305 - ------------------------------------------------------------------------------------------------------------------------- CUMULATIVE PREFERRED STOCK, WITHOUT PAR VALUE (entitled to $100 a share plus accumulated dividends in the event of liquidation; aggregate liquidation preference of $59,468; outstanding shares are as of December 31, 1999) - ------------------------------------------------------------------------------------------------------------------------- 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 - ------------------------------------------------------------------------------------------------------------------------- Total Preferred Stock - redemption not required $59,376 $59,376 - ------------------------------------------------------------------------------------------------------------------------- LONG-TERM DEBT (interest rates are as of December 31, 1999) First mortgage bonds: 6.125% due 2000 $150,000 $ 150,000 6.75% due 2002 100,000 100,000 5.875% and 7.875% due 2004 300,000 300,000 6.80% due 2007 200,000 200,000 6.875% to 8.625% due 2021-2023 500,000 500,000 First mortgage bonds - secured senior notes: 5.95% due 2009 400,000 - First mortgage bonds - secured medium-term notes: 7.15% due 1999 - 50,000 First mortgage bonds - pollution control series: 6.30% to 6.90% due 2009-2014 93,530 93,530 4.19% and 4.20% due 2024 122,600 122,600 - ------------------------------------------------------------------------------------------------------------------------- Total First Mortgage Bonds 1,866,130 1,516,130 - ------------------------------------------------------------------------------------------------------------------------- Other long-term debt: Pollution control obligations backed by letter of credit, 4.50% to 5.40% due 2014-2017 442,000 442,000 Other pollution control obligations, 5.70% 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 6) 362,600 488,000 Extendible notes reclassified to long-term debt (Note 6) 331,760 - Miscellaneous notes 54,846 56,691 - ------------------------------------------------------------------------------------------------------------------------- Total Other Long-Term Debt 1,371,846 1,167,331 - ------------------------------------------------------------------------------------------------------------------------- Unamortized premium and discount, net (12,165) (15,875) Current portion of long-term debt (197,250) (53,172) - ------------------------------------------------------------------------------------------------------------------------- Total Long-Term Debt, Net $3,028,561 $2,614,414 - ------------------------------------------------------------------------------------------------------------------------- Total Capitalization $6,500,584 $5,623,095 - ------------------------------------------------------------------------------------------------------------------------- SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
57
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS - -------------------------------------------- YEARS ENDED DECEMBER 31 (IN THOUSANDS EXCEPT PER SHARE DATA) 1999 1998 1997 - --------------------------------------------------------------------------------------------------------------------------- Retained Earnings at Beginning of Year $1,728,301 $1,613,881 $1,503,658 Net income 382,255 399,238 388,317 Preferred stock dividends at stated rates (2,967) (2,967) (4,627) Common stock dividends at annual per share rate of $2.015, $1.955 and $1.895, respectively (300,244) (281,851) (272,011) Other adjustments - - (1,456) - --------------------------------------------------------------------------------------------------------------------------- Retained Earnings at End of Year $1,807,345 $1,728,301 $1,613,881 - ---------------------------------------------------------------------------------------------------------------------------
CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED) - ------------------------------------------------- (IN THOUSANDS EXCEPT PER SHARE DATA) FIRST QUARTER SECOND QUARTER THIRD QUARTER FOURTH QUARTER - ------------------------------------------------------------------------------------------------------------------------- YEAR ENDED DECEMBER 31, 1999 Operating revenues $762,902 $762,822 $1,025,746 $806,145 Operating income 199,408 157,371 308,963 174,801 Net income 92,212 63,159 147,854 79,030 Common stock data: Basic and diluted earnings per common share .63 .43 .97 .51 Dividend paid per common share .50 .50 .50 .50 Price per share - high 47 7/8 45 43 1/4 36 13/16 low 37 5/8 36 5/8 34 1/8 29 1/4 - ------------------------------------------------------------------------------------------------------------------------- YEAR ENDED DECEMBER 31, 1998 Operating revenues $761,495 $748,941 $964,291 $716,941 Operating income 194,266 159,593 354,536 139,155 Net income 86,571 65,469 186,024 61,174 Common stock data: Basic earnings per common share .60 .45 1.29 .42 Diluted earnings per common share .60 .45 1.28 .42 Dividend paid per common share .485 .485 .485 .485 Price per share - high 45 3/4 45 1/2 46 5/8 49 1/16 low 40 5/8 39 1/2 39 15/16 45 1/16 - ------------------------------------------------------------------------------------------------------------------------- SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
58 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Organization and Basis of Presentation a. Organization Carolina Power & Light Company (the Company) is a public service corporation primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North and South Carolina and the transmission, distribution and sale of natural gas in portions of North Carolina. b. Basis of Presentation The consolidated financial statements are prepared in accordance with generally accepted accounting principles. 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 Public Service Commission of South Carolina (SCPSC). Certain amounts for 1998 and 1997 have been reclassified to conform to the 1999 presentation, with no effect on previously reported net income or common stock equity. 2. Florida Progress Corporation The Company, Florida Progress Corporation (FPC), a Florida corporation, and CP&L Energy, Inc. (CP&L Energy), a North Carolina corporation and wholly owned subsidiary of the Company, formerly known as CP&L Holdings, Inc. entered into an Amended and Restated Agreement and Plan of Share Exchange dated as of August 22, 1999, amended and restated as of March 3, 2000 (the "Amended Agreement"). Under the terms of the Agreement, all outstanding shares of common stock, no par value, of FPC common stock would be acquired by CP&L Energy in a statutory share exchange with an approximate value of $5.3 billion. Each share of FPC common stock, at the election of the holder, will be exchanged for (i) $54.00 in cash and one contingent value obligation (CVO), or (ii) the number of shares of common stock, no par value, of CP&L Energy equal to the ratio determined by dividing $54.00 by the average of the closing sale price per share of CP&L Energy common stock (Final Stock Price) as reported on the New York Stock Exchange composite tape for the twenty consecutive trading days ending with the fifth trading day immediately preceding the closing date for the exchange, and one CVO or (iii) a combination of cash and CP&L Energy common stock, and one CVO; provided, however, that shareholder elections shall be subject to allocation and proration to achieve a mix of the aggregate exchange consideration that is 65% cash and 35% common stock. The number of shares of CP&L Energy common stock that will be issued as stock consideration will vary if the Final Stock Price is within a range of $37.13 to $45.39, but not outside that range. Thus, the maximum number of shares of CP&L Energy common stock into which one share of FPC common stock could be exchanged would be 1.4543, and the minimum would be 1.1897. In addition, FPC shareholders will receive one contingent value obligation for each share of FPC stock owned. Each contingent value obligation will represent the right to receive contingent payments that may be made by CP&L Energy based on certain cash flows that may be derived from future operations of four synthetic fuel plants currently owned by FPC. In conjunction with this proposed share exchange, CP&L Energy plans to issue debt to fund the cash portion of the exchange. The transaction has been approved by the Boards of Directors of FPC, the Company and CP&L Energy. Consummation of the exchange is subject to the satisfaction or waiver of certain closing conditions including, among others, the approval by the shareholders of FPC and the approval of the issuance of CP&L Energy common stock in the exchange by the shareholders of the Company or CP&L Energy; the approval or regulatory review by the Federal Energy Regulatory Commission (FERC), the SEC, the Nuclear Regulatory Commission (NRC), the North Carolina Utilities Commission (NCUC), and certain other federal and state regulatory bodies; the expiration or early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976; and other customary closing conditions. In addition, FPC's obligation to consummate the exchange is conditioned upon the Final Stock Price being not less than $30.00. Both the Company and FPC have agreed to certain undertakings and limitations regarding the conduct of their respective businesses prior to the closing of the transaction. The transaction is expected to be completed in the fall of 2000. Either party may terminate the Agreement under certain circumstances, including if the exchange has not been consummated on or before December 31, 2000; provided that if certain conditions have not been satisfied on 59 December 31, 2000, but all other conditions have been satisfied or waived then such date shall be June 30, 2001. In the event that FPC or the Company terminate the Agreement in certain limited circumstances, FPC would be required to pay the Company a termination fee of $150 million, plus the Company's reasonable out-of-pocket expenses which are not to exceed $25 million in the aggregate. On January 31, 2000, applications were filed with the NRC seeking approval of the change in control of FPC that will result from the share exchange. On February 3, 2000, CP&L Energy filed an application with the NCUC for authorization of the share exchange with FPC and the issuance of common stock in connection with the transaction. On February 3, 2000, CP&L Energy and FPC filed a joint application with the FERC requesting approval of the share exchange. The Company cannot predict the outcome of these matters. 3. Summary of Significant Accounting Policies a. Principles of Consolidation The consolidated financial statements include the activities of the Company and its majority-owned subsidiaries. These subsidiaries have invested in areas such as natural gas transmission and distribution, communications technology, energy-management services and merchant generation plants. Significant intercompany balances and transactions have been eliminated in consolidation except as permitted by Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," which provides that profits on intercompany sales to regulated affiliates are not eliminated if the sales price is reasonable and the future recovery of the sales price through the rate-making process is probable. 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. Utility Plant The cost of additions, including betterments and replacements of units of property, is charged to 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. Gas utility plant is not currently subject to the lien of the Company's mortgage. The balances of utility plant in service at December 31 are listed below (in thousands), with a range of depreciable lives for each: 1999 1998 ----------- ----------- Electric Production plant (7-33 years) $6,413,121 $6,295,252 Transmission plant (30-75 years) 1,018,114 986,609 Distribution plant (12-50 years) 2,676,881 2,469,613 General plant and other (8-75 years) 525,707 529,164 ----------- ----------- Total electric utility plant $10,633,823 $10,280,638 Gas plant (10-40 years) 354,773 - ----------- ----------- Utility plant in service $10,988,596 $10,280,638 =========== =========== As prescribed in regulatory uniform systems of accounts, an allowance for the cost of borrowed and equity funds used to finance utility plant construction (AFUDC) is charged to the cost of plant. Regulatory authorities consider AFUDC an 60 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 for electric utility plant was 6.4% in 1999 and 5.6% in both 1998 and 1997. The composite AFUDC rate for gas utility plant was 10.09% in 1999. d. Diversified Business Property The following is a summary of diversified business property (in thousands): 1999 1998 --------- --------- Property, plant and equipment $ 195,892 $27,422 Construction work in progress 65,848 43,619 Accumulated depreciation (21,758) (5,027) --------- --------- Diversified business property, net $ 239,982 $66,014 ========= ========= Diversified business property is stated at cost. Depreciation is computed on a straight-line basis using estimated useful lives of the assets, ranging from 3 to 20 years. e. 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 3f), as a percent of average depreciable property other than nuclear fuel, were approximately 3.9% in 1999, 1998 and 1997. Depreciation provisions totaled $409.6 million, $394.4 million and $382.1 million in 1999, 1998 and 1997, respectively. Depreciation and amortization expense also includes amortization of deferred operation and maintenance expenses associated with Hurricane Fran, which struck significant portions of the Company's service territory in September 1996. In 1996, the NCUC authorized the Company to defer these expenses (approximately $40 million) with amortization over a 40-month period, which expired in December 1999. Pursuant to authorizations from the NCUC and the SCPSC, the Company accelerated the amortization of certain regulatory assets over a three-year period beginning January 1997 and expiring December 1999. The accelerated amortization of these regulatory assets resulted in additional depreciation and amortization expenses of approximately $68 million in each year of the three-year period. Depreciation and amortization expense also includes amortization of plant abandonment costs (see Note 9c). 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. Goodwill, the excess of purchase price over fair value of net assets of businesses acquired, is being amortized on a straight-line basis over periods ranging from 10 to 40 years. Accumulated amortization was $11.5 million and $4.7 million at December 31, 1999 and 1998, respectively. f. 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 61 upon in applicable rate agreements. Decommissioning cost provisions, which are included in depreciation and amortization expense, were $33.3 million in 1999 and 1998 and $33.2 million in 1997. Accumulated decommissioning costs, which are included in accumulated depreciation, were $568.0 million and $496.3 million at December 31, 1999 and 1998, respectively. These costs include amounts retained internally and amounts funded in an external decommissioning trust. The balance of the nuclear decommissioning trust was $379.9 million and $310.7 million at December 31, 1999 and 1998, respectively. Trust earnings increase the trust balance with a corresponding increase in the accumulated decommissioning balance. These balances are adjusted for net unrealized gains and losses related to changes in the fair value of trust assets. Based on the site-specific estimates discussed below, and using an assumed after-tax earnings rate of 7.75% 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 1998, using 1998 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 1998 dollars, are $279.8 million for Robinson Unit No. 2, $299.3 million for Brunswick Unit No. 1, $298.5 million for Brunswick Unit No. 2 and $328.1 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 (FASB) is proceeding with its project regarding accounting practices related to obligations associated with the retirement of long-lived assets, and an exposure draft of a proposed accounting standard was issued during the first quarter of 2000. It is uncertain what effects it may ultimately have on the Company's accounting for nuclear decommissioning and other retirement costs. g. Other Policies The Company recognizes utility revenues as service is rendered to customers. 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. The Company is also allowed to recover the costs of gas purchased for resale through customer rates. Other property and investments are stated principally at cost. The Company maintains an allowance for doubtful accounts receivable, which totaled approximately $16.8 million and $14.2 million at December 31, 1999 and 1998, respectively. Inventory, which includes fuel, materials and supplies, and gas in storage, is carried at average cost. 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, except that the balance existing at December 31, 1996 was amortized on a three-year accelerated basis (see Note 9a). The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. h. New Accounting Standard The FASB has delayed the effective date for SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The delay, published as SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133," changes the effective date to fiscal years beginning after June 15, 2000. The Company expects to determine any effects of SFAS No. 133 by mid-2000. 62 4. NCNG Acquisition On July 15, 1999, the Company completed the acquisition of North Carolina Natural Gas Corporation (NCNG) for an aggregate purchase price of approximately $364 million. Each outstanding share of NCNG common stock was converted into the right to receive 0.8054 shares of Company common stock, resulting in the issuance of approximately 8.3 million shares. The acquisition has been accounted for as a purchase and, accordingly, the operating results of NCNG have been included in the Company's consolidated financial statements since the date of acquisition. The excess of the aggregate purchase price over the fair value of net assets acquired, approximately $240 million, has been recorded as goodwill of the acquired business and is being amortized primarily over a period of 40 years. NCNG, operating as a wholly owned subsidiary of the Company, is engaged in the transmission and distribution of natural gas. These gas services are provided under regulated rates to approximately 178,000 customers in eastern and south central North Carolina. In conjunction with the acquisition, the Company and NCNG signed a joint stipulation agreement with the Public Staff of the NCUC in which the Company agreed to cap base retail electric rates, exclusive of fuel costs, with limited exceptions, through December 2004, and NCNG agreed to cap margin rates for gas sales and transportation services, with limited exceptions, through November 1, 2003. Management is of the opinion that this agreement will not have a material effect on the consolidated results of operations or financial position of the Company. The acquisition of NCNG was not deemed significant to the Company's consolidated results of operations; therefore, proforma financial information has been omitted. 5. Financial Information by Business Segment The Company provides services through the following business segments: electric, natural gas and other. The electric segment generates, transmits, distributes and sells electric energy in North and South Carolina. Electric operations are subject to the rules and regulations of the FERC, the NCUC and the SCPSC. The natural gas segment transmits, distributes and sells gas in portions of North Carolina. Gas operations are subject to the rules and regulations of the NCUC. The other segments primarily include telecommunication services, energy management services, propane and miscellaneous non-regulated activities. For reportable segments presented in the accompanying table, segment earnings (losses) before taxes include intersegment sales accounted for at prices representative of unaffiliated party transactions. 63
Natural Segment (in thousands) Electric Gas Other Elimination Totals - --------------------------------------------------------------------------------------------------------------------- For the year ended 12/31/99 Revenues Unaffiliated $ 3,138,846 $ 97,886 $ 119,866 $ - $ 3,356,598 Intersegment - 1,017 30,618 (30,618) 1,017 -------------------------------------------------------------------------------- Total Revenues $ 3,138,846 $ 98,903 $ 150,484 $ (30,618) $ 3,357,615 Depreciation and Amortization $ 486,502 $ 9,168 $ 16,804 - $ 512,474 Interest Expense $ 183,098 $ 3,225 $ 1,403 $ (6,859) 180,867 Earnings(Losses) Before Taxes $ 715,359 $ 4,360 $ (72,759) $ (6,284) $ 640,676 Total Segment Assets $ 8,705,547 $ 550,132 $ 370,805 $ (132,465) $ 9,494,019 Capital and Investment Expenditures $ 671,401 $ 24,047 $ 193,131 $ - $ 888,579 ===================================================================================================================== Natural Segment Electric Gas Other Elimination Totals - --------------------------------------------------------------------------------------------------------------------- For the year ended 12/31/98 Revenues Unaffiliated $ 3,130,045 $ - $ 61,623 $ - $ 3,191,668 Intersegment - - 21,887 (21,887) - -------------------------------------------------------------------------------- Total Revenues $ 3,130,045 $ - $ 83,510 $ (21,887) $ 3,191,668 Depreciation and Amortization $ 487,097 $ - $ 2,951 - $ 490,048 Interest Expense $ 174,433 $ - $ 149 $ (197) $ 174,385 Earnings(Losses) Before Taxes $ 737,999 $ - $ (70,325) $ (10,942) $ 656,732 Total Segment Assets $ 8,211,372 $ - $ 189,175 $ 859 $ 8,401,406 Capital and Investment Expenditures $ 463,729 $ - $ 64,077 $ - $ 527,806 ===================================================================================================================== Natural Segment Electric Gas Other Elimination Totals - --------------------------------------------------------------------------------------------------------------------- For the year ended 12/31/97 Revenues Unaffiliated $ 3,024,089 $ - $ 12,498 $ - $ 3,036,587 Intersegment - - - - - -------------------------------------------------------------------------------- Total Revenues $ 3,024,089 $ - $ 12,498 $ - $ 3,036,587 Depreciation and Amortization $ 481,650 $ - $ 228 $ - $ 481,878 Interest Expense $ 177,874 $ - $ 58 $ (586) $ 177,346 Earnings(Losses) Before Taxes $ 658,840 $ - $ (25,278) $ (11,529) $ 622,033 Total Segment Assets $ 8,138,282 $ - $ 89,694 $ (7,248) $ 8,220,728 Capital and Investment Expenditures $ 372,512 $ - $ 4,426 $ - $ 376,938 =====================================================================================================================
64 RECONCILIATION OF FINANCIAL INFORMATION BY BUSINESS SEGMENT TO CONSOLIDATED FINANCIAL STATEMENTS: DEPRECIATION AND AMORTIZATION (in thousands)
SEGMENT CONSOLIDATED PERIOD TOTALS ADJUSTMENTS TOTALS --------------------------------------------------------------------------- For the year ended 12/31/99 $ 512,474 $ (16,804) $ 495,670 For the year ended 12/31/98 $ 490,048 $ (2,951) $ 487,097 For the year ended 12/31/97 $ 481,878 $ (228) $ 481,650 INTEREST EXPENSE (in thousands) SEGMENT CONSOLIDATED PERIOD TOTALS ADJUSTMENTS TOTALS ---------------------------------------------------------------------------- For the year ended 12/31/99 $180,867 $ (1,403) $ 179,464 For the year ended 12/31/98 $174,385 $ (149) $ 174,236 For the year ended 12/31/97 $177,346 $ (58) $ 177,288
Adjustments to depreciation and amortization and interest expense consist of expenses related to the other segments that are included in diversified business operating expenses on a consolidated basis. 6. Revolving Credit Facilities As of December 31, 1999, the Company's revolving credit facilities totaled $750 million, all of which are long-term agreements. The Company is required to pay minimal annual commitment fees to maintain its credit facilities. Consistent with management's intent to maintain its commercial paper, pollution control revenue refunding bonds (pollution control bonds) and other short-term indebtedness on a long-term basis, and as supported by its long-term revolving credit facilities, the Company included in long-term debt commercial paper, pollution control bonds, and other short-term indebtedness outstanding of approximately $363 million, $56 million and $331 million, respectively, as of December 31, 1999. Commercial paper and pollution control bonds outstanding of approximately $488 million and $56 million, respectively, were reclassified as long-term debt as of December 31, 1998. For commercial paper, pollution control bonds and other short-term indebtedness, weighted-average interest rates were 6.07%, 3.32% and 5.88%, respectively, at December 31, 1999. The weighted-average interest rates for commercial paper and pollution control bonds were 5.22% and 3.67%, respectively, as of December 31, 1998. 7. Fair Value of Financial Instruments The carrying amounts of cash and cash equivalents, commercial paper and extendible notes approximate fair value due to the short maturities of these instruments. At December 31, 1999 and 1998, there were miscellaneous investments with carrying amounts of approximately $60 million and $66 million, respectively, included in miscellaneous other property and investments. The carrying amount of these investments approximates fair value due to the short maturity of certain instruments and certain instruments are presented at fair value. The carrying amount of the Company's long-term debt was $2.54 billion and $2.20 billion at December 31, 1999 and 1998, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $2.47 billion and $2.31 billion at December 31, 1999 and 1998, respectively. External funds have been established, as required by the NRC, as a mechanism to fund certain costs of nuclear decommissioning (see Note 3f). These nuclear decommissioning trust funds are invested in stocks, bonds and cash equivalents. Nuclear decommissioning trust funds are presented at amounts that approximate fair value. Fair value is obtained from quoted market prices for the same or similar investments. 65 8. Capitalization As of December 31, 1999, the Company had 21,594,424 shares of authorized but unissued common stock reserved and available for issuance, primarily 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. During 1999, the Company issued stock in conjunction with the NCNG acquisition as discussed in Note 4. In addition, CP&L Energy's Board of Directors has authorized the issuance of shares in conjunction with the planned share exchange with FPC (see Note 2). The Company's mortgage, as supplemented, and charter contain provisions limiting the use of retained earnings for the payment of dividends under certain circumstances. As of December 31, 1999, there were no significant restrictions on the use of retained earnings. As of December 31, 1999, long-term debt maturities for the years 2000, 2002, 2003 and 2004 amounted to $197 million, $100 million, $7 million and $300 million, respectively, excluding commercial paper, pollution control bonds and other short-term indebtedness reclassified as long-term debt. There are no long-term debt maturities in 2001. 9. Regulatory Matters a. Regulatory Assets As a regulated entity, the Company is subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." See Note 16c for additional discussion of SFAS No. 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 unregulated entities. At December 31, 1999 and 1998, the balances of the Company's regulatory assets were as follows (in thousands):
1999 1998 ---- ---- Income taxes recoverable through future rates* $229,008 $277,894 Harris Plant deferred costs 56,142 60,021 Abandonment costs* 1,675 16,083 Loss on reacquired debt (included in unamortized debt expense)* 4,719 20,953 Deferred fuel 81,699 42,647 Items included in other assets and deferred debits: Deferred DOE enrichment facilities-related costs 40,897 45,917 Deferred hurricane-related costs - 11,927 Emission allowance carrying costs* - 4,144 ----------- ---------- Total $414,140 $479,586 =========== ==========
* ALL OR CERTAIN PORTIONS OF THESE REGULATORY ASSETS HAVE BEEN SUBJECT TO ACCELERATED AMORTIZATION (SEE NOTE 3E). b. Retail Rate Matters In late 1998 and early 1999, the Company filed, and the respective commissions subsequently approved, proposals in the North and South Carolina retail jurisdictions to accelerate cost recovery of its nuclear generating assets beginning January 1, 2000, and continuing through 2004. The accelerated cost recovery began immediately after the 1999 expiration of the accelerated amortization of certain regulatory assets (see Note 3e). Pursuant to the orders, the Company's depreciation expense for nuclear generating assets will increase by a minimum of $106 million to a maximum of $150 million per year. Recovering the costs of the nuclear generating assets on an accelerated basis will better position the Company for the uncertainties associated with potential restructuring of the electric utility industry. 66 In conjunction with the acquisition with NCNG, the Company signed a joint stipulation agreement with the Public Staff of the NCUC in which the Company agreed to cap base retail electric rates and margin rates for gas sales and transportation services (see Note 4). c. Plant-Related Deferred Costs In the 1988 rate orders, the Company was ordered to remove from rate base and treat as abandoned plant certain costs related to the Harris Plant. Abandoned plant amortization related to the 1988 rate orders was completed in 1998 for the wholesale and North Carolina retail jurisdictions and in 1999 for the South Carolina retail jurisdiction. Amortization of plant abandonment costs is included in depreciation and amortization expense and totaled $15.0 million, $24.2 million and $30.8 million in 1999, 1998 and 1997, respectively. 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 $0.6 million, $1.7 million and $3.5 million in 1999, 1998 and 1997, respectively, and is reported in other, net. 10. Risk Management Activities and Derivatives Transactions The Company uses a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk if the counterparty fails to perform under the contract. The Company minimizes such risk by performing credit reviews using, among other things, publicly available credit ratings of such counterparties. Potential nonperformance by counterparties is not expected to have a material effect on the consolidated financial position or consolidated results of operations of the Company. a. Commodity Instruments - Non-Trading At December 31, 1999, the Company held several forward contracts that reduced the exposure to market fluctuations relative to the price and delivery of electricity products. Selling electricity forward contracts can reduce price risk on the Company's available but unsold generation. These contracts provide for physical delivery of the related commodity, and the financial effects of such contracts are recorded in the month of settlement. The Company from time to time enters into electricity option contracts to ensure a reliable source of capacity to meet its customers' electricity requirements or to limit risk associated with electricity prices. It is management's intent to take or make physical delivery under such contracts. Premiums paid or received are deferred and charged to income during the option period. The Company's maximum exposure associated with purchased options is limited to premiums paid. Option sales are made only if the Company can, with reasonable certainty, make physical delivery from Company-owned resources. b. Commodity Instruments - Trading The Company from time to time engages in the trading of electricity commodity instruments and, therefore, experiences net open positions. The Company manages open positions with strict policies which limit its exposure to market risk and require daily reporting to management of potential financial exposures. When such instruments are entered into for trading purposes, the instruments are carried on the balance sheet at fair value, with changes in fair value recognized in earnings. Net losses related to trading electricity commodity instruments were not material during 1999 and 1998, and there was no trading activity in 1997. c. Other Financial Instruments The Company may from time to time enter into derivative instruments to hedge interest rate risk or equity securities risk. At December 31, 1998, the Company had an outstanding interest rate lock with a fair value asset position of approximately $1 million. The interest rate lock was settled during 1999 in conjunction with the issuance of long-term debt, and the Company received approximately $9.7 million, which will reduce interest expense over the 10-year debt term. 67 11. Stock-Based Compensation Plans a. Employee Stock Ownership Plan The Company sponsors the Stock Purchase-Savings Plan (SPSP) for which substantially all full-time employees and certain part-time employees are eligible. The SPSP, which has Company matching 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 Company matching and incentive contributions and/or reinvested dividends. All or a portion of the dividends paid on ESOP suspense shares and on ESOP shares allocated to participants may be used to repay ESOP acquisition loans. To the extent used to repay such loans, the dividends are deductible for income tax purposes. There were 6,365,364 and 6,953,612 ESOP suspense shares at December 31, 1999 and 1998, respectively, with a fair value of $193.7 million and $327.3 million, respectively. ESOP shares allocated to plan participants totaled 12,966,269 and 12,416,040 at December 31, 1999 and 1998, respectively. The Company's matching and incentive goal compensation cost under the SPSP is determined based on matching percentages and incentive goal attainment as defined in the plan. Such compensation cost is allocated to participants' accounts in the form of Company common stock, with the number of shares determined by dividing compensation cost by the common stock market value. The Company currently meets common stock share needs with open market purchases and with shares released from the ESOP suspense account. Total matching and incentive compensation cost recorded in 1999, 1998 and 1997 was approximately $17.3 million, $15.3 million and $13.4 million, respectively, substantially all of which was met with shares released from the suspense account. 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. b. Other Stock-Based Compensation Plans The Company has compensation plans for officers and key employees of the Company that are stock-based in whole or in part. The two primary active stock-based compensation programs are the Performance Share Sub-Plan (PSSP) and the Restricted Stock Awards program (RSA), both of which were established pursuant to the Company's 1997 Equity Incentive Plan. Under the terms of the PSSP, officers and key employees of the Company are granted performance shares that vest over a three-year consecutive period. Each performance share has a value that is equal to, and changes with, the value of a share of the Company's common stock, and dividend equivalents are accrued on, and reinvested in, the performance shares. For grant years prior to 1999, the sole performance measure under the PSSP is the Company's total shareholder return as compared to that of a peer group of utilities. Beginning in the 1999 grant year, the Company added an additional performance measure, earnings before interest, income taxes, depreciation and amortization, which is also compared to a peer group of utilities. Compensation expense is recognized over the vesting period based on the expected ultimate cash payout. Compensation expense is reduced by any forfeitures. The RSA, which began in 1998, allows the Company to grant shares of restricted common stock to key employees of the Company. The restricted shares vest on a graded vesting schedule over a minimum of three years. Compensation expense, which is based on the fair value of common stock at the grant date, is recognized over the applicable vesting period, with corresponding increases in common stock equity. Compensation expense is reduced by any forfeitures. Restricted shares are not included as shares outstanding in the basic earnings per share calculation until the shares are no longer forfeitable. Changes in restricted stock shares outstanding were: 68
1999 1998 ---- ---- Beginning balance 265,300 - Granted 66,600 274,800 Forfeited - (9,500) -------------- --------------- Ending balance 331,900 265,300 ============== ===============
The total amount expensed for other stock-based compensation plans was $2.2 million, $1.3 million and $4.3 million in 1999, 1998 and 1997, respectively. 12. Postretirement Benefit Plans The Company has a noncontributory defined benefit retirement (pension) plan for substantially all full-time employees. The components of net periodic pension cost are (in thousands):
1999 1998 1997 --------- --------- --------- Actual return on plan assets $(127,167) $ (87,382) $(110,346) Variance from expected return, Deferred 52,043 17,462 57,368 --------- --------- --------- Expected return on plan assets $ (75,124) $ (69,920) $ (52,978) Service cost 20,467 18,357 18,643 Interest cost 46,846 45,877 42,468 Amortization of transition obligation 106 106 106 Amortization of prior service cost (benefit) (1,314) (158) 967 Amortization of actuarial gain (3,932) (6,440) (36) --------- --------- --------- Net periodic pension cost (benefit) $ (12,951) $ (12,178) $ 9,170 ========= ========= =========
Prior service costs and benefits are amortized on a straight-line basis over the average remaining service period of active participants. Actuarial gains and losses in excess of 10% of the greater of the pension obligation or the market-related value of assets are amortized over the average remaining service period of active participants. 69 Reconciliations of the changes in the plan's benefit obligations and the plan's funded status are (in thousands): 1999 1998 --------- --------- Pension obligation Pension obligation at January 1 $ 678,210 $ 598,160 Interest cost 46,846 45,877 Service cost 20,467 18,357 Benefit payments (41,585) (25,466) Actuarial loss (gain) (50,120) 77,785 Plan amendments 5,546 (36,503) Acquisition of NCNG 28,760 -- --------- --------- Pension obligation at December 31 $ 688,124 $ 678,210 Fair value of plan assets at December 31 947,143 830,213 --------- --------- Funded status $ 259,019 $ 152,003 Unrecognized transition obligation 582 688 Unrecognized prior service benefit (18,175) (25,429) Unrecognized actuarial gain (245,343) (145,657) --------- --------- Accrued pension obligation at December 31 $ (3,917) $ (18,395) ========= ========= Reconciliations of the fair value of pension plan assets are (in thousands): 1999 1998 ---------- --------- Fair value of plan assets at January 1 $ 830,213 $ 768,297 Actual return on plan assets 127,167 87,382 Benefit payments (41,585) (25,466) Acquisition of NCNG 31,348 - ---------- --------- Fair value of plan assets at December 31 $ 947,143 $ 830,213 ========= ========= The weighted-average discount rate used to measure the pension obligation was 7.5% in 1999 and 7.0% in 1998. The assumed rate of increase in future compensation used to measure the pension obligation was 4.20% in 1999, 1998 and 1997. The expected long-term rate of return on pension plan assets used in determining the net periodic pension cost was 9.25% in 1999, 1998 and 1997. 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. 70 The components of net periodic OPEB cost are (in thousands): 1999 1998 1997 -------- -------- -------- Actual return on plan assets $ (5,931) $ (3,877) $ (4,628) Variance from expected return, Deferred 2,553 785 2,186 -------- -------- -------- Expected return on plan assets $ (3,378) $ (3,092) $ (2,442) Service cost 7,936 7,182 7,988 Interest cost 13,914 13,402 11,065 Amortization of transition obligation 5,760 5,641 5,889 Amortization of actuarial gain (1) (549) -- -------- -------- -------- Net periodic OPEB cost $ 24,231 $ 22,584 $ 22,500 ======== ======== ======== Actuarial gains and losses in excess of 10% of the greater of the OPEB obligation or the market-related value of assets are amortized over the average remaining service period of active participants. Reconciliations of the changes in the plan's benefit obligations and the plan's funded status are (in thousands): 1999 1998 --------- --------- OPEB obligation OPEB obligation at January 1 $ 196,846 $ 181,324 Interest cost 13,914 13,402 Service cost 7,936 7,182 Benefit payments (5,769) (4,774) Actuarial loss (gain) (7,307) 3,428 Plan amendment 1,062 (3,716) Acquisition of NCNG 6,806 -- --------- --------- OPEB obligation at December 31 $ 213,488 $ 196,846 Fair value of plan assets at December 31 43,235 37,304 --------- --------- Funded status $(170,253) $(159,542) Unrecognized transition obligation 76,593 78,978 Unrecognized prior service cost 1,062 -- Unrecognized actuarial gain (17,261) (7,314) --------- --------- Accrued OPEB obligation at December 31 $(109,859) $ (87,878) ========= ========= 71 Reconciliations of the fair value of OPEB plan assets are (in thousands): 1999 1998 --------- --------- Fair value of plan assets at January 1 $37,304 $33,427 Actual return on plan assets 5,931 3,877 --------- --------- Fair value of plan assets at December 31 $43,235 $37,304 ========= ========= The assumptions used to measure the OPEB obligation are: 1999 1998 --------- --------- Weighted-average discount rate 7.50% 7.00% Initial medical cost trend rate for pre-Medicare benefits 7.50% 6.60% Initial medical cost trend rate for post-Medicare benefits 7.25% 6.40% Ultimate medical cost trend rate 5.00% 4.50% Year ultimate medical cost trend rate is achieved 2006 2006 The expected long-term rate of return on plan assets used in determining the net periodic OPEB cost was 9.25% in 1999, 1998 and 1997. The medical cost trend rates were assumed to decrease gradually from the initial rates to the ultimate rates. Assuming a 1% increase in the medical cost trend rates, the aggregate of the service and interest cost components of the net periodic OPEB cost for 1999 would increase by $4.0 million, and the OPEB obligation at December 31, 1999, would increase by $29.3 million. Assuming a 1% decrease in the medical cost trend rates, the aggregate of the service and interest cost components of the net periodic OPEB cost for 1999 would decrease by $3.1 million and the OPEB obligation at December 31, 1999, would decrease by $23.6 million. During 1999, the Company completed the acquisition of NCNG (see Note 4). NCNG's pension and OPEB liabilities, assets and net periodic costs are reflected in the above information as appropriate. Effective January 1, 2000, NCNG's benefit plans were merged with those of the Company. 13. Earnings Per Common Share Restricted stock awards and contingently issuable shares had a dilutive effect on earnings per share for 1999 and increased the weighted-average number of common shares outstanding for dilutive purposes by 290,474, 250,660 and 11,893 for 1999, 1998 and 1997, respectively. The weighted-average number of common shares outstanding for dilutive purposes was 148.6 million, 144.2 million and 143.7 million for 1999, 1998 and 1997, respectively. 14. Income Taxes Deferred income taxes are provided for temporary differences between book and tax bases of assets and liabilities. Investment tax credits related to operating income are amortized over the service life of the related property. 72 Net accumulated deferred income tax liabilities at December 31 are (in thousands): 1999 1998 ---------- ---------- Accelerated depreciation and property cost differences $1,583,610 $1,632,119 Deferred costs, net 70,478 66,757 Miscellaneous other temporary differences, net 26,403 10,885 ---------- ---------- Net accumulated deferred income tax liability $1,680,491 $1,709,761 ========== ========== Total deferred income tax liabilities were $2.20 billion and $2.21 billion at December 31, 1999 and 1998, respectively. Total deferred income tax assets were $519 million and $501 million at December 31, 1999 and 1998, respectively. The net of deferred income tax liabilities and deferred income tax assets is included on the Consolidated Balance Sheets under the captions other current liabilities and accumulated deferred income taxes. Reconciliations of the Company's effective income tax rate to the statutory federal income tax rate are: 1999 1998 1997 ---- ---- ---- Effective income tax rate 40.3% 39.2% 37.5% State income taxes, net of federal income tax benefit (4.6) (4.7) (4.9) Investment tax credit amortization 1.6 1.5 1.7 Other differences, net (2.3) (1.0) 0.7 ---- ---- ---- Statutory federal income tax rate 35.0% 35.0% 35.0% ==== ==== ==== The provisions for income tax expense are comprised of (in thousands): 1999 1998 1997 --------- --------- --------- Income tax expense (credit) Current - federal $ 253,140 $ 254,400 $ 258,050 state 48,075 51,817 56,747 Deferred - federal (30,011) (34,842) (61,384) state (2,484) (3,675) (9,465) Investment tax credit (10,299) (10,206) (10,232) --------- --------- --------- Total income tax expense $ 258,421 $ 257,494 $ 233,716 ========= ========= ========= 15. 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 73 operating expenses. The Company's share of expenses for the jointly owned units is included in the appropriate expense category. The Company's ownership interest in the jointly owned generating facilities is listed below with related information as of December 31, 1999 (dollars in thousands):
Company Megawatt Ownership Accumulated Under Facility Capability Interest Plant Investment Depreciation Construction - ------------------------ ----------------- ------------- ------------------ --------------- -------------- Mayo Plant 745 83.83% $ 451,640 $ 205,278 $10,471 Harris Plant 860 83.83% 3,002,812 910,144 67,088 Brunswick Plant 1,631 81.67% 1,426,398 1,065,561 3,163 Roxboro Unit No. 4 700 87.06% 240,649 116,237 19,175
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. 16. 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 of, and energy from, the Harris Plant. 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 $26 million. These contractual purchases, including purchases from the Mayo Plant that ended in 1997, totaled $36.5 million, $34.4 million and $36.2 million for 1999, 1998 and 1997, respectively. 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 10-year levelization period. At December 31, 1999 and 1998, the Company had deferred purchased capacity costs, including carrying costs accrued on the deferred balances, of $56.1 million and $60.0 million, respectively. Increased purchases (which are not being deferred for future recovery) resulting from the 1993 agreement with Power Agency were approximately $23 million, $19 million and $17 million for 1999, 1998 and 1997, respectively. During 1999, the Company had two long-term agreements for the purchase of power and related transmission services 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 (Rockport). The second agreement, which expired mid-1999, was with Duke Energy for the purchase of 400 megawatts of firm capacity. The estimated minimum annual payment for power purchases under the Rockport agreement is approximately $31 million, representing capital-related capacity costs. Total purchases (including transmission use charges) under the Rockport agreement amounted to $59.5 million, $59.3 million and $61.9 million for 1999, 1998 and 1997, respectively. Total purchases (including transmission use charges) under the agreement with Duke Energy amounted to $33.8 million, $75.5 million and $69.5 million for 1999, 1998 and 1997, respectively. b. Insurance The Company is a member of Nuclear Electric Insurance Limited (NEIL), which provides primary and excess insurance coverage against property damage to members' nuclear generating facilities. Under the primary program, the Company is insured for $500 million at each of its nuclear plants. In addition to primary coverage, NEIL also provides decontamination, premature decommissioning and excess property insurance with limits of $1.4 billion on the Brunswick Plant, $2 billion on the Harris Plant and $800 million on the Robinson Plant. 74 Insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at nuclear generating units is also provided through membership in NEIL. The Company is insured thereunder, following a twelve week deductible period, for 52 weeks in weekly amounts of $1.95 million at Brunswick Unit No. 1, $1.93 million at Brunswick Unit No. 2, $2.0 million at the Harris Plant and $1.7 million at Robinson Unit No. 2. An additional 104 weeks of coverage is provided at 80% of the above weekly amounts. For the current policy period, the Company is subject to retrospective premium assessments of up to approximately $12.5 million with respect to the primary coverage, $13.7 million with respect to the decontamination, decommissioning and excess property coverage and $5.0 million for the incremental replacement power costs coverage in the event covered expenses at insured facilities exceed premiums, reserves, reinsurance and other NEIL resources. These resources as of December 31, 1999 totaled approximately $5.0 billion. Pursuant to regulations of the NRC, the Company's property damage insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and stable condition after an accident and, second, to decontamination costs, before any proceeds can be used for decommissioning, 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 $9.7 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 $83.9 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 No. 71 The Company's ability to continue to meet the criteria for application of SFAS No. 71 (see Note 9a) may be affected in the future by competitive forces and restructuring in the electric utility industry. In the event that SFAS No. 71 no longer applied to a separable portion of the Company's operations, related regulatory assets and liabilities would be eliminated unless an appropriate regulatory recovery mechanism is provided. Additionally, these factors could result in an impairment of electric utility plant assets as determined pursuant to SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." 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 federal and state laws. There are several manufactured gas plant (MGP) sites to which both the electric utility and the gas utility have some connection. In this regard, both the electric utility and the gas utility, along with others, are participating in a cooperative effort with the North Carolina Department of Environment and Natural Resources, Division of Waste Management (DWM). The DWM has established a uniform framework to address MGP sites. The investigation and remediation of specific MGP sites will be addressed pursuant to one or more Administrative Orders on Consent (AOC) between the DWM and the potentially responsible party or parties. Both the electric utility and the gas utility have signed AOCs to investigate certain sites at which investigation includes the completion of interim remedial measures where appropriate and anticipate signing AOCs to remediate sites as well. Both the electric utility and the gas utility continue to identify parties connected to individual MGP sites, and to determine their relative relationship to other parties at those sites and the degree to which they will undertake efforts with others at individual sites. The Company does not expect the costs associated with these sites to be material to the financial position or consolidated results of operations of the Company. The Company is periodically notified by regulators such as the North Carolina Department of Environment and Natural Resources, the South Carolina Department of Health and Environmental Control, and the U.S. Environmental Protection Agency (EPA) of its involvement or potential involvement in sites, other than MGP sites, that may require investigation 75 and/or remediation. Although the Company may incur costs at the sites about which it has been notified, based upon the current status of these sites, the Company does not expect those costs to be material to the consolidated financial position or results of operations of the Company. The EPA has been conducting an enforcement initiative related to a number of coal-fired utility power plants in an effort to determine whether modifications at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The Company has recently been asked to provide information to the EPA as part of this initiative and has cooperated in providing the requested information. The EPA has initiated enforcement actions, which may have potentially significant penalties against other companies that have been subject to this initiative. The Company cannot predict the outcome of this matter. The EPA published a final rule approving petitions under section 126 of the Clean Air Act which requires certain sources to make reductions in nitrogen oxide emissions by 2003. The Company's fossil-fueled electric generating plants are included in these petitions. The Company and other states are participating in litigation challenging the EPA's action. The Company cannot predict the outcome of this matter. 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 begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract. In April 1995, the DOE issued a final interpretation that it did not have an unconditional obligation to take spent nuclear fuel by January 31, 1998. In Indiana & Michigan Power v. DOE, the Court of Appeals vacated the DOE's final interpretation and ruled that the DOE had an unconditional obligation to begin taking spent nuclear fuel. The Court did not specify a remedy because the DOE was not yet in default. After the DOE failed to comply with the decision in Indiana & Michigan Power v. DOE, a group of utilities (including the Company) petitioned the Court of Appeals in Northern States Power (NSP) v. DOE, seeking an order requiring the DOE to begin taking spent nuclear fuel by January 31, 1998. The DOE took the position that their delay was unavoidable, and the DOE was excused from performance under the terms and conditions of the contract. The Court of Appeals issued an order which precluded the DOE from treating the delay as an unavoidable delay. However, the Court of Appeals did not order the DOE to begin taking spent nuclear fuel, stating that the utilities had a potentially adequate remedy by filing a claim for damages under the contract. After the DOE failed to begin taking spent nuclear fuel by January 31, 1998, a group of utilities (including the Company) filed a motion with the Court of Appeals to enforce the mandate in NSP v. DOE. Specifically, the utilities asked the Court to permit the utilities to escrow their waste fee payments, to order the DOE not to use the waste fund to pay damages to the utilities, and to order the DOE to establish a schedule for disposal of spent nuclear fuel. The Court denied this motion based primarily on the grounds that a review of the matter was premature, and that some of the requested remedies fell outside of the mandate in NSP v. DOE. Subsequently, a number of utilities each filed an action for damages in the Court of Claims and before the Court of Appeals. The Company is in the process of evaluating whether it should file a similar action for damages. In NSP v. U.S., the Court of Claims decided that NSP must pursue its administrative remedies instead of filing an action in the Court of Claims. NSP has filed an interlocutory appeal to the Court of Appeals based on NSP's position that the Court of Claims has jurisdiction to decide the matter. A group of utilities (including the Company) has submitted an amicus brief in support of NSP's position. The Company also continues to monitor legislation that has been introduced in Congress which might provide some limited relief. The Company cannot predict the outcome of this matter. With certain modifications and additional approval by the NRC, the Company's spent nuclear fuel storage facilities will be 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. The Company has initiated the process of obtaining the additional NRC approval. 76 3. In the opinion of management, liabilities, if any, arising under other pending claims would not have a material effect on the financial position and consolidated results of operations of the Company. 77 CAROLINA POWER & LIGHT COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Year Ended December 31, 1999
- ----------------------------------------------------------------------------------------------------------------------- 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 Accounts Reserves Period - ----------------------------------------------------------------------------------------------------------------------- Reserves deducted from related assets on the balance sheet: Uncollectible accounts $ 14,226,931 $ 6,966,304 $ 2,607,368 $ 6,990,838 $ 16,809,765 =============== =============== =============== ================ =============== Reserves deducted from related assets on the balance sheet: Inventory $ 145,051 $ 75,752 $ 322,279 $ 145,582 $ 397,500 =============== =============== =============== ================ =============== Reserves other than those deducted from assets on the balance sheet: Injuries and damages $ 1,010,556 $ 1,194,082 $ -0- $ 1,465,077 $ 739,561 =============== =============== =============== ================ =============== Reserve for possible coal mine investment losses $ 7,328,465 $ -0- $ -0- $ 307,369 $ 7,021,096 =============== =============== =============== ================ =============== Reserve for employee retirement and compensation plans $ 151,475,256 $ 10,314,770 $ 5,016,896 $ 5,130,952 $ 161,675,970 =============== =============== =============== ================ =============== Reserve for environmental investigation and remediation costs $ 321,448 $ -0- $ 1,025,000 $ -0- $ 1,346,448 =============== =============== =============== ================ =============== Reserve for product warranty $ 465,000 $ 438,168 $ -0- $ 87,939 $ 815,229 =============== =============== =============== ================ ===============
78 CAROLINA POWER & LIGHT COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Year Ended December 31, 1998
- ----------------------------------------------------------------------------------------------------------------------- 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 Accounts Reserves Period - ----------------------------------------------------------------------------------------------------------------------- Reserves deducted from related assets on the balance sheet: Uncollectible accounts $ 3,366,361 $ 17,993,081$ -0- $ 7,132,511 $ 14,226,931 =============== =============== =============== ================ =============== Reserves deducted from related assets on the balance sheet: Inventory $ -0- $ 145,051 $ -0- $ -0- $ 145,051 =============== =============== =============== ================ =============== Reserves other than those deducted from assets on the balance sheet: Injuries and damages $ 1,319,664 $ 806,828 $ -0- $ 1,115,936 $ 1,010,556 =============== =============== =============== ================ =============== Reserve for possible coal mine investment losses $ 7,505,994 $ -0- $ -0- $ 177,529 $ 7,328,465 =============== =============== =============== ================ =============== Reserve for employee retirement and compensation plans $ 142,232,971 $ 16,569,740 $ -0- $ 7,327,455 $ 151,475,256 =============== =============== =============== ================ =============== Reserve for environmental investigation and remediation costs $ 1,815,909 $ -0- $ -0- $ 1,494,461 $ 321,448 =============== =============== =============== ================ =============== Reserve for product warranty $ -0- $ 465,000 $ -0- $ -0- $ 465,000 =============== =============== =============== ================ ===============
79
CAROLINA POWER & LIGHT COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS Year Ended December 31, 1997 - --------------------------------------------------------------------------------------------------------------------------- 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 Accounts Reserves Period - --------------------------------------------------------------------------------------------------------------------------- Reserves deducted from related assets on the balance sheet: Uncollectible accounts $ 3,689,783 $ 6,296,392 $ -0- $ 6,619,814 $ 3,366,361 =============== =============== ================ ================ ================ Reserves other than those deducted from assets on the balance sheet: Injuries and damages $ 1,277,888 $ 714,353 $ -0- $ 672,577 $ 1,319,664 =============== =============== ================ ================ ================ Reserve for possible coal mine investment losses $ 7,625,008 $ -0- $ -0- $ 119,014 $ 7,505,994 =============== =============== ================ ================ ================ Reserve for employee retirement and compensation plans $ 107,569,407 $ 39,690,015 $ -0- $ 5,026,451 $ 142,232,971 =============== =============== ================ ================ ================ Reserve for environmental investigation and remediation costs $ 1,815,909 $ -0- $ -0- $ -0- $ 1,815,909 =============== =============== ================ ================ ================
80 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 2000 definitive proxy statement dated March 31, 2000, 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 2000 definitive proxy statement dated March 31, 2000, 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 Capital Research and Management Company, 333 South Hope Street, Los Angeles, CA 90071, which as of December 31, 1999, owned 9,450,000 shares of common stock (5.9% of class) as investment advisor and manager of The American Funds Group of Mutual Funds. b) Information on security ownership of the Company's management is set forth in the Company's 2000 definitive proxy statement dated March 31, 2000, 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 2000 definitive proxy statement dated March 31, 2000, and incorporated by reference herein. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. a) The following documents are filed as part of the report: 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 81 3. Exhibits Filed: See EXHIBIT INDEX b) Reports on Form 8-K filed during or with respect to the last quarter of 1999 and the portion of the first quarter of 2000 prior to the filing of this Form 10-K: 1. Current Report on Form 8-K dated October 25, 1999. 82 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. CAROLINA POWER & LIGHT COMPANY ------------------------------ Date: 3/24/00 (Registrant) ------- By: /s/Robert B. McGehee -------------------- Executive Vice President and Interim Chief Financial Officer By: /s/Larry M. Smith --------------------- Vice President and Controller 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 3/15/00 - -------------------------- Officer and Director (William Cavanaugh III, Chairman, President and Chief Executive Officer) /s/ Robert B. McGehee Principal Financial 3/15/00 - ---------------------- Officer (Robert B. McGehee, Executive Vice President, General Counsel, Chief Administrative Officer and Interim Chief Financial Officer) /s/ Leslie M. Baker, Jr. Director 3/15/00 - ------------------------ (Leslie M. Baker, Jr.) /s/ Edwin B. Borden Director 3/15/00 - -------------------- (Edwin B. Borden) /s/ David L. Burner Director 3/15/00 - -------------------- (David L. Burner) /s/ Charles W. Coker Director 3/15/00 - --------------------- (Charles W. Coker) 83 Director 3/15/00 - ------------------------ (Richard L. Daugherty) /s/ Robert L. Jones Director 3/15/00 - -------------------- (Robert L. Jones) /s/ Estell C. Lee Director 3/15/00 - ------------------ (Estell C. Lee) /s/ William O. McCoy Director 3/15/00 - --------------------- (William O. McCoy) /s/ E. Marie McKee Director 3/15/00 - ------------------- (E. Marie McKee) /s/ John H. Mullin, III Director 3/15/00 - ------------------------ (John H. Mullin, III) /s/ Sherwood H. Smith, Jr. Director 3/15/00 - -------------------------- (Sherwood H. Smith, Jr., Chairman Emeritus) /s/ J. Tylee Wilson Director 3/15/00 - -------------------- (J. Tylee Wilson)
84 EXHIBIT INDEX EXHIBIT NUMBER DESCRIPTION *2(a) Agreement and Plan of Merger By and Among Carolina Power & Light Company, North Carolina Natural Gas Corporation and Carolina Acquisition Corporation, dated as of November 10, 1998 (filed as Exhibit No. 2(b) to Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1998, File No. 1-3382.) *2(b) Agreement and Plan of Merger by and among Carolina Power & Light Company, North Carolina Natural Gas Corporation and Carolina Acquisition Corporation, Dated as of November 10, 1998, as Amended and Restated as of April 22, 1999 (filed as Exhibit 2 to Quarterly Report on Form 10-Q for the quarterly period ended March 31, 1999, File No. 1-3382). *2(c) Agreement and Plan of Exchange, dated as of August 22, 1999, by and among Carolina Power & Light Company, Florida Progress Corporation and CP&L Holdings, Inc. (filed as Exhibit 2.1 to Current Report on Form 8-K dated August 22, 1999, File No. 1-3382). *2(4) Amended and Restated Agreement and Plan of Exchange, by and among Carolina Power & Light Company, Florida Progress Corporation and CP&L Energy, Inc., dated as of August 22, 1999, amended and restated as of March 3, 2000 (filed as Annex A to Joint Preliminary Proxy Statement of Carolina Power & Light Company and Florida Progress Corporation dated March 6, 2000, File No. 1-03382). *3a(1) Restated Charter of Carolina Power & Light Company, as amended May 10, 1996 (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). *3a(2) Restated Charter of Carolina Power & Light Company as amended on May 10, 1996 (filed as Exhibit 3(i) to Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1997, File No. 1-3382). *3b(1) By-Laws of Carolina Power & Light Company, as amended May 10, 1996 (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). *3b(2) By-Laws of Carolina Power & Light Company, as amended on September 18, 1996 (filed as Exhibit 3(ii) to Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1997, File No.1-3382). *3b(3) By-Laws of Carolina Power & Light Company, as amended on March 17, 1999 (filed as Exhibit No. 3b(3) to Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-3382). *4a(1) Resolution of Board of Directors, dated December 8, 1954, authorizing the issuance of, and establishing the series designation, dividend rate and redemption 85 prices for the Company's Serial Preferred Stock, $4.20 Series (filed as Exhibit 3(c), File No. 33-25560). *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). *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). *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). *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 (Douglas J. MacInnes, Successor), Trustees and the First through Fifth Supplemental Indentures thereto (Exhibit 2(b), File No. 2-64189); and the Sixth through Sixty-sixth 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; 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(c) 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) to Post-Effective Amendment No. 1, File No. 33-38349; Exhibit 4(e), File No. 33-50597; Exhibit 4(e) and 4(f), File No. 33-57835; Exhibit to Current Report on Form 8-K dated August 28, 1997, File No. 1-3382; Form of Carolina Power & Light Company First Mortgage Bond, 6.80% Series Due August 15, 2007 filed as Exhibit 4 to Form 10-Q for the period ended September 30, 1998, File No. 1-3382; Exhibit 4(b), File No. 333-69237; and Exhibit 4(c), File No. 1-03382.) *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(c) to Current Report on Form 8-K dated April 13, 1995, File No. 1-3382). *4c(2) Resolutions adopted by the Executive Committee of the Board of Directors at a 86 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). *4d Indenture (for Senior Notes), dated as of March 1, 1999 between Carolina Power & Light Company and The Bank of New York, as Trustee, and the First Supplemental Senior Note Indenture thereto, (filed as Exhibits No. 4(a) and 4(b) to Current Report on Form 8-K dated March 19, 1999, File No. 1-03382). *4(e) Indenture (For Debt Securities), dated as of October 28, 1999 between Carolina Power & Light Company and The Chase Manhattan Bank, as Trustee (filed as Exhibit 4(a) to Current Report on Form 8-K dated November 5, 1999, File No. 1-03382). *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). *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). *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). *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). *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). *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). 87 + *10b(1) Directors Deferred Compensation Plan effective January 1, 1982 as amended (filed as Exhibit 10(g), File No. 33-25560). + *10b(2) Supplemental Executive Retirement Plan effective January 1, 1984 (filed as Exhibit 10(h), File No. 33-25560). + *10b(3) Retirement Plan for Outside Directors (filed as Exhibit 10(i), File No. 33-25560). + *10b(4) Executive Deferred Compensation Plan effective May 1, 1982 as amended (filed as Exhibit 10(j), File No. 33-25560). + *10b(5) Key Management Deferred Compensation Plan (filed as Exhibit 10(k), File No. 33-25560). + *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). +*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). +*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). +*10b(9) 1997 Equity Incentive Plan, approved by the Company's shareholders May 7, 1997, effective as of January 1, 1997 (filed as Appendix A to the Company's 1997 Proxy Statement, File No. 1-03382). +*10b(10) Performance Share Sub-Plan of the 1997 Equity Incentive Plan, adopted by the Personnel, Executive Development and Compensation Committee of the Board of Directors, March 19, 1997, subject to shareholder approval of the 1997 Equity Incentive Plan, which was obtained on May 7, 1997, (filed as Exhibit 10(b), File No. 1-03382). +*10b(11) Resolutions of Board of Directors dated July 9, 1997, amending the Deferred Compensation Plan for Key Management Employees of Carolina Power & Light Company. +*10b(12) Resolutions of Board of Directors dated July 9, 1997, amending the Supplemental Executive Retirement Plan of Carolina Power & Light Company. +*10b(13) Amended Management Incentive Compensation Program of Carolina Power & Light Company, as amended December 10, 1997. +*10b(14) Carolina Power & Light Company Restoration Retirement Plan, effective January 1, 1998. +*10b(15) Carolina Power & Light Company Non-Employee Director Stock Unit Plan, effective January 1, 1998. +*10b(16) Carolina Power & Light Company Restricted Stock Agreement, as approved 88 January 7, 1998, pursuant to the Company's 1997 Equity Incentive Plan (filed as Exhibit No. 10 to Quarterly Report on Form 10-Q for the quarterly period ended March 31, 1998, File No. 1-3382.) +*10b(17) Resolutions of Board of Directors dated July 17, 1998, amending the Supplemental Executive Retirement Plan of Carolina Power & Light Company, effective January 1, 1999, (filed as Exhibit No. 10(a) to Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1998, File No. 1-3382.) +*10b(18) Amended Management Incentive Compensation Plan of Carolina Power & Light Company, effective January 1, 1999, as amended by the Organization and Compensation Committee of the Board of Directors on July 17, 1998, (filed as Exhibit No. 10(b) to Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1998, File No. 1-3382.) +*10b(19) Supplemental Senior Executive Retirement Plan of Carolina Power & Light Company, as amended January 1, 1999 (filed as Exhibit No. 10b(19) to Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-3382). +*10b(20) Carolina Power & Light Company Restoration Retirement Plan, as amended January 1, 1999 (filed as Exhibit No. 10b(20) to Annual Report on Form 10-K for the fiscal year ended December 31, 1998, File No. 1-3382). +10b(21) Performance Share Sub-Plan of the 1997 Equity Incentive Plan, as Revised and Restated March 17, 1999. +10b(22) Amended Management Incentive Compensation Plan of Carolina Power & Light Company, as amended January 1, 2000. +*10b(23) Carolina Power & Light Company Management Deferred Compensation Plan, adopted as of January 1, 2000, (filed as Exhibit 4 to Form S-8 dated October 25, 1999, File No. 333-89685). +10b(24) Amended and Restated Supplemental Senior Executive Retirement Plan of Carolina Power & Light Company, effective January 1, 1984, as last amended March 15, 2000. +*10b(25) Employment Agreement dated September 1, 1992, by and between the Company and William Cavanaugh III (filed as Exhibit 10b, File No. 1-03382). +*10b(26) Employment Agreement dated April 1, 1993, by and between the Company and William S. Orser (filed as Exhibit 10b, File No. 1-03382). +*10b(27) Employment Arrangement dated September 27, 1994 by and between the Company and Glenn E. Harder (filed as Exhibit 10b, File No. 1-03382). +*10b(28) Personal Services Agreement dated September 18, 1996, by and between the Company and Sherwood H. Smith, Jr. (filed as Exhibit 10b, File No.1-03382). 89 +*10b(29) Employment Agreement dated June 2, 1997, by and between the Company and Robert B. McGehee (filed as Exhibit 10b, File No. 1-03382). +*10b(30) Employment Agreement dated September 24, 1997, by and between the Company and John E. Manczak (filed as Exhibit 10b, File No. 1-03382). +*10b(31) Employment Agreement dated August 3, 1998, by and between the Company and Tom D. Kilgore (filed as Exhibit 10b(27) to the Company's Annual Report on Form 10-K for the year ended December 31, 1998, File No. 1-3382). +10b(32) Agreement dated April 27, 1999 between the Company and Sherwood H. Smith, Jr. +10b(33) Employment Agreement dated July 15, 1999 by and between North Carolina Natural Gas Corporation and Calvin B. Wells. +10b(34) Employment Arrangement dated August 5, 1999 by and between the Company and Larry M. Smith. 12 Computation of Ratio of Earnings to Fixed Charges and Preferred Dividends Combined and Ratio of Earnings to Fixed Charges. 21 Subsidiaries of Carolina Power & Light Company 23(a) Consent of Deloitte & Touche LLP. 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. 90 EX-10 2 EX-10B(21)PERFORMANCE SHARE SUB-PLAN EXHIBIT 10B(21) EXHIBIT A TO 1997 EQUITY INCENTIVE PLAN PERFORMANCE SHARE SUB-PLAN -------------------------- (As Revised and Restated March 17, 1999) This Performance Share Sub-Plan ("Sub-Plan") sets forth the rules and regulations adopted by the Committee for issuance of Performance Share Awards under Section 10 of the 1997 Equity Incentive Plan ("Plan"). Capitalized terms used in this Sub-Plan that are not defined herein shall have the meaning given in the Plan. In the event of any conflict between this Sub-Plan and the Plan, the terms and conditions of the Plan shall control. No Award Agreement shall be required for participation in this Sub-Plan. SECTION 1. DEFINITIONS When used in this Sub-Plan, the following terms shall have the meanings as set forth below, and are in addition to the definitions set forth in the Plan. 1.1 "Account" means the account used to record and track the number of Performance Shares granted to each Participant as provided in Section 2.4. 1.2 "Award" as used in this Sub-Plan means each aggregate award of Performance Shares as provided in Section 2.2. 1.3 "EBITDA" means earnings before interest, taxes, depreciation, and amortization as determined from time to time by the Committee. 1.4 "EBITDA Growth" means the percentage increase (if any) in EBITDA for any Year, as compared to the previous Year as determined from time to time by the Committee. 1.5 "Peer Group" means the utilities included in the Standard & Poors Utility (Electric Power Companies) Index. 1.6 "Performance Period" for purposes of this Sub-Plan means three consecutive Years beginning with the Year in which an Award is granted. 1.7 "Performance Schedule" means Attachment 1 to this Sub-Plan, which sets forth the Performance Measures applicable to this Sub-Plan. 1.8 "Performance Share" for purposes of this Sub-Plan means each unit of an Award granted to a Participant, the value of which is equal to the value of Company Stock as hereinafter provided. 1.9 "Retire" or "Retirement" means termination of employment on or after: (a) becoming 65 years old with at least 5 years of service; (b) becoming 55 years old with at least 15 years of service; or (c) achieving at least 35 years of service, regardless of age. 1.10 "Salary" means the regular base rate of compensation payable by the Company to a Participant on an annual basis as of the date an Award is Granted. Salary does not include bonuses, if any, or incentive compensation, if any. Such compensation shall not be reduced by any deferrals made under any other plans or programs maintained by the Company. 1.11 "Total Shareholder Return" means the total percentage return realized by the owner of a share of stock during a relevant Year or any part thereof. Total Shareholder Return is equal to the appreciation or depreciation in value of the stock (which is equal to the closing value of the stock on the last trading day of the relevant period minus the closing value of the stock on the last trading day of the preceding Year) plus the dividends declared during the relevant period, divided by the closing value of the stock on the last trading day of the preceding Year. Closing values for the stock on the dates given above shall be those published in the Wall Street Journal. 1.12 "Year" means a calendar year. SECTION 2. SUB-PLAN PARTICIPATION AND AWARDS 2.1 Participant Selection. Participants under this Sub-Plan shall be selected by the Committee in its sole discretion as provided in Section 4.2 of the Plan. 2.2 Awards. Subject to any adjustments to be made under Section 2.5, the Compensation Committee may, in its sole discretion, grant Awards to some or all of the Participants in the form of a specific number of Performance Shares. The total value of any Award shall not exceed the following limitations, based on the Participant's Salary on the date that the Award is granted: ----------------------------------- --------------------- Participant Award Limitation ----------------------------------- --------------------- President/CEO 75% of Salary ----------------------------------- --------------------- Group Executives 50% of Salary ----------------------------------- --------------------- Department Heads and Key Managers* Level I 30% of Salary Level II 25% of Salary Level III 20% of Salary ----------------------------------- --------------------- *Levels shall be determined in the sole discretion of the Committee 2 2.3 Award Valuation at Grant. In calculating the limitations set forth in Section 2.2, the value of each Performance Share shall be equal to the closing price of a share of Stock on the last trading day before the Award is granted, as published in the Wall Street Journal. Each Award is deemed to be granted on the day that it is approved by the Committee. 2.4 Accounting and Adjustment of Awards. The number of Performance Shares awarded to a Participant shall be recorded in a separate Account for each Participant. The number of Performance Shares recorded in a Participant's Account shall be adjusted to reflect any splits or other adjustments in the Stock. If any cash dividends are paid on the Stock, the number of Performance Shares in each Participant's Account shall be increased by a number equal to (i) the dividend multiplied times the number of Performance Shares in each Participant's Account, divided by (ii) the closing price of a share of Stock on the payment date of the dividend, as published in the Wall Street Journal. 2.5 Performance Schedule and Calculation of Awards. Each Award shall become vested on January 1 immediately following the end of the applicable Performance Period, subject to adjustment in accordance with the following procedure. (a) One half of the Award shall be adjusted as follows: (i) The Total Shareholder Return for the Company shall be determined for each Year during the Performance Period, and shall then be averaged (the "Company TSR"). (ii) The average Total Shareholder Return for all Peer Group utilities shall be determined for each Year during the Performance Period, and shall then be averaged ( the "Peer Group TSR"). (iii) The Peer Group TSR for the Performance Period shall be subtracted from the Company TSR for the Performance Period. The remainder shall then be used to determine the number of vested Performance Shares using the Performance Schedule, based on one half of the number of Performance Shares in the Participant's Account. (b) The other half of the Award shall be adjusted as follows: (i) The EBITDA Growth for the Company shall be determined for each Year during the Performance Period, and shall then be averaged (the Company EBITDA Growth"). 3 (ii) The average EBITDA Growth for all Peer Group utilities shall be determined for each Year during the Performance period, and shall be averaged (the Peer Group EBITDA Growth"). (iii) The Peer Group EBITDA Growth for the Performance Period shall be subtracted from the Company EBITDAGrowth for the Performance Period. The remainder shall then be used to determine the number of vested Performance Shares using the Performance Schedule, based on one half of the number of Performance Shares in the Participant's Account. (c) The total number of vested Performance Shares payable to the Participant shall be the sum of the amounts determined in accordance with subsections (a) and (b) above. (d) The Performance Measures and the Performance Schedule will not change during any Performance Period with regard to any Awards that have already been granted. The Committee reserves the right to modify or adjust the Performance Measures and/or the Performance Schedule in the Committee's sole discretion with regard to future grants. 2.6 Payment Options. Except as provided in Section 3, Awards shall be paid after expiration of the Performance Period. The Company will pay in cash to each Participant the aggregate value of vested Performance Shares, which shall be determined in accordance with Section 2.7. Payment shall be made as follows: (a) 100% on or about April 1 of the Year immediately following expiration of the Performance Period; or (b) in accordance with an alternative payment election made by Participant substantially in the form attached hereto as Attachment 2, provided that such election is executed by the Participant and returned to the Vice President, Human Resources Department no later than the end of the first Year of the Performance Period. Once made, this election is irrevocable. 2.7 Valuation of Performance Shares. For the purposes of payment of under Section 2.6, the aggregate value of vested Performance Shares shall be equal to the total number of vested Performance Shares in the Participant's Account (after any applicable adjustments under Section 2.5) multiplied times the closing price of the Stock on the last trading day before payment of the Award, as published in the Wall Street Journal. SECTION 3. EARLY VESTING AND FORFEITURE 3.1 Retirement, Death, Disability, Divestiture or Change in Control. If prior to expiration of the Performance Period the Participant Retires, dies or becomes disabled, or in the event of a Divestiture or a Change in Control during a Performance Period, the 4 Participant's Award shall immediately become vested, and the aggregate value of the Award shall be paid in cash after being adjusted accordance with the following procedure. (a) One half of the Award shall be adjusted as follows: (i) The Total Shareholder Return for the Company shall be determined for each Year or partial Year, and a weighted average Total Shareholder Return for the Company shall be calculated for the period between the first day of the Performance Period and the date the Participant Retires, dies or becomes Disabled, or the date of the Divestiture, or the date that the Change in Control becomes effective (the "Prorated Company TSR"). (ii) The average Total Shareholder Return for all Peer Group utilities shall be determined for each Year or partial Year, and a weighted average Total Shareholder Return shall be calculated for the period between the first day of the Performance Period and the date the Participant Retires, dies or becomes Disabled, or the date of the Divestiture, or the date that the Change in Control becomes effective ( the "Prorated Peer Group TSR"). (iii) The Prorated Peer Group TSR for the Performance Period shall be subtracted from the Prorated Company TSR for the Performance Period. The remainder shall then be used to determine the vested Performance Shares using the Performance Schedule, based on one half of the number of Performance Shares in the Participant's Account. (b) The other half of the Award shall be adjusted as follows: (i) The EBITDA Growth for the Company shall be determined for each Year or partial Year, and a weighted average EBITDA Growth for the Company shall be calculated for the period between the first day of the Performance Period and the end of the calendar quarter immediately preceding the date that the Participant Retires, dies or becomes Disabled, or end of the calendar quarter immediately preceding the date of the Divestiture, or the date that the Change in Control becomes effective (the "Prorated Company EBITDA Growth"). (ii) The average EBITDA Growth for all Peer Group utilities shall be determined for each Year or partial Year, and a weighted average EBITDA Growth shall be calculated for the period between the first day of the Performance Period and the end of the calendar quarter immediately preceding the date the Participant Retires, dies or becomes Disabled, or the end of the calendar quarter immediately preceding the date of the 5 Divestiture, or the date that the Change in Control becomes effective ( the "Prorated Peer Group EBITDA Growth"). (iii) The Prorated Peer Group EBITDA Growth for the Performance Period shall be subtracted from the Prorated Company EBITDA Growth for the Performance Period. The remainder shall then be used to determine the vested Performance Shares using the Performance Schedule, based on one half of the number of Performance Shares in the Participant's Account. (c) The total number of vested Performance Shares payable to the Participant shall be the sum of the amounts determined in accordance with subsections (a) and (b) above. (d) If the Participant Retires, the Award shall be paid in accordance with the Participant's election as provided in Section 2.6. If the Participant dies or becomes disabled, or in the event of a Divestiture or Change in Control, payment shall be made in cash within a reasonable time after the Participant dies or becomes Disabled, or within a reasonable time after the Divestiture or Change in Control becomes effective, notwithstanding any election under Section 2.6. Payment upon death shall be made to the Participant's Designated Beneficiary. The aggregate value of the vested Performance Shares shall be determined in accordance with section 3.2. 3.2 Valuation of Performance Shares. For the purposes of payment under Section 3.1, the aggregate value of vested Performance Shares shall be equal to the number of vested Performance Shares in the Participant's Account (after any applicable adjustments under Section 3.1) multiplied times the closing price of the Stock on the date that the Participant Retires, dies or becomes Disabled, or on the date of the Divestiture or Change in Control (as applicable), as published in the Wall Street Journal. 3.3 Termination of Employment. In the event that a Participant's employment with the Company terminates for any reason other than Retirement, death or Disability, any Award made to the Participant which has not vested as provided in Section 2 shall be forfeited. Any vested Awards shall be paid within a reasonable time after termination, notwithstanding any election to defer the payment of any Award under Section 2.6. 4. NON-ASSIGNABILITY OF AWARDS The Awards and any right to receive payment under the Plan and this Sub-Plan may not be anticipated, alienated, pledged, encumbered, or subject to any charge or legal process, and if any attempt is made to do so, or a Participant becomes bankrupt, then in the sole discretion of the Committee, any Award made to the Participant which has not vested as provided in Sections 2 and 3 shall be forfeited. 5. AMENDMENT AND TERMINATION 6 This Sub-Plan shall be subject to amendment, suspension, or termination as provided in the Plan. 7 ATTACHMENT 1 ------------ PERFORMANCE SCHEDULE -------------------- PERFORMANCE SHARE CALCULATION(1) -------------------------------- The following table shall be used to adjust one half of the Participant's Award in accordance with Section 2.5(a) or Section 3.1(a) of the Plan: IF THE COMPANY TSR(2) MINUS THEN THE 50% OF THE VESTED THE PEER GROUP TSR(2) IS: PERFORMANCE SHARE AWARD SHALL BE MULTIPLIED BY: 5% or better 2.00 4.0 - 4.99 1.75 3.0 - 3.99 1.50 2.0 - 2.99 1.25 1.0 - 1.99 1.00 (0.99) - 0.99 .50 (1.0) - (1.99) .25 (2.0) or less 0.00 8 The following table shall be used to adjust one half of the Participant's Award in accordance with Section 2.5(b) or Section 3.1(b) of the Plan: IF THE COMPANY EBITDA GROWTH(2) MINUS THEN THE 50% OF THE VESTED THE PEER GROUP EBITDA GROWTH(2) IS: PERFORMANCE SHARE AWARD SHALL BE MULTIPLIED BY: 5% or better 2.00 4.0 - 4.99 1.75 3.0 - 3.99 1.50 2.0 - 2.99 1.25 1.0 - 1.99 1.00 0.00 - 0.99 .50 Less than 0 0 (1) The number of Performance Shares as calculated above shall be paid in accordance with the provisions of Section 2.5 and 2.6 of the Sub-Plan. (2) For purposes of Section 3, the Prorated Company TSR and EBITDA Growth and Prorated Peer Group TSR and EBITDA Growth shall be used, and the number of Performance Shares as calculated above shall be paid in accordance with the provisions of Section 3.1 of the Sub-Plan. 9 ATTACHMENT 2 ------------ PERFORMANCE SHARE SUB-PLAN 199_ DEFERRAL ELECTION FORM As an employee of Carolina Power & Light Company ("Company"), and a participant in the Performance Share Sub-Plan of the 1997 Equity Incentive Plan ("Sub-Plan"), I hereby elect to defer payment of my Award otherwise payable to me by the Company and attributable to services to be performed by me during the Performance Period beginning on January __, 199__. This election shall apply to [CHECK ONE]: [ ] 100% of the Award [ ] 50% of the Award [ ] 75% of the Award [ ] 25% of the Award Upon vesting, I understand that my Award shall continue be recorded in my Account as Performance Shares as described in the Sub-Plan and adjusted to reflect the payment and reinvesting of the Company's common stock dividends over the deferral period, until paid in full. I hereby elect to defer receipt (or commencement of receipt) of my Award until the date specified below, or as soon as practical thereafter [CHECK ONE]: [ ] a specific date certain at least 5 years from expiration of the Performance Period: 4 / 1 / * --------------------- (month/day/year) [ ] the April 1 following the date of retirement [ ] the April 1 following the first anniversary of my date of retirement * Notwithstanding my election above, if I elect a date certain distribution and I retire before that date certain, I understand that the Company will commence distribution of my account no later than the April 1 following the first anniversary of the date of retirement, or as soon as practical thereafter, even though said date is earlier than 5 years from expiration of the Performance Period. I hereby elect to be paid as described in the Sub-Plan in the form of [CHECK ONE]: [ ] a single payment [ ] annual payments commencing on the date set forth above and payable on the anniversary date thereof over: [ ] a two year period [ ] a three year period [ ] a four year period [ ] a five year period I understand that I will receive "earnings" on those deferred amounts when they are paid to me. I understand that the election made as indicated herein is irrevocable and that all deferral elections are subject to the provisions of the Sub-Plan, including provisions that may affect timing of distributions. I understand and acknowledge that my interests herein and my rights to receive distribution of the deferred amounts may not be anticipated, alienated, sold, transferred, assigned, pledged, encumbered, or subjected to any charge or legal process, and if any attempt is made to do so, or I become bankrupt, my interest may be terminated by the Committee, which, in his sole discretion. I further understand that nothing in the Sub-Plan shall be interpreted or construed to require the Company in any manner to fund any obligation to me, or to my beneficiary(ies) in the event of my death. - ------------------------------- ----------------------------------- (Signature) (Date) - ------------------------------- ----------------------------------- (Print Name) (Company Location) Received: Agent of Chief Executive Officer - ------------------------------- ----------------------------------- (Signature) (Date) EX-10 3 EX-10B(22) AMENDED MANAGE. INCENTIVE COMP. PLAN EXHIBIT 10B(22) AMENDED MANAGEMENT INCENTIVE COMPENSATION PLAN OF CAROLINA POWER & LIGHT COMPANY AS AMENDED JANUARY 1, 2000
TABLE OF CONTENTS Page ARTICLE I PURPOSE........................................................................1 ARTICLE II DEFINITIONS....................................................................1 ARTICLE III ADMINISTRATION.................................................................4 ARTICLE IV PARTICIPATION..................................................................5 ARTICLE V AWARDS.........................................................................5 ARTICLE VI DISTRIBUTION AND DEFERRAL OF AWARDS............................................9 ARTICLE VII TERMINATION OF EMPLOYMENT......................................................15 ARTICLE VIII MISCELLANEOUS..................................................................15
ii ARTICLE I --------- PURPOSE ------- The purpose of the Management Incentive Compensation Plan (the "Plan") of Carolina Power & Light Company (the "Sponsor") is to promote the financial interest of the Sponsor and its Affiliated Companies, including its growth, by (i) attracting and retaining executive officers and other management-level employees who can have a significant positive impact on the success of the Sponsor and its Affiliated Companies; (ii) motivating such personnel to help the Sponsor and its Affiliated Companies achieve annual incentive, performance and safety goals; (iii) motivating such personnel to improve their own as well as their business unit/work group's performance through the effective implementation of human resource strategic initiatives; and (iv) providing annual cash incentive compensation opportunities that are competitive with those of other major corporations. The Sponsor amends the Plan effective January 1, 2000. ARTICLE II ---------- DEFINITIONS ----------- The following definitions are applicable to the Plan: 1. "Award": The benefit payable to a Participant hereunder, consisting of a Corporate Component and a Noncorporate Component. 2. "Affiliated Company" shall mean any corporation or other entity that is required to be aggregated with the Sponsor pursuant to Sections 414(b), (c), (m), or (o) of the Internal Revenue Code of 1986, as amended (the "Code"), but only to the extent required. 3. "Company": Carolina Power & Light Company, a North Carolina corporation, or any successor to it in the ownership of substantially all of its assets and each Affiliated Company that, with the consent of the Compensation Committee, adopts the Plan and is included in Exhibit B, as in effect from time to time. 4. "Compensation Committee": The Organization and Compensation Committee of the Board of Directors of the Sponsor. 5. "Corporate Factor": The factor determined by the Compensation Committee to be utilized in calculating the Corporate Component of an Award pursuant to Article V, Section 3.a. hereof, which can range from 0 to 1.5. 6. "Corporate Component": That portion of an Award based upon the overall performance of the Sponsor, as determined in Article V, Section 3.a. hereof. 7. "Date of Retirement": The first day of the calendar month immediately following the Participant's Retirement. 8. "EBITDA": The earnings of the Sponsor before interest, taxes, depreciation, and amortization as determined from time to time by the Compensation Committee. 9. "EBITDA Growth": The percentage increase (if any) in EBITDA of the Sponsor for any Year, as compared to the previous Year as determined from time to time by the Compensation Committee. 10. "Noncorporate Component": That portion of an Award based upon the level of attainment of a Company, business unit/group, departmental, and individual Performance Measures, as provided in Article V, Section 3 .b. hereof, which can range from 0 to 1.5. 11. "Participant": An employee of any Company who is selected pursuant to Article IV hereof to be eligible to receive an Award under the Plan. 2 12. "Peer Group": The utilities included in the Standard & Poors Utility (Electric Power Companies) Index. 13. "Performance Measure": A goal or goals established for measuring the performance of a Company, business unit/group, department, or individual used for the purpose of computing the Noncorporate Component of an Award for a Participant. 14. "Performance Unit": A unit or credit, linked to the value of the Sponsor's Common Stock under the terms set forth in Article VI hereof. 15. "Plan": The Management Incentive Compensation Plan of Carolina Power & Light Company as contained herein, and as it may be amended from time to time. 16. "Retirement": A Participant's termination of employment with a Company after having met at least one of the following requirements: at least age 65 with 5+ years of service, at least age 55 with 15+ years of service, or 35+ years of service regardless of age. 17. "Salary": The compensation paid by a Company to a Participant in a relevant Year, consisting of regular or base compensation, such compensation being understood not to include bonuses, if any, or incentive compensation, if any. Provided, that such compensation shall not be reduced by any cash deferrals of said compensation made under any other plans or programs maintained by such Company. 18. "Section 16 Participants": Those Participants who are subject to the provisions of Section 16 of the Securities Exchange Act of 1934, as amended (the "1934 Act"). Individuals who are subject to Section 16 of the 1934 Act include, without limitation, directors and certain officers of the Sponsor, and any individual who beneficially owns more than ten percent of a class of the Sponsor's equity securities registered under Section 12 of the 1934 Act. 3 19. "Senior Management Committee": The Senior Management Committee of the Sponsor. 20. "Target Award Opportunity": The target for an Award under this Plan as set forth in Section 2 of Article V hereof. 21. "Year": A calendar year. ARTICLE III ----------- ADMINISTRATION -------------- The Plan shall be administered by the Chief Executive Officer of the Sponsor. Except as otherwise provided herein, the Chief Executive Officer of the Sponsor shall have sole and complete authority to (i) select the Participants; (ii) establish and adjust (either before or during the relevant Year) a Participant's Performance Measures, their relative percentage weight, and the performance criteria necessary for attainment of various performance levels; (iii) approve Awards; (iv) establish from time to time regulations for the administration of the Plan; and (v) interpret the Plan and make all determinations deemed necessary or advisable for the administration of the Plan, all subject to its express provisions. Notwithstanding the foregoing, with respect to Participants who are at or above the Department Head level in any Company, the performance criteria and Awards shall be subject to the specific approval of the Compensation Committee. In addition, the Compensation Committee shall have the sole authority to determine the total payout under the Plan up to a maximum of three percent (3%) of the Sponsor's after-tax income for a relevant Year. 4 A majority of the Compensation Committee shall constitute a quorum, and the acts of a majority of the members present at any meeting at which a quorum is present, or acts approved in writing by a majority of the members of the Committee without a meeting, shall be the acts of such Committee. ARTICLE IV PARTICIPATION ------------- The Chief Executive Officer of the Sponsor shall select from time to time the Participants in the Plan for each Year from those employees of each Company who, in his opinion, have the capacity for contributing in a substantial measure to the successful performance of the Company that Year. No employee shall at any time have a right to be selected as a Participant in the Plan for any Year nor, having been selected as a Participant for one Year, have the right to be selected as a Participant in any other Year. ARTICLE V --------- AWARDS ------ 1. Eligibility. In order for any Participant to be eligible to receive an Award, two conditions must be met. First, a contribution must be earned by one or more groups of employees under the Employee Stock Incentive Plan feature of the Sponsor's Stock Purchase-Savings Plan. Second, the Sponsor must also meet minimum threshold performance levels for return on common equity, EBITDA Growth, and other measures for the relevant Year as may be established by the Compensation Committee. Threshold performance for return on common 5 equity and EBITDA Growth is the weighted average of a Peer Group of utilities, averaged over the most recent three-year period. To satisfy threshold performance, the Sponsor must be above the three-year average with respect to return on common equity and EBITDA Growth. 2. Target Award Opportunities. The following table sets forth Target Award Opportunities, expressed as a percentage of Salary, for various levels of participation in the Plan: ------------------------------------------ ------------------------------- Participation Target Award 0pportunities ------------------------------------------ ------------------------------- Chief Executive Officer of Sponsor 60% ------------------------------------------ ------------------------------- Chief Operating Officer of Sponsor 60% ------------------------------------------ ------------------------------- Executive Vice Presidents of Sponsor 40% ------------------------------------------ ------------------------------- ------------------------------------------ ------------------------------- Senior Vice Presidents of Sponsor 35% ------------------------------------------ ------------------------------- Department Heads (or equivalent) 25% ------------------------------------------ ------------------------------- Other Participants: Key Managers 20% Other Managers 15% ------------------------------------------ ------------------------------- The Target Award Opportunity for the Chief Executive Officer of the Sponsor shall be 60%; however, the Compensation Committee of the Board shall be authorized to change that amount from year to year, or to award an amount of compensation based on other considerations, in its complete discretion. 3. Award Components. Awards under the Plan to which Participants are eligible consist of the sum of a Corporate Component and a Noncorporate Component. The portion of the Target Award Opportunities attributable to the Corporate Component and Noncorporate Component, respectively, for various levels of participation, is set forth in the following table: 6 - ---------------------------------------------- ---------------- --------------- Participants Corporate Noncorporate Component Component - ---------------------------------------------- ---------------- --------------- Chief Executive Officer of Sponsor 100% - - ---------------------------------------------- ---------------- --------------- Chief Operating Officer of Sponsor 100% - - ---------------------------------------------- ---------------- --------------- Executive Vice Presidents of Sponsor 75% 25% - ---------------------------------------------- ---------------- --------------- Senior Vice Presidents of Sponsor 75% 25% - ---------------------------------------------- ---------------- --------------- Department Heads (or equivalent) 50% 50% - ---------------------------------------------- ---------------- --------------- Other Participants 50% 50% - ---------------------------------------------- ---------------- --------------- a. Corporate Component. The Corporate Component of an Award is based upon the overall performance of the Sponsor. In the event the conditions set forth in Section 1 of Article V are met and the Compensation Committee, in its discretion, determines an appropriate Corporate Factor, that Corporate Factor shall be multiplied by the portion of a Participant's Target Award Opportunity attributable to the Corporate Component in order to determine the percentage of such Participant's Salary which will comprise the Corporate Component of his or her Award. Notwithstanding the foregoing, if the second condition set forth in Section 1 of Article V is not fully met, the Compensation Committee may nevertheless in its discretion determine an appropriate Corporate Factor and grant a Corporate Component of an Award to the Participants. b. Noncorporate Component. The Noncorporate Component of an Award for a Participant is based upon the level of attainment of Company, business unit/group, departmental and individual Performance Measures. Performance Measures for each Participant and their relative weight are determined pursuant to authority granted in Article III hereof. (i) Performance Levels. There are three levels of performance related to each of a Participant's Performance Measures: outstanding, target, and threshold. The specific performance criteria for each level of a Participant's Performance Measures shall be set forth in 7 writing prior to the beginning of an applicable Year, or within thirty (30) days after a Participant first becomes eligible to participate in the Plan, and shall be determined pursuant to authority granted in Article III hereof. The payout percentages to be applied to each Participant's Target Award Opportunity are as follows: Performance Level Payout Percentage ----------------- ----------------- Outstanding 150% Target 100% Threshold 50% Payout percentages shall be adjusted for performance between the designated performance levels, provided, however, that performance which falls below the "Threshold" performance level results in a payout percentage of zero unless the Chief Executive Officer of Sponsor directs otherwise. (ii) Determination of Noncorporate Component. In order to determine a Participant's Noncorporate Component, if any, for a particular Year, the Chief Executive Officer of Sponsor initially shall determine the appropriate payout percentage for each of such Participant's Performance Measures. Thereafter, each payout percentage is multiplied by the percentage weight assigned to each such Performance Measure and the results added together. That aggregate amount is multiplied by the Participant's Target Award Opportunity for the Noncorporate Award Component for the respective Year and the result is multiplied by the Participant's Salary. (iii) Change of Job Status. Participants who change organizations during a Year will have their Noncorporate Component prorated based upon the Performance Measures achieved in each organization and the length of time served in each organization. In the 8 discretion of the Chief Executive Officer of Sponsor, employees may become Participants during a Year based on promotions and may receive an Award prorated based on the length of time served in the qualifying job and the Performance Measures achieved while in the qualifying job. 4. New Participants. Any Award that is earned during the Year of selection shall be pro rated based on the length of time served in the qualifying job. 5. Reduction of Award Amount. In the event of documented performance deficiencies of a Participant during a Year, the Chief Executive Officer of Sponsor, in his discretion, may reduce the Award payable to such Participant for such Year. 6. Example. Attached as Exhibit A and incorporated by reference is an example of the process by which an Award is granted hereunder. Said exhibit is intended solely as an example and in no way modifies the provisions of this Article V. ARTICLE VI DISTRIBUTION AND DEFERRAL OF AWARDS ----------------------------------- 1. Distribution of Awards. Unless a Participant elects to defer an award pursuant to the remaining provisions of this Article VI, awards under the Plan earned during any Year shall be paid in cash in the succeeding Year, normally no later than March 15 of such succeeding Year. 2. Deferral Election. A Participant may elect to defer the Plan Award he or she has earned for any Year by completing and submitting to the Vice President, Human Resources, a deferral election form by the later of (1) November 30 of the Year in which the Award is earned or (2) the thirtieth (30th) day after first becoming eligible to participate in the deferral election provisions of the Plan; provided, however, that for the 1995 Plan Year, deferral elections shall be 9 made by no later than November 30, 1995. Such election shall apply to the Participant's Award, if any, otherwise to be paid as soon as practicable after the Year during which it was earned. A Participant's deferral election may apply to 100%, 75%, 50%, or 25% of the Plan Award; provided, however, that in no event shall the amount deferred be less than $1,000. The election to defer shall be irrevocable as to the Award earned during the particular Year. 3. Period of Deferral. At the time of a Participant's deferral election, a Participant must also select a distribution date. Subject to Section 6, the distribution date may be: (a) any date that is at least five (5) years subsequent to the date the Plan Award would otherwise be payable, but not later than the second anniversary of the Participant's Date of Retirement; or (b) any date that is within two years following the Participant's Date of Retirement. Subject to Section 6, a Participant may extend the distribution date for one or more additional Year(s) by making a new deferral election at least one (1) year before the previously selected distribution date occurs; provided, however, that in no event shall the subsequent distribution date be a date that is more than two years beyond the Participant's Date of Retirement. 4. Performance Units. All Awards which are deferred under the Plan shall be recorded in the form of Performance Units. Each Performance Unit is generally equivalent to a share of the Sponsor's Common Stock. In converting the cash award to Performance Units, the number of Performance Units granted shall be determined by dividing the amount of the Award by 85% of the average value of the opening and closing price of a share of the Sponsor's Common Stock on the last trading day of the month preceding the date of the Award. The Performance Units attributable to the 15% discount from the average value of the Sponsor's Common Stock shall be referred to as the "Incentive 10 Performance Units." The Incentive Performance Units and any adjustments or earnings attributable to those Performance Units shall be forfeited by the Participant if he or she terminates employment either voluntarily or involuntarily other than for death or retirement prior to five years from March 15 of the Year in which payment would have been made if the Award had not been deferred. 5. Plan Accounts. A Plan Deferral Account will be established on behalf of each Participant, and the number of Performance Units awarded to a Participant shall be recorded in each Participant's Plan Deferral Account as of the first of the month coincident with or next following the month in which a deferral becomes effective. The number of Performance Units recorded in a Participant's Plan Deferral Account shall be adjusted to reflect any splits or other adjustments in the Sponsor's Common Stock, the payment of any cash dividends paid on the Sponsor's Common Stock and the payment of Awards under this Plan to the Participant. To the extent that any cash dividends have been paid on the Sponsor's Common Stock, the number of Performance Units shall be adjusted to reflect the number of Performance Units that would have been acquired if the same dividend had been paid on the number of Performance Units recorded in the Participant's Plan Deferral Account on the dividend record date. For purposes of determining the number of Performance Units acquired with such dividend, the average of the opening and closing price of the Sponsor's Common Stock on the payment date of the Sponsor's Common Stock dividend shall be used. Each Participant shall receive an annual statement of the balance of his Plan Deferral Account, which shall include the Incentive Performance Units and associated earnings and adjustments that are subject to being forfeited as provided above. 11 6. Payment of Deferred Plan Awards. Subject to Section 4 related to forfeiture of Incentive Performance Units, Deferred Plan Awards shall be paid in cash by each Company beginning no later than the next April 1 following the distribution date or the deferred distribution date specified by the Participant in accordance with Section 3. To convert the Performance Units in a Participant's Plan Deferral Account to a cash payment amount, Performance Units shall be multiplied by the average of the opening and closing price of the Sponsor's Common Stock on the last trading day preceding the payment of the Deferred Plan Award. Except as otherwise provided below, deferred amounts will be paid either in a single lump-sum payment or in up to five (5) annual payments. In the event that a Participant elects to receive the deferred Plan Award in equal annual payments, the amount of the Award to be received in each year shall be determined as follows: (a) To determine the amount of the initial annual payment, the number of Performance Units in the Participant's Plan Deferral Account will be divided by the total number of annual payments to be received, and the result will be multiplied by the average of the opening and closing price of the Sponsor's Common Stock on the last trading day preceding the due date of the initial payment. (b) To determine the amount of each successive annual payment, the Plan Deferral Account balance will be divided by the number of annual payments remaining, and the result will be multiplied by the average of the opening and closing price of the Sponsor's Common Stock on the last trading day preceding the due date of the annual payment. 7. Termination of Employment/Effect on Deferral Election. If the employment of a Participant terminates prior to the last day of a Year for which a Plan Award is determined, then any deferral election made with respect to such Plan Award for such Year shall not become 12 effective and any Plan Award to which the Participant is otherwise entitled shall be paid as soon as practicable after the end of the Year during which it was earned, in accordance with paragraph 1 of this Article VI. 8. Termination of Employment/Acceleration of Deferral. Notwithstanding the foregoing, if a Participant terminates employment by reason other than death or Retirement, full payment of all amounts due to the Participant shall be accelerated and paid on the first day of the month following the date of termination. Incentive Performance Units shall be subject to forfeiture as provided in Section 4. 9. Financial Hardship Payments. In the event of a severe financial hardship occasioned by an emergency, including, but not limited to, illness, disability or personal injury sustained by the Participant or a member of the Participant's immediate family, a Participant may apply to receive a distribution earlier than initially elected. The Chief Executive Officer of Sponsor or his designee may, in his sole discretion, either approve or deny the request. The determination made by the Chief Executive Officer of Sponsor will be final and binding on all parties. If the request is granted, the payments will be accelerated only to the extent reasonably necessary to alleviate the financial hardship. Incentive Performance Units shall not be subject to early distribution under this Section 9 until five years from March 15 of the Year in which payment would have been made if the Award had not been deferred. 10. Death of a Participant. If the death of a Participant occurs before a full distribution of the Participant's Plan Deferral Account is made, payment shall be made to the beneficiary designated by the Participant to receive such amounts in accordance with the schedule specified in the Participant's Deferral Election form. Said payment shall be made as soon as practical following notification that death has occurred. In the absence of any such designation, payment 13 shall be made to the personal representative, executor or administrator of the Participant's estate. 11. Non-Assignability of Interests. The interests herein and the right to receive distributions under this Article VI may not be anticipated, alienated, sold, transferred, assigned, pledged, encumbered, or subjected to any charge or legal process, and if any attempt is made to do so, or a Participant becomes bankrupt, the interests of the Participant under this Article VI may be terminated by the Chief Executive Officer of Sponsor, which, in his sole discretion, may cause the same to be held or applied for the benefit of one or more of the dependents of such Participant or make any other disposition of such interests that he deems appropriate. 12. Unfunded Deferrals. Nothing in this Plan, including this Article VI, shall be interpreted or construed to require the Sponsor or any Company in any manner to fund any obligation to the Participants, terminated Participants or beneficiaries hereunder. Nothing contained in this Plan nor any action taken hereunder shall create, or be construed to create, a trust of any kind, or a fiduciary relationship between the Sponsor or any Company and the Participants, terminated Participants, beneficiaries, or any other persons. Any funds which may be accumulated in order to meet any obligation under this Plan shall for all purposes continue to be a part of the general assets of the Sponsor or Company; provided, however, that the Sponsor or Company may establish a trust to hold funds intended to provide benefits hereunder to the extent the assets of such trust become subject to the claims of the general creditors of the Sponsor or Company in the event of bankruptcy or insolvency of the Sponsor or Company. To the extent that any Participant, terminated Participant, or beneficiary acquires a right to receive payments from the Sponsor or Company under this Plan, such rights shall be no greater than the rights of any unsecured general creditor of the Sponsor or Company. 14 ARTICLE VII ----------- TERMINATION OF EMPLOYMENT ------------------------- A Participant must be actively employed by a Company on the next January 1 immediately following the Year for which a Plan Award is earned in order to be entitled to payment of the full amount of any Award for that Year. In the event the active employment of a Participant shall terminate or be terminated for any reason before the next January 1 immediately following the Year for which a Plan Award is earned, such Participant shall receive his or her Award for the year, if any, in an amount that the Chief Executive Officer of the Sponsor deems appropriate. ARTICLE VIII ------------ MISCELLANEOUS ------------- 1. Assignments and Transfers. The rights and interests of a Participant under the Plan may not be assigned, encumbered or transferred except, in the event of the death of a Participant, by will or the laws of descent and distribution. 2. Employee Rights Under the Plan. No Company employee or other person shall have any claim or right to be granted an Award under the Plan or any other incentive bonus or similar plan of the Sponsor or any Company. Neither the Plan, participation in the Plan nor any action taken thereunder shall be construed as giving any employee any right to be retained in the employ of the Sponsor or any Company. 15 3. Withholding. The Sponsor or Company (as applicable) shall have the right to deduct from all amounts paid in cash any taxes required by law to be withheld with respect to such cash payments. 4. Amendment or Termination. The Compensation Committee may in its sole discretion amend suspend or terminate the Plan or any portion thereof at any time. 5. Governing Law. This Plan shall be construed and governed in accordance with the laws of the state of North Carolina. 6. Effective Date. This Plan, as amended, shall be effective as of January 1, 1999. 7. Entire Agreement. This document (including the exhibit attached hereto and any future amendments to said exhibit that may be made by the Chief Executive Officer of the Sponsor) sets forth the entire Plan. 16 EXHIBIT A (to be supplied) 17 EXHIBIT B North Carolina Natural Gas Company 18 DESIGNATION OF BENEFICIARY MANAGEMENT INCENTIVE COMPENSATION PLAN OF CAROLINA POWER & LIGHT COMPANY As provided in the MANAGEMENT INCENTIVE COMPENSATION PLAN of Carolina Power & Light Company, I hereby designate the following person as my beneficiary in the event of my death before a full distribution of my Deferral Account is made. PRIMARY BENEFICIARY: ------------------------------- ------------------------------- ------------------------------- CONTINGENT BENEFICIARY: ------------------------------- ------------------------------- ------------------------------- Any and all prior designations of one or more beneficiaries by me under the MANAGEMENT INCENTIVE COMPENSATION PLAN of Carolina Power & Light Company are hereby revoked and superseded by this designation. I understand that the primary and contingent beneficiaries named above may be changed or revoked by me at any time by filing a new designation in writing with the Sponsor's Human Resources Department. DATE:__________________ SIGNATURE OF PARTICIPANT:_________________________________ The Participant named above executed this document in our presence on the date set forth above WITNESS: WITNESS: ------------------------ -------------------------- 19 EX-10 4 EX-10B(24) SUPP. SENIOR EXECUTIVE RETIREMENT PLAN EXHIBIT 10B(24) AMENDED AND RESTATED SUPPLEMENTAL SENIOR EXECUTIVE RETIREMENT PLAN OF CAROLINA POWER & LIGHT COMPANY Effective January 1, 1984 (As last amended effective March 15, 2000) TABLE OF CONTENTS ARTICLE I - STATEMENT OF PURPOSE ARTICLE II - DEFINITIONS Terms 2.01 Affiliated Companies 2.02 Assumed Deferred Vested Pension Benefit 2.03 Assumed Early Retirement Pension Benefit 2.04 Assumed Normal Retirement Pension Benefit 2.05 Board 2.06 Committee 2.07 Company 2.08 Designated Beneficiary 2.09 Early Retirement Date 2.10 Eligible Spouse 2.11 Final Average Salary 2.12 Normal Retirement Date 2.13 Participant 2.14 Pension 2.15 Plan 2.16 Retirement Plan 2.17 Salary 2.18 Service 2.19 Severance Date 2.20 Social Security Benefit 2.21 Spouse's Pension 2.22 Target Early Retirement Benefit 2.23 Target Normal Retirement Benefit 2.24 Target Pre-Retirement Death Benefit 2.25 Target Severance Benefit 2.26 ARTICLE III - ELIGIBILITY AND PARTICIPATION Eligibility 3.01 Date of Participation 3.02 Duration of Participation 3.03 ARTICLE IV - RETIREMENT BENEFITS Normal Retirement Benefit 4.01 Early Retirement Benefit 4.02 Surviving Spouse Benefit 4.03 Re-employment of Retired Participant 4.04 ARTICLE V - PRE-RETIREMENT DEATH BENEFITS Eligibility 5.01 Amount 5.02 Alternative Benefit 5.03 Commencement and Duration 5.04 ARTICLE VI - SEVERANCE BENEFITS Eligibility 6.01 Amount 6.02 Commencement and Duration 6.03 Surviving Spouse Benefit 6.04 ARTICLE VII - ADMINISTRATION Committee 7.01 Voting 7.02 Records 7.03 Liability 7.04 Expenses 7.05 ARTICLE VIII - AMENDMENT AND TERMINATION ARTICLE IX - MISCELLANEOUS Non-Alienation of Benefits 9.01 No Trust Created 9.02 No Employment Agreement 9.03 Binding Effect 9.04 Suicide 9.05 Claims for Benefits 9.06 Entire Plan 9.07 ARTICLE X - CONSTRUCTION Governing Law 10.01 Gender 10.02 Headings, etc. 10.03 Action 10.04 ARTICLE I ---------- STATEMENT OF PURPOSE -------------------- This Plan is designed and implemented for the purpose of enhancing the earnings and growth of Carolina Power & Light Company (the "Sponsor") by providing to the limited group of senior management employees largely responsible for such earnings and long-term growth deferred compensation in the form of supplemental retirement income benefits, thereby increasing the incentive of such key senior management employees to make the Sponsor and its Affiliated Companies more profitable. The benefits are normally payable to Participants upon retirement or death. The terms of the benefits operate in conjunction with the Participant's benefits payable under the Sponsor's Supplemental Retirement Plan and are designed to supplement such Supplemental Retirement Plan benefits and provide the Participant with additional financial security upon retirement or death. The Plan is intended to constitute an unfunded retirement plan for a select group of management or highly compensated employees within the meaning of Title I of the Employee Retirement Income Security Act of 1974, as amended. The Sponsor hereby restates and amends the Plan effective March 15, 2000. 1 ARTICLE II ---------- DEFINITIONS ----------- 2.01 Terms - Unless otherwise clearly required by the context, the terms used herein shall have the following meaning. Capitalized terms that are not defined below shall have the meaning ascribed to them in the Retirement Plan. 2.02 Affiliated Company shall mean any corporation or other entity that is required to be aggregated with the Sponsor pursuant to Section 414(b), (c), (m), or (o) of the Internal Revenue Code of 1996, as amended (the "Code"), but only to the extent required. 2.03 Assumed Deferred Vested Pension Benefit shall mean the monthly benefit of the deferred vested Pension to commence on his Normal Retirement Date payable in the form of an annuity to which a separated Participant would be entitled under the Retirement Plan, calculated with the following assumptions based on such Participant's marital status at the time benefits hereunder commence: (a) In the case of a Participant with an Eligible Spouse, in the form of a 50% Qualified Joint and Survivor Annuity as provided in the Retirement Plan. (b) In the case of a Participant without an Eligible Spouse, in the form of a Single Life Annuity as provided in the Retirement Plan. (c) Without regard to any other benefit payment option under the Retirement Plan. 2.04 Assumed Early Retirement Pension Benefit shall mean the monthly benefit of the normal retirement Pension payable in the form of an annuity to which a Participant would be entitled under the Retirement Plan at his Normal Retirement Date, based upon his projected years of Service at his Normal Retirement Date and upon his Final Average Salary as of his Early Retirement Date, and calculated with the following assumptions based upon his marital status at the time benefits hereunder commence: 2 (a) In the case of a Participant with an Eligible Spouse, in the form of a 50% Qualified Joint and Survivor Annuity as provided in the Retirement Plan. (b) In the case of a Participant without an Eligible Spouse, in the form of a Single Life Annuity as provided in the Retirement Plan. (c) Without regard to any other benefit payment option under the Retirement Plan. 2.05 Assumed Normal Retirement Pension Benefit shall mean the monthly benefit of the normal retirement Pension payable in the form of an annuity to which a Participant would be entitled under the Retirement Plan if he retired at his Normal Retirement Date, calculated with the following assumptions based on his marital status at the time benefits hereunder commence: (a) In the case of a Participant with an Eligible Spouse, in the form of a 50% Qualified Joint and Survivor Annuity as provided in the Retirement Plan. (b) In the case of a Participant without an Eligible Spouse, in the form of a Single Life Annuity as provided in the Retirement Plan. (c) Without regard to any other benefit payment option under the Retirement Plan. 2.06 Board shall mean the Board of Directors of Sponsor. 2.07 Committee shall mean the Committee on Organization and Compensation of the Board. 2.08 Company shall mean Carolina Power & Light Company or any successor to it in the ownership of substantially all of its assets, and each Affiliated Company that, with the consent of the Board adopts the Plan and is included in Appendix A, as in effect from time to time. Appendix A shall set forth any limitations imposed on employees of Affiliated Companies that adopt the Plan, including limitations on "Service," notwithstanding any provision of the Plan to the contrary. 2.09 Designated Beneficiary shall mean one or more beneficiaries as designated by a Participant in writing delivered to the Committee. In the event no such written designation is made by a Participant or if such beneficiary shall not be living or in existence at the time for commencement of payment to any Designated Beneficiary under the Plan, the Participant shall be deemed to have designated his estate as such beneficiary. 3 2.10 Early Retirement Date shall mean the date on which a Participant who qualifies for the early retirement benefit of Section 4.02 hereof retires from the employ of the Company and its affiliated entities. 2.11 Eligible Spouse shall mean the spouse of a Participant who, under the laws of the State where the marriage was contracted, is deemed married to that Participant on the date on which the payments from this Plan are to begin to the Participant, except that for purposes of Articles V and VI hereof, Eligible Spouse shall mean a person who is married to a Participant for a period of at least one year prior to his death. 2.12 Final Average Salary shall mean a Participant's average monthly Salary (as defined in Section 2.18 hereof) during the 36 completed calendar months of highest compensation within the 120-month period immediately preceding the earliest to occur of the Participant's death, Severance Date, Early Retirement Date, or Normal Retirement Date, whichever is applicable. Provided, however, if a Participant becomes entitled to a benefit hereunder while under a period of long-term disability under the Sponsor's Group Insurance Plan, Final Average Salary shall be determined for the 12 calendar months immediately preceding the commencement of such period of long-term disability. Provided, further, in determining average monthly Salary (i) annual bonuses and other similar payments shall be deemed received in twelve (12) equal payments beginning with the eleventh preceding month and ending with the month in which actual payment is made, and (ii) amounts of compensation deferred under any deferred compensation plan or arrangement shall be deemed received in the months such payments would have been received assuming no deferral had occurred. For years of Service granted under the terms of a written employment agreement as provided under Section 2.19, Salary during each such month is deemed to be zero dollars ($0.00) for purposes of calculating Final Average Salary. 2.13 Normal Retirement Date shall mean the first day of the calendar month coinciding with or next following the Participant's 65th birthday. 4 2.14 Participant shall mean an employee of the Company who is eligible and is participating in this Plan in accordance with Article III hereof. 2.15 Pension shall mean a level monthly annuity which is payable under the Retirement Plan as of the Benefit Commencement Date if the Participant elected an annuity form of benefit. 2.16 Plan shall mean the "Supplemental Senior Executive Retirement Plan of Carolina Power & Light Company" as contained herein and as it may be amended from time to time hereafter. 2.17 Retirement Plan shall mean the "Supplemental Retirement Plan of Carolina Power & Light Company" (as amended effective January 1, 1999) as it may be amended from time to time hereafter. 2.18 Salary shall mean the sum of: (1) The annual base compensation paid by the Company to a Participant, and (2) annual cash awards made under incentive compensation programs excluding, however, any payment made under the Sponsor's Long-Term Compensation Program or the Sponsor's 1997 Equity Incentive Plan, and (3) amounts of annual compensation deferred under any deferred compensation plan or arrangement (including, without limitation, the "Executive Deferred Compensation Plan," the "Deferred Compensation Plan for Key Management Employees of Carolina Power & Light Company," the "Carolina Power & Light Company Management Deferred Compensation Plan" effective January 1, 2000, and the "Stock Purchase - Savings Plan of Carolina Power & Light Company") and which, but for the deferral, would have been reflected in Internal Revenue Service Form W-2. 2.19 Service shall have the same meaning as "Eligibility Service," determined as provided in Sections 2.02 and 3.01 of the Retirement Plan, plus any additional years of service that may be granted to the Participant in connection with this Plan under the terms of a written 5 employment agreement (or any amendment thereto) entered into between the Company and the Participant . 2.20 Severance Date shall mean the earlier of: (a) The date a Participant leaves the employ of the Company and all affiliated entities other than on account of his death, a period of long-term disability under the Company's Group Insurance Plan, or retirement at either his Early Retirement Date or upon or after his Normal Retirement Date, or (b) The first anniversary of the date on which a Participant is first absent from the service of the Sponsor and all Affiliated Companies, with or without pay, other than on account of his death, a period of long-term disability under the Company's Group Insurance Plan, or his retirement at either his Early Retirement Date or upon or after his Normal Retirement Date. If a Participant shall leave the employ of the Company and all Affiliated Companies under circumstances described in (b) and shall during such absence (and before the first anniversary of commencement of said absence) quit or be discharged, his Severance Date shall be the date he quits or is discharged. 2.21 Social Security Benefit means the monthly amount of benefit which a Participant is or would be entitled to receive at age 65 as a primary insurance amount under the federal Social Security Act, as amended, whether or not he applies for such benefit, and even though he may lose part or all of such benefit through delay in applying for it, by making application prior to age 65 for a reduced benefit, by entering into covered employment, or for any other reason. The amount of such Social Security Benefit to which the Participant is or would be entitled shall be estimated by the Committee for the purposes of this Plan as of the January 1 of the year in which his Severance Date or retirement occurs on the following basis: (a) For a Participant entitled to a normal retirement benefit, on the basis of the federal Social Security Act as in effect on the January 1 coincident with or next preceding 6 his Normal Retirement Date (regardless of any retroactive changes made by legislation enacted after said January 1); (b) For a Participant entitled to an early retirement benefit, on the basis of the federal Social Security Act as in effect on the January 1 coincident with or next preceding his Early Retirement Date (regardless of any retroactive change made by legislation enacted after said January 1), assuming that his employment, and Salary in effect at his Early Retirement Date, continued to age 65; or (c) For a Participant entitled to a severance benefit, on the basis of the federal Social Security Act as in effect on the January 1 coincident with or next preceding his Severance Date (regardless of any retroactive change made by legislation enacted after said January 1), assuming that his employment, and Salary in effect at his Severance Date, continued to age 65. For purposes of the calculations required under paragraphs (a) and (b) above, if a Participant is disabled under a period of long-term disability under the Company's Group Insurance Plan, said Social Security Benefit shall be calculated as if his Salary in effect at the commencement of such period of long-term disability continued to age 65. 2.22 Spouse's Pension shall mean the actual monthly benefit payable to an Eligible Spouse under the Retirement Plan, assuming the Eligible Spouse elected a 50% Joint and Survivor Annuity form of benefit. 2.23 Target Early Retirement Benefit shall mean an amount equal to a Participant's Final Average Salary determined at his Early Retirement Date multiplied by four percent (4%) for each projected year of Service at his Normal Retirement Date up to a maximum of sixty-two percent (62%). 2.24 Target Normal Retirement Benefit shall mean an amount equal to a Participant's Final Average Salary determined at his Normal Retirement Date multiplied by four percent (4%) for each projected year of Service at his Normal Retirement Date up to a maximum of sixty-two percent (62%). 7 2.25 Target Pre-Retirement Death Benefit shall mean an amount equal to a deceased Participant's Final Average Salary determined at his death multiplied by four percent (4%) for each year of Service at his death up to a maximum of sixty-two percent (62%). 2.26 Target Severance Benefit shall mean an amount equal to a Participant's Final Average Salary determined at his Severance Date multiplied by four percent (4%) for each year of Service at his Severance Date up to a maximum of sixty-two percent (62%). 8 ARTICLE III ----------- ELIGIBILITY AND PARTICIPATION ----------------------------- 3.01 Eligibility. Any executive employee of a Company who has served on the Senior Management Committee of the Sponsor and who has been a Senior Vice President or above for a minimum period of three (3) years and who has at least ten (10) years of Service shall be eligible to participate in this Plan. 3.02 Date of Participation. Each executive who is eligible to become a Participant under Section 3.01 shall become a Participant on the first day of the month following the month in which he is first eligible to participate. 3.03 Duration of Participation. Each executive who becomes a Participant shall continue to be a Participant until the termination of his employment with the Company or, if later, the date he is no longer entitled to benefits under this Plan. 9 ARTICLE IV ---------- RETIREMENT BENEFITS ------------------- 4.01 Normal Retirement Benefit. (a) Eligibility. A Participant whose employment with the Company terminates on or after his Normal Retirement Date shall be eligible for the normal retirement benefit described in this Section 4.01. (b) Amount and Form. The monthly payment hereunder shall be in the form of a Single Life Annuity if the Participant has no Eligible Spouse and in the form of a 50% Qualified Joint and Survivor Annuity if the Participant has an Eligible Spouse. The eligible Participant's normal retirement benefit shall be a monthly amount equal to his Target Normal Retirement Benefit reduced by the sum of (1) his Assumed Normal Retirement Pension Benefit and (2) his Social Security Benefit. (c) Commencement and Duration. Monthly normal retirement benefit payments shall commence at the same time as the eligible Participant's normal retirement Pension payable from the Retirement Plan and shall continue in monthly installments thereafter ending with a payment for the month in which such eligible Participant's death occurs, unless the benefit is being paid in the form of a Qualified Joint and Survivor Annuity, in which case the survivor benefit shall be paid to the Eligible Spouse, if living, for his or her life. If at the time of commencement of payment such eligible Participant does not have an Eligible Spouse the monthly benefit payments shall be guaranteed for one hundred twenty (120) monthly payments with any such guaranteed payments remaining at such Participant's death payable to his Designated Beneficiary. 10 4.02 Early Retirement Benefit. (a) Eligibility. Upon recommendation of the Chief Executive Officer of the Company and approval of the Committee, a Participant whose employment with the Company terminates upon or after his attainment of age fifty-five (55) with at least fifteen (15) years of Service (except for purposes of calculating benefits payable under Article V. PRE-RETIREMENT DEATH BENEFITS and Article VI. SEVERANCE BENEFITS, as applicable) but prior to his Normal Retirement Date, shall be eligible for the early retirement benefit described in this Section 4.02. (b) Amount and Form. The monthly payment hereunder shall be in the form of a Single Life Annuity if the Participant has no Eligible Spouse and in the form of a 50% Qualified Joint and Survivor Annuity if the Participant has an Eligible Spouse. The eligible Participant's early retirement benefit shall be a monthly amount equal to his Target Early Retirement Benefit reduced by the sum of (1) his Assumed Early Retirement Pension Benefit and (2) his Social Security Benefit; provided, however, such benefit will be reduced, where applicable, by the following: (i) The amount of 2.5% for each year that such benefit is received prior to his Normal Retirement Date, and (ii) If such eligible Participant's projected years of Service at his Normal Retirement Date are less than fifteen (15), his Target Early Retirement Benefit and his Assumed Early Retirement Pension Benefit shall be calculated based upon his actual years of Service at his Early Retirement Date rather than upon his projected years of Service at his Normal Retirement Date. 11 (c) Commencement and Duration. Monthly early retirement benefit payments shall commence on the first day of the month following the Participant's attainment of age 65, provided, such Participant may make written application to the Committee to have payments commence on the first day of any month following his Early Retirement Date and the decision of the Committee, based upon its sole and absolute discretion, to allow such early commencement of payment shall be final. After commencement of payment, said early retirement benefit payments shall continue in monthly installments thereafter ending with a payment for the month in which such eligible Participant's death occurs, unless the benefit is being paid in the form of a Qualified Joint and Survivor Annuity, in which case the survivor benefit shall be paid to the Eligible Spouse, if living, for his or her life. If at the time of commencement of payment such eligible Participant does not have an Eligible Spouse, the monthly benefit payments shall be guaranteed for one hundred twenty (120) monthly payments with any such guaranteed payments remaining at such Participant's death payable to his Designated Beneficiary. 4.03 Surviving Spouse Benefit. The surviving Eligible Spouse of a Participant who is receiving a Qualified Joint and Survivor Benefit as a normal retirement benefit or as an early retirement benefit shall be eligible for the surviving spouse benefit upon the death of the Participant for the duration of the Eligible Spouse's life. 4.04 Re-employment of Retired Participant. A retired Participant receiving or eligible to receive the retirement benefits described in Sections 4.01 and 4.02 hereof who is re-employed by a Company shall be ineligible to again participate in this Plan. 12 ARTICLE V PRE-RETIREMENT DEATH BENEFITS 5.01 Eligibility. A Participant's surviving Eligible Spouse shall be eligible for the pre-retirement death benefit as described in this Article V if such Participant dies while in the employ of the Company with 10 or more years of Service. 5.02 Amount. Such surviving Eligible Spouse shall be entitled to a monthly pre-retirement death benefit payable in the form of an annuity in an amount equal to the difference, if any, between (a) forty percent (40%) of the Target Pre-Retirement Death Benefit and (b) the Spouse's Pension. 5.03 Alternative Benefit. If greater than the monthly benefit of Section 5.02 hereof, the surviving Eligible Spouse of a Participant who dies while in the employ of the Company after attaining age fifty-five (55) with ten (10) years of Service shall be entitled to a monthly pre-retirement death benefit equal to fifty percent (50%) of the early retirement benefit the Participant would have been entitled to receive under Section 4.02 hereof (calculated using both reductions, where applicable, in subsections 4.02(b)(i) and 4.02(b)(ii)) as if he had retired immediately prior to his death with the recommendation of the Chief Executive Officer and approval of the Committee. 5.04 Commencement and Duration. The surviving Eligible Spouse's monthly pre-retirement death benefit payments shall commence in the month following the Participant's death and shall be paid in monthly installments thereafter ending with a payment for the month in which such surviving Eligible Spouse's death occurs. 13 ARTICLE VI SEVERANCE BENEFITS 6.01 Eligibility. Upon his termination of employment with the Company at his Severance Date, a Participant who has completed ten (10) or more years of Service shall be eligible for one of the severance benefits described in this Article VI. 6.02 Amount. (a) If at his Severance Date such eligible Participant is not entitled to a deferred vested Pension pursuant to Section 5.03 of the Retirement Plan or an early retirement Pension pursuant to Section 5.02 of the Retirement Plan, his severance benefit shall be a monthly amount equal to his Target Severance Benefit reduced by his Social Security Benefit. (b) If at his Severance Date such eligible Participant is entitled to a deferred vested Pension pursuant to Section 5.03 of the Retirement Plan, his severance benefit shall be a monthly amount equal to his Target Severance Benefit reduced by the sum of (1) his Assumed Deferred Vested Pension Benefit and (2) his Social Security Benefit. (c) If at his Severance Date such eligible Participant is entitled to an early retirement Pension pursuant to Section 5.02 of the Retirement Plan, his severance benefit shall be a monthly amount equal to his Target Severance Benefit reduced by the sum of (1) his Assumed Early Retirement Pension Benefit and (2) his Social Security Benefit; provided, however, such Assumed Early Retirement Pension Benefit shall be calculated based upon his actual years of Service at his Severance Date rather than upon his projected years of Service at his Normal Retirement Date. 14 6.03 Commencement and Duration. Monthly severance benefit payments shall commence on the eligible Participant's Normal Retirement Date and shall continue in monthly installments thereafter ending with a payment for the month in which such eligible Participant's death occurs. 6.04 Surviving Spouse Benefit. (a) Eligibility. The surviving Eligible Spouse of a Participant who is receiving or who dies after attaining age fifty-five (55) entitled to receive a severance benefit hereunder shall be eligible for the surviving spouse benefit described in this Section 6.04. (b) Amount. Such surviving Eligible Spouse shall be entitled to a monthly surviving spouse benefit in an amount equal to fifty percent (50%) of the severance benefit which the deceased Participant was receiving or entitled to receive at his Normal Retirement Date under either Section 6.02(a) or 6.02(b) hereof on the day before his death. (c) Commencement and Duration. The monthly surviving spouse benefit payment shall commence in the month following the Participant's death and shall be paid in monthly installments thereafter ending with a payment for the month in which such surviving Eligible Spouse's death occurs. 15 ARTICLE VII ------------ ADMINISTRATION -------------- 7.01 Committee. This Plan shall be administered by the Committee. The Committee shall have all powers necessary to enable it to carry out its duties in the administration of the Plan. Not in limitation, but in application of the foregoing, the Committee shall have the duty and power to determine all questions that may arise hereunder as to the status and rights of Participants in the Plan. 7.02 Voting. The Committee shall act by a majority of the number then constituting the Committee, and such action may be taken either by vote at a meeting or in writing without a meeting. 7.03 Records. The Committee shall keep a complete record of all its proceedings and all data relating to the administration of the Plan. The Committee shall select one of its members as a Chairman. The Committee shall appoint a Secretary to keep minutes of its meetings and the Secretary may or may not be a member of the Committee. The Committee shall make such rules and regulations for the conduct of its business as it shall deem advisable. 7.04 Liability. To the extent permitted by law, no member of the Committee shall be liable to any person for any action taken or omitted in connection with the interpretation and administration of this Plan unless attributable to his own gross negligence or willful misconduct. The Sponsor shall indemnify the members of the Committee against any and all claims, losses, damages, expenses, including counsel fees, incurred by them, and any liability, including any amounts paid in settlement with their approval, arising from their action or failure to act, except when the same is judicially determined to be attributable to their gross negligence or willful misconduct. 7.05 Expenses. The cost of payments from this Plan and the expenses of administering the Plan shall be borne by each Company with respect to its own employees. 16 ARTICLE VIII ------------ AMENDMENT AND TERMINATION ------------------------- The Sponsor reserves the right, at any time or from time to time, by action of its Board , to modify or amend in whole or in part any or all provisions of the Plan. In addition, the Sponsor reserves the right by action of its Board to terminate the Plan in whole or in part. Provided, however, any such modification, amendment or termination shall not reduce benefits accrued at such time nor increase vesting requirements with respect to such accrued benefits. 17 ARTICLE IX ---------- MISCELLANEOUS ------------- 9.01 Non-Alienation of Benefits. No right or benefit under the Plan shall be subject to anticipation, alienation, sale, assignment, pledge, encumbrance, or charge, and any attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge any right or benefit under the Plan shall be void. No right or benefit hereunder shall in any manner be liable for or subject to the debts, contracts, liabilities or torts of the person entitled to such benefits. If the Participant or Eligible Spouse shall become bankrupt, or attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge any right hereunder, then such right or benefit shall, in the discretion of the Committee, cease and terminate, and in such event, the Committee may hold or apply the same or any part thereof for the benefit of the Participant or his spouse, children, or other dependents, or any of them, in such manner and in such amounts and proportions as the Committee may deem proper. 9.02 No Trust Created. The obligations of the Sponsor and each Company to make payments hereunder shall constitute a liability of the Sponsor and each Company, as the case may be, to a Participant. Such payments shall be made from the general funds of the Sponsor or a Company, and the Sponsor or a Company shall not be required to establish or maintain any special or separate fund, or purchase or acquire life insurance on a Participant's life, or otherwise to segregate assets to assure that such payment shall be made, and neither a Participant nor Eligible Spouse shall have any interest in any particular asset of the Sponsor or a Company by reason of its obligations hereunder. Nothing contained in the Plan shall create or be construed as creating a trust of any kind or any other fiduciary relationship between the Sponsor, a Company and a Participant or any other person. 9.03 No Employment Agreement. Neither the execution of this Plan nor any action taken by the Sponsor or a Company pursuant to this Plan shall be held or construed to confer on a Participant any legal right to be continued as an employee of the Sponsor or a Company 18 in an executive position or in any other capacity whatsoever. This Plan shall not be deemed to constitute a contract of employment between the Sponsor or a Company and a Participant, nor shall any provision herein restrict the right of any Participant to terminate his employment with the Sponsor or a Company. 9.04 Binding Effect. Obligations incurred by the Sponsor or a Company pursuant to this Plan shall be binding upon and inure to the benefit of the Sponsor or a Company, its successors and assigns, and the Participant or his Eligible Spouse. 9.05 Suicide. No benefit shall be payable under the Plan to a Participant or Eligible Spouse where such Participant dies as a result of suicide within two (2) years of his commencement of participation herein. 9.06 Claims for Benefits. Each Participant or Eligible Spouse must claim any benefit to which he is entitled under this Plan by a written notification to the Committee. If a claim is denied, it must be denied within a reasonable period of time, and be contained in a written notice stating the following: A. The specific reason for the denial. B. Specific reference to the Plan provision on which the denial is based. C. Description of additional information necessary for the claimant to present his claim, if any, and an explanation of why such material is necessary. D. An explanation of the Plan's claims review procedure. The claimant will have 60 days to request a review of the denial by the Committee, which will provide a full and fair review. The request for review must be in writing delivered to the Committee. The claimant may review pertinent documents, and he may submit issues and comments in writing. The decision by the Committee with respect to the review must be given within 60 days after receipt of the request, unless special circumstances require an extension (such as for a hearing). In no event shall the decision be delayed beyond 120 days after receipt of the 19 request for review. The decision shall be written in a manner calculated to be understood by the claimant, and it shall include specific reasons and refer to specific Plan provisions as to its effect. 9.07 Entire Plan. This document and any amendments contain all the terms and provisions of the Plan and shall constitute the entire Plan, any other alleged terms or provisions being of no effect. 20 ARTICLE X ---------- CONSTRUCTION ------------ 10.01 Governing Law. This Plan shall be construed and governed in accordance with the laws of the State of North Carolina, to the extent not preempted by Federal Law. 10.02 Gender. The masculine gender, where appearing in the Plan, shall be deemed to include the feminine gender, and the singular may include the plural, unless the context clearly indicates to the contrary. 10.03 Headings, etc. The cover page of this Plan, the Table of Contents and all headings used in this Plan are for convenience of reference only and are not part of the substance of this Plan. 10.04 Action. Any action under this Plan required or permitted by the Sponsor shall be by action of its Board or its duly authorized designee. 21 APPENDIX A ---------- North Carolina Natural Gas Company ("NCNG"); provided that for all purposes of the Plan, Service for an employee of NCNG on December 31, 1999 (as defined in Section 2.19) shall include employment only with NCNG (or another adopting Company) on or after January 1, 2000; and further provided that the accrued benefit calculated under Sections 2.03, 2.04 and 2.05 shall not include the "Accrued Benefit" under Supplement A, Paragraph A-2 of the Retirement Plan, attributable to the NCNG Employees Pension Plan. 22 EX-10 5 EX-10B(32) AGREEMENT DATED APRIL 27, 1999 EXHIBIT 10B(32) April 27, 1999 Mr. Sherwood H. Smith, Jr. 408 Drummond Drive Raleigh, NC 27609 Dear Sherwood: This letter will confirm the discussion we have recently had concerning your upcoming retirement as Chairman of the Board of Directors of Carolina Power & Light Company. Your current Agreement with the Company anticipates that you will not serve as Chairman after the May 1999 Annual Meeting, and your current term as a Director expires at that meeting. We have agreed that you will accept a nomination at the May 1999 meeting to be a Director in Class II and to serve a one-year term expiring in 2000. We also anticipate that at the Board meeting in May you will be elected to the honorary position of Chairman Emeritus. The Agreement states that you will continue to provide various services to the Company through September 30, 1999. We also appreciate your commitment to be available to continue to provide these types of services to the Company after September 30, 1999. These additional services will be as requested by, and performed under the general direction of, CP&L's Chief Executive Officer, as agreed to by you. The compensation for such services will be as approved by the Chief Executive Officer. In addition, you will receive the standard compensation for service as an outside Director after September 30, 1999, until your term as Director expires. (The non-compete provisions of your Agreement will, of course, continue.) The Company will continue to provide the services and benefits described in your Agreement, including a home alarm and security service, a company network telephone, and facsimile equipment at your residence, and a car telephone. The Company will also provide you with its standard car allowance for three years following the expiration of the Agreement (through September 30, 2002). Finally, as noted in the Agreement, the Company will also continue to provide office and secretarial support. We are currently arranging accommodations in One Hannover Square with the intent of relocating your office in June. These services and appropriate office accommodations will be supplied until you attain the age of 80. After such time, if services or accommodations of any kind might be appropriate, the matter will be determined at that time by the Chief Executive Officer. I look forward to having you continue on the Board of Directors for another year. Very truly yours, /s/William Cavanaugh III William Cavanaugh III Agreed: /s/Sherwood H. Smith, Jr. ------------------------- Sherwood H. Smith, Jr. EX-10 6 EX-10B(33)EMPLOYMENT AGREEMENT DATED JULY 15, 1999 EXHIBIT 10B(33) EMPLOYMENT AGREEMENT BETWEEN NORTH CAROLINA NATURAL GAS CORPORATION AND CALVIN B. WELLS JULY 15, 1999 EMPLOYMENT AGREEMENT -------------------- EMPLOYMENT AGREEMENT ("Agreement"), dated as of the July 15, 1999, between North Carolina Natural Gas Corporation ("NCNG" or "Company"), a Delaware Corporation headquartered in Fayetteville, North Carolina and a subsidiary of Carolina Power & Light Company ("CP&L"), and Calvin B. Wells ("Wells"). RECITALS --------- 1. On or around July 15, 1999 ("Closing Date"), North Carolina Natural Gas Corporation will, through a merger transaction, become a wholly owned subsidiary of Carolina Power & Light ("CP&L"). NCNG, as it existed prior to this merger, will be referred to herein as "Pre-Merger NCNG." 2. Wells was employed as Chief Executive Officer of Pre-Merger NCNG and entered into an Employment Agreement with Pre-Merger NCNG on September 11, 1985 ("Prior Agreement"). 3. NCNG and Wells wish to enter into an employment relationship whereby Wells will be employed as Chief Executive Officer of NCNG after the Closing Date. 4. NCNG and Wells wish to rescind his Prior Agreement and enter into this new Employment Agreement which will supersede all prior agreements on the subject matter. 5. The parties wish to enter into this Agreement to set forth certain terms related to that relationship. PROVISIONS NOW, THEREFORE, in consideration of the mutual covenants and promises contained herein and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and accepted, the parties hereto hereby agree as follows: 1. TERM OF EMPLOYMENT. ------------------ (a). Employment. The Company hereby agrees to employ Wells, and Wells hereby accepts employment with NCNG, for the Employment Term stated herein, subject to the terms and conditions hereof. (b). Employment Term. Unless sooner terminated in accordance with the provisions of Section 6, Wells' term of employment with NCNG under this Agreement (the "Employment Term") shall commence on the Closing Date ("Employment Date"), and shall 1 continue until July 15, 2002. Should Wells' employment with NCNG continue past July 15, 2002, then such employment shall not be subject to this Employment Agreement. 2. RESPONSIBILITIES; OTHER ACTIVITIES. ---------------------------------- Wells shall occupy the position of Chief Executive Officer of NCNG and shall undertake the general responsibilities and duties of such position as directed by NCNG's Board of Directors. During the Employment Term, Wells shall perform faithfully the duties of Wells' position, devote all of Wells' working time and energies to the business and affairs of NCNG and shall use Wells' best efforts, skills and abilities to promote NCNG. 3. SALARY. ------ As compensation for the services to be performed hereunder: Wells will be paid a salary at the annual rate of Two Hundred Sixty Seven Thousand Three Hundred Dollars ($267,300) (less applicable withholdings) beginning on the Employment Date. Annual salary for each subsequent year of the Employment Term shall be subject to adjustment by the NCNG Board of Directors at its discretion, provided that Wells' annual salary shall not be less than $267,300.00. Annual salary shall be deemed earned proportionally as Wells performs services over the course of the Salary Year. Payments of annual salary shall be made, except as otherwise provided herein, in accordance with NCNG's standard payroll policies and procedures. 4. PRIOR AGREEMENT. ---------------- The parties agree that the Prior Agreement between Pre-Merger NCNG and Wells dated September 11, 1985 is no longer in effect and that this Employment Agreement supersedes Wells' Prior Agreement with Pre-Merger NCNG. 5. BENEFITS. -------- During the Employment Term, Wells shall be entitled to participate in all Company sponsored benefit programs as NCNG or CP&L may have in effect in accordance with their terms. Provided, however, that nothing contained in this Agreement shall require NCNG or CP&L to continue to offer such benefits or programs or to limit NCNG's or CP&L's absolute right to modify or eliminate these benefits. (a). Existing Pre-Merger NCNG Plans. Wells will continue participating in the following existing Pre-Merger NCNG Plans until December 31, 1999, in accordance with their terms: North Carolina Natural Gas Executive Pension Restoration Plan, North Carolina Natural Gas Employees' Pension Plan, North Carolina Natural Gas 401(k) Plan, and all other health and welfare plans as described in the existing Pre-Merger NCNG Handbook, in which Wells is eligible to participate. Wells' rights to benefits under these Plans will be based upon the terms of these Plans. 2 (b). Terminating Pre-Merger NCNG Plans. The parties acknowledge that the following Pre-Merger North Carolina Natural Gas plans will terminate, in accordance with their terms, on or around the Closing Date: the NCNG Long Term Incentive Plan; the NCNG Annual Incentive Plan; the NCNG Employee Stock Purchase Plan; and the NCNG Key Employee Stock Option Plan. Wells' rights to benefits in those plans will be based upon the terms of those plans. (c). CP&L Plans and Post-Merger NCNG Plans. Wells will be eligible to participate in the following benefit plans subject to their terms: (i). Management Incentive Compensation Program. Wells will be eligible to participate in the CP&L Management Incentive Compensation Program (MICP) beginning in 2000, for which payment will be made on or before March 31, 2001, in accordance with the terms of the plan. Pursuant to the terms of the MICP, Wells' target compensation under such program will be approximately 35% of base salary earnings. Wells will be entitled to a 1999 Bonus for the remainder of 1999 to be calculated under the terms of the CP&L MICP and prorated accordingly. (ii). Long Term Incentives. Wells will be eligible to participate in the CP&L Performance Share Sub-Plan under the 1997 Equity Incentive Plan in accordance with the terms of the plan. Wells' participation in this plan shall begin January 1, 2000. (iii). Restricted Stock Agreement. NCNG and Wells have entered into a Restricted Stock Agreement effective July 15, 1999. (iv). Management Deferred Compensation Plan. Wells will be eligible to participate in CP&L's management Deferred Compensation Plan in accordance with the terms of the plan. Wells' participation in this plan shall begin January 1, 2000. (v). Supplemental Retirement Plan. Wells will be eligible for participation in CP&L's Supplemental Retirement Plan (SRP), subject to its terms. Wells' participation in this plan shall begin January 1, 2000. Wells will also be eligible to participate in the CP&L Restoration Retirement Plan on January 1, 2000, subject to its terms. (vi). Executive Permanent Life Insurance Program. Wells shall be eligible to participate in CP&L's Executive Permanent Life Insurance Program, subject to its terms. Wells' participation in this plan shall begin January 1, 2000. (vii). Personal Accident Insurance Program. Wells shall be eligible to participate in CP&L's Personal Accident Insurance Program, subject to its terms. Wells' participation in this plan shall begin January 1, 2000. (viii). Stock Purchase Savings Plan. Wells shall be eligible to participate in CP&L's Stock Purchase Savings Plan, subject to its terms. Wells' participation in this plan shall begin January 1, 2000. 3 (ix). Financial/ Estate Planning. Consistent with CP&L's practice with respect to other senior executives, Wells will be reimbursed for financial and estate planning including financial planning and tax preparation. Wells shall be immediately eligible for this benefit. (x). Choice Benefits Program. Wells shall be eligible to participate in CP&L's Choice Benefits Program, subject to its terms. Wells' participation in this program shall begin January 1, 2000. (xi). Vacation. Wells shall be entitled to five (5) weeks of paid vacation days beginning January 1, 2000. (xii). Holiday. Wells will be eligible for ten (10) paid holidays in each calendar year as provided in the NCNG Handbook. (xiii). Automobile Allowance. Wells will be eligible to receive an automobile allowance of $1350 per month (less withholdings) subject to the terms of NCNG's policies. Wells will also be eligible for a cellular phone and reserved parking at NCNG's expense. Wells shall be eligible for his automobile allowance at the expiration of his current automobile lease. (xiv). Annual Physical. NCNG will pay for an annual physical examination by a physician of Wells' choice beginning January 1, 2000. (xv). Capital City Club. NCNG will pay an initiation fee and monthly dues for a membership at the Capital City Club for Wells. Wells shall be immediately eligible for this benefit. (xvi). Airline Club Membership. NCNG will provide airline club membership in accordance with NCNG policy. Wells shall be immediately eligible for this benefit. (xvii). Country Club Membership. At Wells' option, if joined, NCNG will pay an initiation fee and monthly dues for a membership for Wells at a country club approved by the NCNG Board of Directors. Business related expenses will be reimbursed consistent with NCNG's expense account guidelines. Wells shall be immediately eligible for this benefit. (xviii). Personal Computer. NCNG will provide a personal computer to Wells to be used at his personal residence. Wells shall be immediately eligible for this benefit. 4 (d). Funding of Benefits under NCNG Executive Pension Restoration Plan. (i). Under the NCNG Restoration Pension Plan as referenced in Section 5(a), Wells shall be entitled to benefits that shall have accrued thereunder through December 31, 1999. As further provided in the Plan, such benefits are payable from the general assets of NCNG. (ii). Conditions for Trust. NCNG agrees to establish a trust, as described in Section 5(d)(iii) below, to fund the payment of benefits to Wells under NCNG's Executive Pension Restoration Plan in the event that: (aa). A change-in-control of NCNG or CP&L occurs; or (bb). Wells retires under the NCNG Employee's Pension Plan or CP&L's Supplemental Retirement Plan (as applicable). Retirement by Wells shall be deemed to have occurred in the event that his employment is terminated with NCNG and he becomes eligible to begin receiving benefits under the NCNG Executive Pension Restoration Plan. (iii). Trust. Should the conditions specified in Section 5(d)(ii) transpire, and should NCNG thereby be required to establish a trust as provided therein, such trust shall be: (aa). A trust of which NCNG is the grantor, within the meaning of subpart E, Part I, subchapter J, chapter 1, subtitle A of the Internal Revenue Code; (bb). A trust under which Wells is a beneficiary as of his retirement date or as of the change-in-control date (as applicable); and (cc). A trust the assets of which shall be subject to the claims of NCNG's general creditors in accordance with Internal Revenue Service Revenue Procedure 92-64. (iv). Further Modifications. Nothing in this Agreement shall in any way limit or prohibit NCNG from amending or terminating NCNG's Employee's Pension Plan, CP&L's Supplemental Retirement Plan, NCNG's Executive Pension Restoration Plan, or any other benefit plan of NCNG or CP&L. (v). Change-in-Control. (aa). Defined. A Change-in-Control of NCNG or CP&L shall be deemed to have occurred only in the event that any one of the following circumstances or conditions transpires: (i). The acquisition by any person (including a group, within the meaning of Section 13(d) or 14(d)(2) of the Securities Exchange Act of 1934, as amended) of beneficial ownership of 15 percent or more of the NCNG's or CP&L's then outstanding voting securities; 5 (ii). A tender offer is made and consummated for the ownership of 51 percent or more of NCNG's or CP&L's then outstanding voting securities; (iii). The first day on which less than 66 2/3 percent of the total membership of the Board of Directors of NCNG or CP&L are Continuing Directors of either NCNG or CP&L ("Continuing Directors" being members of such Board as of the effective date of this Agreement), provided, however, that any person becoming a director subsequent to such date whose election or nomination for election was supported by 75 percent or more of the directors who then comprised Continuing Directors shall be considered to be a Continuing Director); or (iv). Approval by the stockholders of the NCNG or CP&L of a merger, consolidation, liquidation or dissolution of the NCNG or CP&L, or of the sale of all or substantially all of the assets of NCNG or CP&L; (bb). Holding Company or Structural Reorganization. Movement of NCNG or CP&L to a holding company structure, issuance of stock to the shareholders of CP&L or any holding company, or any other corporate reorganization among affiliated companies whereby the ultimate ownership of NCNG does not materially change as a result of a the transaction shall not be deemed to be a Change-in-Control. (cc). Effective Date for Change-in-Control. A Change-in-Control shall not be deemed to have occurred until Wells receives written certification from CP&L's President and Chief Executive Officer or, in the event of his or her inability to act, CP&L's Chief Financial Officer, or any Executive or Senior Vice President of the CP&L that one of the events set forth in Section 5(d)(v)(aa) above has occurred. The officers referred to in the previous sentence shall be those officers in office immediately prior to the occurrence of one of the events set forth above in Section 5(d)(v)(aa). Any determination that such an event has occurred shall, if made in good faith on the basis of information available at that time, be conclusive and binding on NCNG and Wells and Wells' beneficiaries for all purposes of this Agreement. 6. TERMINATION OF EMPLOYMENT. ------------------------- (a). The employment relationship between Wells and NCNG may be terminated by either NCNG or Wells with or without advance notice and may be terminated with or without cause as defined below. (b). Termination Without Cause or Change in Control. If Wells' employment is terminated before the end of the Employment Term Without Cause or as a result of a Change in Control (as defined in Section 5(d)) of NCNG, then Wells will be provided with severance benefits as described below, subject to paragraph 6(h). 6 (i). Severance Benefits. In accordance with a termination under this paragraph 6(b), and subject to paragraph 6(h), Wells shall be entitled to the benefits described below. All payments shall be subject to required payroll withholdings, including any withholdings for excise taxes for parachute payments. In addition, Wells acknowledges that he is liable for all federal and state income and excise taxes due on these severance or other payments from NCNG. (aa). Salary. Wells shall be entitled to continuation of his then current base annual salary for two (2) years and eleven (11) months following such termination, paid on a semi-monthly basis. Provided, however, that if Wells is re-employed before the expiration of the two (2) years and eleven (11) months period following termination, remaining severance shall be reduced to the difference, if any, between the salary continued hereunder and the salary in the new position. (bb). Welfare Benefit Plans and 401(k) Plan. NCNG shall pay Wells a monthly sum to compensate Wells for the employer-paid portion of medical, life, AD&D and disability coverage and for the loss of the company match under the 401(k) plan. Such sum shall be grossed up to cover state and federal income taxes, but not any excise taxes due for parachute payments which may apply. Provided, however, that these payments shall cease sixty (60) days following Wells' re-employment before the end of the two (2) year and eleven (11) month period following termination. Upon re-employment, NCNG shall have no further obligation to Wells under this paragraph 6(b)(i)(bb). (cc). Retirement Plan. In order to compensate Wells for loss of pension benefits, NCNG shall calculate a "make up" pension benefit. This "make up" pension benefit shall equal the value which would have been added to Wells' pension benefit, under the retirement plan in which he is participating at the time of termination, had his employment been continued for two (2) years and eleven (11) months beyond the termination date, or to the date sixty (60) days following Wells' re-employment, whichever is earlier. The "make up" pension benefit shall be calculated within a reasonable period of time following such date. The net present value of the "make up" pension benefit (less applicable withholdings) shall be payable, in semi-monthly payments, over a five (5) year period beginning on the first of the month following such calculation. (i). Calculation. If Wells' employment is terminated under this paragraph on or before December 31, 1999, then the "make up" pension benefits will be calculated based upon the final average pay as it would have been determined under the NCNG Employees' Pension Plan and the North Carolina Natural Gas Executive Pension Plan as of the date of termination. If Wells' employment is terminated on or after January 1, 2000, then this "make up" pension benefit shall be calculated based upon the base salary as determined under the CP&L Supplemental Retirement Plan and the CP&L Restoration Retirement Plan as of the date of termination. (dd). Re-employment. Wells acknowledges that benefits under paragraph 6(b) are affected by his re-employment before the expiration of two (2) years and 7 eleven (11) months from the date of termination. Wells agrees that he shall provide written notice to NCNG of any such re-employment within fourteen (14) days of the date re-employment commences. Such notice shall include the terms of employment, including start date, salary, benefit availability, and other information as may be requested by the NCNG Board of Directors. Such notice shall be delivered to: Vice President, Human Resources, Carolina Power & Light Company, P. O. Box 1551, Raleigh, North Carolina, 27602. For purposes of this Agreement, re-employment shall include, but not be limited to, work as an employee, agent, consultant, independent contractor, or in any other capacity, for an employer, firm, or other entity, or for one's own business. (c). Constructive Termination. If Wells is reassigned to another position with significantly and materially reduced responsibilities, or his annual salary is reduced by 15% or more, then, at Wells' option, Wells may deem such action to be a Constructive Termination. Should Wells wish to deem such action a Constructive Termination, then Wells must notify, in writing, the NCNG Board of Directors within 30 days of the date Wells received notification of the change in his duties or salary. Should Wells declare such action to be a Constructive Termination, then he shall be entitled to the benefits described in paragraph 6(b), subject to paragraph 6(h). (d). Voluntary Termination - If Wells terminates his employment voluntarily for any reason at any time, then he shall be eligible to retain all benefits under existing benefit programs which have vested pursuant to the terms of those programs, but he shall not be entitled to any form of salary continuance or any form of severance benefit. (e). Termination for Cause - The Company may elect at any time to terminate Wells' employment immediately hereunder and remove Wells from employment for Cause. For purposes of this paragraph 6, cause for the termination of employment shall be defined as: (i) the willful and continued failure by him substantially to perform his duties with the Company (other than any such failure resulting from his incapacity due to physical or mental illness), or (ii) the willful engaging by him in misconduct which is materially injurious to the Company, monetarily or otherwise. Upon the termination of Wells' employment for Cause, NCNG shall have no further obligation to Wells under this Agreement except as specifically provided in this Agreement. Upon such termination, Wells shall be entitled to all earned but unpaid salary accrued to the date of termination. Any continued rights and benefits Wells, or Wells' legal representatives, may have under employee benefit plans and programs of NCNG upon Wells' termination for cause, if any, shall be determined in accordance with the terms and provisions of such plans and programs. (f). Termination Due to Death. In the event of the death of Wells at any time during the Employment Term, Wells' employment hereunder shall terminate and NCNG shall have no further obligation to Wells under this Agreement except as specifically provided in this Agreement. Wells' estate shall be entitled to receive all earned but unpaid salary accrued to the date of termination. Any rights and benefits Wells, or Wells' estate or other legal representatives, may have under employee benefit plans and programs of NCNG upon Wells' 8 death during the Employment Term, if any, shall be determined in accordance with the terms and provisions of such plans and programs. (g). Termination Due to Medical Condition. (i). At any time NCNG may terminate Wells' employment hereunder, subject to the Americans With Disabilities Act or other applicable law, due to medical condition if (i) for a period of 180 consecutive days during the Employment Term, Wells is totally and permanently disabled as determined in accordance with the Company's long-term disability plan, if any, as in effect during such time or (ii) at any time during which no such plan is in effect, Wells is substantially unable to perform Wells' duties hereunder because of a medical condition for a period of 180 consecutive days during the Employment Term. (ii). Upon the termination of Wells' employment due to medical condition, NCNG shall have no further obligation to Wells under this Agreement except as specifically provided in this Agreement. Upon such termination, Wells shall be entitled to all earned but unpaid salary accrued to the date of termination. Any continued rights and benefits Wells, or Wells' legal representatives, may have under employee benefit plans and programs of NCNG upon Wells' termination due to medical condition, if any, shall be determined in accordance with the terms and provisions of such plans and programs. (h). Release of Claims - In order to receive continuation of salary and benefits under this paragraph 6, Wells agrees to execute a written release of all claims against NCNG, and its employees, officers, directors, subsidiaries and affiliates, on a form acceptable to NCNG. 7. ASSIGNABILITY. ------------- No rights or obligations of Wells under this Agreement may be assigned or transferred by Wells, except that (a) Wells' rights to compensation and benefits hereunder may be transferred by will or laws of intestacy to the extent specified herein and (b) Wells' rights under employee benefit plans or programs described in Section 5 may be assigned or transferred in accordance with the terms of such plans or programs, or regular practices thereunder. NCNG may assign or transfer its rights and obligations under this Agreement. 8. CONFIDENTIALITY. Wells will not disclose the terms of this Agreement except (i) to financial and legal advisors under an obligation to maintain confidentiality, or (ii) as required by law, including but not limited to, a valid court order or subpoena (and in such event will use Wells' best efforts to obtain a protective order requiring that all disclosure be kept under court seal) and will notify NCNG promptly upon receipt of such order or subpoena. 9. MISCELLANEOUS. ------------- 9 (a). Governing Law. This Agreement shall be governed by, and construed in accordance with, the laws of the State of North Carolina without reference to laws governing conflicts of law. (b). Entire Agreement. This Agreement contains all of the understandings and representations between the parties hereto pertaining to the subject matter hereof and supersedes all undertakings and agreements, including specifically the Prior Agreement entered into on September 11, 1985, whether oral or in writing, previously entered into by them with respect thereto. (c). Amendment or Modification; Waiver. No provision in this Agreement may be amended or waived unless such amendment or waiver is agreed to in writing, signed by Wells and by an officer of NCNG thereunto duly authorized to do so. Except as otherwise specifically provided in the Agreement, no waiver by a party hereto of any breach by the other party hereto of any condition or provision of the Agreement to be performed by such other party shall be deemed a waiver of a similar or dissimilar provision or condition at the same or any prior or subsequent time. (d). Notice. Any notice (with the exception of notice of termination by NCNG, which may be given by any means and need not be in writing) or other document or communication required or permitted to be given or delivered hereunder shall be in writing and shall be deemed to have been duly given or delivered if (i) mailed by United States mail, certified, return receipt requested, with proper postage prepaid, or (ii) otherwise delivered by hand or by overnight delivery, against written receipt, by a common carrier or commercial courier or delivery service, to the party to whom it is to be given at the address of such party as set forth below (or to such other address as a party shall have designated by notice to the other parties given pursuant hereto): If to Wells: Calvin B. Wells North Carolina Natural Gas 150 Rowan Street Fayetteville, NC 28301 If to NCNG: Carolina Power & Light Company 411 Fayetteville Street Raleigh, North Carolina 27602 Attention: Vice President-Human Resources Any such notice, request, demand, advice, schedule, report, certificate, direction, instruction or other document or communication so mailed or sent shall be deemed to have been duly given, if 10 sent by mail, on the third business day following the date on which it was deposited at a United States post office, and if delivered by hand, at the time of delivery by such commercial courier or delivery service, and, if delivered by overnight delivery service, on the first business day following the date on which it was delivered to the custody of such common carrier or commercial courier or delivery service, as all such dates are evidenced by the applicable delivery receipt, airbill or other shipping or mailing document. (e). Severability. In the event that any provision or portion of this Agreement shall be determined to be invalid or unenforceable for any reason, the remaining provisions or portions of this Agreement shall be unaffected thereby and shall remain in full force and effect to the fullest extent permitted by law. (f). References. In the event of Wells' death or a judicial determination of Wells' incompetence, reference in this Agreement to Wells shall be deemed, where appropriate, to refer to Wells' legal representative, or, where appropriate, to Wells' beneficiary or beneficiaries. (g). Headings. Headings contained herein are for convenient reference only and shall not in any way affect the meaning or interpretation of this Agreement. (h). Counterparts. This Agreement may be executed in several counterparts, each of which shall be deemed to be an original, but all of which together shall constitute one and the same instrument. (i). Rules of Construction. The following rules shall apply to the construction and interpretation of this Agreement: (i). Singular words shall connote the plural number as well as the singular and vice versa, and the masculine shall include the feminine and the neuter. (ii). All references herein to particular articles, paragraphs, sections, subsections, clauses, Schedules or Exhibits are references to articles, paragraphs, sections, subsections, clauses, Schedules or Exhibits of this Agreement. (iii). Each party and its counsel have reviewed and revised (or requested revisions of) this Agreement, and therefore any rule of construction requiring that ambiguities are to be resolved against a particular party shall not be applicable in the construction and interpretation of this Agreement or any exhibits hereto or amendments hereof. (iv). As used in this Agreement, "including" is illustrative, and means "including but not limited to." (j). Remedies. Remedies specified in this Agreement are in addition to any others available at law or in equity. 11 (k). Withholding Taxes. All payments under this Agreement shall be subject to applicable income, excise and employment tax withholding requirements. IN WITNESS WHEREOF, the parties hereto have executed, or have caused this Agreement to be executed by their duly authorized officer, as the case may be, all as of the day and year written below. By: _______________________________ Date: ___________________ Calvin B. Wells By: _______________________________ Date: ___________________ North Carolina Natural Gas Corporation Title: _______________________________ 12 EX-10 7 EX-10B(34) EMPLOY. AGREEMENT DATED AUG. 5, 1999 EXHIBIT 10B(34) August 2, 1999 Mr. Larry M. Smith 205 South 26th Street West Des Moines, Iowa 50265 Dear Larry: I am pleased to confirm the offer of employment with Carolina Power & Light Company as the Vice President & Controller at an annual salary of $168,000. The offer is contingent on approval from the Board of Directors, satisfactory completion of an employment background investigation, and eligibility to be employed in the United States. We ask that you kindly inform of your decision to accept our offer by August 9, 1999. Please return one copy of this letter with your signature to indicate your acceptance of our offer. Also, please read, sign, and return the Fair Credit Reporting Act Disclosure and Authorization Statement which describes your federal rights related to any employment background check. We are looking forward to having you join us as a vital member of the team and feel that you can make a significant contribution to CP&L in our Financial Services Group. If I can answer any questions about the offer or provide any additional information, please call me at 919-546-5533. Sincerely, /s/Glenn E. Harder Glenn E. Harder Chief Financial Officer Attachment ACCEPTED: /s/Larry M. Smith 8/5/99 - --------------------------------- Signature/Date c: Randy Mizelle Glenn E. Harris [] [] [] [] [] [] [] [] [] [] [] [] [] [] [] [] [] [] [] [] TO BE COMPLETED ONLY IF OFFER IS ACCEPTED: Birthdate: 2/26/56 ------- VP & CONTROLLER COMPENSATION/BENEFITS/PERQUISITES BASE SALARY $168,000 annually, subject to periodic - ----------- review and normally adjusted in March, at the time other department head salaries are reviewed. SHORT-TERM Participation in Management Incentive INCENTIVE Compensation Program with an annual - ---------- target of 25% of actual base salary earnings. LONG-TERM Participation in the Performance Share INCENTIVE Sub-Plan which provides for an annual - --------- award of 25% of base salary awarded in performance shares equivalent in value to the market price of the Company's common stock at the time of the granting of the award, earned over a three-year period and adjusted based on performance. SPLIT-DOLLAR LIFE Participant in a permanent life INSURANCE PLAN insurance program with a target benefit - ----------------- of 3 times projected base salary assuming a salary growth of 5%. Participation in this "split dollar" program is conditional upon passing underwriting and waiving all but $50,000 coverage in the group term plan within Choice Benefits. AUTOMOBILE Car Allowance of $1200 per month with - ---------- cellular telephone. LUNCHEON CLUB Initiation fees and dues provided to the - ------------- Capital City Club. ANNUAL PHYSICAL One annual physical examination covered, - ---------------- to be provided by a physician of employee's choice. BENEFITS Choice Benefits Program including - -------- options for medical, dental, employee and dependent life, and AD&D insurance. PENSION PLAN Participation in Company funded - ------------ retirement plan that provides lump sum and/or lifetime benefits for you and your surviving spouse upon completion of 5 years of employment. STOCK PURCHASE Provides for $.50 match per dollar up to SAVINGS PLAN six percent (6%) of base salary. - -------------- Additional contributions are possible for another $.50 based upon meeting Company performance goals. DISABILITY INCOME Coverage under plan that provides for - ----------------- 60% of salary (or 70% of base salary including Family Social Security benefits). VACATION One week during the balance of 1999. - -------- Four weeks beginning January 2000. Per company policy thereafter. HOLIDAYS Current company policy is 10 days. - -------- TERMINATION Employment may be terminated at will by - ----------- the Company or by you without notice. If, following a Change-of-Control and within 2 years of employment, employment is terminated other than for good cause by the Company, you will be provided one year's base salary over the following 12 months, paid on a semi-monthly basis, subject to signing a release agreement. A Change-of-Control will be deemed to occur if there is a change in the form of ownership of CP&L (e.g., CP&L is acquired or otherwise changes form of ownership). Change in CP&L's corporate structure such as reorganization under or into a holding company, shall not be considered the basis for constructive termination. Good cause for the termination of employment shall be defined as: (i) any act of Mr. Smith's including, but not limited to, misconduct, negligence, unlawfulness, dishonesty or inattention to the business, which is detrimental to CP&L's interests; or (ii) Mr. Smith's unsatisfactory job performance or failure to comply with CP&L's direction, policies, rules or regulations. EX-12 8 COMPUTATION OF RATIO OF EARNINGS EXHIBIT NO. 12 COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED DIVIDENDS COMBINED AND RATIO OF EARNINGS TO FIXED CHARGES
-------------------------------------------------------------------- Years Ended December 31, -------------------------------------------------------------------- 1999 1998 1997 1996 1995 ---- ---- ---- ---- ---- (Thousands of Dollars) Earnings, as defined: Net income $ 382,255 399,238 $ 388,317 $ 391,277 $ 372,604 Fixed charges, as below 202,491 191,832 193,632 204,593 226,833 Income taxes, as below 250,272 249,180 225,491 247,691 232,343 ------------------------- ------------ ------------- ------------- Total earnings, as defined $ 835,018 840,250 $ 807,440 $ 843,561 $ 831,780 ========================= ============ ============= ============= Fixed Charges, as defined: Interest on long-term debt $ 180,676 169,901 $ 163,468 $ 172,622 $ 187,397 Other interest 10,298 11,156 18,743 19,155 25,896 Imputed interest factor in rentals-charged Principally to operating expenses 11,517 10,775 11,421 12,816 13,540 ------------------------- ------------ ------------- ------------- Total fixed charges, as defined $ 202,491 191,832 $ 193,632 $ 204,593 $ 226,833 ========================= ============ ============= ============= Earnings Before Income Taxes $ 632,527 648,418 $ 613,808 $ 638,968 $ 604,947 ========================= ============ ============= ============= Ratio of Earnings Before Income Taxes to Net Income 1.66 1.62 1.58 1.63 1.62 Income Taxes: Income tax expense 258,421 257,494 233,716 255,916 240,683 Included in AFUDC - deferred taxes in book depreciation (8,149) (8,314) (8,225) (8,225) (8,340) ------------------------- ------------ ------------- ------------- Total income taxes $ 250,272 249,180 $ 225,491 $ 247,691 $ 232,343 ========================= ============ ============= ============= Fixed Charges and Preferred Dividends Combined: Preferred dividend requirements $ 2,967 2,967 $ 6,052 $ 9,609 $ 9,609 Portion deductible for income tax purposes (312) (312) (312) (312) (312) ------------------------- ------------ ------------- ------------- Preferred dividend requirements not deductible $ 2,655 2,655 $ 5,740 $ 9,297 $ 9,297 ========================= ============ ============= ============= Preferred dividend factor: Preferred dividends not deductible times ratio of Earnings before income taxes to net income $ 4,407 4,301 $ 9,069 $ 15,154 $ 15,061 Preferred dividends deductible for income taxes 312 312 312 312 312 Fixed charges, as above 202,491 191,832 193,632 204,593 226,833 ------------------------- ------------ ------------- ------------- Total fixed charges and preferred dividends combined $ 207,210 196,445 $ 203,013 $ 220,059 $ 242,206 ========================= ============ ============= ============= Ratio of Earnings to Fixed Charges and Preferred Dividends Combined 4.03 4.28 3.98 3.83 3.43 Ratio of Earnings to Fixed Charges 4.12 4.38 4.17 4.12 3.67
EX-21 9 SUBSIDIARIES EXHIBIT 21 SUBSIDIARIES OF CAROLINA POWER & LIGHT COMPANY AT DECEMBER 31, 1999 The following is a list of certain subsidiaries of Carolina Power & Light Company and their respective states of incorporation: Interpath Communications, Inc. North Carolina Virginia North Carolina Natural Gas Corporation Delaware Cape Fear Energy Corporation (1) North Carolina NCNG Cardinal Pipeline Investment Corporation (1) North Carolina NCNG Energy Corporation (1) North Carolina NCNG Pine Needle Investment Corporation (1) North Carolina Strategic Resource Solutions Corp. North Carolina ACT Controls, Inc. (2) North Carolina Applied Computer Technologies Corp. (2) Delaware Spectrum Controls, Inc. (2) North Carolina SRS Engineering Corp. (2) North Carolina (1) Subsidiary of North Carolina Natural Gas Corporation. (2) Subsidiary of Strategic Resource Solutions Corp. EX-23 10 EX-23(A)CONSENT OF DELOITTE & TOUCHE LLP 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. 333-69237 on Form S-3, Registration Statement No. 333-70679 on Form S-8 and Registration Statement No. 333-89685 on Form S-8 of Carolina Power & Light Company, of our report dated February 8, 2000, except for Note 2, as to which the date is March 3, 2000 appearing in this Annual Report on Form 10-K of Carolina Power & Light Company for the year ended December 31, 1999. /s/ DELOITTE & TOUCHE LLP Raleigh, North Carolina March 21, 2000 EX-27 11 FDS
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM (CONSOLIDATED FINANCIAL STATEMENTS AS OF DECEMBER 31, 1999) AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 12-MOS DEC-31-1999 DEC-31-1999 PER-BOOK $6,764,813 $492,436 $1,079,333 $297,749 $859,688 $9,494,019 $1,606,096 $(794) $1,807,345 $3,412,647 $0 $59,376 $3,028,561 $168,240 $0 $0 $197,250 $0 $0 $0 $2,627,945 $9,494,019 $3,357,615 $258,421 $2,517,072 $2,775,493 $582,122 $(20,403) $561,719 $179,464 $382,255 $(2,967) $379,288 $300,244 $137,067 $832,120 2.56 2.55
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