ITEM 1. BUSINESS _________________
GENERAL _______
1. COMPANY. Carolina Power & Light Company (Company) is a public service corporation formed under the laws of North Carolina in 1926, and is engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. The Company had 8,027 employees at December 31, 1993. The principal executive offices of the Company are located at 411 Fayetteville Street, Raleigh, North Carolina 27601, telephone number: 919-546-6111.
2. SERVICE.
a. The territory served, an area of approximately 30,000 square miles, includes a substantial portion of the coastal plain in North Carolina extending to the Atlantic coast between the Pamlico River and the South Carolina border, the lower Piedmont section in North Carolina, an area in northeastern South Carolina, and an area in western North Carolina in and around the City of Asheville. The estimated total population of the territory served is approximately 3.5 million.
b. The Company provides electricity at retail in 219 communities, each having an estimated population of 500 or more, and at wholesale to one joint municipal power agency, 4 municipalities and 18 electric membership corporations. At December 31, 1993, the Company was furnishing electric service to approximately 1,032,000 customers.
3. SALES. During 1993, 32.6% of operating revenues was derived from residential sales, 20.5% from commercial sales, 25.7% from industrial sales, 17.2% from resale sales and 4.0% from other sources. Of such operating revenues, approximately 85% was derived from North Carolina and approximately 15% from South Carolina. For the twelve months ended December 31, 1993, average revenues per kilowatt-hour (kWh) sold to residential, commercial and industrial customers were 8.28 cents, 6.94 cents and 5.49 cents, respectively. Sales to residential customers for the past five years are listed below.
Average Average Annual Annual Revenue Year kWh Use Bill per kWh ____ _______ _______ _______
1989 12,419 $ 987.19 7.95 cents 1990 11,957 995.01 8.32 1991 12,472 1,040.70 8.34 1992 12,396 1,029.82 8.31 1993 13,167 1,090.16 8.28
4. PEAK DEMAND.
a. A 60-minute system peak demand record of 10,144 megawatts (MW) was reached on January 19, 1994. 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 0.22%.
b. Total system peak demand for 1991 increased by 3.2%, for 1992 increased by 3.1%, and for 1993 increased by 3.8%, as compared with the preceding year. The Company currently projects a 2.3% average annual growth in system peak demand over the next ten years. The year-to-year change in actual peak demand is influenced by the specific weather conditions during those years and may not exhibit a consistent pattern. Total system load factors, expressed as the ratio of the average load supplied to the peak load demand, for the years 1991-1993 were 57.8%, 57.4% and 59.0%, respectively. The Company forecasts capacity margins of 15.2% and 13.4% over anticipated system peak load for 1994 and 1995. This forecast assumes normal weather conditions in each year consistent with long-term experience, and is based upon the rated Maximum Dependable Capacity of generating units in commercial operation and scheduled firm purchases of power. See ITEM 1, "Generating Capability" and "Interconnections With Other Systems." However, some of the generating units included in arriving at these capacity margins may be unavailable as a result of scheduled outages, environmental modifications or unplanned outages. See ITEM 1, "Environmental Matters" and "Nuclear Matters." The data contained in this paragraph includes North Carolina Eastern Municipal Power Agency's (Power Agency) load requirements and capability from its ownership interests in certain of the Company's generating facilities. See ITEM 1, "Generating Capability," paragraph 1.
GENERATING CAPABILITY _____________________
1. FACILITIES. The Company has a total system installed generating capability of 9,613 MW, with generating capacity provided primarily from the installed generating facilities listed in the table below. The remainder of the Company's generating capacity is composed of 53 coal, hydro and combustion turbine units ranging in size from a 2.5 MW hydro unit to a 78 MW coal-fired unit. Pursuant to certain agreements with Power Agency, which is comprised of former North Carolina municipal wholesale customers of the Company and Virginia Electric and Power Company (Virginia Power), 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 (collectively, the Joint Facilities). Of the total system installed generating capability of 9,613 MW (including Power Agency's share), 55% is coal, 32% is nuclear, 2% is hydro and 11% is fired by other fuels including No. 2 oil, natural gas and propane.
MAJOR INSTALLED GENERATING FACILITIES
Year Maximum Plant Unit Commercial Primary Dependable Location No. Operation Fuel Capacity ________ ____ __________ _______ __________
Asheville 1 1964 Coal 198 MW (Skyland, N.C.) 2 1971 Coal 194 MW
Cape Fear 5 1956 Coal 143 MW (Moncure, N.C.) 6 1958 Coal 173 MW
H. F. Lee 1 1952 Coal 79 MW (Goldsboro, N.C.) 2 1951 Coal 76 MW 3 1962 Coal 252 MW
H. B. Robinson 1 1960 Coal 174 MW (Hartsville, S.C.) 2 1971 Nuclear 683 MW
Roxboro 1 1966 Coal 385 MW (Roxboro, N.C.) 2 1968 Coal 670 MW 3 1973 Coal 707 MW 4 1980 Coal 700 MW*
L. V. Sutton 1 1954 Coal 97 MW (Wilmington, N.C.) 2 1955 Coal 106 MW 3 1972 Coal 410 MW
Brunswick 1 1977 Nuclear 767 MW* (Southport, N.C.) 2 1975 Nuclear 754 MW*
Mayo 1 1983 Coal 745 MW* (Roxboro, N.C.)
Harris 1 1987 Nuclear 860 MW* (New Hill, N.C.) ____________
*Facilities are jointly owned by the Company and Power Agency, and the capacity shown includes Power Agency's share.
2. MAINTENANCE OF PROPERTIES. The Company maintains all of its properties in good operating condition in accordance with sound management practices. The average life expectancy for 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 1993. Over the next ten years, system sales growth is forecasted to average 2.3% per year and annual growth in system peak demand is projected to average 2.3%. The Company's generation additions schedule reflects no additions until 1996, when three new combustion turbine generating units are currently scheduled to commence commercial operation. These units, having a total generating capacity of approximately 225 MW, will be located at the Company's Darlington County Electric Plant near Hartsville, South Carolina and are expected to cost an aggregate of approximately $93 million. The generation additions schedule, which is updated annually, also includes generation additions of 3,600 MW in combustion turbine generating units to be added over the period 1997 to 2007 at undesignated sites and a 500 MW baseload coal unit in 2008 at an undesignated site.
4. RELICENSING OF HYDROELECTRIC PLANT. In 1973, the Company filed an application with the Federal Power Commission, now the Federal Energy Regulatory Commission (FERC), for a new long-term license for its 105 MW Walters Hydroelectric Plant (Project No. 432-004). North Carolina Electric Membership Corporation (NCEMC), doing business as Carolina Electric Cooperatives, filed a competing application in August 1974 (Project No. 2748-000). Since the initial license expired in 1976, the Company has continued to operate the Walters Hydroelectric Plant under an annual license issued by the FERC. Loss of the license would result in significant additional costs to the Company; however, the financial impact would be dependent on future ratemaking treatment. The FERC issued orders staying the relicensing proceedings until February 1990. Thereafter, the FERC set the matter for hearing, and the North Carolina Department of Environment, Health and Natural Resources and the Tennessee Wildlife Resources Agency intervened in this proceeding. A two- phase evidentiary hearing was concluded in October 1991, but the FERC has not yet rendered its decision. On September 17, 1993, the Company and NCEMC filed a settlement agreement (Settlement Agreement) with the FERC. Under the terms of the Settlement Agreement, NCEMC will withdraw its competing request for a license for the Walters Hydroelectric Plant. The Settlement Agreement also resolves, as between the parties, issues related to NCEMC's objections to the Company's purchase power contract with Duke Power Company (Duke) and NCEMC's interest in transferring base load capacity from its ownership in Duke's Catawba Nuclear Station (Docket Nos. ER 89-106-000, EL 91-55-000 and ER 92-199-000). See ITEM 1, "Interconnections with Other Systems," paragraph 3.a. for further discussion of the purchase power contract. Also on September 17, 1993, the parties filed with the FERC a Power Coordination Agreement (PCA) and an Interchange Agreement (IA), both dated August 27, 1993. The PCA and IA set forth explicitly the future relationship between the parties and establish a framework under which they will operate. The PCA provides NCEMC the option to gradually assume responsibility for a portion of its load, subject to agreed upon limits, thereby enabling the Company to further enhance its planning for generation and transmission property. Additionally, the Company will sell electricity and provide necessary transmission and coordinating services to NCEMC subject to rates that will benefit the Company and its customers. On October 7, 1993, the FERC Staff filed comments partially opposing the settlement on technical grounds, but recommending that it be certified to the FERC. The Company filed its response to those comments with the FERC on October 18, 1993. On October 26, 1993, the Administrative Law Judge (ALJ) certified the case to the FERC for its decision. In his certification the ALJ noted that the settlement is a good one and will greatly benefit the people of North Carolina. On February 28, 1994, the Company and NCEMC agreed to extend the time for obtaining FERC approval of the PCA and the IA from February 28, 1994 to April 29, 1994. Another settlement agreement regarding various environmental issues has been signed by all the parties and was filed with the FERC for approval on February 16, 1994. On March 8, 1994, the FERC Staff filed comments supporting this settlement agreement. Approval of the settlement agreements and issuance of the license by the FERC will conclude this matter. The Company cannot predict the outcome of these matters.
INTERCONNECTIONS WITH OTHER SYSTEMS ___________________________________
1. INTERCONNECTIONS. The Company's facilities in Asheville and vicinity are integrated into the total system through the facilities of Duke via interconnection agreements that permit transfer of power to and from the Asheville area. The Company also has major interconnections with the Tennessee Valley Authority (TVA), Appalachian Power Company (APCO), Virginia Power, South Carolina Electric and Gas Company (SCE&G), South Carolina Public Service Authority (SCPSA) and Yadkin, Inc. (Yadkin). Major interconnections include 115 kV and 230 kV ties with SCE&G and SCPSA; 115 kV, 230 kV and 500 kV ties with Duke and Virginia Power; a 115 kV tie with Yadkin; a 161 kV tie with TVA; and three 138 kV ties and one 230 kV tie with APCO. See paragraph 3.b. below.
2. INTERCHANGE AGREEMENTS.
a. The Company has interchange agreements with APCO, Duke, SCE&G, SCPSA, TVA, Virginia Power and Yadkin which provide for the purchase and sale of power for hourly, daily, weekly, monthly or longer periods. Purchases and sales under these agreements may be made due to changes in the in-service dates of new generating units, outages at existing units, economic considerations or for other reasons.
b. The Virginia-Carolinas Subregion of the Southeastern Electric Reliability Council is made up of the Company, Duke, Nantahala Power & Light Company, SCE&G, SCPSA and Virginia Power, plus the Southeastern Power Administration and Yadkin. Electric service reliability is promoted by contractual arrangements among the members of electric reliability organizations at the area, regional and national levels, including the Southeastern Electric Reliability Council and the North American Electric Reliability Council.
3. PURCHASE POWER CONTRACTS.
a. In March 1987, the Company entered into a purchase power contract with Duke, whereby Duke would provide 400 MW of firm capacity to the Company's system over the period January 1, 1992, through December 31, 1997. The contract was filed with the FERC in December 1988 (Docket No. ER89-106). NCEMC, Power Agency, Nucor Steel, the South Carolina Consumer Advocate and others moved to intervene in the proceeding, objecting to various aspects of the contract. A hearing was held in January 1990, but the FERC has not yet rendered its decision. Pursuant to an amendment of the contract, commencement of the purchase of power by the Company was delayed until July 1993 and termination was extended through June 1999. This amendment was filed with the FERC and accepted for filing, subject to refund, pursuant to an Order dated January 21, 1992. The docket was consolidated with Docket No. ER89-106 and a settlement agreement resolving issues related to the purchase power contract and other matters was filed with the FERC for approval on September 17, 1993. See ITEM 1, "Generating Capability," paragraph 4 for further discussion of the settlement agreement and other agreements between the Company and NCEMC. Pending the FERC's approval of the settlement, the Company began purchasing 400 MW of generating capacity from Duke in July 1993. The estimated minimum annual payment for power under the six-year agreement is $43 million, which represents capital-related capacity costs. Other costs associated with the agreement include fuel, energy-related operation and maintenance expenses and transmission use charges. The Company cannot predict the outcome of this matter.
b. The Company has entered into an agreement, which has been approved by the FERC, with APCO and Indiana Michigan Power Company (Indiana Michigan), operating subsidiaries of American Electric Power Company, to upgrade a transmission interconnection with APCO in the Company's western service area, establish a new interconnection in the Company's eastern service area, and purchase 250 MW of generating capacity from Indiana Michigan's Rockport Unit No. 2. The transmission interconnection upgrade in the Company's western service area was completed in 1992. The purchase of generating capacity began on January 1, 1990, and will continue for a period of 20 years. The estimated minimum annual payment for power purchased under the terms of the agreement is approximately $30 million, which represents capital-related capacity costs. Other costs associated with the agreement include demand-related production expenses, fuel, energy-related operation and maintenance expenses and transmission use charges.
4. FAYETTEVILLE. The Company has an agreement with the City of Fayetteville's Public Works Commission (City) to exchange capacity and energy. The City has a 70 MW heat recovery unit and eight 27.5 MW dual fuel (gas or oil) fired combustion turbine units. The heat recovery unit and five of the combustion turbine units are being used by the City to satisfy energy requirements during periods of peak demand. The agreement makes provisions for the purchase and sale of capacity and/or energy for economic and reliability reasons to the mutual benefit of both parties. On March 10, 1994, the City and the Company entered into a new ten-year agreement under which the Company will continue to be the City's wholesale supplier of electricity. See ITEM 1, "Wholesale Rate Matters," paragraph 3.c. for further discussion of the new agreement.
COMPETITION AND FRANCHISES __________________________
1. COMPETITION.
a. Generally, in municipalities and other areas where the Company provides retail electric service, no other utility directly renders such service. In recent years, however, customers interested in building their own generation facilities, competition from unregulated energy suppliers and changing government regulations have fostered the development of alternative sources of electricity for certain of the Company's wholesale and industrial customers. The Public Utility Regulatory Policies Act (PURPA) has facilitated the entry of non-utility companies into the electric generation business. Under PURPA, non-utility companies are allowed to construct "qualifying facilities" for the production of electricity in connection with industrial steam supplies and, under certain circumstances, to compel a utility to purchase the electricity generated at prices reflecting the utility's avoided cost as set by state regulatory bodies. Over the near term, the purchase of power from qualifying facilities has increased the Company's total cost of generation.
b. In 1992, the Energy Policy Act of 1992 (Energy Act) was signed into law. The Energy Act addresses a wide range of energy issues, including several matters affecting bulk power competition in the electric utility industry. It creates exemptions from regulation under the Public Utility Holding Company Act of 1935 for persons or corporations that own and/or operate in the United States certain generating and interconnecting transmission facilities dedicated exclusively to wholesale sales, thereby encouraging the participation of utility affiliates, independent power producers and other non-utility participants in the development of wholesale power generation. In addition, the Energy Act confers expanded authority upon the FERC to issue orders requiring public utilities, such as the Company, to transmit power and energy to or for wholesale purchasers and sellers, and to require public utilities to enlarge or construct additional transmission capacity to provide these services. The Energy Act also requires or facilitates numerous initiatives to increase energy efficiency at federal and other facilities. Implementation of portions of this legislation through rulemaking is in progress at the FERC. The Company is unable to predict the ultimate impact the Energy Act will have on its operations. When fully implemented, the Energy Act could impact the Company's load forecasts and plans for power supply to the extent additional generation is facilitated by the Energy Act, current wholesale customers elect to purchase from other suppliers, or new opportunities are created for the Company to expand its wholesale load.
The possible migration of some of the Company's load has created greater planning uncertainty and risks for the Company. The Company has been addressing these risks by negotiating long-term contracts with its customers, which allow the Company flexibility in managing its load and efficiently planning its future resource requirements. In this regard, in 1993 the Company signed a significant long-term agreement with NCEMC, which represents 17 of the Company's wholesale customers, and restructured its agreement with Power Agency. Also in 1993, the Company signed power supply agreements with the City of Camden, South Carolina and French Broad Electric Membership Corporation. In 1994, the City of Fayetteville's Public Works Commission entered into a new contract with the Company. In the industrial sector, the Company continues its efforts on a number of programs designed to retain and expand existing load and to attract new business to its service territory.
2. FRANCHISES. The Company is a regulated public utility and holds franchises to the extent necessary to operate in the municipalities and other areas it serves.
CONSTRUCTION PROGRAM ____________________
1. CAPITAL REQUIREMENTS. During 1993 the Company expended approximately $613 million for capital requirements. The Company revised its capital program in 1993 as part of its annual business planning process. Capital requirements, including anticipated construction expenditures for plant modifications, for the years 1994 through 1996 are set forth below. These estimates include Clean Air Act compliance expenditures of approximately $79 million, and generating facility addition expenditures of approximately $248 million. See ITEM 1, "Environmental Matters," paragraph 2 for further discussion of the impact of the Clean Air Act on the Company.
Estimated Capital Requirements ______________________________ (In Millions)
1994 1995 1996 TOTAL ____ ____ ____ _____
Construction Expenditures $386 $476 $540 $1,402 Nuclear Fuel Expenditures 25 79 94 198 AFUDC (18) (29) (40) (87) ____ ____ ____ ______ Net expenditures (a) 393 526 594 1,513 Long-Term Debt Maturities 50 275 55 380 ____ ____ ____ ______ TOTAL $443 $801 $649 $1,893 ==== ==== ==== ======
_______________
(a) Reflects reductions of approximately $25 million, $25 million and $27 million for 1994, 1995 and 1996, respectively, in net capital requirements resulting from Power Agency's projected payment of its ownership share of capital expenditures related to the Joint Facilities.
FINANCING PROGRAM _________________
1. CAPITAL REQUIREMENTS. Based on the Company's most recent estimate of capital requirements, the Company does not expect to have external funding requirements in 1994 or 1996 due to the low level of long-term debt maturities in those years. External funding requirements, which do not include early redemptions of long-term debt or redemptions of preferred stock, are expected to approximate $300 million in 1995. These funds will be required for construction, long-term debt maturities and general corporate purposes, including the repayment of short-term debt. The Company may from time to time sell additional securities beyond the amount needed to meet capital requirements to allow for the early redemption of outstanding issues of long-term debt, the redemption of preferred stock, the reduction of short-term debt or for other corporate purposes. The amounts and timing of the sales of securities will depend upon market conditions and the specific needs of the Company. See ITEM 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," for further analysis and discussion of the Company's financing plans and capital resources and liquidity.
2. SEC FILINGS.
a. The Company has on file with the Securities and Exchange Commission (SEC) a shelf registration statement (File No. 33-50597), enabling the Company to issue an aggregate of $600 million principal amount of First Mortgage Bonds, $450 million of which remain available for issuance. Additionally, the Company has entered into a distribution agreement with respect to the possible future sale of an aggregate amount of $200 million principal amount of First Mortgage Bonds, designated as Secured Medium-Term Notes, Series C, $110 million of which remain available for issuance.
b. The Company has on file with the SEC a shelf registration statement (File No. 33-5134) enabling the Company to issue up to $180 million of Serial Preferred Stock.
3. FINANCINGS. External financings during 1993 and early 1994 included:
- The issuance on February 17, 1993, of $150 million principal amount of First Mortgage Bonds, 6 1/8% Series due February 1, 2000, for net proceeds of approximately $147.8 million.
- The issuance on March 3, 1993, of $150 million principal amount of First Mortgage Bonds, 7 1/2% Series due March 1, 2023, for net proceeds of approximately $147.4 million.
- The issuance on July 7, 1993, of $100 million principal amount of First Mortgage Bonds, 5 3/8% Series due July 1, 1998, for net proceeds of approximately $99.1 million.
- The issuance on August 26, 1993, of $100 million principal amount of First Mortgage Bonds, 6 7/8% Series due August 15, 2023, for net proceeds of approximately $98.2 million.
- During the period from September through December 1993, the Company issued an aggregate of $90 million principal amount of First Mortgage Bonds, Secured Medium-Term Notes, Series C, with interest rates ranging from 4.85% to 5.06% and maturity dates ranging from 1996 to 1998. Net proceeds from the issuances of these First Mortgage Bonds aggregated $89.4 million.
- The issuance on January 19, 1994, of $150 million principal amount of First Mortgage Bonds, 5 7/8% Series due January 15, 2004, for net proceeds of approximately $148 million.
The proceeds from the issuances listed above were used to reduce the outstanding balance of commercial paper and other short-term debt, to redeem outstanding long-term debt and for other general corporate purposes.
4. REDEMPTIONS/RETIREMENTS. Redemptions and retirements during 1993 included:
- The redemption on March 25, 1993, of $82.549 million principal amount of First Mortgage Bonds, 8 1/2% Series due October 1, 2007, at 100.26% of the principal amount of such bonds plus accrued interest to the date of redemption.
- The redemption on April 1, 1993, of $70 million aggregate principal amount of First Mortgage Bonds, 7 3/4% Series due October 1, 2001, at 102.30% of the principal amount of such bonds plus accrued interest to the date of redemption.
- The purchase and cancellation on April 14, 1993, of $1.8 million aggregate principal amount of The Wake County Industrial Facilities and Pollution Control Financing Authority Pollution Control Revenue Bonds (Carolina Power & Light Company Project) Series 1987 due March 1, 2017, at 100.00% of the principal amount of such bonds plus accrued interest to the date of purchase, pursuant to provisions of the related trust indenture.
- The redemption on April 16, 1993, of $100 million aggregate principal amount of First Mortgage Bonds, 8 7/8% Series due March 1, 2016, at 105.77% of the principal amount of such bonds plus accrued interest to the date of redemption.
- The retirement on June 22, 1993, of $25 million aggregate principal amount of First Mortgage Bonds, 8.75% Secured Medium-Term Notes, Series A, which matured on that date.
- The redemption on August 18, 1993, of $100 million principal amount of First Mortgage Bonds, 8 1/2% Series due January 1, 2017, at 104.64% of the principal amount of such bonds plus accrued interest to the date of redemption.
- The retirement on September 1, 1993, of $100 million principal amount of First Mortgage Bonds, 9% Series, which matured on that date.
- The redemption on September 16, 1993, of $30 million principal amount of First Mortgage Bonds, 4 1/2% Series due July 1, 1994, at 100% of the principal amount of such bonds plus accrued interest to the date of redemption.
- The redemption on October 1, 1993, of $65 million principal amount of First Mortgage Bonds, 7 3/8% Series due January 1, 2001, at 101.91% of the principal amount of such bonds plus accrued interest to the date of redemption.
- The redemption on October 1, 1993, of $100 million principal amount of First Mortgage Bonds, 7 3/4% Series due May 1, 2002, at 102.21% of the principal amount of such bonds plus accrued interest to the date of redemption.
- The retirement on November 15, 1993, of $100 million principal amount of First Mortgage Bonds, 8 1/8 % Series, which matured on that date.
5. CREDIT FACILITIES. The Company's credit facilities presently total $208.1 million, consisting of a $115 million Revolving Credit Agreement with nine domestic money centers and major regional banks, a $70 million long-term Revolving Credit Agreement with eight foreign banks and a Revolving Credit Agreement of $23.1 million with fifteen regional banks.
RETAIL RATE MATTERS ___________________
1. GENERAL. The Company is subject to regulation in North Carolina by the North Carolina Utilities Commission (NCUC) and in South Carolina by the South Carolina Public Service Commission (SCPSC) with respect to, among other things, rates for electric energy sold at retail, retail service territory and issuances of securities.
2. CURRENT RETAIL RATES. The rates of return granted to the Company in its most recent general rate cases are as follows:
1988 North Carolina Utilities Commission Order (test year ended March 31, 1987) ______________________________________________
Capital Weighted Weighted Capital Structure Ratio Cost Rate Cost _________________ _______ _________ ________
Long-Term Debt 48.57% 8.62% 4.19% Preferred Stock 7.43 8.75 .65 Common Equity 44.00 12.75 5.61 _____
Rate of Return 10.45% =====
1988 South Carolina Public Service Commission Order (test year ended September 30, 1987) ___________________________________________________
Capital Weighted Weighted Capital Structure Ratio Cost Rate Cost _________________ _______ _________ ________
Long-Term Debt 47.82% 8.62% 4.12% Preferred Stock 7.46 8.75 .65 Common Equity 44.72 12.75 5.71 _____
Rate of Return 10.48% =====
3. INTEGRATED RESOURCE PLANNING. Integrated Resource Planning is a process that systematically compares all reasonably available resources, both demand-side and supply-side, in order to develop that mix of resources that allows a utility to meet customer demand in a most cost effective manner, giving due regard to system reliability and safety. The Company is required to file its IRP with the NCUC and the SCPSC once every three years. The Company filed its 1992 Integrated Resource Plan (IRP) with the NCUC on April 24, 1992, and by order dated June 29, 1993, the NCUC approved the Company's 1992 IRP. The Company filed its 1992 IRP with the SCPSC on April 30, 1992, and by order dated April 8, 1993, the SCPSC found that the Company's 1992 IRP complied with the SCPSC's integrated resource planning rules. 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.
4. DEMAND SIDE MANAGEMENT. The Company's Demand Side Management (DSM) programs are an integral part of its IRP. The Company offers a variety of conservation, load management, and strategic sales programs to its residential, commercial and industrial customers. The objectives of the DSM programs are to improve system operating efficiencies, meet customer needs in a growing service area, defer the need for future generating units and delay the need for future rate increases. Currently, the Company offers time-of-use rates to all its retail customers, low interest loans to its residential customers for the installation of additional insulation and high efficiency heat pumps in existing homes, financial incentives and an energy conservation discount for all-electric homes that meet enhanced thermal integrity and appliance efficiency standards, financial incentives for Company control of residential water heaters and air conditioners in most of the major metropolitan areas served by the Company, incentives for the curtailment of large industrial loads, and energy audits for large commercial and industrial customers, as well as many other programs. Additional programs are in various stages of investigation and development. The Company had achieved a summer peak load reduction capability of 1,559 MW as of December 31, 1993, through its conservation and load management programs. The Company also has rates available for the purchase of power from cogeneration and small power production facilities, as well as standby service rates for customers using their own generation equipment. At the end of 1993, the Company had 43 cogenerators and small power producers on-line with facilities capable of generating a total of approximately 471 MW, of which 283 MW is used internally by customers and 188 MW is sold to the Company.
In addition to this cogeneration and small power production, which is associated with the Company's Conservation and Load Management Programs, other cogeneration projects have been installed and used as planned generation resources. This additional capacity includes approximately 266 MW that was fully operational at the end of 1993. The Company has a Hydroelectric Generation Program designed to provide technical assistance to entrepreneurs who are reactivating abandoned hydroelectric generating sites in the Company's service territory. Presently, Hydroelectric Generation Program capability on the Company's system totals approximately 15 MW. Other proposals for generation are received and evaluated by the Company from time to time. See ITEM 1, "Competition and Franchises."
5. FUEL COST RECOVERY. In the North Carolina retail jurisdiction, the NCUC establishes base fuel costs in general rate cases and holds hearings annually to determine whether a rider should be added to base fuel rates to reflect increases or decreases in the cost of fuel and the fuel cost component of purchased power as well as changes in the fuel cost component of sales to other utilities. The NCUC considers the changes in the Company's cost of fuel during a historic test period ending March 31 of each year and corrects any past over-or under-recovery. The Company's 1994 North Carolina fuel case hearing is scheduled to begin on August 2, 1994. In the South Carolina retail jurisdiction, fuel rates are set by the SCPSC based on projected costs for a future six-month test period. At the semi-annual hearings, any past over-or under-recovery of fuel costs is taken into account in establishing the new projected rate for the subsequent six-month billing period. The Company's spring 1994 South Carolina fuel case hearing was scheduled to begin on March 15, 1994; however, on February 1, 1994, the SCPSC approved a settlement agreement that resolved all issues between all parties to the spring fuel proceeding. Pursuant to the settlement, the Company's current fuel factor of 1.425 cents/kWh will continue in effect for the six month period April 1 through September 30, 1994. Issues related to outages at Brunswick Unit No. 1 and the Robinson Nuclear Plant during the period July 1, 1993 through June 30, 1994 will be considered in the fall 1994 South Carolina fuel case hearing. See ITEM 1, "Nuclear Matters," paragraph 7.d., for considerations by the NCUC and the SCPSC regarding costs related to the Brunswick Plant outage, and for a discussion of the settlement agreements, reached in 1993, that resolved issues related to a period of the Brunswick Unit No. 1 outage, and settled the annual North Carolina and semi-annual South Carolina fuel adjustment proceedings.
On December 14, 1992, the South Carolina Supreme Court rendered its decision in Nucor Steel's (Nucor) appeal (Opinion No. 23761) of the SCPSC's decision in the Company's fall 1990 South Carolina fuel case. In that fuel case the SCPSC considered the three week operator training outage experienced by the Brunswick Nuclear Plant in the spring of 1990, and also considered a refueling outage experienced by Brunswick Unit No. 2 during the test period. The South Carolina Supreme Court affirmed in part and reversed in part the SCPSC's decision. As a result of the court's decision, approximately $422,000 must be refunded to the Company's customers. As part of the settlement of the spring 1994 South Carolina fuel case, the Company agreed to reduce its fuel cost under-recovery account by this amount.
Nucor's appeal of the Company's fall 1990 South Carolina fuel case also challenged the SCPSC's decision to exclude certain testimony offered by Nucor regarding a partial outage experienced by the Company's Robinson Unit No. 2 during the spring and summer of 1990. When this issue was presented to the Court of Common Pleas of Richland County, South Carolina, the court found that the SCPSC should have considered Nucor's testimony, and remanded the matter to the SCPSC. The SCPSC considered the testimony, but found it unpersuasive and reaffirmed its earlier orders on this issue. On September 8, 1993, Nucor appealed the SCPSC's decision to reaffirm its earlier orders to the Court of Common Pleas of Richland County, South Carolina. The Company cannot predict the outcome of this matter.
6. IMPACT OF ENERGY ACT. Section 111 of the Energy Act requires all state commissions to consider whether the adoption of certain standards would further the purposes of the PURPA. These standards relate to the use of integrated resource planning by electric utilities, investments in conservation and demand side management, and energy efficiency investments in power generation and supply. Both the NCUC and the SCPSC have opened dockets to consider these standards. With regard to the NCUC proceeding, direct testimony was filed by the Company on February 8, 1994. A hearing was held on March 8, 1994, but the NCUC has not yet issued its ruling. With regard to the SCPSC proceeding, the Company filed initial written comments on March 1, 1994, and reply comments are due on April 15, 1994. The SCPSC will issue its decision based upon the written comments. The Company cannot predict the outcome of these matters.
WHOLESALE RATE MATTERS ______________________
1. GENERAL. The Company is subject to regulation by the FERC with respect to rates for transmission and sale of electric energy at wholesale, the interconnection of facilities in interstate commerce (other than interconnections for use in the event of certain emergency situations), the licensing and operation of hydroelectric projects and, to the extent the FERC determines, accounting policies and practices. The Company and its wholesale customers last agreed to a general increase in wholesale rates in 1988.
2. FERC MATTERS.
a. On April 12, 1991, NCEMC and one of its members, Brunswick Electric Membership Corporation, filed a Complaint and Motion for a Refund (Complaint) with the FERC, Docket No. EL91-28-000, alleging that the Company's wholesale rates and fuel clause billings were excessive and requesting that the Company provide its real-time load signal to NCEMC. All of the Company's remaining wholesale customers intervened in this proceeding. On December 6, 1991, the FERC issued an order which denied the Company's request to dismiss this Complaint, set certain matters for hearing and initiated an investigation on behalf of the intervenors (Docket No. EL91-54-000) to determine if the Company's wholesale rates are excessive. On January 10, 1992, a FERC Administrative Law Judge ordered that NCEMC's case be severed from the FERC-initiated investigation so that the proceedings could continue independently of each other. With regard to the FERC-initiated investigation, on November 12, 1992, the FERC approved the settlement agreement that was filed by the Company and all of the intervenors. With regard to NCEMC's case, the Company has settled with NCEMC on all issues, and on September 15, 1993, the FERC approved the settlement agreement between the parties. The agreement provides for the continuation of existing wholesale rate levels and resolves the wholesale fuel clause billing issue through June 30, 1993. The impact of the settlement totaled approximately $8 million, net of tax, and decreased the Company's 1993 earnings by $.05 per common share. On January 11, 1994, the Company and the intervenor that remained a party to the proceeding initiated by NCEMC filed a settlement agreement with the FERC for approval. On January 31, 1994, the FERC staff filed comments partially opposing the settlement, but recommending that it be certified to the FERC. On February 10, 1994, the Company and the intervenor filed comments supporting the settlement, and rebutting the FERC staff's contrary position. The settlement was certified to the FERC on February 17, 1994. Although the Company cannot predict the outcome of this matter, it does not believe that amounts associated with the settlement will be material to the results of operations of the Company.
b. In 1989, Power Agency delivered to the Company a Notice of Intention to Arbitrate certain disputed matters related to Power Agency's use of capacity and energy from the South Carolina Public Service Authority (Santee Cooper), which matters Power Agency originally raised in a complaint before the FERC in 1988 (FERC Docket No. EL88-27-000). In June 1990, the arbitrator issued an order in favor of the Company on the most significant issues of contention between the Company and Power Agency. In addition, the arbitrator ordered the Company and Power Agency to meet for at least 120 days to negotiate a power coordination agreement relating to Power Agency's use of capacity and energy from Santee Cooper. On October 2, 1991, Power Agency filed a complaint at the FERC (Docket No. EL92-1-000) alleging that the Company had refused to agree to just and reasonable terms and conditions for power coordination agreements for Power Agency's purchase of firm capacity and energy from Santee Cooper for the period beginning January 1, 1994, and for Power Agency's use of a combustion turbine electric generating project it planned at that time to place in service on June 1, 1995. In 1993, Power Agency agreed to delay the commercial operation date of its turbine generating project for three years, until June 1, 1998. Power Agency's delay of the project was part of the agreement the Company and Power Agency entered into on April 7, 1993 to restructure portions of their contracts covering power supplies and jointly-owned interests in several of the Company's generating units. See ITEM 1, "Wholesale Rate Matters," paragraph 2.c. for further discussion of the April 7, 1993 agreement between the Company and Power Agency. On September 23, 1993, Power Agency and the Company entered into an agreement in principle that resolves all remaining issues relating to the Santee Cooper and turbine generator transactions. The parties continue to negotiate the details of a final settlement. Because the Santee Cooper transaction with Power Agency commenced on January 1, 1994, the Company and Power Agency have entered into an interim agreement covering the Santee Cooper transaction until a final agreement can be developed. The interim agreement between the parties was approved by the FERC on December 30, 1993. The Company cannot predict the outcome of these matters.
c. On April 7, 1993, the Company and Power Agency entered into an agreement to restructure portions of their contracts covering power supplies and jointly-owned interests in several of the Company's generating units. Under the terms of the agreement, the Company is increasing the amount of capacity and energy purchased from Power Agency's ownership interest in the Harris Plant. Additionally, the buyback period has been extended six years through 2007. Also, pursuant to the agreement, a portion of the Harris Plant will not be recoverable through sales of supplemental power to Power Agency. As a result, the Company recorded a write-off in 1993 of approximately $14.7 million, net of tax, or $.09 per common share. Pursuant to that agreement, Power Agency also agreed to the dismissal with prejudice of the Complaint it filed against the Company on July 14, 1988 in the Superior Court of Wake County, North Carolina (Docket No. 88 CVS 6512) alleging that the Company failed to disclose alleged design, management and other problems at the Harris Plant in connection with the sale of capacity to Power Agency. The agreement also provides that Power Agency will delay the commercial operation date of its combustion turbine generating project for three years, until June 1, 1998, and will withdraw the demand of its letter dated January 20, 1993 regarding the costs incurred at the Brunswick Plant during the outage that began in 1992. See ITEM 1, "Wholesale Rate Matters," paragraph 2.b. for further discussion of the agreement. The agreement was filed with the FERC on May 19, 1993 for approval of the provisions that are subject to the FERC's jurisdiction. The Company cannot predict the outcome of this matter.
3. OTHER WHOLESALE MATTERS.
a. By letter dated September 23, 1991, the City of Bennettsville, South Carolina (City) notified the Company that it was terminating service as a wholesale customer effective September 30, 1994, and that it intended to enter into a contract to purchase power at wholesale from Marlboro Electric Cooperative, Inc. On December 31, 1991, the Company filed a Declaratory Judgment Complaint in the Court of Common Pleas of Marlboro County, South Carolina (Docket No. 91-CP-34-316) seeking a determination as to the appropriate termination date and as to whether a cooperative can serve the City. On February 13, 1992, the Company filed a Motion for Summary Judgment in this proceeding. By order filed September 21, 1992, the Court of Common Pleas of Marlboro County, South Carolina denied the Company's Motion for Summary Judgment regarding the Marlboro Electric Cooperative, Inc.'s authority to serve the City and granted the Motions for Summary Judgment of Marlboro Electric Cooperative, Inc. and the City. On October 21, 1992, the Company filed a Notice of Appeal in the South Carolina Supreme Court. By order dated March 7, 1994, the South Carolina Supreme Court ruled that the City of Bennettsville can purchase power from Marlboro Electric Cooperative, Inc. beginning in 1995. The Company plans no further appeals. In 1993, the City's average peak load was approximately 16 MW.
b. In March 1990, the City of Camden, South Carolina (City) notified the Company that it would terminate its purchase of wholesale power from the Company as of March 31, 1993. The Company responded that the appropriate termination date was May 1, 1995. A petition filed with the FERC by the City relating to this issue was dismissed in July 1991. On December 3, 1991, the City filed a Declaratory Judgment Complaint in the Court of Common Pleas of Kershaw County, South Carolina (Docket No. 91-CP-28-613) seeking a determination as to the proper termination date. In 1992, Motions for Summary Judgment were filed by both parties in this action. On November 9, 1992, the Court granted the Company's Motion for Summary Judgment. The City filed a Notice of Appeal to the Supreme Court of South Carolina. In 1993, both parties filed briefs in the Supreme Court of South Carolina. On January 10, 1994, the parties filed with the FERC for approval a contract amendment that will extend their contractual relationship at least through 1998. By letter dated March 9, 1994, the FERC approved the contract amendment, effective March 11, 1994. Consequently, the parties will seek a dismissal of the State court litigation. In 1993, the City's average peak load was approximately 30 MW.
c. On March 10, 1994, the City of Fayetteville's Public Works Commission and the Company entered into a new power supply and coordination agreement under which the Company will continue to provide bulk power to the City. The agreement provides for the sale of a minimum of 140 to 160 MW of base load service and other services for a minimum of ten years, and at the parties' option, for up to fifteen years. The agreement also resolves all wholesale fuel clause billing issues between the City and the Company through December 31, 1993. The agreement will enable the Company to effectively and efficiently meet the growing needs of the City of Fayetteville for years to come. On March 16, 1994, the agreement was filed with the FERC for approval. The Company cannot predict the outcome of this matter.
ENVIRONMENTAL MATTERS _____________________
1. GENERAL. In the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes and other environmental matters, the Company is subject to regulation by various federal, state and local authorities. The Company considers itself to be in substantial compliance with those environmental regulations currently applicable to its business and operations and believes it has all necessary permits to conduct such operations. Except as noted below in paragraph 2, the Company does not currently anticipate that its potential capital expenditures for environmental pollution control purposes will be material. Environmental laws and regulations, however, are constantly evolving and the character, scope and ultimate costs for compliance with such evolving laws and regulations cannot now be accurately estimated. Costs associated with compliance with pollution control laws and regulations at the Company's existing facilities, which are expected to be incurred from 1994 through 1996, are included in the estimates of capital requirements under ITEM 1, "Construction Program."
2. CLEAN AIR LEGISLATION. The 1990 amendments to the Clean Air Act (Act) require substantial reductions in sulfur dioxide and nitrogen oxides emissions from fossil-fueled electric generating plants. The Company is not required to take action to comply with the Act's Phase I requirements, which must be met by January 1, 1995. Phase II of the Act, which contains more stringent provisions, will become effective January 1, 2000. To reduce sulfur dioxide emissions, as required by Phase II, the Company will modify equipment to allow certain of the Company's plants to burn lower sulfur coal, and is planning for the installation of scrubbers. Installation of additional equipment will also be necessary to reduce nitrogen oxides emissions. The Company anticipates that it will be able to delay the installation and operation of scrubbers until 2005 by purchasing sulfur dioxide emission allowances. Each sulfur dioxide emission allowance, issued by the Environmental Protection Agency (EPA), will allow a utility to emit one ton of sulfur dioxide. In 1993, the Company purchased emission allowances under the EPA's emission allowance trading program. The Company estimates that the total capital cost to comply with the requirements of Phase II of the Act may approximate $340 million during the period 1994 through 1999, and an additional $460 million during the period 2000 through 2005. These estimates, for installation or modification of equipment, are in nominal dollars (undiscounted future amounts expected to be expended). The required modifications and additions are expected to increase operating and maintenance costs by a total of $20 million for the period 1994 through 1999, $48 million for the period 2000 through 2004, and by $42 million annually, beginning in 2005. Actual plans for compliance with the Act's requirements have not been finalized, and the amount required for capital expenditures and for increased operating and maintenance expenditures cannot be determined with certainty at this time. The financial impact of the additional expenditures will be dependent on future ratemaking treatment. The NCUC and the SCPSC are currently allowing the Company to accrue carrying charges on its investment in emission allowances. A plan for compliance with Phase II of the Act must be submitted to the EPA by January 1, 1996. The Company cannot predict the outcome of this matter.
3. SUPERFUND. The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA and, indirectly, the states, to require generators and certain transporters of certain hazardous substances released from or at a site, and the owners and operators of such site, to clean up the site or reimburse the costs therefor. This statute has been interpreted to impose joint and several liability on responsible parties. There are presently several sites with respect to which the Company has been notified by the EPA or the State of North Carolina of its potential liability, as described below in greater detail.
a. On December 2, 1986, the EPA notified the Company of its potential liability pursuant to CERCLA for the investigation and cleanup activities associated with the Maxey Flats Nuclear Disposal Site in Fleming County, Kentucky. The EPA indicated that the site was operated from 1963 to 1977 under the management of Nuclear Engineering Company (now U. S. Ecology). The EPA estimated that the Company sent 304,459 cubic feet of waste to the disposal site. In response to the EPA's notice, the Company and several other potentially responsible parties (PRPs) formed a steering committee (the Maxey Flats Steering Committee) to undertake a remedial investigation/feasibility study pursuant to CERCLA. As a result of this study, the EPA has selected a remedial action which is currently estimated to have a present value cost of between $57 million and $78 million. Subsequent analysis of waste volume sent to the site performed by the Maxey Flats Steering Committee established that the Company contributed only approximately 1% of the total waste volume. It is expected that the Company's share of remediation costs will be based on the ratio of the Company's waste volume to that of other participating PRPs. The Company is currently ranked twenty-fourth on the waste-in list. On June 30, 1992, the EPA sent the Company, along with a number of other companies, agencies and organizations, a notice demanding reimbursement of response costs of approximately $5.8 million that have been incurred at the site and seeking to initiate formal negotiations regarding performance of the remedial design and remedial action for the site. On July 20, 1992, the Company responded that it would negotiate these matters through the Maxey Flats Steering Committee. In December 1992, the EPA rejected the offer the Maxey Flats Steering Committee filed regarding the performance of the remedial design and remedial action for this site. The Maxey Flats Steering Committee submitted amended offers to the EPA in 1993. The EPA has engaged in settlement negotiations with the Maxey Flats Steering Committee. Although the Company cannot predict the outcome of these matters, it does not anticipate that costs associated with this site will be material to the results of operations of the Company.
b. On December 2, 1986, the EPA notified the Company that it is a PRP with respect to the disposal, treatment or transportation for disposal or treatment of polychlorinated biphenyls (PCBs) at the Martha C. Rose Chemicals, Inc. (Rose) facility located in Holden, Missouri. Roughly 190,000 pounds of PCB wastes (approximately .8% of the total waste volume) are alleged to have been sent to the site by the Company. By volume, the Company ranks twenty-third on the waste-in list. Site stabilization was completed by Clean Sites, Inc., the third party hired to negotiate a cleanup between the waste generators and the EPA. By letter dated November 12, 1993, the EPA approved the final remediation design for the Rose site. Final site cleanup is expected to begin in 1994. There is currently over 90% participation by the PRPs in the site cleanup. It is estimated that cleanup will cost approximately $30 million. The Company has contributed approximately $293,000 to the waste generators' group and does not expect that it will be required to contribute additional funds to complete remediation of this site. Although the Company cannot predict the outcome of this matter, it does not anticipate that the costs associated with this site will be material to the results of operations of the Company.
c. In May 1989, the EPA notified the Company that it is a PRP with respect to the disposal of PCB transformers allegedly sent through Saline County Salvage to Elliot's Auto Parts Site in Benton, Arkansas. In its responses to the EPA, the Company stated its belief that no Company electrical equipment went to the site. Additionally, the Company declined to enter into an Administrative Order of Consent. In December 1992, the Elliot's Auto Parts PRP Committee requested that the Company pay a share of the estimated $2.65 million cost of cleaning up the site, and threatened to initiate litigation should the Company not contribute to the cleanup cost. The Company responded that it would be willing to participate in cleanup activities at the site if documentation was produced showing that the Company contributed any hazardous substances to the site. On January 21, 1993, the Elliot's Auto Parts PRP Committee produced documents alleging that the Company contributed hazardous substances to the site. Although the documentation provided does not clearly establish that the Company disposed of transformers at the Elliot's site, the Company is currently negotiating with the Elliot's Auto Parts PRP Committee to avoid protracted litigation. The Elliot's Auto Parts PRP Committee has completed remedial activities at the site at a cost of approximately $2.7 million and will soon submit a final report to the EPA. Although the Company cannot predict the outcome of this matter, it does not anticipate that costs associated with this site will be material to the results of operations of the Company.
d. By letter dated May 21, 1991, the EPA notified the Company that it is a PRP with respect to the disposal of hazardous substances at the Benton Salvage site in Benton, Arkansas. The Company has been unable to identify any records of shipments by the Company to that site. Until any such documentation can be produced, the Company does not intend to participate in cleanup activities at the site. The Company cannot predict the outcome of this matter.
e. On April 15, 1991, the North Carolina Department of Environment, Health, and Natural Resources (DEHNR) notified the Company that it is a PRP with respect to the disposal of hazardous waste at the Seaboard Chemical Corporation (Seaboard) site in Jamestown, North Carolina. DEHNR has indicated that it is offering PRPs the opportunity to perform voluntary site cleanup. Seaboard records indicate that there are over 1,300 PRPs for the site and that the Company's contribution to waste disposal is less than 1% of the total waste disposed. On May 29, 1992, the Company entered into an Administrative Order on Consent with DEHNR, Division of Solid Waste Management, to undertake and perform a Work Plan for Surface Removal (Removal Work Plan). On July 28, 1993, DEHNR determined that the Removal Work Plan had been substantially completed. DEHNR further recommended that the Seaboard Group (a group of PRPs with respect to the Seaboard site) undertake additional remedial activities at the Seaboard site. The Seaboard Group is currently considering its response to DEHNR's recommendation. The Company estimates that to date its costs associated with completion of the Removal Work Plan total approximately $12,000. Although the Company cannot predict the outcome of this matter, it does not anticipate that costs associated with this site will be material to the results of operations of the Company.
f. On January 9, 1992, the EPA sent notice to the Company, along with a number of other companies and persons, stating that the Company is a PRP with respect to the additional remediation of hazardous wastes at the Macon-Dockery site located near Cordova, North Carolina. The Company made arrangements in the past for the transportation and sale of waste and residual oil to C&M Oil Distributors, a company that operated an oil reprocessing facility at the Macon-Dockery site for a period of several months. However, the information available to the Company indicates that no hazardous wastes from Company facilities were sent to the site. Previously, in 1987, the EPA sent notice to the Company that the EPA believed the Company was a PRP with respect to costs incurred by the EPA for initial site cleanup of the Macon-Dockery site. The Company was also a third-party defendant in a lawsuit brought in federal district court to recover the cleanup costs incurred by the EPA. That lawsuit was subsequently settled. Unless the EPA produces evidence which establishes that hazardous wastes from Company facilities were sent to the site, the Company does not intend to participate in these new cleanup activities. The Company cannot predict the outcome of this matter.
4. OTHER ENVIRONMENTAL MATTERS.
a. On April 21, 1989, the North Carolina Division of Environmental Management (DEM) requested that the Company install a groundwater compliance monitoring system at the Company's Wilmington Oil Terminal located in New Hanover County, North Carolina. The request was prompted by the discovery of petroleum contamination beneath a neighboring oil transportation facility. DEM requested the installation of the monitoring system in order to determine if groundwater quality standards have been violated at the Wilmington Oil Terminal and if any such violations have contributed to the contamination underneath the neighboring facility. During the second half of 1989, six groundwater monitoring wells were installed and samples were collected and analyzed for the presence of petroleum hydrocarbons. Samples from one of the six wells indicated gasoline contamination and samples from a second well indicated No. 2 fuel oil contamination. The Company provided information on these monitoring wells to the DEM and in February 1993, DEM granted the Company permission to install a remediation system to collect and treat contaminated groundwater. This system conveys the groundwater to the neighboring facility for co-treatment of the contaminated water. Although the Company cannot predict the outcome of this matter, it believes that any remediation expense would not exceed $100,000 annually.
b. Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under various federal and state laws, and a contingent liability may exist for their remediation. The production of manufactured gas was commonplace from the late 1800s until the 1950s. The Company has learned of the existence of several manufactured gas plant (MGP) sites to which the Company and certain entities which were later merged into the Company may have had some connection. In 1992, the State of North Carolina, through DEHNR's Division of Solid Waste Management (DSWM), launched an initiative to encourage former owners and operators of MGP sites to voluntarily assess those sites and to undertake remedial action where necessary. In this regard, the Company is participating in the North Carolina MGP Group (Group), a group of entities alleged to be former owners or operators of MGP sites, that was formed in response to DSWM's initiative. In December 1993, the Group and DSWM entered into a Memorandum of Understanding relative to the establishment of a uniform program and framework for addressing MGP sites for which DSWM has contended that members of the Group have potential responsibility. It is anticipated that the investigation and remediation of specific MGP sites will be addressed pursuant to one or more Administrative Orders on Consent between DSWM and individual potentially responsible parties. Additionally, a current owner of one such site formerly owned by Tidewater Power Co., which merged into the Company in 1952, made an informal claim against the Company for the cost of investigation and possible remediation, if necessary, of hazardous materials at this site. The Company and the current owner have entered into an agreement to share the cost of investigation and remediation of the site. Due to the lack of information with respect to the operation of MGP sites and the uncertainty concerning questions of liability and potential environmental harm, the extent and cost of required remedial action, if any, and the extent to which liability may be asserted against the Company or against others are not currently determinable. The Company cannot predict the outcome of these matters or the extent to which other former MGP sites may become the subject of inquiry.
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 NRC, which has broad power to impose nuclear safety and security requirements. In the event of non-compliance, the NRC has the authority to impose fines, set license conditions, or shut down a nuclear unit, or some combination of these, depending upon its assessment of the severity of the situation, until compliance is achieved. The electric utility industry in general has experienced challenges in a number of areas relating to the operation of nuclear plants, including substantially increased capital outlays for modifications; the effects of inflation upon the cost of operations; increased costs related to compliance with changing regulatory requirements; renewed emphasis on achieving excellence in all phases of operations; unscheduled outages; outage durations; and uncertainties regarding storage facilities for spent nuclear fuel. See paragraph 7.c. 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 1994, 1995 and 1996 are expected to total approximately $108 million, $78 million and $55 million, respectively (including AFUDC).
2. SPENT FUEL AND OTHER HIGH-LEVEL RADIOACTIVE WASTE. The Nuclear Waste Policy Act of 1982 (Act) provides the framework for development by the federal government of interim storage and permanent disposal facilities for high-level radioactive waste materials. The Act promotes increased usage of interim storage of spent nuclear fuel at existing nuclear plants. The Company will continue to maximize the usage of spent fuel storage capability within its own facilities for as long as feasible. Pursuant to the Act, the Company, through a joint agreement with the U. S. Department of Energy (DOE) and the Electric Power Research Institute, has built a demonstration facility at the Robinson Plant that allows for the dry storage of 56 spent nuclear fuel assemblies. As of December 31, 1993, sufficient on-site spent nuclear fuel storage capability is available for the full-core discharge of Brunswick Unit No. 1 through 1994, Brunswick Unit No. 2 through 1996, and Robinson Unit No. 2 through 1998, assuming normal operating and refueling schedules. The Harris Plant spent fuel storage facilities, with certain modifications together with the spent fuel storage facilities at the Brunswick and Robinson Units, are sufficient to provide storage space for spent fuel generated on the Company's system through the expiration of the current operating licenses for all of the Company's nuclear generating units. Subsequent to the expiration of the licenses, as part of decommissioning of the units, dry storage may be necessary. 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, on April 27, 1989, the Company filed an application with the NRC for the issuance of a license to construct and operate an independent spent fuel storage facility for the dry storage of spent nuclear fuel at the Brunswick Plant. The Company cannot predict whether or not a license will ultimately be issued by the NRC.
As required by the Act, the Company entered into a contract with the DOE under which the DOE will dispose of the Company's spent nuclear fuel. The contract includes a provision requiring the Company to pay the DOE for disposal costs. Disposal costs of fuel burned are based upon actual nuclear generation and are paid on a quarterly basis. Effective January 31, 1992, the DOE revised the method for calculating the nuclear waste disposal cost which will reduce the Company's quarterly payment. Existing overpayments, with interest, will be refunded in the form of credits over the next two fiscal years. Disposal costs, excluding waste disposal credits, are approximately $20 million annually based on the expected level of operations and the present disposal fee per kWh of nuclear generation, and are currently recovered through the Company's fuel adjustment clauses. See ITEM 1, "Retail Rate Matters," paragraph 5. Disposal fees may be reviewed annually by the DOE and adjusted, if necessary. The Company cannot predict at this time whether the DOE will be able to perform its contract and provide interim storage or permanent disposal repositories for spent fuel and/or high-level radioactive waste materials on a timely basis.
3. LOW-LEVEL RADIOACTIVE WASTE. Disposal costs for low-level radioactive waste that results from normal operation of nuclear units have increased significantly in recent years and are expected to continue to rise. Pursuant to the Low-Level Radioactive Waste Policy Act of 1980, as amended in 1985, each state is responsible for disposal of low-level waste generated in that state. States that do not have existing sites may join in regional compacts. The States of North Carolina and South Carolina are participants in the Southeast regional compact and, currently, dispose of waste at an existing disposal site in South Carolina along with other members of the compact. 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, recently selected a preferred site in Wake County, North Carolina. Although the Company does not control the future availability of low-level waste disposal facilities, the cost of waste disposal or the development process, it is actively supporting the development of new facilities and is committed to a timely and cost-effective solution to low-level waste disposal. Should shipments to the existing regional compact site cease, present projections indicate that existing on-site storage facilities at the Company's nuclear plants are sufficient to provide approximately eight months of storage capacity. The Company cannot predict the outcome of this matter.
4. DECOMMISSIONING.
a. Pursuant to a 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 a 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 this regard, the Company entered into a Master Decommissioning Trust Agreement dated July 19, 1990 (Trust), with Wachovia Bank of North Carolina, N.A., as Trustee, as a vehicle to achieve such decommissioning funding. In June 1991, the Company began depositing amounts currently collected in rates into the Trust. At the currently approved jurisdictional funding levels, contributions to the Trust will be approximately $19 million on an annualized basis. Through December 31, 1993, the Company had collected through rates an aggregate of $221.6 million for decommissioning, which includes amounts funded internally and externally.
b. The Company is required to increase external funding to the NRC-prescribed minimum no later than January 1, 1996. This NRC-prescribed minimum exceeds amounts currently collected in rates. In future rate filings, the Company will request rate recovery based on site-specific estimates for prompt dismantlement decommissioning. The requested rate recovery will also include funding plans that assume external funding of, at least, the NRC-prescribed minimum. The financial impact on the Company will depend on future ratemaking treatment. The NCUC and SCPSC have allowed other utilities to recover costs based on site-specific estimates for prompt dismantlement decommissioning and funding plans similar to those the Company intends to use.
c. The Company's most recent site-specific estimates of decommissioning costs were developed in 1993, and are based on prompt dismantlement decommissioning, which reflects the cost of removal of all radioactive and other structures currently at the site. These estimates, in 1993 dollars, are as follows: $257.7 million for Robinson Unit No. 2; $284.3 million for the Harris Plant; $235.4 million for Brunswick Unit No. 1; and $221.4 million for Brunswick Unit No. 2. These estimates are subject to change based on a variety of factors, including, but not limited to, inflation, 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 certain of the Company's 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 ITEM 1, "Generating Capabilities," paragraph 1.
5. OPERATING LICENSES. Facility Operating Licenses, issued by the NRC, may be amended by the NRC to extend the expiration dates of an operating license of a nuclear facility to allow for up to 40 years of commercial operation. The current expiration dates for the Company's nuclear facilities allow for the entire 40 years of commercial operation and 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. DESIGN BASIS RECONSTITUTION EFFORTS. The Company has been in the process of reviewing the design basis documentation for Robinson Unit No. 2 since 1988 and for the Brunswick Plant since 1990. Significantly more design detail has been required by the NRC for recently constructed plants than was needed when Robinson Unit No. 2 and the Brunswick Plant were built. In order to operate effectively in the current regulatory environment, the Company must be able to provide documentary evidence of compliance with regulations and design documents. The design basis reconstitution effort involves research, compilation and verification of documents that set forth the key design requirements of the various safety systems. The Company's review of the design basis documentation for Robinson Unit No. 2 was completed in 1993, and the Brunswick Plant effort is still in progress. The baseline effort for the two Brunswick Units is scheduled for completion by the end of 1996, and is projected to have a total cost of approximately $40 million. The Company cannot predict the outcome of this matter.
7. OTHER NUCLEAR MATTERS.
a. Large diameter reactor recirculation system piping in boiling water reactor (BWR) units, such as the Brunswick Units, has the potential to crack as a result of intergranular stress corrosion (IGSCC) and the NRC required an ultrasonic inspection of such piping at BWR units. As a result of these inspections, certain portions of the large diameter reactor recirculation piping were replaced at both of the Brunswick Units. Subsequently, ultrasonic testing for IGSCC was performed on Brunswick Unit No. 1 during an outage in 1991 and identified a feedwater nozzle weld which required further study. The NRC authorized restart of Unit No. 1 and, based upon additional information provided by the Company, approved full-cycle operation of Unit No. 1. The feedwater nozzle in question is being evaluated for possible replacement as part of modifications scheduled for Brunswick during the next refueling outage.
b. In 1991, the NRC issued a final rule on nuclear plant maintenance that will become effective on July 10, 1996. In general terms, the new maintenance rule prescribes the establishment of performance criteria for each safety system based on the significance of that system. The rule also requires monitoring of safety system performance against the established acceptance criteria, and provides that remedial action be taken when performance falls below the established criteria. The Company has been working closely with the Nuclear Management and Resources Council and with other utilities to develop its compliance approach and to minimize the financial and operational impacts of the new rule. The Company anticipates its compliance will be on schedule and is evaluating the magnitude of the financial and operational impacts of this new rule. The Company cannot predict the outcome of this matter.
c. On November 23, 1988, the NRC requested in Generic Letter 88-20 that utilities perform Individual Plant Examinations (IPEs) to determine potential vulnerabilities to severe accidents beyond the design basis accidents for which the plants are designed. These are considered to be very low probability events. The Company submitted the results of the first phase (for internally initiated events) in August 1992 for the Brunswick and Robinson Plants. Potential enhancements for the Robinson Plant are currently being evaluated, and the Company cannot predict at this time the exact magnitude of financial and operational impacts which may result from these evaluations. For the Brunswick Plant, no modifications were required to meet the guidelines of the IPE. On August 20, 1993, the Company submitted the results of the Harris Plant IPE. While some Harris Plant procedural changes were made due to the IPE results, the IPE did not reveal any significant financial or operational impacts or identify any need for plant modifications. The Company cannot predict at this time the exact magnitude of the financial and operational impact of the second phase of the IPE (for externally initiated events) to be completed for all three plants during 1994-1995.
d. In April 1992, both units at the Company's Brunswick Plant were taken out of service in order for the Company to address anchor bolt deficiencies and related wall construction issues in the diesel generator building. During the outage, in addition to resolving the anchor bolt deficiencies and related diesel generator building wall construction issues, the Company conducted detailed inspections and engineering evaluations of the plant's miscellaneous steel, performed necessary corrective and preventive maintenance and made certain modifications.
An intensive on-site review of Brunswick Unit No. 2 was conducted by a NRC operational readiness assessment team from March 29 through April 9, 1993. The team concluded that the depth and capability of the Brunswick staff, the organizational structure and in-place programs were adequate to support Unit No. 2 restart and operation. On April 27, 1993, the NRC issued its determination that Unit No. 2 was ready for restart. The Company promptly began a detailed startup process at Unit No. 2 to ensure a safe, controlled and deliberate return to service. The Company returned Unit No. 2 to service in May 1993. In late December 1993, Unit No. 2 set a new continuous run record for that unit of more than 219 days.
In July 1993, cracks were discovered in the Brunswick Unit No. 1 reactor vessel shroud during inspections made as part of refueling activities performed during the outage. The Company conducted intensive ultrasonic testing and physical sampling inspections of the cracks. The results of this investigation provided data used to develop new stiffening braces to ensure that the shroud will continue to perform its design function. Shroud modifications were completed in late December 1993. Costs associated with the shroud repairs were not material to the results of operations of the Company. The Company commenced startup of Unit No. 1 on February 1, 1994 under a gradual power ascension startup plan. This power ascension plan was completed 27 days ahead of schedule when Unit No. 1 was returned to normal operation on February 23, 1994, after successfully completing extensive startup testing. Additional shroud inspections may be conducted during future refueling outages to identify and monitor other minor cracking in the shroud. The Company cannot predict the outcome of this matter.
In July 1993, the Company also determined that the Brunswick Unit No. 2 shroud has minor crack indications which do not compromise the safety or operation of the Unit. Shroud modifications, similar to those performed on Unit No. 1, will be undertaken on Unit No. 2 during the spring 1994 refueling outage. The Company does not expect that costs associated with the shroud modifications will be material to the results of operations of the Company.
On October 14, 1993, two private organizations, the National Whistleblower Center and the Coastal Alliance for a Safe Environment, and an individual filed a petition with the NRC under 10 C.F.R. Section 2.206 alleging that the Company was aware of the shroud cracks as early as 1984 and engaged in criminal activities to conceal its knowledge of the cracks. The petitioners requested that the NRC require the Company to state whether it knew about the cracks in 1984 and determine whether the Company has engaged in criminal wrongdoing. To date, the petitioners have failed to provide the Company with any evidence substantiating their claims. Additionally, the Company conducted an internal technical review of this matter which did not reveal any evidence that substantiates the petitioners' claims. The results of this technical review were submitted to the NRC in November 1993. Although the Company cannot predict the outcome of this matter, it believes the allegations contained in the petition are without merit.
In December 1993, the NRC issued its latest Systematic Assessment of Licensee Performance (SALP) report for the Brunswick Plant. The report rated Brunswick's plant operations and plant support as "superior," and the Plant's maintenance and engineering as "good." The NRC, in both the report and at a public meeting, recognized significant improvements made at the plant.
On July 28, 1993, the Company, the Public Staff, the Attorney General of the State of North Carolina, and Carolina Industrial Group for Fair Utility Rates II entered into an agreement that resolved as between them all issues related to the Brunswick Plant outage on or before the date of the agreement, avoided higher fuel charges to the Company's customers and settled the Company's 1993 North Carolina fuel adjustment proceeding. The Company had $31.2 million in fuel expenses for the twelve-month period ended March 31, 1993 that had not been recovered from North Carolina customers through the Company's rates. As a part of the agreement, the Company agreed to forgo recovering $25.5 million of these fuel expenses, and to recover the remaining $5.7 million through rates over a twelve-month period beginning in September 1993. That $5.7 million is subject to refund at the end of three years if the Brunswick Plant does not achieve a specified operating performance level. Additionally, the Company agreed that if the Brunswick Plant's performance for the three-year period ending March 31, 1996 does not achieve a specified operating performance level, the Company could lose up to $10 million in additional fuel expenses. By order dated September 14, 1993, the NCUC approved the agreement. The forgone fuel expense recovery of $25.5 million reduced the Company's 1993 earnings by approximately $.10 per common share.
On September 7, 1993, the Company, the Staff of the SCPSC, Nucor Steel, and the Consumer Advocate for the State of South Carolina, which represents the using and consuming public in matters before the SCPSC, entered into an agreement to settle the fall 1993 SCPSC fuel proceeding. The settlement resolved all issues related to fuel costs incurred by the Brunswick Plant through June 30, 1993, avoided higher fuel charges to the Company's customers and settled the fall 1993 semi-annual South Carolina fuel adjustment proceedings. The SCPSC approved the agreement by order dated September 14, 1993. Pursuant to the terms of the settlement, the Company agreed to forgo recovery of a total of $15.6 million in fuel expenses. The forgone fuel expense recovery of $15.6 million reduced the Company's 1993 earnings by approximately $.06 per common share.
The NRC, the NCUC and the SCPSC will continue to review the Company's activities at the Brunswick Plant. Except as noted, the Company cannot predict the extent to which these and other actions may impact its ability to recover costs associated with this outage.
e. On November 17, 1993, during startup from a scheduled refueling outage at the Company's H. B. Robinson Plant Unit No. 2, the Company discovered problems with the fuel supplier's fabrication of certain fuel assemblies which had been loaded during the outage. A problem relating to the calibration of the power level instrumentation was also identified. The Company elected to interrupt and delay the startup process pending analysis and correction of the problems, and notified the NRC of its decision. The NRC issued a Confirmatory Action Letter, dated November 19, 1993, in which it confirmed, among other things, that the Company would conduct detailed root cause analyses of the fuel assembly and power level instrumentation issues and would take appropriate corrective actions. On November 20, 1993, an NRC Augmented Inspection Team (AIT) began its investigation of the fuel assembly and power level instrumentation issues. In investigating the fuel assembly issue, the AIT visited both the Robinson Plant and the fuel supplier's facilities. Results of the AIT's investigation were initially released in a public meeting on December 6, 1993 and the AIT's report was issued on January 5, 1994. An enforcement conference was conducted on March 14, 1994 for the purpose of discussing apparent violations identified in the AIT's report in the areas of management control of refueling and restart activities. The NRC will determine whether or not to issue violations and what, if any, resulting penalty should be imposed upon the Company. The Company cannot predict the outcome of this matter.
In a separate action, on March 14, 1994, the NRC issued a Notice of Violation and Proposed Imposition of Civil Penalty in the amount of $37,500 relating to the degradation of both Robinson Unit No. 2 emergency diesel generators and failure to correct conditions which affected operation of one of the diesel generators in mid-November, 1993. The base civil penalty for this type of violation is $50,000, but the propsoed penalty was reduced to $37,500 due to the Company's comprehensive performance in analyzing the root cause of the diesel generator problem. The Company has thirty days from the date of the Notice to pay or protest the civil penalty, in whole or in part. The Company intends to pay the civil penalty. The Company cannot predict the outcome of this matter.
On February 8, 1994, the NRC issued its SALP report for Robinson Unit No. 2 for the period June 1992 through December 1993. While the NRC noted that overall performance of Robinson Unit No. 2 was reasonably good, it indicated that performance declined in several areas, primarily due to the matters discussed above. The NRC rated Robinson Unit No. 2's performance as "good" in operations, engineering and plant support and "acceptable" in maintenance.
In early February 1994, the Company satisfied the conditions of the NRC's confirmatory action letter, and returned Robinson Unit No. 2 to service on March 21, 1994 under a power ascension plan.
f. The Company is insured against public liability for a nuclear incident up to $9.4 billion per occurrence, which is the maximum limit on public liability claims pursuant to the Price-Anderson Act. The $9.4 billion coverage includes $200 million primary coverage and $9.2 billion secondary financial protection through assessments on nuclear reactor owners. In the event that public liability claims from an insured nuclear incident exceed $200 million, the Company would be subject to a pro rata assessment, for each reactor it owns, of up to $75.5 million, plus a 5% surcharge, for each incident. Payment of such assessment would be made over time as necessary to limit the payment in any one year to no more than $10 million per reactor owned. Power Agency would be responsible for its ownership share of the assessment on jointly-owned units.
FUEL ____
1. SOURCES OF GENERATION. Total system generation (including Power Agency's share) by primary energy source, along with purchased power, for the years 1990 through 1994 is set forth below:
1990 1991 1992 1993 1994 _______________________________________________ (estimated)
Fossil 47% 47% 56% 54% 47% Nuclear 41 41 27 31 40 Purchased Power 10 10 15 13 11 Hydro 2 2 2 2 2
2. COAL. The Company has intermediate and long-term agreements from which it expects to receive approximately 88% of its coal burn requirements in 1994. During 1992 and 1993, the Company obtained approximately 79% (8,185,000 tons) and 73% (7,198,000 tons), respectively, of its coal burn requirements from intermediate and long-term agreements. Over the next ten years, the Company expects to receive approximately 75% of its coal burn requirements from intermediate and long-term agreements. Existing agreements have expiration dates ranging from 1994 to 2006. During 1993, the Company maintained from 48 to 99 days' supply of coal, based on anticipated burn rate. All of the coal that the Company is currently purchasing under intermediate and long-term agreements is considered to be low sulfur coal by industry standards. Recent amendments to the Clean Air Act may result in increases in the price of low sulfur coal prior to the effective date of the first phase of the Act, with such impact to continue beyond the effective date of the second phase of the Act. See ITEM 1, "Environmental Matters," paragraph 2. The Company purchased approximately 2,250,000 tons of coal in the spot market during 1992 and 2,650,000 tons in 1993. No spot coal was purchased in 1991. The Company's contract coal purchase prices during 1993 ranged from approximately $23.19 to $39.38 per ton (F.O.B. mine). The average cost to the Company of coal delivered for the past five years is as follows:
Year $/Ton Cents/Million BTU ____ _____ _________________
1989 45.01 179 1990 45.88 183 1991 47.40 190 1992 43.25 174 1993 43.10 172
3. OIL. The Company uses No. 2 oil primarily for its combustion turbine units, which are used for emergency backup and peaking purposes. The Company burned approximately 8.4 million and 9.1 million gallons of No. 2 oil during 1992 and 1993, respectively. The Company has a No. 2 oil supply contract for its normal requirements. In the event base-load capacity is unavailable during periods of high demand, the Company may increase the use of its combustion turbine units, thereby increasing No. 2 oil consumption. The Company intends to meet any additional requirements for No. 2 oil through additional contract purchases or purchases in the spot market. There can be no assurance that adequate supplies of No. 2 oil will be available to meet the Company's requirements. To reduce the Company's vulnerability to dislocations in the oil market, seven combustion turbine units with a total generating capacity of 364 MW have been converted to burn either propane or No. 2 oil. In addition, twelve combustion turbine units with a total generating capacity of 425 MW can burn natural gas when available. Over the last five years, No. 2 oil, natural gas and propane accounted for 1.7% of the Company's total burned fuel cost. In 1993, No. 2 oil, natural gas and propane accounted for 1.5% of total burned fuel cost. The availability and cost of fuel oil could be adversely affected by energy legislation enacted by Congress, disruption of oil or gas supplies, labor unrest and the production, pricing and embargo policies of foreign countries.
4. NUCLEAR. The nuclear fuel cycle requires the mining and milling of uranium ore to provide uranium oxide concentrate (U3O8), the conversion of U3O8 to uranium hexafluoride (UF6), the enrichment of the UF6 and the fabrication of the enriched uranium into fuel assemblies. The Company has on hand or has contracted for raw materials and services for its nuclear units through the years shown below:
Raw Materials and Service _______________________________________________ Unit Uranium Conversion Enrichment Fabrication ____ _______ __________ __________ ___________
Robinson No. 2 1996 1995 1994 1999 Brunswick No. 1 1996 1995 1994 1998 Brunswick No. 2 1996 1995 1994 1998 Harris Plant 1996 1995 1994 1998
These contracts are expected to supply the necessary nuclear fuel to operate Robinson Unit No. 2 through 1995, Brunswick Unit No. 1 through 1995, Brunswick Unit No. 2 through 1996, and the Harris Plant through 1996. The Company expects to meet its U3O8 requirements through the years shown above from inventory on hand and amounts received under contract. Although the Company cannot predict the future availability of uranium and nuclear fuel services, the Company does not currently expect to have difficulty obtaining U3O8 and the services necessary for its conversion, enrichment and fabrication into nuclear fuel for years later than those shown above. For a discussion of the Company's plans with respect to spent fuel storage, see ITEM 1, "Nuclear Matters," paragraph 2.
5. DOE ENRICHMENT FACILITIES DECONTAMINATION AND DECOMMISSIONING FUND. Under Title XI of the Energy Policy Act of 1992, Public Law 102-486, Congress established a decontamination and decommissioning fund for the DOE's gaseous diffusion enrichment plants. Contributions to this fund will be made by U.S. domestic utilities who have purchased enrichment services from DOE since it began sales to non-Department of Defense customers. Each utility's share of the contributions will be based on that utility's past purchases of services as a percentage of all purchases of services by U.S. utilities, with total annual contributions capped at $150 million per year, indexed to inflation, and an overall cap of $2.25 billion over 15 years, also indexed to inflation. The Company made its first payment, totaling approximately $5.2 million, to the fund on September 30, 1993. At December 31, 1993, the Company had recorded a liability of $77.7 million representing its estimated share of the contributions and expects to recover these amounts as a component of fuel cost.
6. PURCHASED POWER. In 1993 the Company purchased 6,375,907 MWh or approximately 13% of its energy requirements and had available 1,649 MW of firm purchased capacity under contract at the time of peak load. The Company also had a 100 MW firm capacity commitment to SCE&G during the peak due to a limited-term sale agreement for the summers of 1993 and 1994. See ITEM 1, "Interconnections with Other Systems," paragraph 3. The Company may acquire purchased power capacity in the future to accommodate a portion of its system load needs.
OTHER MATTERS _____________
1. SAFETY INSPECTION REPORTS. On April 3, 1990, the FERC sent a letter to the Company providing comments on its review of the Company's Fifth (1987) Independent Consultant's Safety Inspection Report (required every five years under FERC Regulation 18 CFR Part 12) for the Walters Hydroelectric Project and requesting the Company to undertake certain supplemental analyses and investigations regarding the stability of the dam under extreme and improbable loading conditions. Similar letters were sent by the FERC on May 30, 1990, with respect to the Company's Blewett and Tillery Hydroelectric Plants. With the independent consultant, the Company has begun addressing the issues raised by the FERC and is working with the FERC to complete investigations and analyses with respect to each of these matters. While both the FERC and the Company do not believe that there are any stability concerns that would be cause for any imminent safety concerns, the outcome of the analyses and investigations is currently unknown. Depending on the outcome of the analyses and the FERC's interpretations, 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.
2. MARSHALL HYDROELECTRIC PROJECT. On November 21, 1991, the FERC notified the Company that the 5 MW Marshall Hydroelectric Project is no longer exempt from 18 CFR Part 12, Subparts 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" to a "high" hazard classification. In accordance with the change in regulatory jurisdiction, the Company developed an emergency action plan which meets FERC regulations and guidelines and engaged its independent consultant to perform a safety inspection. On April 6, 1992, the consultant's safety inspection report was submitted to the FERC for approval. Depending on the outcome of FERC's review of the safety inspection report, 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.
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ITEM 2.
ITEM 2. PROPERTIES _______ __________
In addition to the major generating facilities listed in ITEM 1, "Generating Capability," the Company also operates the following plants:
Plant Location _____ ________
1. Walters North Carolina 2. Marshall North Carolina 3. Tillery North Carolina 4. Blewett North Carolina 5. Darlington South Carolina 6. Weatherspoon North Carolina 7. Morehead City North Carolina
The Company's sixteen power plants represent a flexible mix of fossil, nuclear and hydroelectric resources, with a total generating capacity of 9,613 MW. The Company's strategic geographic location facilitates purchases and sales of power with many other electric utilities, allowing the Company to serve its customers more economically and reliably. Major industries in the Company's service area include textiles, chemicals, metals, paper, automotive components and electronic machinery and equipment.
At December 31, 1993, the Company had 5,830 pole miles of transmission lines including 292 miles of 500 kV and 2,789 miles of 230 kV lines, and distribution lines of approximately 38,560 pole miles of overhead lines and approximately 7,234 miles of underground lines. Distribution and transmission substations in service had a transformer capacity of approximately 34,794 kVA in 2,263 transformers. Distribution line transformers numbered 383,314 with an aggregate 15,264,600 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, subject to the lien of its Mortgage and Deed of Trust, with minor exceptions, restrictions and reservations in conveyances and defects, which are of the nature ordinarily found in properties of similar character and magnitude, to its principal plants and important units, except certain rights-of-way over private property on which are located transmission and distribution lines, title to which can be perfected by condemnation proceedings.
Plant Accounts (including nuclear fuel) - _______________________________________ During the period January 1, 1989 through December 31, 1993, there was added to the Company's utility plant accounts $1,827,147,000, there was retired $469,275,000 of property and there were transfers to other accounts and adjustments for a net decrease of $290,311,000 resulting in net additions during the period of $1,067,561,000 or an increase of approximately 12.6%.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS ______ _________________
Legal and regulatory proceedings are included in the discussion of the Company's business in ITEM 1 and incorporated by reference herein.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS _______ ___________________________________________________
No matters were submitted to a vote of security holders in the fourth quarter of 1993.
EXECUTIVE OFFICERS OF THE REGISTRANT
Name Age Recent Business Experience ____ ___ __________________________
Sherwood H. Smith, Jr. 59 Chairman and Chief Executive Officer, September 1992 to present; Chairman/President and Chief Executive Officer, May 1980 to September 1992. Member of the Board of Directors of the Company since 1971.
William Cavanaugh III 55 President and Chief Operating Officer, September 1992 to present; Group President - Energy Supply, Entergy Corporation, July 1992; Chairman, Chief Executive Officer and Director, System Energy Resources, Inc., April 1992; Chairman and Chief Executive Officer, Entergy Operations, Inc., April 1992; Senior Vice President, System Executive - Nuclear, Entergy Corporation and Entergy Services, Inc., 1987-August 1992; Executive Vice President and Chief Nuclear Officer, Arkansas Power & Light Company and Louisiana Power & Light Company, 1990-August 1992; President and Chief Executive Officer, System Energy Resources, Inc., 1986-April 1992; President and Chief Executive Officer, Entergy Operations, Inc., 1990-April 1992. Member of Board of Directors of Arkansas Power & Light Company and Louisiana Power & Light Company, 1990-August 1992; Member of Board of Directors of System Fuels, Inc., 1992-August 1992; Member of Board of Directors of System Energy Resources, Inc., 1986-August 1992; Member of Board of Directors of Entergy Operations, Inc., 1990-August 1992; Member of Board of Directors of Entergy Services, Inc., 1987-August 1992. Before joining the Company, Mr. Cavanaugh held various senior management and executive positions during a 23-year career with Entergy Corporation, an electric utility holding company with operations in Arkansas, Louisiana and Mississippi. Member of the Board of Directors of the Company since 1993.
Charles D. Barham, Jr. 63 Executive Vice President and Chief Financial Officer - Finance and Administration, November 1990 to present; Senior Vice President - Legal, Planning and Regulatory Group, July 1987; Senior Vice President and General Counsel - Legal and Regulatory Group, May 1982. Member of the Board of Directors of the Company since 1990.
Lynn W. Eury 57 Executive Vice President - Power Supply, April 1989 to present; Senior Vice President - Operations Support, June 1986; Senior Vice President - Fossil Generation and Power Transmission Group, August 1983.
William S. Orser 49 Executive Vice President - Nuclear Generation, April 1993 to present; Executive Vice President - Nuclear Generation, Detroit Edison Company, 1992-April 1993; Senior Vice President - Nuclear Generation, Detroit Edison Company, 1990-1992; Vice President - Nuclear Operations, Detroit Edison Company, 1988-1990. Prior to 1988, Mr. Orser held various other positions with Detroit Edison, and with Portland General Electric Company, Southern California Edison, and the U. S. Navy.
James M. Davis, Jr. 57 Senior Vice President, Group Executive - Fossil Generation and Power Transmission, June 1986 to present; Senior Vice President - Operations Support Group, August 1983.
Norris L. Edge 62 Senior Vice President, Group Executive - Customer and Operating Services, May 1990 to present; Vice President - Rates and Energy Services, September 1989; Vice President - Rates and Service Practices, December 1980.
Richard E. Jones 56 Senior Vice President, General Counsel and Secretary, Group Executive - Legal, Rates, Communications and Public Affairs, January 1993 to present; Group Executive - Legal and Regulatory Services, November 1990 to January 1993; Vice President, General Counsel and Secretary, November 1989; Vice President and General Counsel, July 1987; Vice President, Senior Counsel and Manager - Legal Department, May 1982.
Paul S. Bradshaw 56 Vice President and Controller, March 1980 to present.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS ______ ______________________________________________________
The Company's Common Stock is listed on the New York and Pacific Stock Exchanges. The high and low sales prices per share, adjusted for the two-for-one Common Stock split described below, for the periods indicated, as reported as composite transactions in The Wall Street Journal, and dividends paid are as follows:
1992 High Low Dividends Paid _________________________________________________________________
First Quarter $ 26 15/16 $ 24 9/16 $.395 Second Quarter 27 1/16 24 3/4 .395 Third Quarter 26 5/8 25 .395 Fourth Quarter 28 1/16 25 7/16 .395
1993 High Low Dividends Paid _________________________________________________________________
First Quarter $ 32 7/8 $ 27 1/16 $.410 Second Quarter 34 31 1/4 .410 Third Quarter 34 1/2 32 1/8 .410 Fourth Quarter 33 3/8 28 1/8 .410
The December 31 closing price of the Company's Common Stock was $27 3/4 in 1992 and $30 1/8 in 1993.
As of February 28, 1994, the Company had 72,863 holders of record of Common Stock.
In December 1992, the Board of Directors of the Company authorized a two-for-one split of the Company's Common Stock. On February 1, 1993, one additional share was issued for each share outstanding to shareholders of record on January 11, 1993. The number of common shares and average common share data for all periods reflect the two-for-one stock split.
[TEXT]
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS _______ _________________________________________________
The Company's financial condition and results of operations are affected by numerous factors, including the timing and amount of rate relief, the extent of sales growth and the level of operating costs. The following discussion and analysis should be considered in conjunction with the relevant Sections of ITEM 1, "Selected Financial Data" in ITEM 6, and the Company's financial statements appearing in ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA _______ ___________________________________________
The following financial statements, supplementary data and financial statement schedules are included herein:
Independent Auditors' Report
Financial Statements:
Statements of Income for the Years Ended December 31, 1993, 1992 and 1991
Statements of Cash Flows for the Years Ended December 31, 1993, 1992 and 1991
Balance Sheets as of December 31, 1993 and 1992
Statements of Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991
Schedules of Capitalization as of December 31, 1993 and 1992
Notes to Financial Statements
Quarterly Financial Data
Financial Statement Schedules for the Years Ended December 31, 1993, 1992 and 1991:
V - Utility Plant
VI - Accumulated Provision for Depreciation and Amortization of Electric Utility Plant
VIII - Reserves
IX - Short-term Borrowings
X - Supplementary Income Statement Information
All other schedules have been omitted as not applicable or not required or because the information required to be shown is included in the Financial Statements or the accompanying Notes to Financial Statements.
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders of Carolina Power & Light Company:
We have audited the accompanying balance sheets and schedules of capitalization of Carolina Power & Light Company as of December 31, 1993 and 1992, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1993. Our audits also included the financial statement schedules listed in the Index at Item 8. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
We have also previously audited, in accordance with generally accepted auditing standards, the balance sheets and schedules of capitalization as of December 31, 1991, 1990, and 1989, and the related statements of income, retained earnings and cash flows for the years ended December 31, 1990 and 1989 (none of which are presented herein); and we expressed unqualified opinions on those financial statements. In our opinion, the information set forth in the selected financial data for each of the five years in the period ended December 31, 1993, appearing at Item 6, is fairly presented in all material respects in relation to the financial statements from which it has been derived.
As discussed in Note 6 to the financial statements, in 1993 the Company changed its method of accounting for income taxes to conform with Statement of Financial Accounting Standards No. 109.
/s/ DELOITTE & TOUCHE
Raleigh, North Carolina February 14, 1994
[TEXT]
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. System of Accounts
The accounting records of the Company are maintained in accordance with uniform systems of accounts prescribed by the Federal Energy Regulatory Commission (FERC), the North Carolina Utilities Commission (NCUC) and the South Carolina Public Service Commission (SCPSC).
Certain amounts for 1992 and 1991 have been reclassified to conform to the 1993 presentation.
B. Electric Utility Plant
The cost of additions, including replacements of units of property, and betterments 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. Electric utility plant other than nuclear fuel is subject to the lien of the Company's mortgage.
As prescribed in regulatory uniform systems of accounts, an allowance for the cost of borrowed and equity funds (AFUDC) used to finance electric utility plant construction is charged to the cost of plant. Regulatory authorities consider AFUDC an appropriate charge for inclusion in the Company's utility rates to customers over the service life of the property. The equity funds portion of AFUDC is credited to other income, the borrowed funds portion is credited to interest charges and, in years prior to 1993, a deferred income tax provision was reflected as a reduction in the borrowed funds portion. The composite, net-of-tax AFUDC rate was 7.3% in 1992 and 6.3% in 1991. Due to the implementation of Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes," in 1993, AFUDC-borrowed funds is no longer recorded on a net-of-tax basis (see Note 6). The composite AFUDC rate in 1993, which reflects the implementation of SFAS No. 109, was 8.8%.
Pursuant to the provisions of SFAS No. 109, the deferred income taxes related to AFUDC in undepreciated plant in service at January 1, 1993, were recorded to an accumulated deferred income tax liability with an offsetting adjustment to a regulatory asset.
C. 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 1D), as a percent of average depreciable property other than nuclear fuel, were approximately 3.7% in each of the years 1993, 1992 and 1991. Depreciation and amortization expense also includes amortization of plant abandonment costs (see Note 7) and intangible plant, which primarily includes software development costs.
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 for generation. Costs related to obligations to the DOE for the decommissioning and decontamination of enrichment facilities are also charged to fuel for generation. The disposal and the decommissioning and decontamination costs are components of fuel costs for the purpose of deferred fuel accounting (see Note 1E).
D. Nuclear Decommissioning
Depreciation and amortization expense includes provisions for nuclear decommissioning costs. 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. Cost recovery is based on an internal modified sinking fund methodology assuming 30-year delayed dismantlement decommissioning. In the wholesale jurisdiction, the provisions for nuclear decommissioning costs are based on amounts agreed upon in applicable rate settlements. Accumulated nuclear decommissioning cost provisions included in accumulated depreciation were $221.6 million at December 31, 1993, and $186.4 million at December 31, 1992.
Pursuant to regulations of the Nuclear Regulatory Commission (NRC), the Company is required to provide financial assurance that funds will be available for decommissioning. In this regard, the Company filed decommissioning plans with the NRC and, in 1991, began depositing amounts currently collected in rates in an external decommissioning trust. The Company is required to increase external funding to the NRC-prescribed minimum no later than January 1, 1996. This NRC-prescribed minimum exceeds amounts currently collected in rates. In future rate filings, the Company will request rate recovery based on site-specific estimates for prompt dismantlement decommissioning. The requested rate recovery will also include funding plans that assume external funding of, at least, the NRC-prescribed minimum. The financial impact on the Company will depend on future ratemaking treatment. The NCUC and SCPSC have allowed other utilities to recover costs based on site-specific estimates for prompt dismantlement decommissioning and funding plans similar to those the Company intends to use.
The Company's most recent site-specific estimates of decommissioning costs were developed in 1993 and are based on prompt dismantlement decommissioning, which reflects the cost of removal of all radioactive and other structures currently at the site. These estimates, in 1993 dollars, are $257.7 million for Robinson Unit No. 2, $284.3 million for the Harris Plant, $235.4 million for Brunswick Unit No. 1 and $221.4 million for Brunswick Unit No. 2.
These estimates are subject to change based on a variety of factors, including, but not limited to, inflation, 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 certain of the Company's generating facilities (see Note 8). To the extent of its ownership interests, Power Agency is responsible for satisfying the NRC's financial assurance requirements for decommissioning costs.
E. Other Policies
Customers' meters are read and bills are rendered on a cycle basis. Revenues are recorded as services are rendered.
Regulators of all three jurisdictions require deferred fuel accounting in which the Company defers the difference between fuel costs incurred and the fuel component of customer rates. Customer rates are adjusted periodically to incorporate the approved deferrals.
Other property and investments are stated principally at cost, less accumulated depreciation where applicable. The Company maintains an allowance for doubtful accounts receivable, which totaled $2.3 million at December 31, 1993, and $2.1 million at December 31, 1992. Fuel inventory and inventory of materials and supplies are carried on a first-in, first-out or average cost basis. Long-term debt premiums, discounts and issuance expenses are amortized over the life of the related debt using the straight-line method. Any expenses or call premiums associated with the reacquisition of debt obligations are amortized over the remaining life of the original debt using the straight-line method. For purposes of the Statements of Cash Flows, the Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents.
2. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts of cash, cash equivalents and notes payable approximate fair value because of the short maturities of these instruments. The estimated fair value of long-term debt was obtained from an independent pricing service. Investments in trusts, presented in the table below, primarily includes external decommissioning trust assets and funds invested pursuant to a voluntary employee beneficiary association. The estimated fair values of the Company's trust investments were obtained from quoted market prices. These estimated fair values are as follows (in thousands).
1993 1992 Carrying Fair Carrying Fair Amount Value Amount Value
Long-term debt....$2,799,761 $2,877,300 $2,958,588 $2,978,276 Investments in trusts..........$ 117,022 $ 119,277 $ 91,119 $ 91,844
There are inherent limitations in any estimation technique, and the estimates presented herein are not necessarily indicative of the amounts the Company could realize in current transactions.
3. CAPITALIZATION
A. Common Stock Equity
In December 1992, the Board of Directors authorized a two-for-one split of the Company's common stock. On February 1, 1993, one additional share was issued for each share outstanding to shareholders of record on January 11, 1993. The number of common shares, average common shares and per common share data for all periods reflect the two-for-one stock split.
In 1989, the Company issued common stock shares to the Trustee of the Company's Stock Purchase-Savings Plan (SPSP) in conjunction with a qualified employee stock ownership plan (ESOP) loan. At December 31, 1993, the Trustee was indebted to the Company for $216.2 million. The note receivable from the Trustee is treated as a reduction in common stock equity.
At December 31, 1993, the Company had 14,767,052 shares of authorized but unissued common stock reserved and available for issuance to satisfy the requirements of the Company's stock plans. The Company intends, however, to meet the requirements of these stock plans with issued and outstanding shares presently held by the Trustee of the SPSP or with open market purchases of common stock shares, as appropriate.
The Company's mortgage, as supplemented, and charter contain provisions limiting the use of retained earnings for the payment of dividends under certain circumstances. At December 31, 1993, there were no significant restrictions on the use of retained earnings.
B. Long-Term Debt
As of December 31, 1993, long-term debt maturities for the years 1994 through 1998 were $50 million, $275 million, $55 million, $40 million and $205 million, respectively.
Person County Pollution Control Revenue Refunding Bonds-Series 1992A totaling $56 million have interest rates that must be renegotiated on a weekly basis. First Mortgage Bonds-Pollution Control Series G, J and K, totaling $127 million have three-year interest rate periods that expire in 1994 and 1997. At the time, of interest rate renegotiation, holders of these bonds may require the Company to repurchase their bonds. These obligations are excluded in total from long-term debt maturities in the preceding paragraph. A portion of these bonds is classified as long-term debt in the Balance Sheets, consistent with the Company's intention to maintain the debt as long-term and to the extent that this intention is supported by a $70 million long-term revolving credit agreement (see Note 4). The amount of these obligations not covered by the long-term revolving credit agreement is included in current portion of long-term debt in the Balance Sheets.
4. REVOLVING CREDIT FACILITIES
At December 31, 1993, the Company's unused and readily available revolving credit facilities totaled $208.1 million, consisting of a $115 million revolving credit agreement with nine domestic money centers and major regional banks, a $23.1 million revolving credit agreement with fifteen regional banks and a $70 million long-term revolving credit agreement with eight foreign banks.
5. POSTRETIREMENT BENEFIT PLANS
The Company has a noncontributory defined benefit retirement plan (Plan) for all full-time employees and funds the Plan in amounts that comply with contribution limits imposed by law. Plan benefits reflect an employee's recent compensation, years of service and age at retirement.
[TEXT]
The expected long-term rate of return on plan assets used in determining the net periodic pension cost was 9% for each of the three years.
In addition to pension benefits, the Company provides contributory postretirement benefits, including certain health care and life insurance benefits, for substantially all retired employees. In January 1993, the Company implemented SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." SFAS No. 106 requires the recognition of the costs associated with these other postretirement benefits (OPEB) on an accrual basis. Previously, the cost of OPEB was generally recognized as claims were incurred and premiums were paid. These costs totaled $2.7 million in 1992 and $3.0 million in 1991.
The components of the net periodic cost of OPEB for 1993 are as follows (in thousands).
Actual return on plan assets....................$ (497) Variance from expected return, deferred......... 9 ---------- Expected return on plan assets.................. (488) Service cost.................................... 6,797 Interest cost on accumulated benefit obligation. 9,662 Net amortization................................ 5,966 ---------- Net cost......................................$ 21,937 ==========
A reconciliation of the funded status of the OPEB plans to the amount recognized in the Balance Sheet at December 31, 1993, is presented below (in thousands).
Actuarial present value of benfits for services rendered to date: Current retirees................................$ (62,727) Active employees eligible to retire............. (14,800) Active employees not eligible to retire......... (62,225) ---------- Accumulated postretirement benefit obligation. (139,752) Fair market value of plan assets, invested primarily in equity and fixed-income securities......... 7,584 ---------- Funded status.......................... (132,168) Unrecognized actuarial loss..................... 6,288 Unrecognized transition obligation, being amortized over 20 years beginning January 1, 1993....... 113,345 ---------- Accrued OPEB costs recognized in the Balance Sheet ........................$ (12,535) ==========
The accumulated postretirement benefit obligation (APBO) was determined using a 7.5% weighted-average discount rate. The expected long-term rate of return on plan assets used in determining the net periodic cost of OPEB (NPC) was 9%. The medical cost trend rates used in determining the APBO were assumed to be 10.7% and 9.5% in 1994 for pre-medicare and post-medicare benefits, respectively. These rates were assumed to gradually decline to 5% in 2005, and remain at that level thereafter.
Assuming a one percent increase in the medical cost trend rates, the aggregate of the service and interest cost components of the NPC for 1993 would increase by $1.6 million, and the APBO as of December 31, 1993, would increase by $15.1 million. In general, OPEB costs are paid as claims are incurred and premiums are paid; however, the Company is partially funding future health care benefits for retirees in a trust created pursuant to Section 401(h) of the Internal Revenue Code of 1986.
In future rate filings, the Company will request rate recovery based on the provisions of SFAS No. 106. The NCUC and the SCPSC have allowed other utilities to recover costs based on these provisions.
6. INCOME TAXES
Income taxes are allocated between operating income and other income based on the source of the income that generated the tax. Investment tax credits related to operating income are amortized over the service life of the related property.
On January 1, 1993, the Company implemented SFAS No. 109, which required the Company to establish additional deferred income tax assets and liabilities for certain temporary differences and to adjust deferred income tax accounts for changes in income tax rates. It also prohibits net-of-tax accounting for income statement and balance sheet items. Prior to the implementation of SFAS No. 109, deferred income taxes were not recorded for certain timing differences. At December 31, 1992, deferred income taxes were not provided for cumulative timing differences of approximately $311 million as a result of a rate moderation plan and pre-1976 flow-through.
Substantially all of the adjustments required by SFAS No. 109 were recorded to deferred income tax balance sheet accounts, with offsetting adjustments to certain assets and liabilities. As a result, the cumulative effect on net income was not material. The Company's total assets and liabilities increased by approximately $450 million as a result of the implementation of SFAS No. 109.
As a result of the implementation of SFAS No. 109, the Company no longer records the following income statement items on a net-of-tax basis: Harris Plant deferred costs, Harris Plant carrying costs and allowance for borrowed funds used during construction. In addition, a portion of the tax benefit of ESOP dividends is now recorded to non-operating income tax expense. The remaining portion continues to be recorded directly to retained earnings, but is no longer included in the determination of earnings per common share. Prior period financial statement amounts were not restated.
[TEXT]
A reconciliation of the Company's effective income tax rate to the statutory federal income tax rate follows.
1993 1992 1991
Effective income tax rate............... 35.4% 36.7% 36.3% State income taxes, net of federal income tax benefit.................... (5.1) (5.1) (5.3) Investment tax credit amortization...... 2.3 1.9 2.0 Other differences, net.................. 2.4 .5 1.0 ----- ----- ----- Statutory federal income tax rate.. 35.0% 34.0% 34.0% ===== ===== =====
At December 31, 1993, deferred income tax assets and liabilities were $260.8 million and $1.9 billion, respectively. At December 31, 1992, prior to the implementation of SFAS No. 109, deferred income tax assets and liabilities were $253.5 million and $1.3 billion, respectively. The net accumulated deferred income tax liability was comprised of the following at December 31 (in thousands).
1993 1992 Accelerated depreciation and property cost differences............... $ 1,449,796 $ 1,053,706 Deferred costs, net....................... 168,311 35,984 Miscellaneous other temporary differences, net........................ (12,443) (14,288) ---------- ---------- Net accumulated deferred income tax liability............... $ 1,605,664 $ 1,075,402 ========== ==========
[TEXT]
7. DEFERRED COSTS
The Company eliminated from its construction program and abandoned further efforts to complete Harris Unit Nos. 3 and 4 in December 1981, Harris Unit No. 2 in December 1983 and Mayo Unit No. 2 in March 1987. The NCUC and SCPSC each allowed the Company to recover the cost of these abandoned units over a ten-year period without a return on the unamortized balances. The amortization of Harris Unit Nos. 3 and 4 was completed in 1992. In 1988 rate orders and a 1990 NCUC Order on Remand, the Company was ordered to remove from rate base and treat as abandoned plant certain costs related to the Harris Plant.
Amortization of plant abandonment costs is included in depreciation and amortization expense and totaled $100.7 million in 1993, $92.5 million in 1992 and $95.9 million in 1991. The 1993 amortization of plant abandonment costs reflects increased amortization due to the implementation of the SFAS No. 109 provision that prohibits net-of-tax accounting (see Note 6). The unamortized balances of plant abandonment costs are reported at the present value of future recoveries of these costs. The associated accretion of present value was $13.2 million in 1993, $18.2 million in 1992 and $24.6 million in 1991 and is reported in other income, net.
In 1988, the Company began recovering certain Harris Plant deferred costs over ten years from the date of deferral, with carrying costs accruing on the unamortized balance. Excluding deferred purchased capacity costs (see Note 9A), the unamortized balance of Harris Plant deferred costs was $81.4 million at December 31, 1993, and $64.7 million, net of tax, at December 31, 1992. Due to the implementation of SFAS No. 109 in 1993, Harris Plant deferred costs are no longer recorded on a net-of-tax basis (see Note 6). Harris Plant deferred costs are reported net of amortization on the Statements of Income.
8. JOINT OWNERSHIP OF GENERATING FACILITIES
Power Agency, which includes a majority of the Company's previous municipal wholesale customers, holds undivided ownership interests in certain generating facilities of the Company. The Company and Power Agency are entitled to shares of the generating capability and output of each unit equal to their respective ownership interests. Each also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. The Company's share of expenses for the jointly-owned units is included in the appropriate expense category in the Statements of Income. Power Agency's payment obligation with respect to abandonment costs for Harris Unit Nos. 2, 3 and 4 and Mayo Unit No. 2 is 12.94% of such costs.
The Company's share of the jointly-owned generating facilities is listed below with related information as of December 31, 1993 (dollars in millions).
[TEXT] ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE ______ _____________________________________________
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ________ __________________________________________________
a) Information on the Company's directors is set forth in the Company's 1994 definitive proxy statement dated March 31, 1994, 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.
ITEM 11. EXECUTIVE COMPENSATION _______ ______________________
Information on executive compensation is set forth in the Company's 1994 definitive proxy statement dated March 31, 1994, and incorporated by reference herein.
ITEM 12.
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 Wachovia Bank of North Carolina, N.A., Post Office Box 3099, Winston-Salem, North Carolina 27102 which as of December 31, 1993, owned 24,380,381 shares of Common Stock (15.2% of Class) as Trustee of the Company's Stock Purchase-Savings Plan.
b) Information on security ownership of the Company's management is set forth in the Company's 1994 definitive proxy statement dated March 31, 1994, and incorporated by reference herein.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ________ ______________________________________________
Information on certain relationships and transactions is set forth in the Company's 1994 definitive proxy statement dated March 31, 1994, and incorporated by reference herein.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. _______ ____________________________________________
a) 1. Financial Statements Filed:
See ITEM 8 - Financial Statements and Supplementary Data.
2. Financial Statement Schedules Filed:
See ITEM 8 - Financial Statements and Supplementary Data.
3. Exhibits Filed:
Exhibit No. *3a(1) Restated Charter of Carolina Power & Light Company, dated May 22, 1980 (filed as Exhibit 2(a)(1), File No. 2-64193).
Exhibit No. *3a(2) Amendment, dated May 10, 1989, to Restated Charter of the Company (filed as Exhibit 3(b), File No. 33-33431).
Exhibit No. *3a(3) Amendment, dated May 27, 1992 to Restated Charter of the Company (filed as Exhibit 4(b)(2), File No. 33-55060).
Exhibit No. *3a(4) By-laws of the Company as amended December 12, 1990 (filed as Exhibit 3(c), File No. 33-38298).
Exhibit No. *4a(1) Resolution of Board of Directors, dated December 8, 1954, authorizing the issuance of, and establishing the series designation, dividend rate and redemption prices for the Company's Serial Preferred Stock, $4.20 Series (filed as Exhibit 3(c), File No. 33-25560).
Exhibit No. *4a(2) Resolution of Board of Directors, dated January 17, 1967, authorizing the issuance of, and establishing the series designation, dividend rate and redemption prices for the Company's Serial Preferred Stock, $5.44 Series (filed as Exhibit 3(d), File No. 33-25560).
Exhibit No. *4a(3) Statement of Classification of Shares dated January 13, 1971, relating to the authorization of, and establishing the series designation, dividend rate and redemption prices for the Company's Serial Preferred Stock, $7.95 Series (filed as Exhibit 3(f), File No. 33-25560).
Exhibit No. *4a(4) Statement of Classification of Shares dated September 7, 1972, relating to the authorization of, and establishing the series designation, dividend rate and redemption prices for the Company's Serial Preferred Stock, $7.72 Series (filed as Exhibit 3(g), File No. 33-25560).
Exhibit No. *4b Mortgage and Deed of Trust dated as of May 1, 1940 between the Company and The Bank of New York (formerly, Irving Trust Company) and Frederick G. Herbst (W.T. Cunningham, Successor), Trustees and the First through Fifth Supplemental Indentures thereto (Exhibit 2(b), File No. 2- 64189); and the Sixth through Sixty-second 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), File No. 33-38349; Exhibit 4(e), File No. 33-50597; and Item 7(c) of the Company's Current Report on Form 8-K dated January 19, 1994).
Exhibit No. *10a(1) Purchase, Construction and Ownership Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency, amending letter dated February 18, 1982, and amendment dated February 24, 1982 (filed as Exhibit 10(a), File No. 33-25560).
Exhibit No. *10a(2) Operating and Fuel Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency, amending letters dated August 21, 1981 and December 15, 1981, and amendment dated February 24, 1982 (filed as Exhibit 10(b), File No. 33-25560).
Exhibit No. *10a(3) Power Coordination Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency and amending letter dated January 29, 1982 (filed as Exhibit 10(c), File No. 33-25560).
Exhibit No. *10a(4) Amendment dated December 16, 1982 to Purchase, Construction and Ownership Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Eastern Municipal Power Agency (filed as Exhibit 10(d), File No. 33-25560).
Exhibit No. *10a(5) Agreement Regarding New Resources and Interim Capacity between Carolina Power & Light Company and North Carolina Eastern Municipal Power Agency dated October 13, 1987 (filed as Exhibit 10(e), File No. 33-25560).
Exhibit No. *10a(6) Power Coordination Agreement - 1987A between North Carolina Eastern Municipal Power Agency and Carolina Power & Light Company for Contract Power From New Resources Period 1987-1993 dated October 13, 1987 (filed as Exhibit 10(f), File No. 33-25560).
+Exhibit No. *10c(1) Directors Deferred Compensation Plan effective January 1, 1982 as amended (filed as Exhibit 10(g), File No. 33-25560).
+Exhibit No. *10c(2) Supplemental Executive Retirement Plan effective January 1, 1984 (filed as Exhibit 10(h), File No. 33-25560).
+Exhibit No. *10c(3) Retirement Plan for Outside Directors (filed as Exhibit 10(i), File No. 33- 25560).
+Exhibit No. *10c(4) Executive Deferred Compensation Plan effective May 1, 1982 as amended (filed as Exhibit 10(j), File No. 33-25560).
+Exhibit No. *10c(5) Key Management Deferred Compensation Plan (filed as Exhibit 10(k), File No. 33-25560).
+Exhibit No. *10c(6) Resolutions of the Board of Directors, dated March 15, 1989, amending the Key Management Deferred Compensation Plan (filed as Exhibit 10(a), File No. 33-48607).
+Exhibit No. *10c(7) Resolutions of the Board of Directors dated May 8, 1991, amending the Directors Deferred Compensation Plan (filed as Exhibit 10(b), File No. 33- 48607).
+Exhibit No. *10c(8) Resolutions of the Board of Directors dated May 8, 1991, amending the Executive Deferred Compensation Plan (filed as Exhibit 10(c), File No. 33- 48607).
Exhibit No. 12 Computation of Ratio of Earnings to Fixed Charges and Preferred Dividends Combined and Ratio of Earnings to Fixed Charges.
Exhibit No. 23(a) Consent of Deloitte & Touche.
Exhibit No. 23(b) Consent of Richard E. Jones.
*Incorporated herein by reference as indicated.
+Management contract or compensation plan or arrangment required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
b) Reports on Form 8-K filed during or with respect to the last quarter of 1993 and the first quarter of 1994:
Date of Report Item Reported ______________ _____________
December 1, 1993 Item 5. Other Events
January 19, 1994 Item 7. Financial Statements, Pro Forma Financial Information and Exhibits
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 25th day of March, 1994.
CAROLINA POWER & LIGHT COMPANY (Registrant)
By: /s/ Paul S. Bradshaw 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/ Sherwood H. Smith, Jr. Principal Executive (Chairman and Chief Executive Officer and Director Officer)
/s/ Charles D. Barham, Jr. Principal Financial (Executive Vice President and Officer and Director Chief Financial Officer)
/s/ Paul S. Bradshaw Principal Accounting (Vice President and Controller) Officer
/s/ Edwin B. Borden Director March 25, 1994
/s/ Felton J. Capel Director
/s/ William Cavanaugh III Director (President and Chief Operating Officer)
/s/ George H. V. Cecil Director
/s/ Charles W. Coker Director
/s/ Richard L. Daugherty Director
/s/ William E. Graham, Jr. Director
/s/ Gordon C. Hurlbert Director
/s/ J. R. Bryan Jackson Director
/s/ Robert L. Jones Director
/s/ Estell C. Lee Director
/s/ J. Tylee Wilson Director