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 7,812 employees at December 31, 1994. 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 2 electric membership corporations (North Carolina Electric Membership Corporation, which has 17 members, and French Broad Electric Membership Corporation). At December 31, 1994, the Company was furnishing electric service to approximately 1,057,000 customers.
3. SALES. During 1994, 31.8% of operating revenues was derived from residential sales, 20.7% from commercial sales, 25.8% from industrial sales, 17.4% from resale sales and 4.3% 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, 1994, average revenues per kilowatt-hour (kWh) sold to residential, commercial and industrial customers were 8.22 cents, 6.85 cents and 5.29 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 ____ _______ ______ _______
1990 11,957 $ 995.01 8.32 cents 1991 12,472 1,040.70 8.34 1992 12,396 1,029.82 8.31 1993 13,167 1,090.16 8.28 1994 12,559 1,032.00 8.22
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 1992 increased by 3.1%, for 1993 increased by 3.8%, and for 1994 increased by 5.8%, as compared with the preceding year. The Company currently projects a 2.1% 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 1992-1994 were 57.4%, 59.0% and 56.0%, respectively. The Company forecasts capacity margins of 13.6% over anticipated system peak load for both 1995 and 1996. 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 1994. Over the next ten years, system sales growth is forecasted to average 2.1% per year and annual growth in system peak demand is projected to average 2.1%. The Company's generation additions schedule, which is updated annually, reflects no additions until 1997, 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 $72 million. The generation additions schedule also includes generation additions of up to 1,200 MW in combustion turbine generating units to be added adjacent to the Company's Lee Steam Electric Plant in Wayne County, North Carolina. In December 1994, the Company filed preliminary plans with the North Carolina Utilities Commission (NCUC) and the North Carolina Division of Environmental Management to construct the ten new combustion turbine generating units at the Wayne County site. The units are nominally rated at 100-200 MW each and would represent a capital investment of approximately $300 million. The units would primarily be used during periods of summer and winter peak demands. The schedule, which is subject to change, calls for construction to begin in 1996, with the units beginning commercial service between 1998 and 2000. In addition to this proposed project, the generation addition schedule provides for the addition of 1,400 MW in combustion turbine capacity, and 900 MW combined cycle capacity at undesignated sites over the period 2000 to 2007, 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). On September 17, 1993, the Company and NCEMC filed a settlement agreement (Settlement Agreement) with the FERC for approval. Another settlement agreement regarding various environmental issues was filed with the FERC for approval on February 16, 1994. Through a series of orders, the FERC approved final settlement of this proceeding, and on November 4, 1994, issued the Company a forty year license to operate its Walters Hydroelectric Plant. The license contains numerous conditions for the ongoing operation of the plant, including recreational enhancements, environmental monitoring and funding, and cultural resource management. Issuance of the license for the Walters Plant by the FERC and the Company's acceptance of the license terms conclude this licensing proceeding.
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. 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. A settlement agreement resolving issues related to the purchase power contract and other matters between the Company and NCEMC was filed with the FERC for approval on September 17, 1993. See ITEM 1, "Generating Capability," paragraph 4. 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. Purchases under this agreement, including transmission use charges, totaled $62.9 million in 1994. On January 20, 1995, the FERC issued an order approving a final settlement agreement in this docket, thereby accepting the purchase power contract and making it no longer subject to refund.
b. The Company has entered into an agreement, which has been approved by the FERC, with APCO and Indiana Michigan Power Company (Indiana Michigan), operating subsidiaries of American Electric Power Company, to upgrade a transmission interconnection with APCO in the Company's western service area, establish a new interconnection in the Company's eastern service area, and purchase 250 MW of generating capacity from Indiana Michigan's Rockport Unit No. 2 through 2010. 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. Purchases under this agreement, including transmission use charges, totaled $61.9 million in 1994.
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.
5. POWER AGENCY. The Company is obligated to purchase a percentage of Power Agency's ownership capacity of and energy from the Mayo Plant and the Harris Plant through 1997 and 2007, respectively. The estimated minimum annual payments for these purchases, which reflect capital-related capacity costs, total approximately $27 million. Other costs of such purchases are primarily demand-related production expenses, fuel and energy-related operation and maintenance expenses. Purchases under the agreement with Power Agency totaled $60.4 million in 1994.
COMPETITION AND FRANCHISES __________________________
1. COMPETITION.
a. Generally, in municipalities and other areas where the Company provides retail electric service, no other utility directly renders such service. In recent years, however, customers interested in building their own generation facilities, competition from unregulated energy suppliers and changing government regulations have fostered the development of alternative sources of electricity for certain of the Company's wholesale and industrial customers. The Public Utility Regulatory Policies Act (PURPA) has facilitated the entry of non-utility companies into the wholesale electric generation business. Under PURPA, non-utility companies are allowed to construct "qualifying facilities" for the production of electricity in connection with industrial steam supplies and, under certain circumstances, to compel a utility to purchase the electricity generated at prices reflecting the utility's avoided cost as set by state regulatory bodies. Over the near term, the purchase of power from qualifying facilities has increased the Company's total cost of generation.
b. In 1992, the National Energy Policy Act (Energy Act) changed certain underlying federal policies governing wholesale generation and the sale of electric power. In effect, the Energy Act partially deregulated the wholesale electric utility industry at the generation level by allowing non-utility generators to build and own generating plants for both cogeneration and sales to utilities. Provisions of the Energy Act that most affected the utility industry were the establishment of exempt wholesale generators, and the authority given the FERC to permit wholesale transfer, or wheeling, of power over the transmission lines of other utilities. 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. Although the Energy Act prohibits the FERC from ordering retail wheeling--transmitting power on behalf of another producer to an individual retail customer--some states are considering changing their laws or regulations to allow retail electric customers to buy power from suppliers other than the local utility. The Company believes changes in existing laws in both North Carolina and South Carolina would be required to permit retail wheeling in the Company's retail jurisdictions. The South Carolina Public Service Commission (SCPSC) has ruled that it would be a violation of its past practice and of South Carolina's territorial assignment statute to require utilities to engage in retail wheeling. On February 8, 1995, the Carolina Utility Consumers Association, Inc., a group of industrial customers doing business in North Carolina, filed a petition with the NCUC requesting that the NCUC hold a generic hearing to examine whether retail wheeling would be in the public interest, how it could be implemented in North Carolina and whether it could be implemented without changing state law. The NCUC has issued an order inviting interested parties to comment on the petition. The Company cannot predict the outcome of this matter.
The possible migration of some of the Company's load due to increased competition in the electric industry has created greater planning uncertainty and risks for the Company. The Company has been addressing these risks by securing 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 and 1994 the Company signed long-term agreements with almost all of the Company's wholesale customers, representing approximately 15% of the Company's operating revenues. In the industrial sector, the Company is working to meet the energy needs of its customers. In 1994, the Company reached an agreement with its largest industrial customer that ensures the Company will serve that customer through 2001. Other elements of the Company's strategy for responding to the changing market for electricity include promoting economic development, implementing new market strategies, increasing the focus on managing and reducing costs, and consequently, avoiding future rate increases.
c. In April 1994, the North Carolina Public Staff (Public Staff), which represents the using and consuming public in matters before the NCUC, filed a petition with the NCUC proposing interim guidelines to apply to requests for self-generation deferral rates. By order issued May 13, 1994, the NCUC established a docket (Docket No. E-100, Sub 73) to consider the proposed self-generation deferral rates guidelines, and dispersed energy facilities and economic development rates. Initial comments were filed by the Company and other interested parties on June 13, 1994, and reply comments were filed on June 27, 1994. In response to the parties' comments, on July 1, 1994, the Public Staff filed modifications to the proposed self-generation deferral rate guidelines. By order issued July 21, 1994, the NCUC, with limited exceptions, approved and adopted the modified self-generation deferral rate guidelines proposed by the Public Staff. The guidelines allow the Company to adjust rates to retain certain loads for which self-generation is feasible. In this order, the NCUC also requested that additional comments regarding economic development rates be filed by October 21, 1994, and stated that the issue of dispersed energy facilities would be addressed on a case by case basis. On November 28, 1994, the NCUC issued an order adopting interim guidelines for economic development rates. These guidelines allow the Company to adjust its rates to attract new industrial load that would not have been served in the absence of such rates, provided certain criteria are satisfied. The NCUC will review the economic development rate guidelines after one year.
d. On September 17, 1993, the Company and NCEMC filed with the FERC a Power Coordination Agreement (PCA) and an Interchange Agreement (IA), both dated August 27, 1993. The PCA and IA, which were both filed in connection with the Walters Hydroelectric Plant relicensing proceeding (Project Nos. 432-004 and 2748-000), set forth explicitly the future relationship between the Company and NCEMC, and establish a framework under which they will operate. See ITEM 1, "Generating Capability," paragraph 4 for further discussion of the Walters relicensing proceeding. The FERC granted final approval of the PCA and the IA in June 1994. 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. The PCA allows NCEMC to assume responsibility for up to 200 MW of its load from the Company's system between January 1, 1996 and December 31, 2000. On and after January 1, 1996, the Company expects to continue to supply not less than 1000 MW of electricity to NCEMC until at least December 31, 2000. NCEMC's board of directors has voted to award a power-supply contract for 200 MW to another supplier beginning on January 1, 1996. If approved by the FERC, the contract will displace 200 MW of baseload capacity that NCEMC currently purchases from the Company. Load reductions beyond the year 2000 are subject to specific limits and require five years' advance notice. On November 4, 1994, NCEMC issued two requests for proposals (RFP) to provide up to 225 MW per year (for a minimum of ten years) of baseload power NCEMC would otherwise purchase from the Company beginning in 2001, 2002 and 2003. On March 3, 1995, the Company submitted a bid in response to each RFP to compete for this load. The Company cannot predict the outcome of these matters.
e. By order issued September 30, 1994, the SCPSC established a docket for a generic proceeding to consider the effect of electric and natural gas demand side management programs on competition between the two types of utilities. The order states that the outcome of such a proceeding will not apply to the 1995 integrated resource plans that electric utilities file with the SCPSC. The filing of testimony and scheduling of hearings in the SCPSC proceeding have been indefinitely postponed. The NCUC established a docket for a similar generic proceeding (Docket No. E-100, Sub 71) by order dated February 24, 1994. The NCUC's hearings on this matter concluded on December 20, 1994, but the NCUC has not issued an order in that proceeding. The Company cannot predict the outcome of these matters.
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 1994 the Company expended approximately $386 million for capital requirements. The Company revised its capital program in 1994 as part of its annual business planning process. Capital requirements, including anticipated construction expenditures for plant modifications, for the years 1995 through 1997 are set forth below. These estimates include Clean Air Act compliance expenditures of approximately $117 million, and generating facility addition expenditures of approximately $287 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)
1995 1996 1997 TOTAL ____ ____ ____ _____
Construction Expenditures $358 $445 $527 $1,330 Nuclear Fuel Expenditures 99 77 71 247 AFUDC (19) (25) (34) (78) ____ ____ ____ ______ Net expenditures (a) 438 497 564 1,499 Long-Term Debt Maturities 275 105 100 480 ____ ____ ____ ______ TOTAL $713 $602 $664 $1,979 ==== ==== ==== ======
(a) Reflects reductions of approximately $29 million, $28 million and $21 million for 1995, 1996 and 1997, 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. External funding requirements, which do not include early redemptions of long-term debt or redemptions of preferred stock, are expected to approximate $417 million in 1995 and $120 million in 1997. These funds will be required for construction, long-term debt maturities and general corporate purposes, including the repayment of short-term debt. Based on the Company's most recent estimate of capital requirements, the Company does not expect to have external funding requirements in 1996. 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. 33-57835), enabling the Company to issue an aggregate of $450 million principal amount of First Mortgage Bonds, and an additional $250 million combined aggregate principal amount of First Mortgage Bonds and/or unsecured debt securities of the Company.
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 1994 and early 1995 included:
- 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 issuance 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.
- The issuance on May 12, 1994, of $72.6 million principal amount of First Mortgage Bonds, Pollution Control Series L, Wake County Pollution Control Revenue Refunding Bonds (Carolina Power & Light Company Project) Series 1994A due May 1, 2024 and $50 million principal amount of First Mortgage Bonds, Pollution Control Series M, Wake County Pollution Control Revenue Refunding Bonds (Carolina Power & Light Company Project) Series 1994B due May 1, 2024, for a total net proceeds of $122.6 million. The proceeds from the issuances were used for the redemption on June 15, 1994 of $122.6 million First Mortgage Bonds, Pollution Control Series G, Wake County Pollution Control Revenue Bonds (Carolina Power & Light Company) Series 1984A due June 15, 2014, at 100% of the principal amount of such bonds plus accrued interest to the date of redemption.
- The remarketing on July 1, 1994, of First Mortgage Bonds, Pollution Control Series J, New Hanover County Pollution Control Revenue Bonds (Carolina Power & Light Company Project) Series 1984 due June 15, 2014 and First Mortgage Bonds, Pollution Control Series K, Chatham County Pollution Control Revenue Bonds (Carolina Power & Light Company Project) Series 1984 due June 15, 2014, at a fixed rate of 6.30% to June 15, 2014.
- The issuance on December 28, 1994, of $50 million principal amount of First Mortgage Bonds, Secured Medium-Term Notes, 7.9% Series C, due December 27, 1996 for net proceeds of $49.8 million. The proceeds from the issuance 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.
- The issuance on January 24, 1995, of $60 million principal amount of First Mortgage Bonds, Secured Medium-Term Notes, 7.75% Series C, due January 24, 1997 for net proceeds of $59.7 million. The proceeds were used to reduce the outstanding balance of commercial paper and other short-term debt and for other general corporate purposes.
4. REDEMPTIONS/RETIREMENTS. Redemptions and retirements during 1994 and early 1995 included:
- The redemption on March 24, 1994, of $17.5 million principal amount of First Mortgage Bonds, 8 1/2% Series due October 1, 2007, at 100.25% of the principal amount of such bonds plus accrued interest to the date of redemption.
- The partial redemption on March 24, 1994, of $77.4 million principal amount of First Mortgage Bonds, 8 1/8% Series, due November 1, 2003, at 100.61% of the principal amount of such bonds plus accrued interest to the date of redemption.
- The retirement on April 15, 1994, of $50 million principal amount of First Mortgage Bonds, 5.85% Secured Medium-Term Notes, Series B, which matured on that date.
- The redemption on June 15, 1994, of $122.6 million principal amount of First Mortgage Bonds, Pollution Control Series G, Wake County Pollution Control Revenue Bonds (Carolina Power & Light Company Project) Series 1984A due June 15, 2014, at 100% of the principal amount of such bonds plus accrued interest to the date of redemption.
- The retirement on January 1, 1995, of $125 million principal amount of First Mortgage Bonds, 5.20% Series, which matured on that date.
5. CREDIT FACILITIES. The Company's credit facilities presently total $307.9 million, consisting of long-term agreements totaling $207.9 million and a $100 million short-term agreement.
RETAIL RATE MATTERS ___________________
1. GENERAL. The Company is subject to regulation in North Carolina by the NCUC and in South Carolina by the SCPSC with respect to, among other things, rates 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 cost effective manner, giving due regard to system reliability and safety. The Company is required to file its Integrated Resource Plan (IRP) with the NCUC and the SCPSC once every three years. The Company regularly reviews its IRP in light of changing conditions and evaluates the impact these changes have on its resource plans, including purchases and other resource options. The next IRP is scheduled to be filed with the NCUC on or before April 28, 1995, and with the SCPSC on or before June 30, 1995.
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 currently has no deferred costs related to DSM programs.
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 1995 North Carolina fuel case hearing is scheduled to begin on August 1, 1995. The Company cannot predict the outcome of this matter.
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 1995 South Carolina fuel case was held on March 15, 1995 (Docket No. 95-001-E). On March 21, 1995, the SCPSC approved a fuel factor of 1.34 cents/kWh for the six month period April 1 through September 30, 1995.
6. AVOIDED COST PROCEEDINGS. The NCUC has opened Docket No. E-100, Sub. 75 for its biennial proceeding to establish the avoided cost rates for all electric utilities in North Carolina. Avoided cost rates are intended to reflect the costs that utilities are able to "avoid" by purchasing power from qualifying facilities. The Company has proposed to lower its avoided cost rates. The hearings in this docket concluded on March 9, 1995, but the NCUC has not issued an order in this proceeding. The Company cannot predict the outcome of this matter.
7. 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. The Company cannot predict the outcome of this matter. With regard to the SCPSC proceeding, the Company filed initial written comments on March 1, 1994, and reply comments were due on April 15, 1994. By order dated June 22, 1994, the SCPSC approved a stipulation entered into by the Company and the other parties to the proceeding. In that stipulation, the parties agreed that standards similar to those of Section 111 of the Energy Act have already been implemented to the degree necessary, and therefore, the specific standards of Section 111 do not need to be adopted by the SCPSC in order to implement the purposes of PURPA.
8. MISCELLANEOUS. There are two additional dockets pending in the NCUC. The first docket (Docket No. M-100, Sub 124) involves the proper interpretation of North Carolina General Statute Section 62-140(c) which controls the offer or payment of consideration by a public utility to secure the installation or adoption of the use of the utility's services. This docket will be decided based upon the written comments of the parties. The second docket (Docket No. E- 100, Sub 71) explores the issue of what factors the NCUC should consider when evaluating the reasonableness of proposed DSM programs. Hearings in the second docket have been completed, but the NCUC has not yet issued an order in the proceeding. The Company cannot predict the outcome of these matters.
WHOLESALE RATE MATTERS ______________________
The Company is subject to regulation by the FERC with respect to rates for transmission and sale of electric energy at wholesale, the interconnection of facilities in interstate commerce (other than interconnections for use in the event of certain emergency situations), the licensing and operation of hydroelectric projects and, to the extent the FERC determines, accounting policies and practices. The Company and its wholesale customers last agreed to a general increase in wholesale rates in 1988. At the present time, the Company has no wholesale rate matters pending at the FERC.
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 1995 through 1997, 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 was not required to take action to comply with the Act's Phase I requirements, which had to be met by January 1, 1995. Phase II of the Act, which contains more stringent provisions, will become effective January 1, 2000. 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 2007 by utilizing lower sulfur coal and sulfur dioxide emission allowances. The Company purchased emission allowances under the Environmental Protection Agency's (EPA) emission allowance trading program in 1993 and 1994. Each sulfur dioxide emission allowance will allow a utility to emit one ton of sulfur dioxide. The Company estimates that the total capital cost to comply with Phase II of the Act will approximate $273 million during the period 1995 through 1999 and an additional $272 million during the period 2000 through 2007. 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 $18 million for the period 1995 through 1999, $35 million for the period 2000 through 2006 and by $24 million annually beginning in 2007. Additionally, fuel costs are expected to increase by a total of approximately $277 million for the period 2000 through 2006, and by approximately $62 million annually beginning in 2007. The Company expects these increased fuel costs to be recoverable through applicable fuel adjustment statutes. Actual plans for compliance with the Act's requirements have not been finalized and the amount required for capital expenditures and for increased operating, maintenance and fuel expenditures cannot be determined with certainty at this time. The financial impact of 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, the Commonwealth of Kentucky, which owns the site, and the federal agencies in an effort to reach global settlement. It appears that the Steering Committee and eleven federal agencies will perform the Initial Remediation Phase and the Commonwealth of Kentucky will perform the Balance of Remediation Phase pursuant to a Consent Decree with 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.
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 0.8% 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 remediation began in May 1994, and is scheduled to be completed in early 1995. Final grading, seeding and demobilization is scheduled to be conducted in March 1995. It is currently estimated that cleanup will cost approximately $23.7 million. There is currently over 90% participation by the PRPs in the site cleanup. 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 future costs associated with this site, if any, would 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 the 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 (a group of PRPs with respect to the Elliot's site), 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 negotiated 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. Once the Elliot's Auto Parts PRP Committee receives final approval from the EPA for its final report, the Company, based on its negotiations with the Elliot's Auto Parts PRP Committee, has agreed to (i) pay $90,000 to the Elliot's Auto Parts PRP Committee towards the $2.7 million previously expended to remediate the site; (ii) pay 3.4% toward any future expense incurred in connection with the site; and (iii) execute an Administrative Order on Consent with the EPA. Although the Company cannot predict the outcome of this matter, it does not anticipate that future costs associated with this site, if any, would 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). The Company estimates that to date its costs associated with completion of the Removal Work Plan total approximately $12,000. On July 28, 1993, DEHNR determined that the Removal Work Plan had been substantially completed. DEHNR further recommended that the Seaboard Group (a group of PRPs with respect to the Seaboard site) undertake additional remedial activities at the Seaboard site. The Company recently joined the Seaboard Group II (a group of PRPs formed to conduct additional work at the Seaboard site). Cost estimates for the additional work are not available. Although the Company cannot predict the outcome of this matter, it does not anticipate that costs associated with this site would be material to the results of operations of the Company.
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.
On April 13, 1994, Crown Cork & Seal Company, Inc. and Clark Equipment Co. filed a motion to add the Company as a defendant in an ongoing lawsuit concerning the Macon-Dockery site, which was filed in the United States District Court for the Middle District of North Carolina in Greensboro, North Carolina (Civil Action No. 3:92CV00744) on December 4, 1992. The lawsuit seeks to recover costs incurred in undertaking the Remedial Investigation Feasibility Study and the Remedial Design for the Macon-Dockery site. On July 6, 1994, the United States District Court for the Middle District of North Carolina granted the motion Crown Cork & Seal Company and Clark Equipment Co. filed seeking to name the Company as a defendant in the lawsuit. On September 30, 1994, the Company filed an Answer denying any liability to Crown Cork & Seal Company and Clark Equipment Co. Although the Company cannot predict the outcome of this matter, it does not anticipate that costs associated with this site would be material to the results of operations of the Company.
g. 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 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 this regard, the Company, along with other entities alleged to be former owners and operators of MGP sites in North Carolina, is participating in a cooperative effort with the North Carolina Department of Environment, Health and Natural Resources, Division of Solid Waste Management (DSWM) to establish a uniform framework for addressing those sites. 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 PRPs. To date, the Company has not entered into any such orders.
The Company has recently been approached by another North Carolina public utility concerning a possible cost-sharing arrangement with respect to the investigation and, if necessary, remediation of four MGP sites. The Company is currently engaged in discussions with the other utility regarding this matter. Based on current cost estimates provided by that utility, the Company does not believe its portion of costs associated with the investigation and remediation of these sites, if any, would be material to the results of operations of the Company.
In addition, the Company and a current owner of property that was the site of one MGP owned by Tide Water Power Company (Tide Water Power), which merged into the Company in 1952, have entered into an agreement to share the cost of investigation and remediation of this site. The Company has also been approached by a North Carolina municipality that is the current owner of another MGP site that was formerly owned by Tide Water Power. The Company is engaged in discussions with that municipality concerning a possible cost- sharing arrangement with respect to the investigation and, if necessary, the remediation of that site. Due to the uncertainty concerning potential environmental harm and the full extent to which remedial action will be required at the two sites formerly owned by Tide Water Power, the total cost of investigating and remediating these sites is not determinable at this time.
The Company is continuing its investigation regarding the identities of parties connected to individual MGP sites, the relative relationships of the Company and other parties to those sites, and the degree, if any, to which the Company should undertake shared voluntary efforts with others at individual sites. Except as noted above, 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.
4. OTHER ENVIRONMENTAL MATTERS. 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. In November 1994, the Company was asked by DEM to expand its assessment to determine whether the No. 2 fuel oil spill had migrated off-site. Off-site contamination was confirmed; however, it is not clear that the Company is responsible for such off-site contamination. The Company will discuss this matter with DEM. Although the Company cannot predict the outcome of this matter, it believes that any remediation expense would not exceed $100,000 annually.
5. ENVIRONMENTAL ACCRUAL. In 1994, the Company accrued a liability for the estimated costs associated with investigation and remediation activities for certain MGP sites and for sites other than MGP sites. This accrual was not material to the results of operations of the Company.
NUCLEAR MATTERS _______________
1. GENERAL. Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, as amended, operation of nuclear plants is intensively regulated by the 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.b. 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 1995, 1996 and 1997 are expected to total approximately $72 million, $58 million and $34 million, respectively (including AFUDC).
2. SPENT FUEL AND OTHER HIGH-LEVEL RADIOACTIVE WASTE. The Nuclear Waste Policy Act of 1982 (Nuclear Waste Act) provides the framework for development by the federal government of interim storage and permanent disposal facilities for high-level radioactive waste materials. The Nuclear Waste Act promotes increased usage of interim storage of spent nuclear fuel at existing nuclear plants. The Company will continue to maximize the usage of spent fuel storage capability within its own facilities for as long as feasible. Pursuant to the Nuclear Waste Act, the Company, through a joint agreement with the U. S. Department of Energy (DOE) and the Electric Power Research Institute, has built a demonstration facility at the Robinson Plant that allows for the dry storage of 56 spent nuclear fuel assemblies. As of December 31, 1994, sufficient on-site spent nuclear fuel storage capability is available for the full-core discharge of Brunswick Unit No. 1 through 1995, 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, dry storage may be necessary in conjunction with the decommissioning of the units. The Company is maintaining full-core discharge capability for the Brunswick Units and Robinson Unit No. 2 by transferring spent nuclear fuel by rail to the Harris Plant. As a contingency to the shipment by rail of spent nuclear fuel, on April 27, 1989, the Company filed an application with the NRC for the issuance of a license to construct and operate an independent spent fuel storage facility for the dry storage of spent nuclear fuel at the Brunswick Plant. Due to the success of the Company's shipping efforts to date, however, the Company has requested that the NRC suspend review of the Company's license application pending notification by the Company of its desire to continue the application process. The Company cannot predict the outcome of this matter.
As required by the Nuclear Waste Act, the Company entered into a contract with the DOE under which the DOE agreed to dispose of the Company's spent nuclear fuel. The contract includes a provision requiring the Company to pay the DOE for disposal costs. Disposal costs of fuel burned are based upon actual nuclear generation and are paid on a quarterly basis. Effective January 31, 1992, the DOE revised the method for calculating the nuclear waste disposal cost, which reduced the Company's quarterly payment. Overpayments, with interest, were refunded in the form of credits over the period 1992 through 1994. 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. When shipments to the existing regional compact site cease on December 31, 1995, present projections indicate that existing on-site storage facilities at the Company's nuclear plants are sufficient to provide approximately one year 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 a portion of decommissioning expense into the Trust.
With regard to the Company's recovery through rates of nuclear decommissioning costs, in the Company's retail jurisdictions, provisions for nuclear decommissioning costs were approved by the NCUC and the SCPSC in the Company's 1988 general rate cases, and were based on site-specific estimates that included the costs for removal of all radioactive and other structures at the site. In the wholesale jurisdiction, the provisions for nuclear decommissioning costs are based on amounts agreed upon in applicable rate settlements. Decommissioning cost provisions, which are included in depreciation and amortization, were $29.5 million in 1994, $34.0 million in 1993 and $27.1 million in 1992. Accumulated decommissioning costs, which are included in accumulated depreciation, were $252.7 million at December 31, 1994, and $221.6 million at December 31, 1993, and include amounts retained internally and amounts funded in the Trust. The balance of the Trust, which is included in miscellaneous other property and investments, was $67.6 million at December 31, 1994, and $44.5 million at December 31, 1993. Trust earnings, which increase the trust balance with a corresponding increase in accumulated decommissioning, were $1.5 million in 1994, $1.2 million in 1993 and $.8 million in 1992. Based on the site-specific estimates discussed below and using an assumed after-tax earnings rate of 8.5% and an assumed cost escalation rate of 4%, current levels of rate recovery for nuclear decommissioning costs are adequate to provide for decommissioning of the Company's nuclear facilities.
b. The Company's most recent site-specific estimates of decommissioning costs were developed in 1993 using 1993 cost factors, and are based on prompt dismantlement decommissioning, which reflects the cost of removal of all radioactive and other structures currently at the site, with such removal occurring shortly after operating license expiration. See paragraph 5 below for expiration dates of operating licenses. These estimates, in 1993 dollars, are as follows: $257.7 million for Robinson Unit No. 2; $235.4 million for Brunswick Unit No. 1; $221.4 million for Brunswick Unit No. 2; and $284.3 million for the Harris Plant. These estimates are subject to change based on a variety of factors, including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning, and changes in federal, state or local regulations. The cost estimates exclude the portion attributable to Power Agency, which holds an undivided ownership interest in 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.
c. The Financial Accounting Standards Board has added a project to its agenda regarding the electric utility industry's current accounting practices related to decommissioning costs. Any changes to these practices could affect such items as: 1) when the decommissioning obligation is recognized, 2) where balances of accumulated decommissioning costs are recorded, 3) where income earned on external decommissioning trust balances is recorded and 4) the levels of annual decommissioning cost provisions. The Financial Accounting Standards Board is in the early stages of this project, and consequently, it is uncertain what impacts, if any, this project may have on the Company's accounting for decommissioning costs.
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 was completed in 1994. This documentation will remain at the plants and will be provided to the NRC upon request.
7. OTHER NUCLEAR MATTERS.
a. 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 Energy Institute (formerly the Nuclear Management and Resources Council) and with other utilities to develop its compliance approach and to minimize the financial and operational impacts of the new rule. The Company anticipates its compliance will be on schedule and is evaluating the magnitude of the financial and operational impacts of this new rule. The Company cannot predict the outcome of this matter.
b. On November 23, 1988, the NRC requested in Generic Letter 88-20 that utilities perform Individual Plant Examinations (IPEs) to determine potential vulnerabilities to severe accidents beyond the design basis accidents for which the plants are designed. These are considered to be very low probability events. The Company submitted the results of the first phase (for internally initiated events) in August 1992 for the Brunswick and Robinson Plants. Based on those results, potential enhancements for the Robinson Plant were evaluated and several enhancements were made to the Robinson Plant. These changes had insignificant financial and operational impacts. For the Brunswick Plant, no modifications were required to meet the guidelines of the IPE. On August 20, 1993, the Company submitted the results of the Harris Plant IPE. While some Harris Plant procedural changes were made due to the IPE results, the IPE did not reveal any significant financial or operational impacts or identify any need for plant modifications. 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), which will be completed for all three plants and submitted to the NRC in 1995.
c. 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 Brunswick Plant outage that began in April 1992. 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. The Company commenced startup of Unit No. 1 on February 1, 1994, and Unit No. 1 was returned to normal operation on February 23, 1994, after successfully completing extensive startup testing. In July 1993, the Company also determined that the Brunswick Unit No. 2 shroud had minor crack indications which did not compromise the safety or operation of the Unit. Shroud modifications, similar to those performed on Unit No. 1, were successfully completed on Unit No. 2 during the spring 1994 refueling outage, and Unit No. 2 resumed generating electricity on June 30, 1994. Costs associated with the shroud modifications were not 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. The petitioners failed to provide the NRC or 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. On October 19, 1994, the Director of the NRC's Office of Nuclear Reactor Regulation issued a decision which granted the petitioners' request for an NRC investigation, but concluded that no substantial health and safety issue remains that would warrant institution of further proceedings. The NRC Commissioners declined to review the decision. Thus, the decision became the NRC's final action on November 14, 1994. The petitioners did not file an appeal with the United States Court of Appeals by the February 13, 1995 deadline.
d. 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, a 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. In early February 1994, the Company satisfied the conditions of the NRC's November 19, 1993 Confirmatory Action letter, and returned Robinson Unit No. 2 to service on March 21, 1994 under a power ascension plan. 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. On May 9, 1994, the NRC issued a Severity Level IV Notice of Violation (the next to the lowest severity level) concluding that this situation involved noncompliance with certain NRC requirements. The NRC did not propose a civil penalty in connection with this matter. In a letter to the NRC dated June 8, 1994, the Company acknowledged that the violations had occurred, clarified the events surrounding the occurrences, and described the corrective actions that had been taken to address the situation.
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 proposed penalty was reduced to $37,500 due to the Company's comprehensive performance in analyzing the root cause of the diesel generator problem. On April 13, 1994, the Company submitted a written response to the Notice of Violation and Proposed Imposition of Civil Penalty that the NRC issued in connection with the degradation of the Robinson Unit No. 2 diesel generators, and paid the assessed $37,500 civil penalty.
On February 8, 1994 the NRC issued its Systematic Assessment of Licensee Performance 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 had 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.
The Company received a letter, dated May 6, 1994, from the NRC regarding an apparent violation of NRC requirements related to inattention to licensed duties which was identified at the Company's H. B. Robinson Plant. An enforcement conference between the Company and the NRC was held on May 16, 1994, to discuss this matter. On May 30, 1994, the NRC issued a Severity Level IV Notice of Violation to the Company in connection with this matter, but did not propose a civil penalty. In a letter to the NRC dated June 29, 1994, the Company acknowledged that the violation had occurred and described the corrective actions that had been taken to address the occurrence.
The NRC report regarding inspections conducted at the Robinson Plant during the period May 22 through June 24, 1994, identified certain activities, which occurred in January 1994 that might have violated certain NRC requirements. The activities related to the failure to take adequate corrective action on issues identified by a contractor, inadequate testing of ventilation equipment, and inadequate corrective actions on a design concern involving an isolation valve. An enforcement conference between the Company and the NRC was held on July 26, 1994 to determine whether a violation had occurred and if so, to assess the significance of the violation. By letter dated August 30, 1994, the NRC issued a Notice of Violation and Imposition of Civil Penalty in the amount of $75,000 involving the Company's testing of ventilation equipment at its H.B. Robinson Plant. The Notice also indicated that activities related to the adequacy of corrective action on issues identified by a contractor and the adequacy of corrective actions on a design concern involving an isolation valve constituted violations of NRC requirements; however, no civil penalty was assessed in connection with those violations. By letter dated September 29, 1994, the Company responded to the Notice of Violation and paid the assessed penalty.
In November 1994, the NRC proposed a $100,000 civil penalty for noncompliance with NRC requirements at the Robinson Plant. During a plant cooldown on February 26, 1994, the plant exceeded a technical specification limit. At one point during the process of the plant shutdown, the reactor's pressurizer was allowed to cool down at a rate that is higher than the specified maximum rate. After extensive analysis, the Company determined that the structural integrity of the pressurizer had not been negatively affected and neither had the useful life of any reactor component. The Company has implemented additional administrative controls to monitor the pressurizer throughout the cooldown process, and has conducted additional training to ensure proper monitoring. The NRC concurs with the corrective actions being taken by the Company. The Company paid the assessed penalty on December 22, 1994.
e. The Company is insured against public liability for a nuclear incident up to $8.9 billion per occurrence, which is the maximum limit on public liability claims pursuant to the Price- Anderson Act. The $8.9 billion coverage includes $200 million primary coverage and $8.7 billion secondary financial protection through assessments on nuclear reactor owners. In the event that public liability claims from an insured nuclear incident exceed $200 million, the Company would be subject to a pro rata assessment, for each reactor it owns, of up to $75.5 million, plus a 5% surcharge, for each incident. Payment of such assessment would be made over time as necessary to limit the payment in any one year to no more than $10 million per reactor owned. Power Agency would be responsible for its ownership share of the assessment on jointly- owned 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 1991 through 1995 is set forth below:
1991 1992 1993 1994 1995 ____ ____ ____ ____ ____ (estimated)
Fossil 47% 56% 54% 43% 46% Nuclear 41 27 31 42 41 Purchased Power 10 15 13 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 86% of its coal burn requirements in 1995. During 1993 and 1994, the Company obtained approximately 73% (7,198,000 tons), and 93% (8,120,220 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 1996 to 2006. During 1994, the Company maintained from 40 to 92 days' supply of coal, based on anticipated burn rate. All of the coal that the Company is currently purchasing under intermediate and long-term agreements is considered to be low sulfur coal by industry standards. Recent amendments to the Clean Air Act may result in increases in the price of low sulfur coal which continue beyond the effective date of the second phase of the Act. See ITEM 1, "Environmental Matters," paragraph 2. The Company purchased approximately 2,650,000 tons of coal in the spot market during 1993 and 1,690,000 tons in 1994. The Company's contract coal purchase prices during 1994 ranged from approximately $23.19 to $40.63 per ton (F.O.B. mine adjusted to 12,000 Btu/lb.). The average cost (including transportation costs) to the Company of coal delivered for the past five years is as follows:
Year $/Ton Cents/Million BTU ____ _____ _________________
1990 45.88 183 1991 47.40 190 1992 43.25 174 1993 43.10 172 1994 43.36 174
3. OIL. The Company uses No. 2 oil primarily for its combustion turbine units, which are used for emergency backup and peaking purposes, and for boiler start-up and flame stabilization. The Company burned approximately 9.1 million and 12.6 million gallons of No. 2 oil during 1993 and 1994, 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 1.8% of the Company's total burned fuel cost. In 1994, No. 2 oil, natural gas and propane accounted for 1.9% of the Company's total burned fuel cost. The availability and cost of fuel oil could be adversely affected by energy legislation enacted by Congress, disruption of oil or gas supplies, labor unrest and the production, pricing and embargo policies of foreign countries.
4. NUCLEAR. The nuclear fuel cycle requires the mining and milling of uranium ore to provide uranium oxide concentrate (U3O8), the conversion of U3O8 to uranium hexafluoride (UF6), the enrichment of the UF6 and the fabrication of the enriched uranium into fuel assemblies. Existing 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 1995, and the Harris Plant through 1996. The Company currently has contracts for the ongoing procurement of raw materials and services for its nuclear units through the years shown below:
Raw Materials And Services ___________________________________________________ Unit Uranium Conversion Enrichment Fabrication ____ _______ __________ __________ ___________
Robinson No. 2 1995 1995 2000 2000 Brunswick No. 1 1995 1995 2000 1998 Brunswick No. 2 1995 1995 2000 1998 Harris Plant 1996 1995 2000 1999
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. At December 31, 1994, the Company had recorded a liability of $67.4 million representing its estimated share of the contributions and is recovering this expense as a component of fuel cost.
6. PURCHASED POWER. In 1994 the Company purchased 6,710,346 MWh or approximately 13% of its energy requirements and had available 2,840 MW of firm purchased capacity under contract at the time of peak load. The Company may acquire purchased power capacity in the future to accommodate a portion of its system load needs.
OTHER MATTERS _____________
1. SAFETY INSPECTION REPORTS. On April 3, 1990, the FERC sent a letter to the Company providing comments on its review of the Company's Fifth (1987) Independent Consultant's Safety Inspection Report (required every five years under FERC Regulation 18 CFR Part 12) for the Walters Hydroelectric Project and requesting the Company to undertake certain supplemental analyses and investigations regarding the stability of the dam under extreme and improbable loading conditions. Similar letters were sent by the FERC on May 30, 1990, with respect to the Company's Blewett and Tillery Hydroelectric Plants. With the independent consultant, the Company has begun addressing the issues raised by the FERC and is working with the FERC to complete investigations and analyses with respect to each of these matters. On November 30, 1994, the Company submitted the independent consultant's report to the FERC regarding the stability of the dam at the Walters Project. The independent consultant concluded that the Walters dam has adequate structural stability and reserve capacity to resist both usual and unusual loading conditions without failure and that structural remediation is neither warranted nor recommended. While the Company does not believe that there are any stability concerns that would be cause for any imminent safety concerns, the FERC's review and analysis of the consultant's report are pending. The consultant's final reports regarding the Blewett and Tillery Hydroelectric Plants are not yet completed. Depending on the outcome of these matters, the Company could be required to undertake efforts to enhance the stability of the dams. The cost and need for such efforts have not been determined. The Company cannot predict the outcome of these matters.
2. MARSHALL HYDROELECTRIC PROJECT. On November 21, 1991, the FERC notified the Company that the 5 MW Marshall Hydroelectric Project is no longer exempt from 18 CFR Part 12, 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.
3. STONE CONTAINER DISPUTE. On April 20, 1994, the Company filed a Complaint with the FERC (Docket No. EL-94-62-000 and QF85- 102-005) and in the United States District Court for the Eastern District of North Carolina in Raleigh, North Carolina (Civil Action No. 5:94-CV-285-DI) claiming that the rate the Company pays for power it purchases from Stone Container Corporation (Stone Container) is invalid. The Company entered into a twenty-year purchase power agreement with Stone Container in 1984, and in 1987 began receiving power from a cogeneration facility operated by Stone Container in Florence, South Carolina. It is the Company's position that when Stone Container elected to sell the facility's gross output under a "buy all/sell all" option in 1991, the facility lost its status as a "qualified facility" under PURPA and became a public utility. As a result, the contract rate the Company pays for power purchased from the facility is no longer valid, and a just and reasonable rate should be established by the FERC under the Federal Power Act. The Company will continue to purchase electricity from Stone Container at the current contract rate pending the outcome of this litigation. The Company cannot predict the outcome of this matter.
4. TAX REFUND DISPUTE. On April 28, 1994, the Company filed a Complaint against the U.S. Government in the United States District Court for the Eastern District of North Carolina in Raleigh, North Carolina (Civil Action No. 5:94-CV-313-BR3) seeking a refund of approximately $188 million representing tax and interest related to depreciation deductions the Internal Revenue Service (IRS) previously disallowed for the years 1986 and 1987 on the Company's Harris Plant. The Company maintains that under applicable laws and regulations the Harris Plant was ready and available for operation in 1986. The IRS has previously denied some of the depreciation deductions on the Company's tax returns for the years in question on the ground that in its view the plant was not placed in service until 1987. The Company cannot predict the outcome of this matter.
5. WOLF CREEK COAL DISPUTE. On November 4, 1994, the Company filed a complaint against SMC Mining Company, Wolf Creek Collieries Company and Kermit Coal Company (collectively, the Sellers) in the United States District Court for the Eastern District of North Carolina in Raleigh, North Carolina (Civil Action No. 5:94-CV-846-BO(2)). The Sellers are all companies owned by Ziegler Coal Holding Company (Ziegler). Under the terms of a 1971 contract, as amended, the Sellers are to supply the Company with coal having certain qualities and characteristics from the Wolf Creek mine (Wolf Creek) in Kentucky. The contract provides that the Company has the right to refuse to accept further deliveries from the Sellers if the coal they ship fails to meet the specification for sulfur content for two consecutive months. During the months of August and September 1994, the Sellers shipped to the Company Wolf Creek coal that did not meet the sulfur specifications provided in the contract. As a result of the Sellers' shipment of non-complying coal, on November 4, 1994, the Company exercised its right to suspend future shipments of coal from Wolf Creek until the Sellers can give the Company reasonable assurance that future shipments will meet the contract's specifications. The Complaint asks the court to determine whether the dispute is subject to arbitration and that the Company's suspension of future shipments from the Sellers was legal. On November 4, 1994, the Sellers filed a Complaint against the Company in the Circuit Court of Martin County, Kentucky (Civil Action No. 94-CZ-00212), asking the court to restrain the Company from refusing to accept future shipments of coal under the 1971 contract. On November 4, 1994, the court issued an ex parte temporary restraining order (TRO) which prevents the Company, for the time being, from refusing contract coal deliveries from Wolf Creek. The Company removed the Kentucky state court action to the United States District Court for the Eastern District of Kentucky. On November 9, 1994 the Company filed in the Kentucky federal court a response to the state court's TRO. The response sought to dissolve the TRO, which would allow the Company to refuse coal shipments from Wolf Creek until the dispute is settled. In its response, the Company also moved for transfer of the case to the United States District Court for the Eastern District of North Carolina, which was subsequently granted. On December 1, 1994, a federal District Court judge in Raleigh signed a consent order establishing a three member panel to arbitrate the dispute. The consent order provides that in the interim, Ziegler will ship only coal that complies with the quality specifications as the Company interprets the contract. The Company will receive a price adjustment on the coal purchases if its view of the contract is upheld. The arbitration, currently scheduled to begin in late March 1995 and conclude by the end of April 1995, will resolve the issues of suspension and compliance with contractual quality standards. The arbitration will also address other issues raised by the Company, including two requests for adequate assurance of performance under N.C. Gen. Stat. Section 25-2-609. The Company requested in October 1994 that Sellers provide assurance that they were (1) not sending the Company coal from sources (or mines) outside those specified in the contract and (2) that it had adequate reserves to meet its supply obligations under the contract. Whatever the outcome of this dispute, the Company anticipates no problems in ensuring sufficient coal supplies for its plants. The Company cannot predict the outcome of this matter.
6. CARONET, INC. On November 29, 1994, the Company established a wholly-owned subsidiary, CaroNet, Inc., and the subsidiary joined a regional partnership led by BellSouth Personal Communications, Inc. (BellSouth). On March 14, 1995 BellSouth won its bid for a Federal Communications Commission (FCC) license for the partnership to operate a Personal Communications Services (PCS) system covering most of North Carolina and South Carolina, as well as a small portion of Georgia. PCS, a wireless communications technology, is expected to provide high-quality mobile communications. Wireless technology could also support automated meter reading, automated service connection and disconnection, and control and monitoring of certain aspects of the Company's electric transmission and distribution systems. BellSouth will transfer the PCS license to the partnership. BellSouth will be general partner and handle day-to-day management of the business.
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, 1994, the Company had 5,822 pole miles of transmission lines including 292 miles of 500 kV and 2,790 miles of 230 kV lines, and distribution lines of approximately 39,907 pole miles of overhead lines and approximately 7,557 miles of underground lines. Distribution and transmission substations in service had a transformer capacity of approximately 35,250 kVA in 2,270 transformers. Distribution line transformers numbered 391,474 with an aggregate 15,744,200 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 right- of-way easements over private property on which transmission and distribution lines are located.
The Company believes that its generating facilities are suitable, adequate, well-maintained and in good operating condition.
Plant Accounts (including nuclear fuel) - _______________________________________
During the period January 1, 1990 through December 31, 1994, there was added to the Company's utility plant accounts $1,779,168,000, there was retired $476,328,000 of property and there were transfers to other accounts and adjustments for a net decrease of $319,690,000 resulting in net additions during the period of $983,149,000 or an increase of approximately 11.23%.
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 1994.
EXECUTIVE OFFICERS OF THE REGISTRANT ____________________________________
Name Age Recent Business Experience ____ ___ __________________________
Sherwood H. Smith, Jr. 60 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 56 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, January 1990-August 1992; President and Chief Executive Officer, System Energy Resources, Inc., 1986- August 1992; President and Chief Executive Officer, Entergy Operations, Inc., June 1990-April 1992. Member of Board of Directors of Arkansas Power & Light Company and Louisiana Power & Light Company, January 1990-August 1992; Member of Board of Directors of System Fuels, Inc., 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. 64 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 E. Eury 58 EXECUTIVE VICE PRESIDENT - Power Supply, April 1989 to July 1994 (retired); Senior Vice President - Operations Support, June 1986; Senior Vice President - Fossil Generation and Power Transmission Group, August 1983.
William S. Orser 50 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, 1987-1990. Prior to 1987, Mr. Orser held various other positions with Detroit Edison, and with Portland General Electric Company, Southern California Edison, and the U. S. Navy.
James M. Davis, Jr. 58 SENIOR VICE PRESIDENT, Group Executive - Power Operations, June 1986 to present; Senior Vice President - Operations Support Group, August 1983.
Norris L. Edge 63 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.
Cecil L. Goodnight 52 SENIOR VICE PRESIDENT, Human Resources and Support Services, March 1995- present; Vice President - Human Resources (formerly Employee Relations Department), May 1983 to March 1995.
Glenn E. Harder 43 SENIOR VICE PRESIDENT, Group Executive - Financial Services, October 1994 to present; Vice President - Financial Strategies and Treasurer, Entergy Corporation, September 1991 to October 1994; Vice President -Administrative Services & Regulatory Affairs, Entergy Operations, Inc., May 1991 to August 1991; Vice President, Accounting and Treasurer, System Energy Resources, Inc., October 1986 to May 1991. Before joining the Company, Mr. Harder held various senior management and executive positions with Entergy Corporation, an electric utility holding company with operations in Arkansas, Louisiana and Mississippi, and related entities.
Richard E. Jones 57 SENIOR VICE PRESIDENT, GENERAL COUNSEL AND SECRETARY, Group Executive - Legal, Rates, Communications, Community Relations 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 57 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, as reported as composite transactions in The Wall Street Journal, _______________________ and dividends paid are as follows:
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
1994 High Low Dividends Paid ____ ____ ___ ______________
First Quarter $ 29 3/4 $ 25 5/8 $ .425 Second Quarter 26 5/8 22 7/8 .425 Third Quarter 27 22 3/4 .425 Fourth Quarter 27 3/4 25 1/4 .425
The December 31 closing price of the Company's Common Stock was $30 1/8 in 1993 and $26 5/8 in 1994.
As of February 28, 1995, the Company had 69,748 holders of record of Common Stock.
On July 13, 1994, the Board of Directors of the Company (Board) authorized the Executive Committee of the Board to repurchase up to 10 million shares of the Company's Common Stock on the open market. Under this stock repurchase program, the Company had purchased approximately 4.4 million shares through December 31, 1994.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS _______ _________________________________________________
RESULTS OF OPERATIONS _____________________
Revenues ________
Unusually mild weather in 1994 contributed significantly to a decrease in revenues as compared to 1993. This weather-related decrease totaled $86 million. Additionally, in 1994 the Company completed recovery of the portion of abandoned plant costs collected under a special rider resulting from the 1990 North Carolina Utilities Commission (NCUC) Order on Remand. This reduced 1994 revenues by $28 million, but did not significantly impact net income due to a corresponding decrease in amortization expense. Partially offsetting these decreases was an increase in revenue of $101 million due to customer growth and changes in customer usage patterns.
The increase in revenues in 1993 is primarily the result of an increase in energy sales of 6.2%. The effects of weather did not significantly impact revenues from 1992 to 1993. Revenues did not increase from 1992 to 1993 proportionately with energy sales due to a decline in the fuel factors included in rates and due to lower demand-related charges for certain customer classes.
Operating Expenses __________________
Fuel for generation decreased in 1994 primarily due to a change in the generation mix. Nuclear generation, as a percentage of total generation, increased to 46%, from 34%, and higher-cost fossil generation decreased to 52%, from 64%, due to greater availability of the Company's nuclear generating facilities. In 1993, an 8% increase in total generation, offset somewhat by a decrease in the cost of fossil fuel and by increased use of nuclear generation, resulted in a slight increase in fuel for generation.
Deferred fuel reflects fuel costs or recoveries that are deferred through fuel clauses required by the Company's regulators. These clauses allow the Company to recover fuel costs and fuel-related purchased power costs through the fuel component of customer rates. Any difference between actual costs incurred and the fuel component collected in customer billings is reflected in operating expenses as deferred fuel. As a result, except for fuel settlements such as those discussed below, net income is not impacted significantly by fluctuations in fuel costs.
In 1994, the Company reached settlement agreements with regulators in the North Carolina and South Carolina retail jurisdictions and agreed to forgo recovery of $8 million of deferred fuel costs. In 1993, the Company agreed to forgo recovery of $41.1 million of deferred fuel costs related to the Brunswick Plant's extended outage in 1992 and 1993. The net effect of these agreements resulted in a decrease of $33.1 million in deferred fuel cost from 1993 to 1994. Excluding the effect of these settlements, deferred fuel costs increased from 1993 to 1994 due to lower fuel costs associated with increased nuclear generation and due to the recovery of prior fuel costs as allowed by the North Carolina fuel adjustment statute. From 1992 to 1993, excluding the effect of the 1993 settlements, deferred fuel costs increased due to lower fuel costs.
The increase in purchased power from 1992 to 1994 is primarily attributable to an agreement under which the Company began purchasing 400 megawatts of generating capacity from Duke Power Company in July 1993. Purchases under this agreement accounted for an increase in purchased power of $26 million in 1994 and $37 million in 1993. In addition, purchases from North Carolina Eastern Municipal Power Agency (Power Agency) increased $8 million in 1994 and $14 million in 1993, primarily due to the increased buyback provisions of the Company's 1993 agreement with Power Agency (see Other Business). A substantial portion of the increase in purchased power is capacity cost and, therefore, not recoverable through the Company's fuel clauses.
The increase in other operating expenses from 1993 to 1994 is due to increases in various cost categories such as benefits, salaries and demand-side management programs. Partially offsetting these increases was a 1994 adjustment of $23 million to reduce the Company's nuclear insurance reserves. Other operating expenses increased from 1992 to 1993 due to 1) the Brunswick Plant outage in 1992 and 1993, 2) the recognition of increased expense for postretirement benefits other than pensions due to new accounting requirements and 3) 1992 adjustments that were made to certain accrual and asset balances as a result of more current information at that time. Excluding the effect of the 1994 insurance reserve adjustment, the Company's business plan for the period through 1997 does not project an increase in other operating expenses.
Maintenance expense decreased from 1992 to 1994 primarily due to a decrease in costs associated with the Brunswick Plant's outage in 1992 and 1993. Additionally, maintenance expense decreased in 1993 due to the capitalization of costs associated with plant modifications as compared to the prior year.
The decrease in depreciation and amortization from 1993 to 1994 is primarily attributable to the completion of the amortization of abandoned plant costs for Harris Unit No. 2 and of costs associated with the 1990 NCUC Order on Remand; these decreases in amortization totaled $25 million. In 1993, the Company began amortizing costs associated with two significant software projects, which contributed to a portion of the increase in depreciation and amortization from 1992 to 1993.
The fluctuation in Harris Plant deferred costs from 1992 to 1993 is primarily due to an adjustment made in 1992 in order to better match these costs with the associated revenue recovery. This adjustment decreased 1992 operating expenses by $13.4 million, net of tax. Contributing to the increase in 1993 were adjustments related to the settlement between North Carolina Electric Membership Corporation (NCEMC) and the Company (see Other Business).
Other Income ____________
The fluctuation in Harris Plant carrying costs from 1992 to 1994 is primarily related to the Company's settlement with NCEMC, which was recorded in 1993 and increased carrying costs in that year.
The Harris Plant disallowance - Power Agency line item reflects a write-off recorded as a result of the 1993 settlement with Power Agency (see Other Business).
Beginning in 1994, the Company is no longer recording interest income related to the Company's qualified employee stock ownership plan (ESOP) loan (see New Accounting Standard). Interest income also decreased in 1994 due to the Company's 1993 settlement with Westinghouse Electric Corporation (Westinghouse), which increased interest income in 1993 (see Other Business). Partially offsetting these decreases was an increase for interest income related to certain IRS audit issues. The increase in interest income from 1992 to 1993 is primarily due to the Westinghouse settlement.
Other income, net, decreased in 1994 primarily due to a change in accounting for ESOPs.
Interest Charges ________________
Interest charges on long-term debt decreased from 1992 to 1994 due to long-term debt refinancings that allowed the Company to take advantage of lower interest rates. In addition, for 1993 as compared to 1992, interest rates on the Company's variable rate debt were lower.
LIQUIDITY AND CAPITAL RESOURCES _______________________________
Capital Requirements ____________________
Estimated capital requirements for the period 1995 through 1997 primarily reflect construction expenditures that will be made to add generating facilities, to upgrade existing generating facilities and to add transmission and distribution facilities to meet customer growth. The Company's capital requirements for those years are reflected below (in millions).
1995 1996 1997 ____ ____ ____
Construction expenditures $358 $445 $527 Nuclear fuel expenditures 99 77 71 AFUDC (19) (25) (34) Mandatory redemptions of long-term debt 275 105 100 ____ ____ ____ Total $713 $602 $664 ==== ==== ====
The table above includes Clean Air Act requirement expenditures of approximately $117 million and generating facility addition expenditures of approximately $287 million for the period 1995 through 1997. The generating facility addition expenditures will primarily be used to construct new combustion turbine units, which are intended for use during periods of high demand. The units are scheduled to be placed in service in 1997 through 2000.
The 1990 amendments to the Clean Air Act (Act) require substantial reductions in sulfur dioxide and nitrogen oxides emissions from fossil-fueled electric generating plants. The Company was not required to take action to comply with the Act's Phase I requirements, which had to be met by January 1, 1995. Phase II of the Act, which contains more stringent provisions, will become effective January 1, 2000. To reduce sulfur dioxide emissions as required by Phase II, the Company will modify equipment to allow certain of its plants to burn lower-sulfur coal, and the Company 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 2007 by utilizing lower-sulfur coal and 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. The Company has purchased emission allowances under the EPA's emission allowance trading program.
The Company estimates that the total capital cost to comply with Phase II of the Act will approximate $273 million during the period 1995 through 1999 and an additional $272 million during the period 2000 through 2007. 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 $18 million for the period 1995 through 1999, $35 million for the period 2000 through 2006 and by $24 million annually beginning in 2007. Additionally, fuel costs are expected to increase by a total of approximately $277 million for the period 2000 through 2006 and by approximately $62 million annually beginning in 2007. The Company expects these increased fuel costs to be recoverable through the Company's fuel clauses. Actual plans for compliance with the Act's requirements have not been finalized and the amount required for capital expenditures and for increased operating, maintenance and fuel expenditures cannot be determined with certainty at this time. The NCUC and the South Carolina Public Service Commission (SCPSC) are allowing the Company to accrue carrying charges on its investment in emission allowances.
The Company has two long-term agreements for the purchase of power from other utilities. The first agreement provides for the purchase of 250 megawatts of capacity from Indiana Michigan Power Company's Rockport Unit No.2. The estimated minimum annual payment for these power purchases is approximately $30 million, which represents capital-related capacity costs. Other costs include demand-related production expenses, fuel and energy-related operation and maintenance expenses. In 1994, purchases under this agreement totaled $61.9 million, including transmission use charges. The agreement expires in 2009. The second agreement is with Duke Power Company for the purchase of 400 megawatts of firm capacity through mid-1999. The estimated minimum annual payment for these power purchases is approximately $43 million, which represents capital-related capacity costs. Other costs include fuel and energy-related operation and maintenance expenses. Purchases under this agreement, including transmission use charges, totaled $62.9 million in 1994. The agreement with Duke Power Company was recently approved by the Federal Energy Regulatory Commission (FERC).
In addition, the Company is obligated to purchase a percentage of Power Agency's ownership capacity of and energy from the Mayo Plant and the Harris Plant through 1997 and 2007, respectively. The estimated minimum annual payments for these purchases, which reflect capital-related capacity costs, total approximately $27 million. Other costs of such purchases are primarily demand-related production expenses, fuel and energy-related operation and maintenance expenses. Purchases under the agreement with Power Agency totaled $60.4 million in 1994.
Cash Flow and Financing _______________________
Net cash used in investing activities primarily consists of capital expenditures, which include replacement or expansion of existing facilities and construction to comply with pollution control laws and regulations. Capital expenditures in 1994 were lower than in 1993 primarily due to work performed at the Brunswick Plant in 1993.
During 1994, the Company issued $322.6 million in long-term debt. The proceeds of these issuances were primarily used to redeem or retire $267.4 million of long-term debt. External funding requirements, which do not include early redemptions of long-term debt or redemptions of preferred stock, are expected to approximate $417 million in 1995 and $120 million in 1997. These funds will be required for construction, mandatory redemptions of long-term debt and general corporate purposes, including the repayment of short-term debt. The Company does not expect to have external funding requirements in 1996.
In 1994, the Board of Directors of the Company authorized the Executive Committee of the Board to repurchase up to 10 million shares of the Company's common stock on the open market. Under this stock repurchase program, the Company has purchased approximately 4.4 million shares through December 31, 1994.
The Company has on file with the Securities and Exchange Commission (SEC) a shelf registration statement enabling the Company to issue an aggregate of $450 million principal amount of first mortgage bonds, and an additional $250 million combined aggregate principal amount of first mortgage bonds and/or unsecured debt securities of the Company.
The Company's ability to issue first mortgage bonds and preferred stock is subject to earnings and other tests as stated in certain provisions of its mortgage, as supplemented, and charter. The Company has the ability to issue an additional $3.4 billion in first mortgage bonds and an additional 14 million shares of preferred stock at an assumed price of $100 per share and a $8.63 annual dividend rate. The Company also has ten million authorized preference stock shares available for issuance that are not subject to an earnings test.
The Company's access to outside capital depends on its ability to maintain its credit ratings. The Company's first mortgage bonds are currently rated A2 by Moody's Investors Service, A by Standard & Poors and A+ by Duff & Phelps. In order to provide flexibility in the timing and amounts of long-term financing, the Company uses short-term financing in the form of commercial paper backed by revolving credit agreements. These revolving credit agreements total $307.9 million. The Company had $68.1 million of commercial paper outstanding at December 31, 1994, which Standard & Poors and Moody's Investors Service have rated A-1 and P-1, respectively.
The amount and timing of future sales of Company securities will depend upon market conditions and the specific needs of the Company. The Company may from time to time sell securities beyond the amount needed to meet capital requirements in order to allow for the early redemption of outstanding issues of long-term debt, the redemption of preferred stock, the reduction of short-term debt or for other corporate purposes.
OTHER MATTERS _____________
Environmental _____________
The Company is subject to federal, state and local regulations addressing air and water quality, hazardous and solid waste management and other environmental matters.
Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under various federal and state laws, and a liability may exist for their remediation. There are several manufactured gas plant (MGP) sites to which the Company and certain entities that were later merged into the Company may have had some connection. In this regard, the Company, along with other entities alleged to be former owners and operators of MGP sites in North Carolina, is participating in a cooperative effort with the North Carolina Department of Environment, Health and Natural Resources, Division of Solid Waste Management (DSWM) to establish a uniform framework for addressing those sites. 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. To date, the Company has not entered into any such orders.
The Company has recently been approached by another North Carolina public utility concerning a possible cost-sharing arrangement with respect to the investigation and, if necessary, the remediation of four MGP sites. The Company is currently engaged in discussions with the other utility regarding this matter.
In addition, a current owner of property that was the site of one MGP owned by Tide Water Power Company (Tide Water Power), which merged into the Company in 1952, and the Company have entered into an agreement to share the cost of investigation and, if necessary, remediation of this site. The Company has also been approached by a North Carolina municipality that is the current owner of another MGP site that was formerly owned by Tide Water Power. The Company is engaged in discussions with that municipality concerning a possible cost-sharing arrangement with respect to the investigation and, if necessary, the remediation of that site.
The Company is continuing its investigation regarding the identities of parties connected to several additional MGP sites, the relative relationships of the Company and other parties to those sites and the degree, if any, to which the Company should undertake shared voluntary efforts with others at individual sites.
The Company has been notified by regulators of its involvement or potential involvement in several sites, other than MGP sites, that require remedial action. Although the Company cannot predict the outcome of these matters, it does not anticipate significant costs associated with these sites.
In 1994, the Company accrued a liability for the estimated costs associated with investigation and remediation activities for certain MGP sites and for sites other than MGP sites. This accrual was not material to the results of operations of the Company. Due to the lack of information with respect to the operation of MGP sites for which a liability has not been accrued and due to the uncertainty concerning questions of liability and potential environmental harm, the extent and cost of required remedial action, if any, are not currently determinable. The Company cannot predict the outcome of these matters or the extent to which other MGP sites may become the subject of inquiry.
Nuclear _______
In the Company's retail jurisdictions, provisions for nuclear decommissioning costs were approved by the NCUC and the SCPSC in the Company's 1988 general rate cases and were based on site-specific estimates that included the costs for removal of all radioactive and other structures at the site. In the wholesale jurisdiction, the provisions for nuclear decommissioning costs are based on amounts agreed upon in applicable rate settlements. Based on the site-specific estimates discussed below, and using an assumed after-tax earnings rate of 8.5% and an assumed cost escalation rate of 4%, current levels of rate recovery for nuclear decommissioning costs are adequate to provide for decommissioning of the Company's nuclear facilities.
The Company's most recent site-specific estimates of decommissioning costs were developed in 1993, using 1993 cost factors, and are based on prompt dismantlement decommissioning, which reflects the cost of removal of all radioactive and other structures currently at the site, with such removal occurring shortly after operating license expiration. These estimates, in 1993 dollars, are $257.7 million for Robinson Unit No. 2, $235.4 million for Brunswick Unit No. 1, $221.4 million for Brunswick Unit No. 2 and $284.3 million for the Harris Plant. The estimates are subject to change based on a variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning, and changes in federal, state or local regulations. The cost estimates exclude the portion attributable to Power Agency, which holds an undivided ownership interest in certain of the Company's generating facilities. Operating licenses for the Company's nuclear units expire in the year 2010 for Robinson Unit No. 2, 2016 for Brunswick Unit No. 1, 2014 for Brunswick Unit No. 2 and 2026 for the Harris Plant.
The Financial Accounting Standards Board has added a project to its agenda regarding the electric utility industry's current accounting practices related to decommissioning costs. Any changes to these practices could affect such items as: 1) when the decommissioning obligation is recognized, 2) where balances of accumulated decommissioning costs are recorded, 3) where income earned on external decommissioning trust balances is recorded and 4) the levels of annual decommissioning cost provisions. The Financial Accounting Standards Board is in the early stages of this project, and consequently, it is uncertain what impacts, if any, this project may have on the Company's accounting for decommissioning costs.
As required under the Nuclear Waste Policy Act of 1982, the Company entered into a contract with the U.S. Department of Energy (DOE) under which the DOE agreed to dispose of the Company's spent nuclear fuel. The Company cannot predict whether the DOE will be able to perform its contractual obligations and provide interim storage or permanent disposal repositories for spent nuclear fuel and/or high-level radioactive waste materials on a timely basis.
With certain modifications, the Company's spent fuel storage facilities are sufficient to provide storage space for spent fuel generated on the Company's system through the expiration of the current operating licenses for all of the Company's nuclear generating units. Subsequent to the expiration of the licenses, dry storage may be necessary.
New Accounting Standard _______________________
In 1994, the Company implemented Statement of Position (SOP) 93-6, "Employers' Accounting for Employee Stock Ownership Plans," on a prospective basis. This SOP required the following changes in accounting for the Company's ESOP: 1) ESOP shares that have not been committed to be released to participants' accounts are no longer considered outstanding for the determination of earnings per common share; 2) dividends on unallocated ESOP shares are no longer recognized for financial statement purposes; 3) interest income related to the qualified ESOP loan is no longer recognized; 4) the difference between the acquisition and allocation prices of ESOP shares, which was previously recorded as other income, net, is now recorded directly to common stock; and 5) all tax benefits of ESOP dividends are now recorded to non-operating income tax expense, whereas in 1993, a portion of the tax benefits was recorded directly to retained earnings. In 1992, prior to the implementation of Statement of Financial Accounting Standards No. 109, all tax benefits of ESOP dividends were recorded to retained earnings and were included in the determination of earnings per common share. In addition, pursuant to SOP 93-6, ESOP loan transactions between the Company and the Stock Purchase Savings Plan Trustee are no longer reflected in the Statement of Cash Flows. The implementation of SOP 93-6 resulted in an increase in earnings per common share of approximately $.04 for 1994.
Other Business ______________
In 1993, the Company and Westinghouse reached an agreement that settled all issues related to the Harris and Robinson Plants' steam generators, as well as certain issues related to Harris Unit Nos. 2, 3 and 4 cancellation costs. The effect of the agreement on the Company's results of operations, approximately $17.3 million, net of tax, increased the Company's 1993 earnings by $.11 per common share. In 1993, the Company and Power Agency entered into an agreement to restructure portions of their contracts covering power supplies and interests in several jointly-owned generating units. Under terms of this agreement, the Company increased the amount of capacity and energy purchased from Power Agency's ownership interest in the Harris Plant. Also, the buyback period was extended six years through 2007. In addition, pursuant to the agreement, a portion of the Company's Harris Plant cost 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. The agreement has been approved by the FERC.
As part of its 1993 agreement with the Company, Power Agency will delay the commercial operation date of a combustion turbine electric generating project from 1995 until 1998. The project could displace up to approximately 180 megawatts of capacity that Power Agency currently purchases from the Company. In 1994, the FERC approved an agreement that resolved issues between Power Agency and the Company with respect to the turbine generating project.
In 1994, the FERC approved the Company's license application to continue operating the Company's 105-megawatt Walters Hydroelectric Plant for the next 40 years. In conjunction with the Walters' relicensing proceeding, the FERC also approved a 30-year Power Coordination Agreement (PCA) between the Company and NCEMC. The agreement assures that the Company will continue to be NCEMC's primary source of electricity for the next several years. The PCA allows NCEMC to assume responsibility for up to 200 megawatts of its load beginning in 1996. NCEMC has given notice that it will purchase 200 megawatts from another supplier beginning January 1996. From January 1996 through 2000, the Company will continue to supply at least 1,000 megawatts of electricity. Load reductions beyond the year 2000 are subject to specific limits and require five years advance notice.
In 1993, the Company and NCEMC entered into a settlement agreement that provided for the continuation of existing wholesale rate levels and resolved a 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.
In 1994, the Company established a wholly-owned subsidiary, CaroNet, Inc., and the subsidiary joined a regional partnership led by BellSouth Personal Communications, Inc. (BellSouth). In March 1995, BellSouth won its bid for a Federal Communications Commission license for the partnership to operate a personal communications services (PCS) system covering most of North Carolina and South Carolina and a small portion of Georgia. PCS, a wireless communications technology, is expected to provide high-quality mobile communications. Wireless technology could also support automated meter reading, automated service connection and disconnection, and control and monitoring of certain aspects of the Company's electric transmission and distribution systems. BellSouth will transfer the PCS license to the partnership. BellSouth will be general partner and handle day-to-day management of the business.
Competition ___________
In 1992, the National Energy Policy Act (Energy Act) changed certain underlying federal policies governing wholesale generation and the sale of electric power. In effect, the Energy Act partially deregulated the wholesale electric utility industry at the generation level by allowing non-utility generators to build and own generating plants for both cogeneration and sales to utilities. Provisions of the Energy Act that most affected the utility industry were the establishment of exempt wholesale generators, and the authority given the FERC to permit wholesale transfer, or wheeling, of power over the transmission lines of other utilities. 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. Although the Energy Act prohibits the FERC from ordering retail wheeling--transmitting power on behalf of another producer to an individual retail customer--some states are considering changing their laws or regulations to allow retail electric customers to buy power from suppliers other than the local utility. The Company believes changes in existing laws in both North Carolina and South Carolina would be required to permit retail wheeling in the Company's retail jurisdictions. The South Carolina Public Service Commission (SCPSC) has ruled that it would be a violation of its past practice and of South Carolina's territorial assignment statute to require utilities to engage in retail wheeling. On February 8, 1995, the Carolina Utility Consumers Association, Inc., a group of industrial customers doing business in North Carolina, filed a petition with the NCUC requesting that the NCUC hold a generic hearing to examine whether retail wheeling would be in the public interest, how it could be implemented in North Carolina and whether it could be implemented without changing state law. The NCUC has issued an order inviting interested parties to comment on the petition. The Company cannot predict the outcome of this matter.
The possible migration of some of the Company's load due to increased competition in the electric industry has created greater planning uncertainty and risks for the Company. The Company has been addressing these risks by securing 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 and 1994, the Company signed long-term agreements with almost all of the Company's wholesale customers, representing approximately 15% of the Company's operating revenues. In the industrial sector, the Company is working to meet the energy needs of its customers. In 1994, the Company reached an agreement with its largest industrial customer, which ensures the Company will serve this customer through 2001. Other elements of the Company's strategy to respond to the changing market for electricity include promoting economic development, implementing new marketing strategies, improving customer satisfaction, increasing the focus on managing and reducing costs and, consequently, avoiding future rate increases.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA _______ ___________________________________________
The following financial statements, supplementary data and financial statement schedules are included herein:
Page(s)
Independent Auditors' Report 45-46
Financial Statements:
Statements of Income for the Years Ended December 31, 1994, 1993 and 1992 47 Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992 48 Balance Sheets as of December 31, 1994 and 1993 49-50 Schedules of Capitalization as of December 31, 1994 and 1993 51 Statements of Retained Earnings for the Years Ended December 31, 1994, 1993 and 1992 52 Quarterly Financial Data 52 Notes to Financial Statements 53-64
Financial Statement Schedules for the Years Ended December 31, 1994, 1993 and 1992:
VIII - Reserves 65-67
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, 1994 and 1993, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1994. 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, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994 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, 1992, 1991, and 1990, and the related statements of income, retained earnings and cash flows for the years ended December 31, 1991 and 1990 (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, 1994, 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 8 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 LLP Raleigh, North Carolina February 13, 1995
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 1993 and 1992 have been reclassified to conform to the 1994 presentation.
B. Electric Utility Plant
The cost of additions, including betterments and replacements of units of property, is charged to electric utility plant. Maintenance and repairs of property, and replacements and renewals of items determined to be less than units of property, are charged to maintenance expense. The cost of units of property replaced, renewed or retired, plus removal or disposal costs, less salvage, is charged to accumulated depreciation. Generally, electric utility plant other than nuclear fuel is subject to the lien of the Company's mortgage. The balances of electric utility plant in service at December 31 are listed below (in millions).
1994 1993
Production plant $ 5,911.2 $ 5,713.9 Transmission plant 879.6 873.4 Distribution plant 1,929.5 1,825.2 General plant and other 470.6 377.0 --------- --------- Electric utility plant in service $ 9,190.9 $ 8,789.5 ========= =========
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 1992, a deferred income tax provision was reflected as a reduction in the borrowed funds portion. Due to the 1993 implementation of Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes," AFUDC-borrowed funds is no longer recorded on a net-of-tax basis (see Note 8). The composite AFUDC rate was 8.4% in 1994 and 8.8% in 1993, and the composite, net-of-tax AFUDC rate was 7.3% in 1992. Pursuant to the provisions of SFAS No. 109, the deferred income tax related to AFUDC in undepreciated plant in service as of January 1, 1993, was recorded to a 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 3.8% in 1994 and 1993, and 3.7% in 1992. Depreciation expense totaled $335.1 million for 1994, $325.4 million for 1993 and $306.0 million for 1992. Depreciation and amortization expense also includes amortization of plant abandonment costs (see Note 7).
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 1F).
D. Nuclear Decommissioning
In the Company's retail jurisdictions, provisions for nuclear decommissioning costs are approved by the NCUC and the SCPSC and are based on site-specific estimates that included the costs for removal of all radioactive and other structures at the site. In the wholesale jurisdiction, the provisions for nuclear decommissioning costs are based on amounts agreed upon in applicable rate settlements. Decommissioning cost provisions, which are included in depreciation and amortization, were $29.5 million in 1994, $34.0 million in 1993 and $27.1 million in 1992.
Accumulated decommissioning costs, which are included in accumulated depreciation, were $252.7 million at December 31, 1994, and $221.6 million at December 31, 1993, and include amounts retained internally and amounts funded in an external decommissioning trust. The balance of the external decommissioning trust, which is included in miscellaneous other property and investments, was $67.6 million at December 31, 1994, and $44.5 million at December 31, 1993. Trust earnings, which increase the trust balance with a corresponding increase in accumulated decommissioning, were $1.5 million in 1994, $1.2 million in 1993 and $.8 million in 1992. Based on the site-specific estimates discussed below, and using an assumed after-tax earnings rate of 8.5% and an assumed cost escalation rate of 4%, current levels of rate recovery for nuclear decommissioning costs are adequate to provide for decommissioning of the Company's nuclear facilities.
The Company's most recent site-specific estimates of decommissioning costs were developed in 1993, using 1993 cost factors, and are based on prompt dismantlement decommissioning, which reflects the cost of removal of all radioactive and other structures currently at the site, with such removal occurring shortly after operating license expiration. These estimates, in 1993 dollars, are $257.7 million for Robinson Unit No. 2, $235.4 million for Brunswick Unit No. 1, $221.4 million for Brunswick Unit No. 2 and $284.3 million for the Harris Plant. The estimates are subject to change based on a variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning, and changes in federal, state or local regulations. The cost estimates exclude the portion attributable to North Carolina Eastern Municipal Power Agency (Power Agency), which holds an undivided ownership interest in certain of the Company's generating facilities. Operating licenses for the Company's nuclear units expire in the year 2010 for Robinson Unit No. 2, 2016 for Brunswick Unit No. 1, 2014 for Brunswick Unit No. 2 and 2026 for the Harris Plant.
The Financial Accounting Standards Board has added a project to its agenda regarding the electric utility industry's current accounting practices related to decommissioning costs. Any changes to these practices could affect such items as: 1) when the decommissioning obligation is recognized, 2) where balances of accumulated decommissioning costs are recorded, 3) where income earned on external decommissioning trust balances is recorded and 4) the levels of annual decommissioning cost provisions. The Financial Accounting Standards Board is in the early stages of this project, and consequently, it is uncertain what impacts, if any, this project may have on the Company's accounting for decommissioning costs.
E. Regulatory Assets and Liabilities
As a regulated entity, the Company is subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Accordingly, the Company records certain assets and liabilities that result from the effects of the ratemaking process, which would not be recorded under generally accepted accounting principles for non-regulated entities. At December 31, 1994, the balances of the Company's regulatory assets were as follows: 1) $384.4 million for income taxes recoverable through future rates, 2) $127.8 million for Harris Plant deferred costs, 3) $71.1 million for abandonment costs, 4) $55 million for loss on reacquired debt, which is included in unamortized debt expense and 5) $66 million for deferred DOE enrichment facilities-related cost, which is included in other assets and deferred debits. At December 31, 1994, the Company had a regulatory liability of $28.3 million related to deferred fuel.
F. Other Policies
Customers' meters are read and bills are rendered on a cycle basis. Revenues are recorded as services are rendered.
Deferred fuel reflects fuel costs or recoveries that are deferred through fuel clauses established by the Company's regulators. These clauses allow the Company to recover fuel costs and the fuel component of purchased power costs through the fuel component of customer rates. Any difference between actual costs incurred and the fuel component collected in customer billings is reflected in operating expenses as deferred fuel. Customer rates are adjusted periodically to incorporate the approved deferrals. In 1993, the Company reached settlement agreements with regulators in the North Carolina and South Carolina retail jurisdictions and agreed to forgo recovery of a total of $41.1 million of deferred fuel expenses.
Other property and investments are stated principally at cost. The Company maintains an allowance for doubtful accounts receivable, which totaled $2.5 million at December 31, 1994, and $2.3 million at December 31, 1993. 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. Employee Stock Ownership Plan
The Company sponsors a Stock Purchase-Savings Plan (SPSP) for which all full-time employees and certain part-time employees are eligible. The SPSP, which has company match and incentive goal features, encourages systematic savings by employees and provides a method of acquiring Company common stock and other diverse investments. The SPSP, as amended in 1989, is an employee stock ownership plan (ESOP) that can enter into acquisition loans for the purpose of acquiring Company common stock to satisfy SPSP common share needs. Qualification as an ESOP did not change the level of benefits received by employees under the SPSP. Common stock acquired with the proceeds of an ESOP loan is held by the SPSP Trustee in a suspense account and is released from the suspense account and made available for allocation to participants as the ESOP loan is repaid, as specified by provisions of the Internal Revenue Code. Such allocations are used to partially meet common stock needs related to participant contributions, Company matching and incentive contributions and/or reinvested dividends. Dividends paid on ESOP suspense shares and on ESOP shares allocated to participants, as well as certain Company contributions, are used to repay ESOP acquisition loans, and such dividends are deductible for income tax purposes.
There were 9,315,789 ESOP suspense shares at December 31, 1994, with a fair value of $248 million. ESOP shares allocated to plan participants totaled 13,891,199 at December 31, 1994. The Company has a long-term note receivable from the SPSP Trustee related to the purchase of common stock from the Company in 1989. The balance of the Company's note receivable from the SPSP Trustee, $204 million at December 31, 1994, is recorded as unearned ESOP common stock and reduces common stock equity.
In 1994, the Company implemented Statement of Position (SOP) 93-6, "Employers' Accounting for Employee Stock Ownership Plans," on a prospective basis. This SOP required the following changes in accounting for the Company's ESOP: 1) ESOP shares that have not been committed to be released to participants' accounts are no longer considered outstanding for the determination of earnings per common share; 2) dividends on unallocated ESOP shares are no longer recognized for financial statement purposes; 3) interest income related to the qualified ESOP loan is no longer recognized; 4) the difference between the acquisition and allocation prices of ESOP shares, which was previously recorded as other income, net, is now recorded directly to common stock; and 5) all tax benefits of ESOP dividends are now recorded to non-operating income tax expense, whereas in 1993, a portion of the tax benefits was recorded directly to retained earnings. In 1992, prior to the implementation of SFAS No. 109, all tax benefits of ESOP dividends were recorded to retained earnings and were included in the determination of earnings per common share. In addition, pursuant to SOP 93-6, ESOP loan transactions between the Company and the SPSP Trustee are no longer reflected in the Statement of Cash Flows. The implementation of SOP 93-6 resulted in an increase in earnings per common share of approximately $.04 for 1994.
3. Capitalization
In 1994, the Board of Directors of the Company authorized the Executive Committee of the Board to repurchase up to 10 million shares of the Company's common stock on the open market. Under this stock repurchase program, the Company has purchased approximately 4.4 million shares through December 31, 1994.
In 1993, the Company's common stock was split and one additional share was issued for each common share outstanding. Prior year financial information was restated to reflect the two-for-one stock split.
At December 31, 1994, 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, 1994, there were no significant restrictions on the use of retained earnings.
At December 31, 1994, long-term debt maturities for the years 1995 through 1999 were $275.1 million, $105 million, $40 million, $205 million and $50 million, respectively.
Person County Pollution Control Revenue Refunding Bonds - Series 1992A totaling $56 million have interest rates that must be negotiated on a weekly basis. At the time of interest rate renegotiation, holders of these bonds may require the Company to repurchase their bonds. These bonds are 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 this intention is supported by the Company's long-term revolving credit agreements.
4. Short-Term Debt and Revolving Credit Facilities
At December 31, 1994 and 1993, the Company's short-term debt balances were $68.1 million and $76 million, respectively. The weighted-average interest rates of these borrowings were 6.18% at December 31, 1994, and 3.65% at December 31, 1993. At December 31, 1994, the Company's unused and readily available revolving credit facilities totaled $307.9 million, consisting of long-term agreements totaling $207.9 million and a $100 million short-term agreement.
5. 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 carrying amount of the Company's long-term debt was $2.86 billion at December 31, 1994, and $2.80 billion at December 31, 1993. The estimated fair value of this debt, which was obtained from an independent pricing service, was $2.70 billion at December 31, 1994, and $2.88 billion at December 31, 1993. There are inherent limitations in any estimation technique, and these estimates are not necessarily indicative of the amount the Company could realize in current transactions.
6. Postretirement Benefit Plans
The Company has a noncontributory defined benefit retirement (pension) plan for all full-time employees and funds the pension plan in amounts that comply with contribution limits imposed by law. Pension plan benefits reflect an employee's compensation, years of service and age at retirement.
The components of net periodic pension cost are (in thousands):
1994 1993 1992
Actual return on plan assets $ 4,897 $(43,604) $(26,882) Variance from expected return, deferred (47,219) 4,490 (9,743) ------- -------- ------- Expected return on plan assets (42,322) (39,114) (36,625) Service cost 19,686 16,776 21,368 Interest cost on projected benefit obligation 35,108 31,928 31,141 Net amortization 831 (2,390) 758 ------- ------- ------ Net periodic pension cost $ 13,303 $ 7,200 $ 16,642 ======= ====== =======
Reconciliations of the funded status of the pension plan at December 31 are (in thousands): 1994 1993
Actuarial present value of benefits for services rendered to date: Accumulated benefits based on salaries to date, including vested benefits of $287.7 million for 1994 and $293.6 million for 1993 $ 330,361 $ 339,301 Additional benefits based on estimated future salary levels 103,766 112,497 -------- -------- Projected benefit obligation 434,127 451,798 Fair market value of plan assets, invested primarily in equity and fixed-income securities 506,605 515,428 -------- -------- Funded status 72,478 63,630 Unrecognized prior service costs 9,471 12,620 Unrecognized actuarial gain (124,447) (119,352) Unrecognized transition obligation, being amortized over 18.5 years beginning January 1, 1987 1,110 1,216 -------- -------- Accrued pension costs recognized in the Balance Sheets $ (41,388) $ (41,886) ======== ========
The assumptions used to measure the projected benefit obligation are:
1994 1993
Weighted-average discount rate 8.5% 7.5% Assumed rate of increase in future compensation 4.2% 4.2%
The expected long-term rate of return on pension plan assets used in determining the net periodic pension cost was 9% in each of the years 1994, 1993 and 1992.
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 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 and totaled $2.7 million in 1992.
The components of net periodic OPEB cost are (in thousands):
1994 1993
Actual return on plan assets $ 42 $ (497) Variance from expected return, deferred (682) 9 ------- ------- Expected return on plan assets (640) (488) Service cost 8,039 6,797 Interest cost on accumulated benefit obligation 9,463 9,662 Net amortization 5,966 5,966 ------- ------- Net periodic OPEB cost $ 22,828 $ 21,937 ======= =======
Reconciliations of the funded status of the OPEB plans at December 31 are (in thousands): 1994 1993
Actuarial present value of benefits for services rendered to date: Current retirees $ 55,799 $ 62,727 Active employees eligible to retire 11,933 14,800 The assumptions used to measure the accumulated postretirement benefit obligation are: Active employees not eligible to retire 63,164 62,225 ------- ------- Accumulated postretirement benefit obligation 130,896 139,752 Fair market value of plan assets, invested primarily in equity and fixed-income securities 12,142 7,584 ------- ------- Funded status (118,754) (132,168) Unrecognized actuarial (gain) loss (15,125) 6,288 Unrecognized transition obligation, being amortized over 20 years beginning January 1, 1993 107,379 113,345 ------- ------- Accrued OPEB costs recognized in the Balance Sheets $(26,500) $(12,535) ======= =======
The assumptions used to measure the accumulated postretirement benefit obligation are:
1994 1993
Weighted-average discount rate 8.5% 7.5% Initial medical cost trend rate for pre-medicare benefits 9.6% 10.7% Initial medical cost trend rate for post-medicare benefits 8.7% 9.5% Ultimate medical cost trend rate 6.0% 5.0% Year ultimate medical cost trend rate is achieved 2005 2005
The expected long-term rate of return on plan assets used in determining the net periodic OPEB cost was 9% in 1994 and 1993. Assuming a one percent increase in the medical cost trend rates, the aggregate of the service and interest cost components of the net periodic OPEB cost for 1994 would increase by $2.5 million, and the accumulated postretirement benefit obligation at December 31, 1994, 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 retiree health care benefits in a trust created pursuant to Section 401(h) of the Internal Revenue Code.
7. Plant-Related Deferred Costs
The Company abandoned 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 costs was completed in 1992, and of Harris Unit No. 2 costs in 1994. 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 related to abandoned plant costs associated with the 1990 NCUC Order on Remand was completed in 1994. Abandoned plant amortization related to the 1988 rate orders will be completed in 1998 for the North Carolina retail and the wholesale jurisdictions and in 2027 for the South Carolina retail jurisdiction.
Amortization of plant abandonment costs is included in depreciation and amortization expense and totaled $60.5 million in 1994, $100.7 million in 1993 and $92.5 million in 1992. Prior to the 1993 implementation of SFAS No. 109, this amortization was reported net of certain deferred taxes (see Note 8). 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 $6.6 million in 1994, $13.2 million in 1993 and $18.2 million in 1992 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 10A), the unamortized balance of Harris Plant deferred costs was $60.8 million at December 31, 1994, and $81.4 million at December 31, 1993.
8. 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.
In 1993, the Company implemented SFAS No. 109 on a prospective basis. SFAS No. 109 required the Company to establish additional deferred tax assets and liabilities for certain temporary differences and to adjust deferred tax accounts for changes in income tax rates. It also prohibited net-of-tax accounting for income statement and balance sheet items. 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. Prior to the implementation of SFAS No. 109, the Company recorded 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. See Note 2 for the impact of SFAS No. 109 on the treatment of tax benefits of ESOP dividends. Prior period financial statement amounts were not restated for SFAS No. 109.
Net accumulated deferred income tax liabilities at December 31 are (in thousands):
1994 1993 Accelerated depreciation and property cost differences $ 1,504,187 $ 1,449,796 Deferred costs, net 144,751 168,311 Miscellaneous other temporary differences, net (7,173) (12,443) ---------- ---------- Net accumulated deferred income tax liability $ 1,641,765 $ 1,605,664 ========== ==========
Total deferred income tax liabilities were $1.9 billion at December 31, 1994, and 1993. Total deferred income tax assets were $297 million at December 31, 1994, and $261 million at December 31, 1993.
The provisions for income tax expense are comprised of (in thousands):
1994 1993 1992 Included in Operating Expenses Income tax expense (credit) Current - federal $ 143,461 $ 108,935 $ 93,319 state 39,185 29,687 37,616 Deferred - federal 23,926 50,719 81,134 state 3,500 11,588 6,342 Investment tax credit adjustments (11,537) (11,612) (11,083) -------- -------- -------- Subtotal 198,535 189,317 207,328 -------- -------- -------- Harris Plant deferred costs Deferred - federal - - 2,523 state - - 597 Investment tax credit adjustments (297) 218 (182) -------- -------- -------- Subtotal (297) 218 2,938 -------- -------- -------- Total included in operating expenses 198,238 189,535 210,266 -------- -------- -------- Included in Other Income Income tax expense (credit) Current - federal (15,732) (6,168) (5,857) state (3,507) (1,291) (1,268) Deferred - federal 8,065 7,483 11,024 state 1,749 1,562 1,986 Investment tax credit adjustments - (1,194) - -------- -------- -------- Subtotal (9,425) 392 5,885 -------- -------- -------- Harris Plant carrying costs Deferred - federal - - 1,612 state - - 357 -------- -------- -------- Subtotal - - 1,969 -------- -------- -------- Other income, net Deferred - federal - - 47 state - - 11 -------- -------- -------- Subtotal - - 58 -------- -------- -------- Total included in other income (9,425) 392 7,912 -------- -------- -------- Included in Interest Charges Allowance for borrowed funds used during construction Deferred - federal - - 1,678 state - - 382 -------- -------- -------- Total included in interest charges - - 2,060 -------- -------- -------- Total income tax expense $ 188,813 $ 189,927 $ 220,238 ======== ======== ========
A reconciliation of the Company's effective income tax rate to the statutory federal income tax rate follows.
1994 1993 1992
Effective income tax rate 37.6% 35.4% 36.7% State income taxes, net of federal income tax benefit (5.5) (5.1) (5.1) Investment tax credit amortization 2.4 2.3 1.9 Other differences, net 0.5 2.4 0.5 ---- ---- ---- Statutory federal income tax rate 35.0% 35.0% 34.0% ==== ==== ====
9. 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 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, 1994 (dollars in millions).
Facility Megawatt Company Plant Accumulated Under Capability Ownership Investment Depreciation Construction Interest
Mayo Plant 745 83.83% $ 432.3 $ 146.9 $ 1.3 Harris Plant 860 83.83% $ 2,994.3 $ 661.0 $ 7.7 Brunswick Plant 1,521 81.67% $ 1,315.0 $ 708.9 $ 59.8 Roxboro Unit No.4 700 87.06% $ 219.2 $ 86.7 $ 4.9
In the table above, plant investment and accumulated depreciation, which includes accumulated decommissioning, are not reduced by the regulatory disallowances related to the Harris Plant.
10. Commitments and Contingencies
A. Purchased Power
The Company is obligated to purchase a percentage of Power Agency's ownership capacity and energy from the Mayo and Harris Plants. For Mayo, the percentage purchased declines ratably over a 15-year period that ends in 1997. In 1993, the Company and Power Agency entered into an agreement to restructure portions of their contracts covering power supplies and interests in jointly-owned units. Pursuant to the agreement, a portion of the Company's Harris Plant cost will not be recoverable through sales of supplemental power to Power Agency. As a result, the Company recorded a write-off in 1993 of $20.6 million, or $14.7 million, net of tax. Under the terms of the 1993 agreement, the Company also increased the amount of capacity and energy purchased from Power Agency's ownership interest in the Harris Plant, and the buyback period was extended six years through 2007. The estimated minimum annual payments for these purchases, which reflect capital-related capacity costs, total approximately $27 million. Other costs of such purchases are primarily demand-related production expenses, fuel and energy-related operation and maintenance expenses. Contractual purchases from the Mayo and Harris Plants totaled $60.4 million for 1994, $52.6 million for 1993 and $39.8 million for 1992. In 1987, the NCUC ordered the Company to reflect the recovery of the capacity portion of these costs on a levelized basis over the original 15-year buyback period, thereby deferring for future recovery the difference between such costs and amounts collected through rates. In 1988, the SCPSC ordered similar treatment, but with a ten-year levelization period. At December 31, 1994 and 1993, the Company had deferred purchased capacity costs, including carrying costs accrued on the deferred balances, of $70.9 million and $67.1 million, respectively. Increased purchases resulting from the 1993 agreement with Power Agency, which were approximately $21 million on an annual basis for 1994 and 1993, are not being deferred for future recovery.
The Company purchases 250 megawatts of generating capacity from Indiana Michigan Power Company's Rockport Unit No. 2. The estimated minimum annual payment for power is approximately $30 million, which represents capital-related capacity costs. Other power costs include demand-related production expenses, fuel and energy-related operation and maintenance expenses. Purchases, including transmission use charges, totaled $61.9 million, $60.2 million and $62.9 million for 1994, 1993 and 1992, respectively. The agreement expires on December 31, 2009.
In mid-1993, the Company began purchasing 400 megawatts of generating capacity from Duke Power Company. The estimated minimum annual payment for power under the six-year agreement is $43 million, which represents capital-related capacity costs. Other power costs associated with the agreement include fuel and energy-related operation and maintenance expenses. Purchases, including transmission use charges, totaled $62.9 million for 1994 and $37.1 million for 1993. The agreement was recently approved by FERC.
B. Insurance
The Company is a member of Nuclear Mutual Limited (NML), which provides primary insurance coverage against property damage to members' nuclear generating facilities. The Company is insured thereunder for $500 million for each of its nuclear generating facilities. For the current policy period, the Company is subject to maximum retrospective premium assessments of approximately $22.7 million in the event that losses at insured facilities exceed premiums, reserves, reinsurance and other NML resources, which are at present more than $741 million.
The Company is also a member of Nuclear Electric Insurance Limited (NEIL), which provides insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages of members' nuclear generating units. The Company is insured thereunder for the first 52 weeks (starting 21 weeks after the outage begins) in weekly amounts of $1.9 million at Brunswick Unit No. 1, $1.9 million at Brunswick Unit No. 2, $2.4 million at the Harris Plant and $1.7 million at Robinson Unit No. 2. The Company is insured for the next 104 weeks for 80% of the above amounts. NEIL also provides decontamination, decommissioning and excess property insurance for nuclear generating facilities. The Company is insured under this coverage for $1.4 billion at each of its nuclear generating facilities. This is in addition to the $500 million coverage provided by NML. For the current policy period, the Company is subject to retrospective premium assessments of up to approximately $10.1 million with respect to the incremental replacement power costs coverage and $43.3 million with respect to the decontamination, decommissioning and excess property coverage in the event covered expenses at insured facilities exceed premiums, reserves, reinsurance and other NEIL resources. These resources are at present more than $2.1 billion. Pursuant to regulations of the Nuclear Regulatory Commission, the Company's property damage insurance policies provide that all proceeds from such insurance be applied, first, to place a plant in safe and stable condition after an accident and, second, to decontaminate it before any proceeds can be used for plant repair or restoration. The Company is responsible to the extent losses may exceed limits of the coverage described above. Power Agency would be responsible for its ownership share of such losses and for certain retrospective premium assessments on jointly-owned units.
The Company is insured against public liability for a nuclear incident up to $8.9 billion per occurrence, which is the maximum limit on public liability claims pursuant to the Price-Anderson Act. In the event that public liability claims from an insured nuclear incident exceed $200 million, the Company would be subject to a pro rata assessment of up to $75.5 million, plus a 5% surcharge, for each reactor owned for each incident. Payment of such assessment would be made over time as necessary to limit the payment in any one year to no more than $10 million per reactor owned. Power Agency would be responsible for its ownership share of the assessment on jointly-owned units.
C. Claims and Uncertainties
(1) The Company is subject to federal, state and local regulations addressing air and water quality, hazardous and solid waste management and other environmental matters.
Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under various federal and state laws, and a liability may exist for their remediation. There are several manufactured gas plant (MGP) sites to which the Company and certain entities that were later merged into the Company may have had some connection. In this regard, the Company, along with other entities alleged to be former owners and operators of MGP sites in North Carolina, is participating in a cooperative effort with the North Carolina Department of Environment, Health and Natural Resources, Division of Solid Waste Management (DSWM) to establish a uniform framework for addressing those sites. 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. To date, the Company has not entered into any such orders.
The Company has recently been approached by another North Carolina public utility concerning a possible cost-sharing arrangement with respect to the investigation and, if necessary, the remediation of four MGP sites. The Company is currently engaged in discussions with the other utility regarding this matter.
In addition, a current owner of property that was the site of one MGP owned by Tide Water Power Company (Tide Water Power), which merged into the Company in 1952, and the Company have entered into an agreement to share the cost of investigation and, if necessary, remediation of this site. The Company has also been approached by a North Carolina municipality that is the current owner of another MGP site that was formerly owned by Tide Water Power. The Company is engaged in discussions with that municipality concerning a possible cost-sharing arrangement with respect to the investigation and, if necessary, the remediation of that site.
The Company is continuing its investigation regarding the identities of parties connected to several additional MGP sites, the relative relationships of the Company and other parties to those sites and the degree, if any, to which the Company should undertake shared voluntary efforts with others at individual sites.
The Company has been notified by regulators of its involvement or potential involvement in several sites, other than MGP sites, that require remedial action. Although the Company cannot predict the outcome of these matters, it does not anticipate significant costs associated with these sites.
In 1994, the Company accrued a liability for the estimated costs associated with investigation and remediation activities for certain MGP sites and for sites other than MGP sites. This accrual was not material to the results of operations of the Company. Due to the lack of information with respect to the operation of MGP sites for which a liability has not been accrued and due to the uncertainty concerning questions of liability and potential environmental harm, the extent and cost of required remedial action, if any, are not currently determinable. The Company cannot predict the outcome of these matters or the extent to which other MGP sites may become the subject of inquiry.
(2) As required under the Nuclear Waste Policy Act of 1982, the Company entered into a contract with the DOE under which the DOE agreed to dispose of the Company's spent nuclear fuel. The Company cannot predict whether the DOE will be able to perform its contractual obligations and provide interim storage or permanent disposal repositories for spent nuclear fuel and/or high-level radioactive waste materials on a timely basis.
With certain modifications, the Company's spent fuel storage facilities are sufficient to provide storage space for spent fuel generated on the Company's system through the expiration of the current operating licenses for all of the Company's nuclear generating units. Subsequent to the expiration of the licenses, dry storage may be necessary.
In the opinion of management, liabilities, if any, arising under other pending claims would not have a material effect on the financial position, results of operations or cash flows of the Company.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE _______ _____________________________________________
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ________ __________________________________________________
a) Information on the Company's directors is set forth in the Company's 1995 definitive proxy statement dated March 31, 1995, and incorporated by reference herein.
b) Information on the Company's executive officers is set forth in Part I and incorporated by reference herein.
ITEM 11. EXECUTIVE COMPENSATION ________ ______________________
Information on executive compensation is set forth in the Company's 1995 definitive proxy statement dated March 31, 1995, and incorporated by reference herein.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT _______ _______________________________________________
a) The Company knows of no person who is a beneficial owner of more than five (5%) percent of any class of the Company's voting securities except for Wachovia Bank of North Carolina, N.A., Post Office Box 3099, Winston-Salem, North Carolina 27102 which as of December 31, 1994, owned 25,027,393 shares of Common Stock (15.9% 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 1995 definitive proxy statement dated March 31, 1995, and incorporated by reference herein.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS _______ ______________________________________________
Information on certain relationships and transactions is set forth in the Company's 1995 definitive proxy statement dated March 31, 1995, and incorporated by reference herein.
PART IV
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-third Supplemental Indentures (Exhibit 2(b)-5, File No. 2-16210; Exhibit 2(b)-6, File No. 2-16210; Exhibit 4(b)-8, File No. 2-19118; 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 Exhibit 4(e) and 4(f), File No. 33-57835.
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 LLP.
Exhibit No. 23(b) Consent of Richard E. Jones.
____________
*Incorporated herein by reference as indicated. +Management contract or compensation plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
b) Reports on Form 8-K filed during or with respect to the last quarter of 1994 and the portion of the first quarter of 1995 prior to the filing of this 10-K:
Date of Report Item Reported ______________ _____________
January 23, 1995 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 24th day of March, 1995.
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) Officer and Director
/s/ Charles D. Barham, Jr. Principal Financial (Executive Vice President Officer and Director and Chief Financial Officer)
/s/ Paul S. Bradshaw Principal Accounting (Vice President and Controller) Officer
/s/ Edwin B. Borden Director March 24, 1995
/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/ 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