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 7,203 employees at December 31, 1995. The principal executive offices of the Company are located at 411 Fayetteville Street, Raleigh, North Carolina 27601, telephone number: 919-546-6111.
2. SERVICE.
a. The territory served, an area of approximately 30,000 square miles, includes a substantial portion of the coastal plain of North Carolina extending to the Atlantic coast between the Pamlico River and the South Carolina border, the lower Piedmont section of North Carolina, an area in northeastern South Carolina, and an area in western North Carolina in and around the City of Asheville. The estimated total population of the territory served is approximately 3.75 million.
b. The Company provides electricity at retail in 219 communities, each having an estimated population of 500 or more, and at wholesale to one joint municipal power agency, 3 municipalities and 2 electric membership corporations (North Carolina Electric Membership Corporation, which has 27 members, 17 of which are served by the Company's system, and French Broad Electric Membership Corporation). At December 31, 1995, the Company was furnishing electric service to approximately 1,087,000 customers.
3. SALES. During 1995, 32% of operating revenues was derived from residential sales, 21% from commercial sales, 24% from industrial sales, 16% from resale sales and 7% from other sources. Of such operating revenues, approximately 67% was derived from North Carolina retail customers, 14% from South Carolina retail customers, 16% from wholesale customers under contract and 3% from bulk power sales. For the twelve months ended December 31, 1995, average revenues per kilowatt-hour (kWh) sold to residential, commercial and industrial customers were 8.03 cents, 6.67 cents and 5.12 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 ____ _______ _______ _______
1991 12,472 $1,040.70 8.34 cents 1992 12,396 1,029.82 8.31 1993 13,167 1,090.16 8.28 1994 12,559 1,032.00 8.22 1995 13,242 1,062.82 8.03
4. PEAK DEMAND.
a. A 60-minute system peak demand record of 10,156 megawatts (MW) was reached on August 14, 1995. At the time of this peak demand, the Company's capacity margin based on installed capacity (less unavailable capacity) and scheduled firm purchases and sales was approximately 7.0%.
b. Total system peak demand for 1993 increased by 3.8%, for 1994 increased by 5.8%, and for 1995 increased by 0.12%, as compared with the preceding year. The Company currently projects that system peak demand will increase at an average annual growth rate of approximately 2.5% over the next ten years. The year-to-year change in actual peak demand is influenced by the specific weather conditions during those years and may not exhibit a consistent pattern. Total system load factors, expressed as the ratio of the average load supplied to the peak load demand, for the years 1993-1995 were 59.0%, 56.0% and 58.9%, respectively. The Company forecasts capacity margins of 12.5% over anticipated system peak load for 1996 and 11.5% for 1997. This forecast assumes normal weather conditions in each year consistent with long-term experience, and is based upon the rated Maximum Dependable Capacity of generating units in commercial operation and scheduled firm purchases of power. See PART I, ITEM 1, "Generating Capability" and "Interconnections With Other Systems." However, some of the generating units included in arriving at these capacity margins may be 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 PART I, ITEM 1, "Generating Capability," paragraph 1.
GENERATING CAPABILITY _____________________
1. FACILITIES. The Company has a total system installed generating capability (including Power Agency's share) of 9,613 MW, with generating capacity provided primarily from the installed generating facilities listed in the table below. The remainder of the Company's generating capacity is composed of 53 coal, hydro and combustion turbine units ranging in size from a 2.5 MW hydro unit to a 78 MW coal-fired unit. Pursuant to certain agreements with 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, 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 1995. Over the next ten years, system sales growth is forecasted to average approximately 2.5% per year and annual growth in system peak demand is projected to average approximately 2.5%. The Company's generation additions schedule, which is updated annually, reflects no additions until 1997, when two new combustion turbine generating units, construction of which began in 1995, are currently scheduled to commence commercial operation. These units, having a total generating capacity of approximately 240 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 $65 million. In December 1994, the Company filed preliminary plans with the North Carolina Utilities Commission (NCUC) and the North Carolina Division of Environmental Management to install up to 1200 MW of new combustion turbine generating units adjacent to the Company's Lee Steam Electric Plant in Wayne County, North Carolina. The Company's current plan is to add 500 MW of combustion turbine capacity in 1998. The units would primarily be used during periods of summer and winter peak demands. The Company filed an Application for a Certificate of Public Convenience and Necessity with the NCUC on September 27, 1995 seeking permission to construct the 500 MW of capacity. The schedule, which is subject to change, calls for construction of the 500 MW of combustion turbine capacity to begin in 1996, with the aggregate cost expected to approximate $135 million and commercial operation anticipated to begin in 1998. The NCUC hearing in this matter was held on January 9, 1996, but the NCUC has not yet rendered its decision. In addition to the proposed Wayne County project, the generation addition schedule provides for the addition of 2,400 MW in combustion turbine capacity, and 1,800 MW of combined cycle capacity at undesignated sites over the period 1999 to 2010, and a 500 MW baseload coal unit in 2010 at an undesignated site.
INTERCONNECTIONS WITH OTHER SYSTEMS ___________________________________
1. INTERCONNECTIONS. The Company's facilities in Asheville and vicinity are integrated into the total system through the facilities of Duke Power Company (Duke) via interconnection agreements that permit transfer of power to and from the Asheville area. The Company also has major interconnections with the Tennessee Valley Authority (TVA), Appalachian Power Company (APCO), Virginia Power, South Carolina Electric and Gas Company (SCE&G), South Carolina Public Service Authority (SCPSA) and Yadkin, Inc. (Yadkin). Major interconnections include 115 kV and 230 kV ties with SCE&G and SCPSA; 115 kV, 230 kV and 500 kV ties with Duke and Virginia Power; a 115 kV tie with Yadkin; a 161 kV tie with TVA; and three 138 kV ties and one 230 kV tie with APCO. See paragraph 3.b. below.
2. INTERCHANGE 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. Pursuant to an amendment of the contract, commencement of the purchase of power by the Company was delayed until July 1993 and termination was extended through June 1999. On January 20, 1995, the FERC issued an order accepting the purchase power contract. The estimated minimum annual payment for power under the six-year agreement is $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 $63.8 million in 1995.
b. The Company has entered into an agreement, which has been approved by the FERC, with APCO and Indiana Michigan Power Company (Indiana Michigan), operating subsidiaries of American Electric Power Company, to upgrade a transmission interconnection with APCO in the Company's western service area, establish a new interconnection in the Company's eastern service area, and purchase 250 MW of generating capacity from Indiana Michigan's Rockport Unit No. 2 through 2009. The upgrade to the transmission interconnection in the Company's western service area was completed in 1992, and the Company recently announced plans to upgrade an existing 138 kV transmission line between Person County, North Carolina and Danville, Virginia, rather than establishing a new interconnection in its eastern service area. The upgrade is currently expected to be completed by mid-1998. The estimated minimum annual payment for power 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, and energy-related operation and maintenance expenses. Purchases under this agreement, including transmission use charges, totaled $61.8 million in 1995.
4. POWER AGENCY. Pursuant to a 1981 Power Coordination Agreement, as amended, entered into between the Company and Power Agency, the Company is obligated to purchase a percentage of Power Agency s ownership capacity of and energy from the Mayo Plant and the Harris Plant through 1997 and 2007, respectively. The estimated minimum annual payments for these purchases, which reflect capital-related capacity costs, total approximately $26 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 $39.4 million in 1995.
COMPETITION AND FRANCHISES __________________________
1. COMPETITION.
a. Generally, in municipalities and other areas where the Company provides retail electric service, no other utility directly renders such service. In recent years, however, customers interested in building their own generation facilities, competition from unregulated energy suppliers and changing government regulations have fostered the development of alternative sources of electricity for certain of the Company's wholesale and industrial customers. The Public Utility Regulatory Policies Act (PURPA) has facilitated the entry of non-utility companies into the wholesale electric generation business. Under PURPA, non-utility companies are allowed to construct "qualifying facilities" for the production of electricity in connection with industrial steam supplies and, under certain circumstances, to compel a utility to purchase the electricity generated at prices reflecting the utility's avoided cost as set by state regulatory bodies. Over the near term, the purchase of power from qualifying facilities has increased the Company's total cost of power supply.
b. In 1992, the National Energy Policy Act (Energy Act) changed certain underlying federal policies governing wholesale generation and the sale of electric power. In effect, the Energy Act partially deregulated the wholesale electric utility industry at the generation level by allowing non-utility generators to build and own generating plants for both cogeneration and sales to utilities. Provisions of the Energy Act that most affected the utility industry were the establishment of
exempt wholesale generators, and the authority given the FERC to 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 after existing contracts expire, or new opportunities are created for the Company to expand its wholesale load.
On March 29, 1995, the FERC issued a Notice of Proposed Rulemaking (Proposal) that would establish guidelines for wholesale wheeling of electric power. The Proposal would require utilities to provide open access to their interstate power transmission network and not give themselves preferential access to their own services. Currently, such power transfers are negotiated case-by-case or under long-term contracts. The FERC's Proposal would establish a standard generic set of terms and conditions, and would define the terms under which independent power producers and others could gain access to a utility's transmission grid to sell power to a wholesale customer such as a municipality or rural electric cooperative. The Company does not favor the Proposal, which is expected to be finalized sometime in 1996, but rather favors the continued evolution of wholesale electric markets. The Company filed comments regarding the Proposal with the FERC on August 7, 1995. In those comments, the Company disagreed with the FERC's approach to regulating wholesale wheeling, and indicated that in issuing the proposed guidelines the FERC exceeded its authority. The Company also suggested ways to improve the proposed guidelines, in the event that they are enacted. On August 11, 1995, the Company filed comments concerning the FERC's inquiry regarding the potential environmental impact of the Proposal. In those comments, the Company noted the FERC's failure to comply with several requirements of the National Environmental Policy Act. On October 4, 1995, the Company filed reply comments which addressed a number of specific points made in the initial comments other parties filed regarding the Proposal. The Company cannot predict the outcome of this matter or the impact of the Proposal on its future results of operations and financial position.
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 competition in the Company's retail jurisdictions. The South Carolina Public Service Commission (SCPSC) has ruled that it would be a violation of its past practice and of South Carolina's territorial assignment statute to require utilities to engage in retail competition. On February 8, 1995, the Carolina Utility Consumers Association, Inc., a group of industrial customers doing business in North Carolina, filed a petition with the NCUC requesting that the NCUC hold a generic hearing to examine whether retail electric competition would be in the public interest, how it could be implemented in North Carolina and whether it could be implemented without changing state law. On July 21, 1995, the NCUC issued an order indicating that it will not convene a formal hearing to investigate these issues at this time. The NCUC's order noted that North Carolina's territorial assignment statute appears to prohibit retail competition, and the issue involves a number of jurisdictional uncertainties. The NCUC concluded that for the time being, it should monitor developments in other states and at the FERC regarding jurisdictional and other issues affecting retail competition. Instead of convening a hearing, the NCUC requested that interested parties suggest, by mid-September 1995, specific issues for further consideration in this docket. On September 19, 1995, the Company filed with the NCUC a list of specific issues it believes should be addressed prior to any form of retail competition being allowed in the state of North Carolina. The issues include, but are not limited to: (i) concerns about system planning and service reliability; (ii) the drastic changes to the laws governing utility regulation that would need to be implemented before retail competition could be allowed; (iii) whether retail choice promotes cost reduction rather than cost shifting; and (iv) how stranded costs will be determined and recovered. The NCUC also indicated that it is considering holding informal proceedings in the future to gather more information on competition issues. The Company cannot predict the outcome of this matter.
The issues described above have created greater planning uncertainty and risks for the Company. The Company has been addressing these risks in the wholesale sector by securing long-term contracts with all of its wholesale customers, representing approximately 16% of the Company's 1995 operating revenues. These long-term contracts will allow the Company flexibility in managing its load and efficiently planning its future resource requirements; however, NCEMC does have the contractual right, subject to five years' advance notice, to reduce the baseload capacity it purchases from the Company after December 31, 2000. See PART I, ITEM 1, "Competition and Franchises," paragraph 1.d for further discussion of the contract between the Company and NCEMC. In the industrial sector, the Company is continuing to work to meet the energy needs of its customers. Other elements of the Company's strategy for responding to the changing market for electricity include promoting economic development, implementing new marketing strategies, improving customer satisfaction, increasing the focus on managing and reducing costs, and consequently, avoiding future rate increases.
c. By order issued May 13, 1994, the NCUC established a docket (Docket No. E-100, Sub 73) to consider proposed self-generation deferral rate guidelines, and dispersed energy facilities and economic development rates. By order issued July 21, 1994, the NCUC approved and adopted guidelines to apply to requests for self-generation deferral rates. The guidelines allow the Company to adjust rates to retain certain loads for which self-generation is feasible. 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. In addition, on June 8, 1995, and July 5, 1995, the Company filed with the NCUC and the SCPSC, respectively, an Economic Development Rider which will permit the Company to provide a discount on the first five years of electric service it provides to businesses that locate to or expand within the Company's service territory if they meet certain criteria, including thresholds for the size of new load, the amount of investment and the number of new jobs provided by the businesses. The Economic Development Rider was approved by the NCUC on July 10, 1995, and by the SCPSC on July 21, 1995.
d. In June 1994, the FERC granted final approval of a Power Coordination Agreement (PCA) and an Interchange Agreement, both dated August 27, 1993, which set forth explicitly the future relationship between the Company and NCEMC, and established a framework under which they will operate (Project Nos. 432-004 and 2748-000). 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 allowed NCEMC to assume responsibility for up to 200 MW of its load from the Company's system between January 1, 1996 and December 31, 2000. Pursuant to this authority, NCEMC's board of directors awarded a power-supply contract for 200 MW to another supplier beginning on January 1, 1996. The contract, which has been accepted by the FERC, displaced 200 MW of baseload capacity that NCEMC previously purchased from the Company; however, the Company expects to continue to supply not less than 1000 MW of electricity to NCEMC from January 1, 1996 until at least December 31, 2000. Load reductions beyond the year 2000 are subject to specific limits and require five years' advance notice. NCEMC has not officially notified the Company that any of the baseload power to be supplied to NCEMC by the Company beginning in 2001 will be provided by another entity; however, on November 4, 1994, NCEMC issued two requests for proposals (RFP) to provide up to 225 MW (for a minimum of ten years) of baseload power NCEMC would otherwise purchase from the Company beginning in 2001, an additional block of up to 225 MW per year beginning in 2002, and a third block of up to 225 MW per year beginning in 2003. On March 3, 1995, the Company submitted a bid in response to each RFP to compete for this load. On September 13, 1995, NCEMC notified the Company that it had decided to suspend negotiations regarding the Company's bids at this time, but requested that the Company leave its bids open for future consideration. Negotiations between the Company and NCEMC have resumed. The Company cannot predict the outcome of these matters.
e. By order issued February 24, 1994, the NCUC established a docket (Docket No. E-100, Sub 71), 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 NCUC also opened a related docket (Docket No. M-100, Sub 124)to determine 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. By orders issued in October 1995, the NCUC issued a new rule, as well as a set of guidelines, that require natural gas and electric utility companies to obtain NCUC approval prior to offering anyone incentives, of more than nominal value, that are intended to influence the recipient's fuel choice. This rule sets forth the procedures a utility must follow to gain such approval, and the guidelines identify the substantive issues that must be addressed by any utility seeking to offer such incentives. The NCUC also ruled that it would not consider the impact of a utility's program involving the provision of an incentive on competitors of the utility.
By order issued September 30, 1994, the SCPSC established a docket for a similar generic proceeding (Docket No. 94-618-E/G). The filing of testimony and scheduling of hearings in the SCPSC proceeding have been indefinitely postponed. The Company cannot predict the outcome of this matter.
f. On March 29, 1995, a bill was introduced in the North Carolina General Assembly (General Assembly) to facilitate the construction of an interstate natural gas pipeline to be built from Aiken, South Carolina to Leland, North Carolina. The bill, as originally introduced, proposed to, among other things, exempt from utility regulation all power generating facilities that receive gas from the pipeline as fuel. On July 29, 1995, the General Assembly passed a bill directing the Joint Utility Review Committee of the General Assembly (Utility Review Committee) to study whether or not the extension of interstate natural gas pipelines into North Carolina can and should be encouraged by amending the North Carolina Public Utilities Act (Public Utilities Act) to exempt from regulation as public utilities facilities that sell electric power and thermal energy generated with natural gas from these pipelines. The bill also directs the Utility Review Committee to study whether the Public Utilities Act should be amended to encourage the construction of new interstate pipelines in North Carolina. The bill orders the Utility Review Committee to report its findings and any recommendations regarding these matters before the General Assembly convenes on May 13, 1996. The Company cannot predict the outcome of this matter.
g. On March 22, 1995, a bill was introduced in the General Assembly that would change fundamentally the nature of public power agencies in the state. The bill, as originally introduced, proposed to, among other things, permit certain organizational changes among the state's municipal power agencies and provide additional authority for the marketing of excess capacity and energy. A substantially amended version of this bill, which authorizes internal reorganization of the state's municipal power agencies, and orders the Utility Review Committee to study other issues contained in the original legislation and report its findings and any recommendations to the General Assembly in 1996, was passed by the General Assembly effective July 11, 1995. On January 11, 1996, representatives of the state's municipal power agencies informed the Utility Review Committee that they do not wish to pursue additional statutory changes during the 1996 session of the General Assembly. The Company cannot predict the outcome of this matter.
h. In late 1995, one of the Company's industrial customers in the City of Darlington, South Carolina ("City"), requested that the City become a municipal electric utility and provide retail electric service to the area. If it were to become a municipal electric utility, the City would possibly seek to purchase bulk power from a supplier other than the Company. The Company has undertaken efforts to educate the City's residents, businesses and industries regarding the many costs and legal issues associated with a municipalization effort. The City plans to undertake studies to determine the feasibility of the municipalization proposal. The results of those studies will likely determine whether the proposal is presented to the City's voters. The Company cannot predict the outcome of this matter.
2. FRANCHISES. The Company is a regulated public utility and holds franchises to the extent necessary to operate in the municipalities and other areas it serves.
CONSTRUCTION PROGRAM ____________________
1. CAPITAL REQUIREMENTS. During 1995 the Company expended approximately $610 million for capital requirements. The Company revised its capital program in 1995 as part of its annual business planning process. Capital requirements, including anticipated construction expenditures for plant modifications, for the years 1996 through 1998 are set forth below. These estimates include Clean Air Act compliance expenditures of approximately $55 million, and generating facility addition expenditures of approximately $327 million. See PART I, 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)
1996 1997 1998 TOTAL ____ ____ ____ _____
Construction Expenditures $406 $489 $447 $1,342 Nuclear Fuel Expenditures 103 64 105 272 AFUDC (15) (18) (33) (66) ____ ____ ____ ______ Net expenditures (a) 494 535 519 1,548 Mandatory Redemptions of 105 100 205 410 Long-Term Debt ____ _____ ____ ______ Long-Term Debt TOTAL $599 $635 $724 $1,958 ==== ==== ==== ======
_________________
(a) Reflects reductions of approximately $12 million, $7 million and $9 million for 1996, 1997 and 1998, respectively, in net capital requirements resulting from Power Agency's projected payment of its ownership share of capital expenditures related to the Joint Facilities.
FINANCING PROGRAM _________________
1. CAPITAL REQUIREMENTS. Based on the Company's most recent estimate of capital requirements, the Company does not expect to have external funding requirements in 1996. External funding requirements, which do not include early redemptions of long-term debt or redemptions of preferred stock, are expected to approximate $14 million in 1997 and $76 million in 1998. These funds will be required for construction, mandatory redemptions of long-term debt and general corporate purposes, including the repayment of short-term debt. The Company 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 PART II, ITEM 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," for further analysis and discussion of the Company's financing plans and capital resources and liquidity.
2. SEC FILINGS.
a. The Company has on file with the Securities and Exchange Commission (SEC) a shelf registration statement (File No. 33-57835), under which an aggregate of $450 million principal amount of First Mortgage Bonds, and an additional $125 million combined aggregate principal amount of First Mortgage Bonds and/or unsecured debt securities of the Company remain available for issuance.
b. The Company has on file with the SEC a shelf registration statement (File No. 33-5134) enabling the Company to issue up to $180 million of Serial Preferred Stock.
3. FINANCINGS. External financings during 1995 included:
- 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.
- On April 21, 1995, the Company issued $125 million principal amount of Quarterly Income Capital Securities (Series A Subordinated Deferrable Interest Debentures) ("Capital Securities") at an interest rate of 8.55%, for net proceeds to the Company of approximately $121 million. The proceeds from the issuance of the Capital Securities were applied to the Company's ongoing maintenance and construction program, and for other general corporate purposes.
4. REDEMPTIONS/RETIREMENTS. Redemptions and retirements during 1995 and early 1996 included:
- The retirement on January 1, 1995, of $125 million principal amount of First Mortgage Bonds, 5.20% Series, which matured on that date.
- The retirement on April 1, 1995, of $77.1 million principal amount of First Mortgage Bonds, 9.14% Series, which matured on that date.
- The retirement on June 8, 1995, of $25 million principal amount of First Mortgage Bonds, 8.92% Secured Medium-Term Notes, Series A, which matured on that date.
- The retirement on July 20, 1995, of $25 million principal amount of First Mortgage Bonds, 8.86% Secured Medium-Term Notes, Series A, which matured on that date.
- The retirement on November 1, 1995, of $23 million principal amount of First Mortgage Bonds, 8.85% Secured Medium-Term Notes, Series A, which matured on that date.
- The redemption on February 27, 1996, of $125 million principal amount of First Mortgage Bonds, 8 7/8% Series due February 15, 2021, at 105.69% of the principal amount of such bonds plus accrued interest to the date of redemption.
- The redemption on March 26, 1996, of $22.626 million principal amount of First Mortgage Bonds, 8 1/8% Series due November 1, 2003, at 100.52% of the principal amount of such bonds plus accrued interest to the date of redemption.
- The redemption on March 26, 1996, of $100 million principal amount of First Mortgage Bonds, 7 3/4% Series due 2003, at 100.18% of the principal amount of such bonds plus accrued interest to the date of redemption.
5. CREDIT FACILITIES. The Company's credit facilities presently total $685 million, consisting of long-term agreements totaling $585 million and a $100 million short-term agreement. The Company is required to pay minimal annual commitment fees to maintain its credit facilities. See PART II, ITEM 8, Notes to Consolidated Financial Statements, Note 3, for a more detailed discussion of the Company's credit facilities.
RETAIL RATE MATTERS ___________________
1. GENERAL. The Company is subject to regulation in North Carolina by the NCUC and in South Carolina by the SCPSC with respect to, among other things, rates and service for electric energy sold at retail, retail service territory and issuances of securities.
2. CURRENT RETAIL RATES. The rates of return granted to the Company in its most recent general rate cases are as follows:
1988 North Carolina Utilities Commission Order (test year ended March 31, 1987) ______________________________________________________________________
Capital Weighted Weighted Capital Structure Ratio Cost Rate Cost _________________ _______ _________ ________
Long-Term Debt 48.57% 8.62% 4.19% Preferred Stock 7.43 8.75 .65 Common Equity 44.00 12.75 5.61 _____ Rate of Return 10.45% =====
1988 South Carolina Public Service Commission Order (test year ended September 30, 1987) ____________________________________________________
Capital Weighted Weighted Capital Structure Ratio Cost Rate Cost _________________ _______ _________ ________
Long-Term Debt 47.82% 8.62% 4.12% Preferred Stock 7.46 8.75 .65 Common Equity 44.72 12.75 5.71 ______ Rate of Return 10.48% =====
3. INTEGRATED RESOURCE PLANNING. Integrated resource planning is a process that systematically compares all reasonably available resources, both demand-side and supply-side, in order to develop that mix of resources that allows a utility to meet customer demand in a cost effective manner, giving due regard to system reliability, safety and the environment. Utilities are required to file their Integrated Resource Plans (IRP) with the NCUC and the SCPSC once every three years. The Company regularly reviews its IRP in light of changing conditions and evaluates the impact these changes have on its resource plans, including purchases and other resource options. The Company filed its 1995 IRP with the NCUC on April 28, 1995, and with the SCPSC on July 3, 1995. By order dated February 20, 1996, the NCUC approved the Company's 1995 IRP as filed. The SCPSC established April 8, 1996 as the deadline for parties to intervene and/or submit comments regarding the Company's 1995 IRP. The Company cannot predict the outcome of this matter.
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. 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. By order dated September 6, 1995, the NCUC approved the Company's request for a reduction in the fuel expense portion of the Company's rates, reflecting the Company's improved nuclear performance, and refunding approximately $44 million in fuel-related revenues, which exceeded actual costs for the test period, and $6 million in related interest. The new fuel factor became effective on September 15, 1995, and will remain in effect for one year. The Company's 1996 fuel case hearing is scheduled to begin on August 6, 1996.
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 1996 fuel case hearing was held on March 14, 1996, but the SCPSC has not yet issued an order in this proceeding.
The Company cannot predict the outcome of these matters.
6. AVOIDED COST PROCEEDINGS. The NCUC opened Docket No. E-100, Sub 74 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 hearings in this docket concluded on March 9, 1995, and on June 23, 1995, the NCUC approved, with one minor exception, the Company's proposed lower avoided cost rates. The Company anticipates that the revised lower rates will result in reduced purchase power expense to the Company, as it enters into new purchase agreements with qualifying facilities. The next NCUC avoided cost proceeding will be held in 1997.
WHOLESALE RATE MATTERS ______________________
1. GENERAL. The Company is subject to regulation by the FERC with respect to rates for transmission and sale of electric energy at wholesale, the interconnection of facilities in interstate commerce (other than interconnections for use in the event of certain emergency situations), the licensing and operation of hydroelectric projects and, to the extent the FERC determines, accounting policies and practices. The Company and its wholesale customers last agreed to a general increase in wholesale rates in 1988; however, wholesale rates have been adjusted since that time through contractual negotiations.
2. FERC MATTERS.
a. By letter dated May 31, 1995, the Company requested that the FERC (Docket No. 95-1139) establish a return on equity (ROE) in connection with the formula rates provided in the PCA dated August 27, 1993 between the Company and NCEMC. The requested ROE is consistent with the rate of return on common equity approved by the NCUC in the Company's 1988 rate case. On February 6, 1996, the Company filed an offer of settlement with the FERC to set the ROE at 10.75 percent. The FERC staff filed comments supporting the settlement on February 14, 1996. The Company cannot predict the outcome of this matter.
b. On May 31, 1995, the Company filed a petition with the FERC (Docket No. EL95-50) seeking to recover certain fuel costs from the Company's wholesale customers. These costs are related to the Company's $6.8 million buyout of its contractual agreement with The Arch Coal Sales Company (Arch Coal). As a result of this buyout, the Company will purchase less coal from Arch Coal in the future and will pay a lower purchase price for that coal. The Company cannot predict the outcome of this matter.
c. On July 7, 1995, Smithfield Foods, Inc., doing business as Carolina Foods Processors, Inc. (Carolina Foods), filed a Complaint with the FERC (Docket No. EL95-60) alleging that certain charges imposed upon NCEMC under the PCA between the Company and NCEMC are unreasonable. These charges are related to generation installed by Carolina Foods, which receives electric service from Four County EMC (a customer of NCEMC). The Company filed its response to the Complaint on August 10, 1995. The Company cannot predict the outcome of this matter.
d. On March 1, 1996, the Company and Power Agency entered into a contractual agreement which provides that Power Agency will delay construction and startup of its 183.7 MW combustion turbine generating project until 2004. (That project was scheduled to begin commercial operation in June of 1998.) Pursuant to a 1981 Power Coordination Agreement, as amended, between Power Agency and the Company, Power Agency is obligated to purchase this electricity from the Company from 1995 through May 31, 1998. As a result of the new agreement, Power Agency will purchase peaking capacity from the Company as follows: 110 MW from June 1, 1998 through December 31, 1998, 116 MW in 1999 and 183.7 MW from 2000 through 2003. The new agreement must be submitted to the FERC for approval. The Company cannot predict the outcome of this matter.
ENVIRONMENTAL MATTERS _____________________
1. GENERAL. In the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes and other environmental matters, the Company is subject to regulation by various federal, state and local authorities. The Company considers itself to be in substantial compliance with those environmental regulations currently applicable to its business and operations and believes it has all necessary permits to conduct such operations. The Company does not currently anticipate that its potential capital expenditures for environmental pollution control purposes will be material. Environmental laws and regulations, however, are constantly evolving and the character, scope and ultimate costs for compliance with such evolving laws and regulations cannot now be accurately estimated. Costs associated with compliance with pollution control laws and regulations at the Company's existing facilities, which are expected to be incurred from 1996 through 1998, are included in the estimates of capital requirements under PART I, ITEM 1, "Construction Program."
2. CLEAN AIR LEGISLATION. The 1990 amendments to the Clean Air Act (Act) require substantial reductions in sulfur dioxide and nitrogen oxides emissions from fossil-fueled electric generating plants. The Company was not required to take action to comply with the Act's Phase I requirements for these emissions, which had to be met by January 1, 1995. The Act's Phase II require- ments, which contain more stringent provisions, will become effective January 1, 2000. The Act required that a Title IV permit application, including certifications regarding compliance with the Phase II sulfur dioxide and nitrogen oxides emissions requirements, be submitted to the appropriate permitting authority for each of the Company's plants by January 1, 1996. The Company submitted its Title IV permit applications in late 1995. The Company plans to meet the Phase II sulfur dioxide emissions requirements by utilizing the most economical combination of lower sulfur coal and sulfur dioxide emission allowances. Each sulfur dioxide emission allowance allows a utility to emit one ton of sulfur dioxide. The has Company purchased emission allowances under the Environmental Protection Agency's (EPA) emission allowance trading program in order to supplement the allowances the EPA granted to the Company. Installation of additional equipment will be necessary to reduce nitrogen oxides emissions. The Company estimates that future capital costs necessary to comply with Phase II of the Act will approximate $180 million. Increased operating and maintenance costs, including emission allowance expense, and increased fuel costs are not expected to be material to the results of operations of the Company. As the Company's plans for compliance with the Act's requirements are subject to change, the amount required for capital expenditures and for increased operating, maintenance and fuel expenditures cannot be determined with certainty at this time. The Company cannot predict the outcome of this matter.
3. SUPERFUND. The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA and, indirectly, the states, to require generators and certain transporters of certain hazardous substances released from or at a site, and the owners and operators of such site, to clean up the site or reimburse the costs therefor. 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, a low-level nuclear waste disposal site located in Fleming County, Kentucky. The EPA indicated that the site was operated from 1963 to 1977 under the management of Nuclear Engineering Company (now U. S. Ecology). The EPA estimated that the Company sent 304,459 cubic feet of low-level radioactive waste to the disposal site. In response to the EPA's notice, the Company and several other potentially responsible parties (PRPs) formed a steering committee (the Maxey Flats Steering Committee) to undertake a remedial investigation/feasibility study pursuant to CERCLA. As a result of this study, the EPA has selected a remedial action which is currently estimated to have a present value cost of between $57 million and $78 million. Subsequent analysis of waste volume sent to the site performed by the Maxey Flats Steering Committee established that the Company contributed only approximately 1% of the total waste volume. It is expected that the Company's share of remediation costs will be based on the ratio of the Company's waste volume to that of other participating PRPs. The Company is currently ranked twenty-fourth on the waste-in list.
On June 30, 1992, the EPA sent the Company, along with a number of other companies, agencies and organizations, a notice demanding reimbursement of response costs of approximately $5.8 million that have been incurred at the site and seeking to initiate formal negotiations regarding performance of the remedial design and remedial action for the site. On July 20, 1992, the Company responded that it would negotiate these matters through the Maxey Flats Steering Committee. In December 1992, the EPA rejected the offer the Maxey Flats Steering Committee filed regarding the performance of the remedial design and remedial action for this site. The Maxey Flats Steering Committee submitted amended offers to the EPA in 1993. The EPA has engaged in settlement negotiations with the Maxey Flats Steering Committee, the Commonwealth of Kentucky, which owns the site, and the federal agencies in an effort to reach global settlement. On June 5, 1995, a De Maximus Consent Decree (Consent Decree) was filed on behalf of the Maxey Flats Steering Committee in the United States District Court for the Eastern District of Kentucky (Civil Action No. 95-58). The Consent Decree provides for the performance of the Initial Remediation Phase and the Balance of Remediation Phase, and for the reimbursement of certain response costs incurred by the EPA. The Department of Justice received comments relating to the proposed Consent Decree until August 18, 1995 and is awaiting court approval of the Consent Decree. 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, on-site cleanup activities were completed in July 1995, and the operation and maintenance (O&M) phase began. During the O&M phase, twenty-three groundwater monitoring wells will be sampled quarterly for a minimum 10-year period. There is currently over 90% participation by the PRPs in the site cleanup. The Company contributed approximately $293,000 to the waste generators' group. In late December 1995, the Rose Chemicals Steering Committee (a group of PRPs with respect to the Rose site) issued refunds of excess monies collected for site remediation. The Company received a refund of $158,639. Although the Company cannot predict the outcome of this matter, it does not anticipate that it will be required to contribute additional funds to complete remediation of this site.
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 on 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 has submitted a final report to the EPA. On July 12, 1995, the Company was informed that the EPA had approved the final report regarding the site on October 13, 1994. Now that the final report has been approved, the settlement agreement between the Company and the Elliot's Auto Parts PRP Committee will be implemented. In this settlement, the Company 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 (AOC) with the EPA. Although the Company cannot predict the outcome of this matter, it does not anticipate that future costs associated with this site, 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 Little Rock, Arkansas. The Company has been unable to identify any records of shipments by the Company to that site. Until any such documentation can be produced, the Company does not intend to participate in cleanup activities at the site. The Company cannot predict the outcome of this matter.
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. The wastes sent from the Company's facilities to the Seaboard site consisted primarily of cleaning and degreasing solvents, solvent contaminated oils and paint-related waste. DEHNR has indicated that it is offering PRPs the opportunity to perform voluntary site cleanup. Seaboard records indicate that there are over 1,300 PRPs for the site and that the Company's contribution to waste disposal is less than 1% of the total waste disposed. On May 29, 1992, the Company entered into an AOC with DEHNR, Division of Solid Waste Management, to undertake and perform a Work Plan for Surface Removal (Removal Work Plan). The Company estimates that to date its costs associated with completion of the Removal Work Plan total approximately $12,000. On July 28, 1993, DEHNR determined that the Removal Work Plan had been substantially completed. DEHNR further recommended that the Seaboard Group (a group of PRPs with respect to the Seaboard site) undertake additional remedial activities at the Seaboard site. The Company has joined the Seaboard Group II (a group of PRPs formed to conduct additional work at the Seaboard site). The Seaboard Group II, the City of High Point, North Carolina and the DEHNR have negotiated an AOC that requires the Seaboard Group II and the City of High Point to conduct a joint Remedial Investigation (RI). The Company has executed that AOC. The City of High Point operated a landfill that bounds the Seaboard site on three sides. The City of High Point has conducted studies of groundwater on its site and those studies have indicated that a joint RI is appropriate. Cost estimates for the additional work are not available. Although the Company cannot predict the outcome of this matter, it does not anticipate that costs associated with this site would be material to the results of operations of the Company.
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. Wastes disposed of at the Macon-Dockery site
include antifreeze, used oils, metals, paint, solvent wastes, and waste acids and bases. The Company made arrangements in the past for the transportation and sale of waste oil and residual oil to C&M Oil Distributors, a company that operated an oil reprocessing facility at the Macon-Dockery site. However, the information available to the Company indicates that no hazardous wastes from Company facilities were sent to the site. In 1987, the EPA notified the Company that it believed the Company was a PRP for costs associated with the EPA's cleanup action at the Macon-Dockery site. The EPA initiated a lawsuit in federal district court against entities other than the Company to recover its cleanup costs. Some of the defendants in that lawsuit brought claims against the Company. In 1989, the Company signed a Consent Decree with the EPA which obligated the Company to pay $15,000 and settled the Company's liability, if any, for third party contribution claims.
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. Discovery in this matter is currently underway. Although the Company cannot predict the outcome of this matter, it does not anticipate that costs associated with this site, if any, would be material to the results of operations of the Company.
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. There are 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 continues to investigate the identities of parties connected to individual MGP sites in North Carolina, 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.
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 DEM requested that, in response to a 1979 spill of No. 2 fuel oil, the Company install a groundwater compliance monitoring system at the Company's Wilmington Oil Terminal located in New Hanover County, North Carolina. During the second half of 1989, six groundwater monitoring wells were installed. One of the six wells indicated gasoline contamination and samples from a second well indicated No. 2 fuel oil contamination. In February 1993, the DEM approved a corrective action plan (CAP) for addressing gasoline and No. 2 fuel oil contamination. In 1995, the Company confirmed the presence of off-site gasoline contamination; however, it is not clear that the Company is responsible for off-site gasoline contamination. The Company is proceeding to seek approval to modify the CAP so that on and off-site contamination will be remediated by natural attenuation and degradation factors. The Company sold the Wilmington Oil Terminal on March 1, 1996, but will continue to address existing on- and off-site gasoline and No. 2 fuel oil contamination. Although the Company cannot predict the outcome of this matter, it does not anticipate that costs associated with this site will be material to the results of operations of the Company.
5. ENVIRONMENTAL ACCRUAL.
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 noncompliance, the NRC has the authority to impose fines, set license conditions, or shut down a nuclear unit, or some combination of these, depending upon its assessment of the severity of the situation, until compliance is achieved. The electric utility industry in general has experienced challenges in a number of areas relating to the operation of nuclear plants, including substantially increased capital outlays for modifications; the effects of inflation upon the cost of operations; increased costs related to compliance with changing regulatory requirements; renewed emphasis on achieving excellence in all phases of operations; unscheduled outages; outage durations; and uncertainties regarding both disposal facilities for low-level radioactive waste and storage facilities for spent nuclear fuel. See paragraphs 2 and 3 below. The Company experiences these challenges to varying degrees. Capital expenditures for modifications at the Company's nuclear units, excluding Power Agency's ownership interests, during 1996, 1997 and 1998 are expected to total approximately $50 million, $34 million and $41 million, respectively (including AFUDC).
2. SPENT FUEL AND OTHER HIGH-LEVEL RADIOACTIVE WASTE. The Nuclear Waste Policy Act of 1982 (Nuclear Waste Act) provides the framework for development by the federal government of interim storage and permanent disposal facilities for high-level radioactive waste materials. The Nuclear Waste Act promotes increased usage of interim storage of spent nuclear fuel at existing nuclear plants. The Company will continue to maximize the use of spent fuel storage capability within its own facilities for as long as feasible. Pursuant to the Nuclear Waste Act, the Company, through a joint agreement with the U. S. Department of Energy (DOE) and the Electric Power Research Institute, has built a demonstration facility at the Robinson Plant that allows for the dry storage of 56 spent nuclear fuel assemblies. As of December 31, 1995, sufficient on-site spent nuclear fuel storage capability is available for the full-core discharge of Brunswick Unit No. 1 through 1997, Brunswick Unit No. 2 through 1998, and Robinson Unit No. 2 through 1997 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, at the Company's request, the NRC suspended review of the Company's license application pending notification by the Company of its desire to continue the application process. The Company cannot predict the outcome of this matter.
As required by the Nuclear Waste Act, the Company entered into a contract with the DOE 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 PART I, 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 were participants in the Southeast regional compact and disposed of waste at a disposal site in South Carolina along with other members of the compact. Effective July 1, 1995, South Carolina withdrew from the Southeast regional compact and excluded North Carolina waste generators from the existing disposal site in South Carolina. As a result, the State of North Carolina does not have access to a low-level radioactive waste disposal facility. The North Carolina Low-Level Radioactive Waste Management Authority, which is responsible for siting and operating a new low-level radioactive waste disposal facility for the Southeast regional compact, has submitted a license application for the site it selected in Wake County, North Carolina to the North Carolina Division of Radiation Protection. Although the Company does not control the future availability of low-level waste disposal facilities, the cost of waste disposal or the development process, it is actively supporting the development of new facilities and is committed to a timely and cost-effective solution to low-level waste disposal. The Company's nuclear plants in North Carolina are currently storing low-level waste on site and are developing additional storage capacity to accommodate future needs. The Company's nuclear plant in South Carolina has access to the existing disposal site in South Carolina. Although the Company cannot predict the outcome of this matter, it does not expect the cost of providing additional on-site storage capacity for low-level radioactive waste to be material to the results of operations or financial position of the Company.
4. DECOMMISSIONING.
a. Pursuant to an NRC rule, licensees of nuclear facilities are required to submit decommissioning funding plans to the NRC for approval to provide reasonable assurance that the licensee will have the financial ability to implement its decommissioning plan for each facility. The rule requires licensees to do one of the following: prepay at least an NRC-prescribed minimum amount immediately; set up an external sinking fund for accumulation of at least that minimum amount 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 agreements. Decommissioning cost provisions, which are included in depreciation and amortization, were $31.2 million in 1995, $29.5 million in 1994 and $34.0 million in 1993. Accumulated decommissioning costs, which are included in accumulated depreciation, were $288.4 million at December 31, 1995, and $252.7 million at December 31, 1994, 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 $110.2 million at December 31, 1995, and $67.6 million at December 31, 1994. Trust earnings, which increase the trust balance with a corresponding increase in accumulated decommissioning, were $4.5 million in 1995, $1.5 million in 1994, and $1.2 million in 1993. Based on the site-specific estimates discussed below and using an assumed after-tax earnings rate of 8.5% and an assumed cost escalation rate of 4%, current levels of rate recovery for nuclear decommissioning costs are adequate to provide for decommissioning of the Company's nuclear facilities.
b. The Company's most recent site-specific estimates of decommissioning costs were developed in 1993 using 1993 cost factors, and are based on prompt dismantlement decommissioning, which reflects the cost of removal of all radioactive and other structures currently at the site, with such removal occurring shortly after operating license expiration. See paragraph 5 below for expiration dates of operating licenses. These estimates, in 1993 dollars, are as follows: $257.7 million for Robinson Unit No. 2; $235.4 million for Brunswick Unit No. 1; $221.4 million for Brunswick Unit No. 2; and $284.3 million for the Harris Plant. These estimates are subject to change based on a variety of factors, including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning, and changes in federal, state or local regulations. The cost estimates exclude the portion attributable to Power Agency, which holds an undivided ownership interest in the Brunswick and Harris nuclear generating facilities. To the extent of its ownership interests, Power Agency is responsible for satisfying the NRC's financial assurance requirements for decommissioning costs. See PART I, ITEM 1, "Generating Capabilities," paragraph 1.
c. The Financial Accounting Standards Board has reached several tentative conclusions with respect to its project regarding accounting practices related to closure and removal of long-lived assets. The primary conclusions as they relate to nuclear decommissioning are: 1) the cost of decommissioning should be accounted for as a liability and accrued as the obligation is incurred; 2) recognition of a liability for decommissioning results in recognition of an increase to the cost of the plant; 3) the decommissioning liability should be measured based on discounted cash flows using a risk-free rate; and 4) decommissioning trust funds should not be offset against the decommissioning liability. An exposure draft was issued in February 1996, and it is uncertain what impacts, if any, the final statement may have on the Company's accounting for nuclear decommissioning and other closure and removal costs.
5. OPERATING LICENSES. Facility Operating Licenses, issued by the NRC, for the Company's nuclear facilities allow for a full 40 years of commercial operation. Expiration dates for these licenses are set forth in the following table.
Facility Operating License Facility Expiration Date ________ __________________________
Robinson Unit No. 2 July 31, 2010 Brunswick Unit No. 1 September 8, 2016 Brunswick Unit No. 2 December 27, 2014 Harris Plant October 24, 2026
6. OTHER NUCLEAR MATTERS.
a. In 1991, the NRC issued a final rule on nuclear plant maintenance that 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. Although the Company cannot predict the outcome of this matter, it does not expect the impacts of the new rule to be material to the Company's results of operations.
b. On November 23, 1988, the NRC requested in Generic Letter 88-20 that utilities perform Individual Plant Examinations (IPEs) to determine potential vulnerabilities to severe accidents beyond the design basis accidents for which the plants are designed. These are considered to be very low probability events. The Company submitted the results of the first phase (for internally initiated events) in August 1992 for the Brunswick and Robinson Plants. Based on those results, potential enhancements for the Robinson Plant were evaluated and several enhancements were made to the Robinson Plant. These changes had insignificant financial and operational impacts. For the Brunswick Plant, no modifications were required to meet the guidelines of the IPE. On August 20, 1993, the Company submitted the results of the Harris Plant IPE. While some Harris Plant procedural changes were made due to the IPE results, the IPE did not reveal any significant financial or operational impacts or identify any need for plant modifications. In June 1995, the Company completed and submitted the results of the second phase of the IPEs (for externally initiated events) for the Company's three nuclear plants. The results of the IPEs indicated that some procedural changes may be required for the Harris and Brunswick Plants. Those results also indicated that both minor procedural changes and minor plant modifications will be required for the Robinson Plant. The Company has filed an implementation plan with the NRC which calls for all IPE actions to be implemented by 1998. Although the Company cannot predict at this time the exact magnitude of the financial and operational impacts of the second phase of the IPEs, it does not expect those impacts to be material to the results of operations or financial position of the Company.
c. Degradation of tubing internal to steam generators in pressurized water reactor power plants (PWR's) due to intergranular stress corrosion cracking has been an on-going industry phenomenon. The Company has determined that the steam generators at the Harris Plant are subject to steam generator degradation and the Company is closely monitoring the steam generator performance. Experience and testing conducted to date indicate that the Harris Plant steam generators will not require replacement before 2001. The steam generators at the H.B. Robinson plant were replaced in 1982 and are expected to perform until the plant's operating license expires. Although the Company cannot predict the outcome of this matter, it does not expect the cost of replacing the steam generators at the Harris Plant to be material to the results of operations or financial position of the Company.
d. The Company is insured against public liability for a nuclear incident up to $8.9 billion per occurrence, which is the maximum limit on public liability claims pursuant to the Price-Anderson Act. The $8.9 billion coverage includes $200 million primary coverage and $8.7 billion secondary financial protection through assessments on nuclear reactor owners. In the event that public liability claims from an insured nuclear incident exceed $200 million, the Company would be subject to a pro rata assessment, for each reactor it owns, of up to $75.5 million, plus a 5% surcharge, for each incident. Payment of such assessment would be made over time as necessary to limit the payment in any one year to no more than $10 million per reactor owned. Power Agency would be responsible for its ownership share of the assessment on jointly-owned units. For a more detailed discussion of nuclear liability insurance, see PART II, ITEM 8, Notes to Consolidated Financial Statements Note 10.B.
FUEL ____
1. SOURCES OF GENERATION. Total system generation (including Power Agency's share) by primary energy source, along with purchased power, for the years 1992 through 1996 is set forth below:
1992 1993 1994 1995 1996 (estimated) ____ ____ ____ ____ ___________
Fossil 56% 54% 43% 44% 47% Nuclear 27 31 42 42 42 Purchased Power 15 13 13 13 10 Hydro 2 2 2 1 1
2. COAL. The Company has intermediate and long-term agreements from which it expects to receive approximately 73% of its coal burn requirements in 1996. During 1994 and 1995, the Company obtained approximately 84% (8,120,220 tons), and 86% (7,531,172 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 1995, the Company maintained from 35 to 99 days' supply of coal, based on anticipated burn rate. All of the coal that the Company is currently purchasing under intermediate and long-term agreements is considered to be low sulfur coal by industry standards. Recent amendments to the Clean Air Act may result in increases in the price of low sulfur coal which continue beyond the effective date of the second phase of the Act. See PART I, ITEM 1, "Environmental Matters," paragraph 2. The Company purchased approximately 1,690,000 tons of coal in the spot market during 1994 and 1,306,000 tons in 1995. The Company's contract coal purchase prices during 1995 ranged from approximately $23.00 to $54.00 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 ____ _____ ________________
1991 47.40 190 1992 43.25 174 1993 43.10 172 1994 43.36 174 1995 44.46 179
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 12.6 million and 8.8 million gallons of No. 2 oil during 1994 and 1995, 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 1.6 % of the Company's total burned fuel cost. In 1995, No. 2 oil, natural gas and propane accounted for 1.2 % 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 1997, Brunswick Unit No. 1 through 1998, Brunswick Unit No. 2 through 1998, and the Harris Plant through 1999. The Company expects to meet its future U3O8 requirements from inventory on hand and amounts received under contract. Although the Company cannot predict the future availability of uranium and nuclear fuel services, the Company does not currently expect to have difficulty obtaining U3O8 and the services necessary for its conversion, enrichment and fabrication into nuclear fuel. For a discussion of the Company's plans with respect to spent fuel storage, see PART I, ITEM 1, "Nuclear Matters," paragraph 2.
5. DOE ENRICHMENT FACILITIES DECONTAMINATION AND DECOMMISSION 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 are being made by U.S. domestic utilities who have purchased enrichment services from DOE since it began sales to non-Department of Defense customers. Each utility's share of the contributions will be based on that utility's past purchases of services as a percentage of all purchases of services by U.S. utilities, with total annual contributions capped at $150 million per year, indexed to inflation, and an overall cap of $2.25 billion over 15 years, also indexed to inflation. At December 31, 1995, the Company had a recorded liability of $61.8 million representing its estimated share of the contributions. The Company is recovering a corresponding regulatory asset as a component of fuel cost.
6. PURCHASED POWER. In 1995 the Company purchased 6,974,597 MWh or approximately 13% of its system energy requirements (including Power Agency) and had available 1,596 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, Subpart C and D, dam safety regulations and that the plant's regulatory jurisdiction was being transferred from the NCUC to the FERC. This change resulted from updated dambreak flood studies which identified the potential impact on new downstream development, thus indicating the need to reclassify the project from a low hazard to a high hazard classification. In accordance with the change in regulatory jurisdiction, the Company developed an emergency action plan which meets FERC guidelines and engaged its independent consultant to perform a safety inspection. On April 6, 1992 the consultant's safety inspection report was submitted to the FERC for approval. In March 1995 the Company received comments on the report from the FERC. As a result of these comments, and a meeting with FERC officials, the Company was requested to perform further analyses and submit its findings to the FERC. The Company subsequently submitted the first phase of the requested analyses to the FERC by letter dated September 15, 1995. Depending on the outcome of the FERC's review, the Company could be required to undertake efforts to enhance the stability of the Marshall dam and/or powerhouse. The cost and need for such efforts have not been determined. The Company cannot predict the outcome of this matter.
3. STONE CONTAINER DISPUTE. On April 20, 1994, the Company filed a Complaint with the FERC (Docket No. EL-94-62-000 and QF85-102-005) and in the United States District Court for the Eastern District of North Carolina in Raleigh, North Carolina (Civil Action No. 5:94-CV-285-DI) claiming that the rate the Company pays for power it purchases from Stone Container Corporation (Stone Container) is invalid. The Company entered into a twenty-year purchase power agreement with Stone Container in 1984, and in 1987 began receiving power from a cogeneration facility operated by Stone Container in Florence, South Carolina. It is the Company's position that when Stone Container elected to sell the facility's gross output under a "buy all/sell all" option in 1991, the facility lost its status as a "qualified facility" under PURPA and became a public utility. As a result, the contract rate the Company pays for power purchased from the facility is no longer valid, and a just and reasonable rate should be established by the FERC under the Federal Power Act. The Company will continue to purchase electricity from Stone Container at the current contract rate pending the outcome of this dispute. The District Court action has been stayed pending a decision by the FERC. Both parties have submitted briefs in the FERC matter and are awaiting the FERC's decision. The Company cannot predict the outcome of this matter.
4. TAX REFUND DISPUTE. On April 28, 1994, the Company filed a Complaint against the U.S. Government in the United States District Court for the Eastern District of North Carolina in Raleigh, North Carolina (Civil Action No. 5:94-CV-313-BR3) seeking a refund of approximately $188 million representing tax and interest related to depreciation deductions the Internal Revenue Service (IRS) previously disallowed for the years 1986 and 1987 on the Company's Harris Plant. The Company maintains that under applicable laws and regulations the Harris Plant was ready and available for operation in 1986. The IRS has previously denied some of the depreciation deductions on the Company's tax returns for the years in question on the ground that in its view the plant was not placed in service until 1987. On December 19, 1995, the jury returned a verdict in favor of the U. S. Government. The Company has filed an appeal of the jury's verdict. The Company cannot predict the outcome of this matter.
5. CARONET, INC. On November 29, 1994, the Company established a wholly-owned subsidiary, CaroNet, Inc., (CaroNet) and the subsidiary joined a regional partnership, BellSouth Carolinas PCS, L. P. (Partnership), led by BellSouth Personal Communications, Inc. (BellSouth). On March 14, 1995 BellSouth won its bid for a Federal Communications Commission (FCC) license for the Partnership to operate a Personal Communications Services (PCS) system covering most of North 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. BellSouth is the general partner and handles day-to-day management of the business. In anticipation of infra- structure construction, the Company invested $50 million in CaroNet on April 28, 1995. The Partnership began construction of the PCS system infra- structure during the summer of 1995, and service start-up is anticipated by mid-1996. CaroNet owns a ten percent limited partnership interest in the Partnership and participates on the Partnership's executive committee. On May 15, 1995 and May 22, 1995, CaroNet filed applications with the NCUC and the SCPSC, respectively, for a Certificate of Public Convenience and Necessity, seeking permission to provide wholesale intrastate telecommunications services in North Carolina and South Carolina. By order dated November 3, 1995, the NCUC stated that it will no longer regulate the provision of wholesale intrastate telecommunications services. As a result of this order, the application CaroNet filed with the NCUC was withdrawn. The hearing regarding the application filed with the SCPSC was held on November 1, 1995, and on November 14, 1995, the SCPSC issued an order granting CaroNet permission to provide wholesale services in South Carolina.
6. CAROCAPITAL, INC. On January 22, 1996, the Company established a wholly-owned subsidiary, CaroCapital, Inc., (CaroCapital), which purchased a minority equity interest in Knowledge Builders, Inc. (Knowledge Builders), an energy-management software and control systems company. The Company invested $5 million in CaroCapital on January 25, 1996, and anticipates that its total investment through 2001 could reach $12 million, subject to the terms and conditions of a Stock Purchase Agreement, which includes certain sales and profitability targets. Although Knowledge Builders and its subsidiaries will continue to operate independently, CaroCapital has designated two directors who are currently serving on the Knowledge Builders' board of directors.
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 (including Power Agency's share) of 9,613 MW. The Company's strategic geographic location facilitates purchases and sales of power with many other electric utilities, allowing the Company to serve its customers more economically and reliably. Major industries in the Company's service area include textiles, chemicals, metals, paper, automotive components and electronic machinery and equipment.
At December 31, 1995, the Company had 5,853 pole miles of transmission lines including 292 miles of 500 kV and 2,821 miles of 230 kV lines, and distribution lines of approximately 40,087 pole miles of overhead lines and approximately 8,302 miles of underground lines. Distribution and transmission substations in service had a transformer capacity of approximately 36,036 kVA in 2,263 transformers. Distribution line transformers numbered 399,972 with an aggregate 16,247,000 kVA capacity.
Power Agency has acquired undivided ownership interests of 18.33% in Brunswick Unit Nos. 1 and 2, 12.94% in Roxboro Unit No. 4, and 16.17% in Harris Unit No. 1 and Mayo Unit No. 1. Otherwise, the Company has good and marketable title, 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, 1991 through December 31, 1995, there was added to the Company's utility plant accounts $1,810,966,031, there was retired $554,503,996 of property and there were transfers to other accounts and adjustments for a net decrease of $4,927,241 resulting in net additions during the period of $1,251,564,794 or an increase of approximately 14.25%.
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 1995.
EXECUTIVE OFFICERS OF THE REGISTRANT
Name Age Recent Business Experience ____ ___ __________________________
Sherwood H. Smith, Jr. 61 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 57 PRESIDENT AND CHIEF OPERATING OFFICER, September 1992 to present; Group President - Energy Supply, Entergy Corporation, July 1992; Chairman and Chief Executive Officer, System Energy Resources, Inc., April 1992; Chairman and Chief Executive Officer, Entergy Operations, Inc., April 1992; Senior Vice President, System Executive - Nuclear, Entergy Corporation and Entergy Services, Inc., 1987-August 1992; Executive Vice President and Chief Nuclear Officer, Arkansas Power & Light Company and Louisiana Power & Light Company, January 1990-August 1992; President and Chief Executive Officer, System Energy Resources, Inc., 1986-August 1992; President and Chief Executive Officer, Entergy Operations, Inc., June 1990-April 1992. Member of Board of Directors of Arkansas Power & Light Company and Louisiana Power & Light Company, January 1990-August 1992; Member of Board of Directors of System Fuels, Inc., August 1992; Member of Board of Directors of System Energy Resources, Inc., 1986-August 1992; Member of Board of Directors of Entergy Operations, Inc., 1990-August 1992; Member of Board of Directors of Entergy Services, Inc., 1987-August 1992. Before joining the Company, Mr. Cavanaugh held various senior management and executive positions during a 23-year career with Entergy Corporation, an electric utility holding company with operations in Arkansas, Louisiana and Mississippi. Member of the Board of Directors of the Company since 1993.
Charles D. Barham, Jr. 65 EXECUTIVE VICE PRESIDENT AND CHIEF FINANCIAL OFFICER - Finance and Administration, November 1990 to August 1995 (retired); 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 (retired May 1995).
Glenn E. Harder 44 EXECUTIVE VICE PRESIDENT AND CHEIF FINANCIAL OFFICER, Financial Services, August 1, 1995 to present; Senior Vice President, Group Executive -Financial Services, October 1994 to August 1995; Vice President - Financial Strategies and Treasurer, Entergy Corporation, September 1991 to October 1994; Vice President - Administrative Services & Regulatory Affairs, Entergy Operations, Inc., May 1991 to August 1991; Vice President,Accounting and Treasurer, System Energy Resources, Inc., October 1986 to May 1991. Before joining the Company, Mr. Harder held various senior management and executive positions with Entergy Corporation, an electric utility holding company with operations in Arkansas, Louisiana and Mississippi, and related entities.
William S. Orser 51 EXECUTIVE VICE PRESIDENT - Nuclear Generation, April 1993 to present; Executive Vice President - Nuclear Generation, Detroit Edison Company, April 1993; Senior Vice President - Nuclear Generation, Detroit Edison Company, 1990-1992; Vice President - Nuclear Operations, Detroit Edison Company, 1987-1990. Prior to 1987, Mr. Orser held various other positions with Detroit Edison, and with Portland General Electric Company, Southern California Edison, and the U. S. Navy.
James M. Davis, Jr. 65 SENIOR VICE PRESIDENT, Group Executive - Power Operations, June 1986 to present; Senior Vice President - Operations Support Group, August 1983.
Norris L. Edge 64 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 53 SENIOR VICE PRESIDENT, Human Resources and Support Services, March 1995-present; Vice President - Human Resources (formerly Employee Relations Department), May 1983 to March 1995.
Richard E. Jones 58 SENIOR VICE PRESIDENT, GENERAL COUNSEL AND SECRETARY, Group Executive - Public and Corporate Relations, November 1990 to present; Vice President, General Counsel and Secretary, November 1989 to November 1990; Vice President and General Counsel, July 1987 to November 1989; Vice President, Senior Counsel and Manager - Legal Department, May 1982.
Paul S. Bradshaw 58 VICE PRESIDENT AND CONTROLLER, March 1980 to September 1, 1995 (retired)
Mark F. Mulhern 36 VICE PRESIDENT AND CONTROLLER, March 1996; Vice President of Finance and Treasurer, HYDRA-CO Enterprises, Inc., a subsidiary of Niagara Mohawk Power Corporation, 1994-1996; Director of Finance and Accounting, HYDRA-CO Enterprises, Inc., 1992-1994; Controller, HYDRA-CO Enterprises, Inc., 1991-1992. Prior to 1991, Mr. Mulhern held various positions with the accounting firm of Price Waterhouse & Co.
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:
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
1995 High Low Dividends Paid ____ ____ ___ ______________
First Quarter $28 5/8 $26 3/8 $ .440 Second Quarter 30 3/4 26 3/4 .440 Third Quarter 34 29 1/2 .440 Fourth Quarter 34 1/2 32 3/8 .440
The December 31 closing price of the Company's Common Stock was $26 5/8 in 1994 and $ 34 1/2 in 1995.
As of February 29, 1996, the Company had 65,581 holders of record of Common Stock.
On July 13, 1994, the Board of Directors of the Company (Board) authorized the repurchase of up to 10 million shares of the Company's Common Stock on the open market. Under this stock repurchase program, the Company purchased approximately 4.2 million shares in 1995 and 4.4 million shares in 1994.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS _______ __________________________________________________
RESULTS OF OPERATIONS _____________________
Revenues ________
Revenue fluctuations as compared to the prior year are due to the following factors (in millions).
1995 1994 Increase Increase (Decrease) (Decrease) ________ ________
Customer growth/changes in usage patterns $ 96 $ 101 Weather 64 (86) Sales to other utilities 46 30 Price (62) (45) Sales to North Carolina Eastern Municipal Power Agency (14) (19) _____ ______ $130 $ (19) ===== ======
The return of more normal weather in 1995 generated a $64 million increase in revenues as compared to 1994 when the Company's service territory experienced unusually mild weather. In 1994, this unusually mild weather resulted in a revenue decrease of $86 million compared to the prior year. For 1995 as compared to 1994, approximately half of the price decrease was due to a decrease in the fuel cost component of customer rates and approximately half was due to the expiration in July 1994 of a North Carolina rate rider under which the Company was allowed to recover certain abandoned plant costs. The reduction in revenue due to the expiration of the rate rider did not significan- tly affect net income due to a corresponding decrease in amortization expense. The price decrease from 1993 to 1994 was due primarily to the expiration of the rate rider. For both comparison periods, sales to North Carolina Eastern Municipal Power Agency (Power Agency) decreased due to the increased availability of generating units owned jointly by the Company and Power Agency. The increased availability of all generating units allowed the Company to increase sales to other utilities during the 1993 to 1995 period. In addition, sales to other utilities increased in 1995 as a result of the Company aggressively seeking bulk power sales. For 1995, approximately $5 million of the increase in sales to other utilities related to capacity and certain energy costs and, therefore, resulted in an increase in net income.
Operating expenses __________________
Fuel expense increased in 1995 primarily as a result of higher total generation. Generation increased approximately 9.6% due to higher sales. Fuel expense decreased in 1994 primarily due to 1993 settlement agreements between the Company and its regulators, which required the Company to forgo recovery of certain deferred fuel costs.
As a result of a 1993 agreement with Power Agency, the Company's purchase of capacity and energy from Power Agency's ownership interest in the Harris Plant decreased from 50% in 1994 to 33% in 1995. This change in buyback percentage reduced purchased power in 1995 by $20 million as compared to 1994. Partially offsetting this decrease in 1995 were increases in purchases from other utilities and cogenerators. For 1994 as compared to 1993, purchased power increased primarily due to an agreement under which the Company began purchasing 400 megawatts of generating capacity from Duke Power Company in mid-1993.
Operation and maintenance expense decreased in 1995 primarily due to lower nuclear outage-related expenses. Partially offsetting this decrease was an increase of $13 million in severance-related costs and a 1994 insurance reserve adjustment of $23 million, which reduced expense in that year. The increase in operation and maintenance expense 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 the 1994 insurance reserve adjustment.
Depreciation and amortization expense decreased from 1993 to 1995. This decrease reflects the completion in July 1994 of the amortization of certain abandoned plant costs associated with a North Carolina rate rider and the completion of the amortization of abandoned plant costs for Harris Unit No. 2 in October 1994. The decreases related to these items totaled $42 million for 1995 as compared to 1994 and $25 million for 1994 compared to 1993.
Other income ____________
The high level of Harris Plant carrying costs in 1993 reflects the Company's settlement with North Carolina Electric Membership Corporation (NCEMC) 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.
In 1993, interest income included interest income associated with the Company's 1993 settlement with Westinghouse Electric Corporation (Westinghouse) and interest income related to the Company's qualified employee stock ownership plan (ESOP) loan. In 1994, the recognition of interest income related to the Company's qualified ESOP loan was discontinued as required by Statement of Position 93-6, "Employers' Accounting for Employee Stock Ownership Plans."
In 1995, other income, net, decreased due to an increase in charitable contributions of approximately $7 million and decreases in various other items, none of which was individually significant. Other income decreased in 1994 primarily due to the change in accounting for ESOPs.
Interest charges ________________
The 1995 increase in other interest charges is primarily due to a $6 million interest accrual related to the 1995 North Carolina Utilities Commission (NCUC) Fuel Order. Because of the improved performance of the Company's nuclear facilities during the test year ended March 31, 1995, the fuel component of customer rates exceeded actual fuel costs. As a result, the Company is refunding this over-recovery of fuel costs with interest over the twelve-month period beginning September 15, 1995. Interest charges on long-term debt decreased in 1994 as compared to 1993 due to long-term debt refinancings that allowed the Company to take advantage of lower interest rates.
1993 settlements ________________
In 1993, the Company reached several agreements that affected the Company's 1993 results of operations. 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 increased the Company's earnings by $17.3 million, net of tax, or $.11 per common share. 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. As part of the agreement, the Company recorded a write-off of approximately $14.7 million, net of tax, or $.09 per common share. In addition, the Company and NCEMC entered into a settlement agreement that pro- vided for the continuation of existing wholesale rate levels and resolved a wholesale fuel clause billing issue through June 30, 1993. The impact of this settlement totaled approximately $8 million, net of tax, and decreased the Company's earnings by $.05 per common share.
LIQUIDITY AND CAPITAL RESOURCES _______________________________
Capital requirements ____________________
Estimated capital requirements for the period 1996 through 1998 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).
1996 1997 1998 ____ ____ ____
Construction expenditures $406 $489 $447 Nuclear fuel expenditures 103 64 105 AFUDC (15) (18) (33) Mandatory redemptions of long-term debt 105 100 205 ____ ____ ____ Total $599 $635 $724 ==== ==== ====
The table above includes Clean Air Act expenditures of approximately $55 million and generating facility addition expenditures of approximately $327 million. The generating facility addition expenditures will primarily be used to construct new combustion turbine units, which are intended for use during periods of high demand. The units are scheduled to be placed in service in 1997 through 2001.
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 power purchases under this agreement is approximately $30 million, which represents capital-related capacity costs. Other costs include demand-related production expenses, fuel and energy-related operation and maintenance expenses. In 1995, purchases under this agreement totaled $61.8 million, including transmission use charges. The agreement expires in December 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 power purchases under this agreement is approximately $43 million, which represents capital-related capacity costs. Other costs include fuel and energy-related operation and maintenance expenses. Purchases under this agreement, including transmission use charges, totaled $63.8 million in 1995.
In addition, pursuant to the terms of the 1981 Power Coordination Agreement, as amended, between the Company and Power Agency, the Company is obligated to purchase a percentage of Power Agency's ownership capacity of, and energy from, the Mayo Plant and the Harris Plant through 1997 and 2007, respectively. The estimated minimum annual payments for these purchases, which reflect capital-related capacity costs, total approximately $26 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 $39.4 million in 1995.
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.
In 1994, the Board of Directors of the Company authorized the repurchase of up to 10 million shares of the Company's common stock on the open market. Under this stock repurchase program, the Company purchased approximately 4.2 million shares in 1995 and 4.4 million shares in 1994.
The Company has on file with the Securities and Exchange Commission (SEC) a shelf registration statement under which an aggregate of $450 million principal amount of first mortgage bonds and an additional $125 million combined aggregate principal amount of first mortgage bonds and/or unsecured debt securities of the Company remain available for issuance. The Company can also issue up to $180 million of additional preferred stock under a shelf registration statement on file with the SEC.
The Company's ability to issue first mortgage bonds and preferred stock is subject to earnings and other tests as stated in certain provisions of its mortgage, as supplemented, and charter. The Company has the ability to issue an additional $3.7 billion in first mortgage bonds and an additional 23 million shares of preferred stock at an assumed price of $100 per share and a $7.51 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 credit facilities total $685 million, consisting of $585 million in long-term agreements and a $100 million short-term agreement. The Company is required to pay minimal annual commitment fees to maintain its credit facilities. The Company had $73.7 million of commercial paper outstanding at December 31, 1995, which Moody's Investors Service, Standard & Poors and Duff & Phelps have rated P-1, A-1 and D-1, respectively.
During 1995, the Company issued $185 million in long-term debt. The proceeds of these issuances, along with internally generated funds, were primarily used to redeem or retire $276.1 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 $14 million in 1997 and $76 million in 1998. These funds will be required for construction, mandatory redemptions of long-term debt and general corporate purposes, including the repayment of short-term debt. The Company does not expect to have external funding requirements in 1996.
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 continues to investigate the identities of parties connected to MGP sites in North Carolina, 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 expect costs associated with these sites to be material to the results of operations of the Company.
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.
The 1990 amendments to the Clean Air Act (Act) require substantial reductions in sulfur dioxide and nitrogen oxides emissions from fossil-fueled electric generating plants. The Company was not required to take action to comply with the Act's Phase I requirements for these emissions, which had to be met by January 1, 1995. Phase II of the Act, which contains more stringent provisions, will become effective January 1, 2000. The Company plans to meet the Phase II sulfur dioxide emissions requirements by the most economical combination of fuel-switching and utilization of sulfur dioxide emission allowances. Each sulfur dioxide emission allowance allows a utility to emit one ton of sulfur dioxide. The Company has purchased emission allowances under the Environmental Protection Agency (EPA)'s emission allowance trading program in order to supplement the allowances the EPA has granted to the Company. Installation of additional equipment will be necessary to reduce nitrogen oxides emissions.
The Company estimates that future capital costs necessary to comply with Phase II of the Act will approximate $180 million. Increased operating and maintenance costs, including emission allowance expense, and increased fuel costs are not expected to be material to the results of operations of the Company. As plans for compliance with the Act's requirements are subject to change, the amount required for capital expenditures and for increased operating, maintenance and fuel expenditures cannot be determined with certainty at this time.
Nuclear _______
In the Company's retail jurisdictions, provisions for nuclear decommissioning costs were approved by the NCUC and the South Carolina Public Service Commission (SCPSC) in the Company's 1988 general rate cases and were based on site-specific estimates that included the costs for removal of all radioactive and other structures at the site. In the wholesale jurisdiction, the provisions for nuclear decommissioning costs are based on amounts agreed upon in applicable rate agreements. Based on the site-specific estimates discussed below, and using an assumed after-tax earnings rate of 8.5% and an assumed cost escalation rate of 4%, current levels of rate recovery for nuclear decommissioning costs are adequate to provide for decommissioning of the Company's nuclear facilities.
The Company's most recent site-specific estimates of decommissioning costs were developed in 1993, using 1993 cost factors, and are based on prompt dismantlement decommissioning, which reflects the cost of removal of all radioactive and other structures currently at the site, with such removal occurring shortly after operating license expiration. These estimates, in 1993 dollars, are $257.7 million for Robinson Unit No. 2, $235.4 million for Brunswick Unit No. 1, $221.4 million for Brunswick Unit No. 2 and $284.3 million for the Harris Plant. The estimates are subject to change based on a variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning, and changes in federal, state or local regulations. The cost estimates exclude the portion attributable to Power Agency, which holds an undivided ownership interest in the Brunswick and Harris nuclear generating facilities. Operating licenses for the Company's nuclear units expire in the year 2010 for Robinson Unit No. 2, 2016 for Brunswick Unit No. 1, 2014 for Brunswick Unit No. 2 and 2026 for the Harris Plant.
The Financial Accounting Standards Board has reached several tentative conclusions with respect to its project regarding accounting practices related to closure and removal of long-lived assets. The primary conclusions as they relate to nuclear decommissioning are: 1) the cost of decommissioning should be accounted for as a liability and accrued as the obligation is incurred; 2) recognition of a liability for decommissioning results in recognition of an increase to the cost of the plant; 3) the decommissioning liability should be measured based on discounted cash flows using a risk-free rate; and 4) decommissioning trust funds should not be offset against the decommissioning liability. An exposure draft was issued in February 1996, and it is uncertain what impacts, if any, the final statement may have on the Company's accounting for nuclear decommissioning and other closure and removal 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.
Other Business ______________
In 1994, the Company established a wholly-owned subsidiary, CaroNet, Inc., which owns a ten percent interest in BellSouth Carolinas PCS, L. P. a limited partnership led by BellSouth Personal Communications, Inc. (BellSouth) and participates in the partnership's executive committee. In 1995, BellSouth won its bid for a Federal Communications Commission license for the limited partnership to operate a personal communications services (PCS) system covering most of North Carolina and South Carolina, as well as a small portion of Georgia. PCS, a wireless communications technology, is expected to provide high-quality mobile communications. BellSouth is the general partner and handles day-to-day management of the business. The Company has invested $50 million in CaroNet, Inc. in anticipation of infrastructure construction by BellSouth. Construction began in 1995 and service start-up is expected by mid-1996. In addition to participating in the limited partnership, CaroNet, Inc. will be providing intrastate and interstate telecommunications services in North Carolina and South Carolina.
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 after existing contracts expire or new opportunities are created for the Company to expand its wholesale load.
In 1995, the FERC proposed a rule designed to bring greater competition to the wholesale electric markets. The major provisions of the proposed rule are: 1) electric utilities under FERC jurisdiction that own or control transmission systems would be required to file with the FERC a tariff that would allow buyers and sellers of bulk power equal and open access to their transmission systems; 2) utilities with transmission systems would be required to provide all new wholesale buyers and sellers of electricity the same equal and open access to the utilities' transmission systems; and 3) these utilities would be permitted to recover certain stranded investments incurred as a result of the restructuring order. The Company does not favor the proposed rule, which is expected to be finalized sometime in 1996, but rather favors the continued evolution of wholesale electric markets. The Company cannot predict the impact of this proposed rule on its future results of operations and financial position.
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, or instituting experimental programs, 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 competition in the Company's retail jurisdictions. In 1995, the Carolina Utility Consumers Association, Inc., a group of industrial customers conducting business in North Carolina, filed a petition with the NCUC requesting that the NCUC hold a generic hearing to investigate retail electric competition. The NCUC has ruled that it would not convene a formal hearing to investigate the issue at this time. The NCUC's order noted that North Carolina's territorial assignment statute appears to prohibit retail competition, and the issue involves a number of jurisdictional uncertainties. Both the NCUC and the SCPSC have indicated that they will monitor other states' activities regarding generation competition and allow interested parties to submit information on the subject. The Company cannot predict the outcome of these matters.
The issues described above have created greater planning uncertainty and risks for the Company. The Company has been addressing these risks in the wholesale sector by securing long-term contracts with all of its wholesale customers, representing approximately 16% of the Company's 1995 operating revenue. These long-term contracts will allow the Company flexibility in managing its load and efficiently planning its future resource requirements; however, NCEMC does have the contractual right, subject to five years' advance notice, to reduce the baseload capacity it purchases from the Company after December 31, 2000. In the industrial sector, the Company is continuing to work to meet the energy needs of its customers. Other elements of the Company's strategy to respond to the changing market for electricity include promoting economic development, implementing new marketing strategies, improving customer satisfaction, increasing the focus on managing and reducing costs and, consequently, avoiding future rate increases.
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ____________________________________________________________________
The following consolidated financial statements, supplementary data and consolidated financial statement schedules are included herein:
Page(s)
Independent Auditors' Report 43
Consolidated Financial Statements:
Consolidated Statements of Income for the Years Ended December 31, 1995, 1994 and 1993 44 Consolidated Statements of Cash Flows for the Years Ended December 31, 1995, 1994 and 1993 45 Consolidated Balance Sheets as of December 31, 1995 and 1994 46-47 Consolidated Schedules of Capitalization as of December 31, 1995 and 1994 48 Consolidated Statements of Retained Earnings for the Years Ended December 31, 1995, 1994 and 1993 49 Consolidated Quarterly Financial Data 49 Notes to Consolidated Financial Statements 50-61
Consolidated Financial Statement Schedules for the Years Ended December 31, 1995, 1994 and 1993:
II - Reserves 62-64
All other schedules have been omitted as not applicable or not required or because the information required to be shown is included in the Consolidated Financial Statements or the accompanying Notes to Consolidated Financial Statements.
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders of Carolina Power & Light Company
We have audited the accompanying consolidated balance sheets and schedules of capitalization of Carolina Power & Light Company and subsidiaries as of December 31, 1995 and 1994, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1995. Our audits also included the financial statement schedules listed in the Index at Item 8. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Carolina Power & Light Company and subsidiaries at December 31, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
We have also previously audited, in accordance with generally accepted auditing standards, the consolidated balance sheets and schedules of capitalization as of December 31, 1993, 1992 and 1991, and the related consolidated statements of income, retained earnings and cash flows for the years ended December 31, 1992 and 1991 (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, 1995, appearing at Item 6, is fairly presented in all material respects in relation to the consolidated financial statements from which it has been derived.
/s/ Deloitte & Touche LLP Raleigh, North Carolina February 12, 1996
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ___________________________________________
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. GENERAL
The Company is a public service corporation engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina.
The accounting records of the Company are maintained in accordance with uniform systems of accounts prescribed by the Federal Energy Regulatory Commission (FERC), the North Carolina Utilities Commission (NCUC) and the South Carolina Public Service Commission (SCPSC). Certain amounts for 1994 and 1993 have been reclassified to conform to the 1995 presentation.
B. USE OF ESTIMATES
In preparing financial statements that conform with generally accepted accounting principles, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and amounts of revenues and expenses reflected during the reporting period. Actual results could differ from those estimates.
C. ELECTRIC UTILITY PLANT
The cost of additions, including betterments and replacements of units of property, is charged to electric utility plant. Maintenance and repairs of property, and replacements and renewals of items determined to be less than units of property, are charged to maintenance expense. The cost of units of property replaced, renewed or retired, plus removal or disposal costs, less salvage, is charged to accumulated depreciation. Generally, electric utility plant other than nuclear fuel is subject to the lien of the Company's mortgage.
The balances of electric utility plant in service at December 31 are listed below (in millions).
1995 1994
____ ____
Production plant $ 6,014.1 $ 5,911.2 Transmission plant 912.7 879.6 Distribution plant 2,037.6 1,929.5 General plant and other 476.0 470.6 -------- -------- Electric utility plant in service $ 9,440.4 $ 9,190.9 ======== ========
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 and the borrowed funds portion is credited to interest charges. The composite AFUDC rate was 8.0% in 1995, 8.4% in 1994 and 8.8% in 1993.
D. DEPRECIATION AND AMORTIZATION
For financial reporting purposes, depreciation of utility plant other than nuclear fuel is computed on the straight-line method based on the estimated remaining useful life of the property, adjusted for estimated net salvage. Depreciation provisions, including decommissioning costs (see Note 1E), as a percent of average depreciable property other than nuclear fuel, were approximately 3.8% in 1995, 1994 and 1993. Depreciation expense totaled $344.0 million in 1995, $335.1 million in 1994 and $325.4 million in 1993. Depreciation and amortization expense also includes amortization of plant abandonment costs (see Note 8).
Amortization of nuclear fuel costs, including disposal costs associated with obligations to the U.S. Department of Energy (DOE), is computed primarily on the unit-of-production method and charged to fuel expense. Costs related to obligations to the DOE for the decommissioning and decontamination of enrichment facilities are also charged to fuel expense.
E. NUCLEAR DECOMMISSIONING
In the Company's retail jurisdictions, provisions for nuclear decommissioning costs are approved by the NCUC and the SCPSC and are based on site-specific estimates that included the costs for removal of all radioactive and other structures at the site. In the wholesale jurisdiction, the provisions for nuclear decommissioning costs are based on amounts agreed upon in applicable rate agreements. Decommissioning cost provisions, which are included in depreciation and amortization, were $31.2 million in 1995, $29.5 million in 1994 and $34.0 million in 1993.
Accumulated decommissioning costs, which are included in accumulated depreciation, were $288.4 million at December 31, 1995 and $252.7 million at December 31, 1994. These costs include amounts retained internally and amounts funded in an external decommissioning trust. The balance of the external decommissioning trust, which is included in miscellaneous other property and investments, was $110.2 million at December 31, 1995 and $67.6 million at December 31, 1994. Trust earnings, which increase the trust balance with a corresponding increase in accumulated decommissioning, were $4.5 million in 1995, $1.5 million in 1994 and $1.2 million in 1993. Based on the site-specific estimates discussed below, and using an assumed after-tax earnings rate of 8.5% and an assumed cost escalation rate of 4%, current levels of rate recovery for nuclear decommissioning costs are adequate to provide for decommissioning of the Company's nuclear facilities.
The Company's most recent site-specific estimates of decommissioning costs were developed in 1993, using 1993 cost factors, and are based on prompt dismantlement decommissioning, which reflects the cost of removal of all radioactive and other structures currently at the site, with such removal occurring shortly after operating license expiration. These estimates, in 1993 dollars, are $257.7 million for Robinson Unit No. 2, $235.4 million for Brunswick Unit No. 1, $221.4 million for Brunswick Unit No. 2 and $284.3 million for the Harris Plant. The estimates are subject to change based on a variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning, and changes in federal, state or local regulations. The cost estimates exclude the portion attributable to North Carolina Eastern Municipal Power Agency (Power Agency), which holds an undivided ownership interest in the Brunswick and Harris nuclear generating facilities. Operating licenses for the Company's nuclear units expire in the year 2010 for Robinson Unit No. 2, 2016 for Brunswick Unit No. 1, 2014 for Brunswick Unit No. 2 and 2026 for the Harris Plant.
The Financial Accounting Standards Board has reached several tentative conclusions with respect to its project regarding accounting practices related to closure and removal of long-lived assets. The primary conclusions as they relate to nuclear decommissioning are: 1) the cost of decommissioning should be accounted for as a liability and accrued as the obligation is incurred; 2) recognition of a liability for decommissioning results in recognition of an increase to the cost of the plant; 3) the decommissioning liability should be measured based on discounted cash flows using a risk-free rate; and 4) decommissioning trust funds should not be offset against the decommissioning liability. An exposure draft was issued in February 1996, and it is uncertain what impacts, if any, the final statement may have on the Company's accounting for nuclear decommissioning and other closure and removal costs.
F. REGULATORY ASSETS AND LIABILITIES
As a regulated entity, the Company is subject to the provisions of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation. "Accordingly, the Company records certain assets and liabilities resulting from the effects of the ratemaking process, which would not be recorded under generally accepted accounting principles for non-regulated entities. At December 31, 1995, the balances of the Company's regulatory assets were as follows: 1) $387.2 million for income taxes recoverable through future rates; 2) $108.0 million for Harris Plant deferred costs; 3) $57.1 million for abandonment costs; 4) $50.4 million for loss on reacquired debt, which is included in unamortized debt expense; 5) $60.5 million for deferred DOE enrichment facilities-related cost, which is included in other assets and deferred debits; and 6) $11.8 million of other regulatory assets included in other assets and deferred debits. At December 31, 1995, the Company had a regulatory liability of $27.5 million related to deferred fuel.
G. OTHER POLICIES
The Company's financial statements reflect consolidation of its majority-owned subsidiaries. Significant intercompany balances and transactions have been eliminated.
Customers' meters are read and bills are rendered on a cycle basis. Revenues are accrued for services rendered but unbilled at the end of each accounting period.
Fuel expense includes fuel costs or recoveries that are deferred through fuel clauses established by the Company's regulators. These clauses allow the Company to recover fuel costs and the fuel component of purchased power costs through the fuel component of customer rates. 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 $2.3 million at December 31, 1995 and $2.5 million at December 31, 1994. 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 Consolidated Statements of Cash Flows, the Company considers all highly-liquid investments with original maturities of three months or less to be cash equivalents.
2. 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):
1995 1994 1993 ____ ____ ____
Actual return on plan assets $(103,381) $ 4,897 $(43,604) Variance from expected return, deferred 59,425 (47,219) 4,490 -------- ------- ------- Expected return on plan assets (43,956) (42,322) (39,114) Service cost 16,344 19,686 16,776 Interest cost on projected benefit obligation 35,592 35,108 31,928 Net amortization (3,580) 831 (2,390) -------- ------- ------- Net periodic pension cost $ 4,400 $ 13,303 $ 7,200 ======== ======= =======
Reconciliations of the funded status of the pension plan at December 31 are (in thousands):
1995 1994 ____ ____
Actuarial present value of benefits for services rendered to date Accumulated benefits based on salaries to date, including vested benefits of $345.1 million for 1995 and $287.7 million for 1994 $ 392,768 $ 330,361 Additional benefits based on estimated future salary levels 130,167 103,766 -------- -------- Projected benefit obligation 522,935 434,127 Fair market value of plan assets, invested primarily in equity and fixed-income securities 610,278 506,605 -------- -------- Funded status 87,343 72,478 Unrecognized prior service costs 8,747 9,471 Unrecognized actuarial gain (124,383) (124,447) Unrecognized transition obligation, amortized over 18.5 years beginning January 1, 1987 1,005 1,110 -------- -------- Accrued pension costs recognized in the Consolidated Balance Sheets $ (27,288) $ (41,388) ======== ========
The assumptions used to measure the projected benefit obligation are:
1995 1994 ____ ____
Weighted-average discount rate 7.75% 8.50% Assumed rate of increase in future compensation 4.20% 4.20%
The expected long-term rate of return on pension plan assets used in determining the net periodic pension cost was 9% in each of the years 1995, 1994 and 1993. In addition to pension benefits, the Company provides contributory postretirement benefits (OPEB), including certain health care and life insurance benefits, for substantially all retired employees.
The components of net periodic OPEB cost are (in thousands):
1995 1994 1993 ____ ____ ____
Actual return on plan assets $(2,514) $ 42 $ (497) Variance from expected return, deferred 1,420 (682) 9 ------ ------ ------ Expected return on plan assets (1,094) (640) (488) Service cost 7,498 8,039 6,797 Interest cost on accumulated benefit obligation 10,595 9,463 9,662 Net amortization 5,530 5,966 5,966 ------ ------ ------ Net periodic OPEB cost $22,529 $22,828 $21,937 ====== ====== ======
Reconciliations of the funded status of the OPEB plans at December 31 are (in thousands):
1995 1994 ____ ____ Actuarial present value of benefits for services rendered to date Current retirees $ 59,809 $ 55,799 Active employees eligible to retire 17,942 11,933 Active employees not eligible to retire 68,819 63,164 ------- -------- Accumulated postretirement benefit obligation 146,570 130,896 Fair market value of plan assets, invested primarily in equity and fixed-income securities 20,869 12,142 ------- -------- Funded status (125,701) (118,754) Unrecognized actuarial gain (15,132) (15,125) Unrecognized transition obligation, amortized over 20 years beginning January 1, 1993 101,414 107,379 ------- -------- Accrued OPEB costs recognized in the Consolidated Balance Sheets $ (39,419) $ (26,500) ======= ========
The assumptions used to measure the accumulated postretirement benefit obligation are:
1995 1994
Weighted-average discount rate 7.75% 8.50% Initial medical cost trend rate for pre-medicare benefits 8.40% 9.60% Initial medical cost trend rate for post-medicare benefits 8.20% 8.70% Ultimate medical cost trend rate 5.25% 6.00% 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 1995, 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 1995 would increase by $2.5 million, and the accumulated postretirement benefit obligation at December 31, 1995, would increase by $16.5 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.
3. SHORT-TERM DEBT AND REVOLVING CREDIT FACILITIES
At December 31, 1995 and 1994, the Company's short-term debt balances were $73.7 million and $68.1 million, respectively. The weighted-average interest rates of these borrowings were 5.86% at December 31, 1995, and 6.18% at December 31, 1994. The Company's commercial paper borrowings are supported by revolving credit facilities. At December 31, 1995, the Company's unused and readily available revolving credit facilities totaled $335 million, consisting of long-term agreements totaling $235 million and a $100 million short-term agreement. The Company is required to pay minimal annual commitment fees to maintain its credit facilities.
4. 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 $2.76 billion at December 31, 1995, and $2.86 billion at December 31, 1994. The estimated fair value of this debt, which was obtained from an independent pricing service, was $2.85 billion at December 31, 1995, and $2.70 billion at December 31, 1994. There are inherent limitations in any estimation technique, and these estimates are not necessarily indicative of the amount the Company could realize in current transactions.
5. CAPITALIZATION
In 1994, the Board of Directors of the Company authorized the repurchase of up to 10 million shares of the Company's common stock on the open market. Under this stock repurchase program, the Company purchased approximately 4.2 million shares in 1995 and 4.4 million shares in 1994.
At December 31, 1995, the Company had 14,767,052 shares of authorized but unissued common stock reserved and available for issuance to satisfy the requirements of the Company's stock plans. The Company intends, however, to meet the requirements of these stock plans with issued and outstanding shares presently held by the Trustee of the Stock Purchase-Savings Plan (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, 1995, there were no significant restrictions on the use of retained earnings.
At December 31, 1995, long-term debt maturities for the years 1996 through 2000 were $105.8 million, $100 million, $205 million, $50 million and $197.3 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 Consolidated Balance Sheets. This classification is 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.
6. EMPLOYEE STOCK OWNERSHIP PLAN
The Company sponsors an SPSP for which all full-time employees and certain part-time employees are eligible. The SPSP, which has company match and incentive goal features, encourages systematic savings by employees and provides a method of acquiring Company common stock and other diverse investments. The SPSP, as amended in 1989, is an employee stock ownership plan (ESOP) that can enter into acquisition loans to acquire Company common stock to satisfy SPSP common share needs. Qualification as an ESOP did not change the level of benefits received by employees under the SPSP. Common stock acquired with the proceeds of an ESOP loan is held by the SPSP Trustee in a suspense account. The common stock is released from the suspense account and made available for allocation to participants as the ESOP loan is repaid, 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. Such dividends are deductible for income tax purposes.
There were 8,697,316 ESOP suspense shares at December 31, 1995, with a fair value of $300.1 million. ESOP shares allocated to plan participants totaled 14,507,665 at December 31, 1995. 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, $194.9 million at December 31, 1995, 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 had not been committed to be released to participants' accounts were no longer considered outstanding for the determination of earnings per common share; 2) dividends on unallocated ESOP shares were no longer recognized for financial statement purposes; 3) interest income related to the qualified ESOP loan was no longer recognized; 4) the difference between the acquisition and allocation prices of ESOP shares, which was previously recorded as other income, net, is recorded directly to common stock; and 5) all tax benefits of ESOP dividends are recorded to non-operating income tax expense, whereas in 1993, a portion of the tax benefits was recorded directly to retained earnings. In addition, pursuant to SOP 93-6, ESOP loan transactions between the Company and the SPSP Trustee were no longer reflected in the Consolidated Statements of Cash Flows. The implementation of SOP 93-6 resulted in an increase in earnings per common share of approximately $.04 for 1994.
7. INCOME TAXES
Deferred income taxes are provided for temporary differences between book and tax bases of assets and liabilities. Income taxes are allocated between operating income and other income based on the source of the income that generated the tax. Investment tax credits related to operating income are amortized over the service life of the related property.
Net accumulated deferred income tax liabilities at December 31 are (in thousands):
1995 1994
Accelerated depreciation and property cost differences $1,613,752 $1,504,187 Deferred costs, net 133,139 144,751 Miscellaneous other temporary differences, net (12,487) (7,173) --------- --------- Net accumulated deferred income tax liability $1,734,404 $1,641,765 ========= =========
Total deferred income tax liabilities were $2.17 billion and $1.94 billion at December 31, 1995, and 1994, respectively. Total deferred income tax assets were $434 million at December 31, 1995, and $297 million at December 31, 1994.
A reconciliation of the Company's effective income tax rate to the statutory federal income tax rate follows.
1995 1994 1993
Effective income tax rate 39.2% 37.6% 35.4% State income taxes, net of federal income tax benefit (5.0) (5.5) (5.1) Investment tax credit amortization 1.6 2.4 2.3 Other differences, net (0.8) 0.5 2.4 ---- ---- ---- Statutory federal income tax rate 35.0% 35.0% 35.0% ==== ==== ====
The provisions for income tax expense are comprised of (in thousands):
1995 1994 1993
Included in Operating Expenses Income tax expense (credit) Current - federal $143,440 $143,461 $108,935 state 41,826 39,185 29,687 Deferred - federal 75,442 23,926 50,719 state 7,860 3,500 11,588 Investment tax credit (9,344) (11,537) (11,612) ------- ------- ------- Subtotal 259,224 198,535 189,317 ------- ------- ------- Harris Plant deferred costs Investment tax credit (297) (297) 218 ------- ------- ------- Total included in operating expenses 258,927 198,238 189,535 ------- ------- -------
Included in Other Income Income tax expense (credit) Current - federal (20,669) (15,732) (6,168) state (4,251) (3,507) (1,291) Deferred - federal 5,254 8,065 7,483 state 1,125 1,749 1,562 Investment tax credit -- -- (1,194) ------- ------- ------- Total included in other income (18,541) (9,425) 392 ------- ------- ------- Total income tax expense $240,386 $188,813 $189,927 ======= ======= =======
8. PLANT-RELATED DEFERRED COSTS
The Company abandoned efforts to complete Harris Unit No. 2 in December 1983 and Mayo Unit No. 2 in March 1987. The NCUC and SCPSC each allowed the Company to recover the cost of these abandoned units over a ten-year period without a return on the unamortized balances. The amortization of Harris Unit No. 2 costs was completed in 1994. In the 1988 rate orders and a 1990 NCUC Order on Remand, the Company was ordered to remove from rate base and treat as abandoned plant certain costs related to the Harris Plant. Amortization related to abandoned plant costs associated with the 1990 NCUC Order on Remand was completed in 1994. Abandoned plant amortization related to the 1988 rate orders will be completed in 1998 for the North Carolina retail and 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 $18.3 million in 1995, $60.5 million in 1994 and $100.7 million in 1993. 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 $4.3 million in 1995, $6.6 million in 1994 and $13.2 million in 1993 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 $38.4 million at December 31, 1995, and $60.8 million at December 31, 1994.
9. JOINT OWNERSHIP OF GENERATING FACILITIES
Power Agency holds undivided ownership interests in certain generating facilities of the Company. The Company and Power Agency are entitled to shares of the generating capability and output of each unit equal to their respective ownership interests. Each also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. The Company's share of expenses for the jointly-owned units is included in the appropriate expense category in the Consolidated Statements of Income.
The Company's share of the jointly-owned generating facilities is listed below with related information as of December 31, 1995 (dollars in millions).
Company Megawatt Ownership Plant Accumulated Under Facility Capability Interest Investment Depreciation Construction ________ __________ ________ __________ ____________ ____________
Mayo Plant 745 83.83% $ 432.9 $ 159.0 $ 7.2 Harris Plant 860 83.83% $ 3,006.6 $ 750.6 $ 8.6 Brunswick Plant 1,521 81.67% $ 1,361.3 $ 758.7 $ 35.8 Roxboro Unit No.4 700 87.06% $ 223.2 $ 91.9 $ 3.1
In the table above, plant investment and accumulated depreciation, which includes accumulated nuclear decommissioning, are not reduced by the regulatory disallowances related to the Harris Plant.
10. COMMITMENTS AND CONTINGENCIES
A. PURCHASED POWER Pursuant to the terms of the 1981 Power Coordination Agreement, as amended, between the Company and Power Agency, the Company is obligated to purchase a percentage of Power Agency's ownership capacity and energy from the Mayo and Harris Plants. For Mayo, the percentage purchased declines ratably over a 15-year period that ends in 1997. In 1993, the Company and Power Agency entered into an agreement to restructure portions of their contracts covering power supplies and interests in jointly-owned units. 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 $26 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 $39.4 million for 1995, $60.4 million for 1994 and $52.6 million for 1993. 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, 1995 and 1994, the Company had deferred purchased capacity costs, including carrying costs accrued on the deferred balances, of $72.7 million and $70.9 million, respectively. Increased purchases resulting from the 1993 agreement with Power Agency, which were approximately $10 million for 1995 and $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 (Rockport) and 400 megawatts of generating capacity from Duke Power Company (Duke). The estimated minimum annual payment for power under these contracts is approximately $30 million for Rockport and $43 million for Duke, representing capital-related capacity costs. Other power costs include demand-related production expenses, fuel and energy-related operation and maintenance expenses for Rockport and fuel and energy-related operation and maintenance expenses for Duke. Purchases, including transmission use charges, for Rockport and Duke, respectively, totaled $61.8 million and $63.8 million for 1995, $61.9 million and $62.9 million for 1994 and $60.2 million and $37.1 million for 1993. The Rockport agreement expires in December 2009 and the Duke agreement expires in mid-1999.
B. INSURANCE
The Company is a member of Nuclear Mutual Limited (NML), which provides primary insurance coverage against property damage to members' nuclear generating facilities. The Company is insured thereunder for $500 million for each of its nuclear generating facilities. For the current policy period, the Company is subject to maximum retrospective premium assessments of approximately $20 million in the event that losses at insured facilities exceed premiums, reserves, reinsurance and other NML resources, which are at present more than $763 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 $1.5 million at Brunswick Unit No. 1, $1.4 million at Brunswick Unit No. 2, $1.7 million at the Harris Plant and $1.4 million at Robinson Unit No. 2. The Company is insured for the next 104 weeks for 80% of the above amounts. NEIL also provides decontamination, decommissioning and excess property insurance for nuclear generating facilities. The Company is insured under this coverage for $1.4 billion per incident. This is in addition to the $500 million coverage provided by NML. For the current policy period, the Company is subject to retrospective premium assessments of up to approximately $7.6 million with respect to the incremental replacement power costs coverage and $42.9 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 $2.2 billion. Pursuant to regulations of the Nuclear Regulatory Commission, the Company's property damage insurance policies provide that all proceeds from such insurance be applied, first, to place a plant in safe and stable condition after an accident and, second, to decontaminate it before any proceeds can be used for plant repair or restoration. The Company is responsible to the extent losses may exceed limits of the coverage described above. Power Agency would be responsible for its ownership share of such losses and for certain retrospective premium assessments on jointly-owned nuclear units.
The Company is insured against public liability for a nuclear incident up to $8.9 billion per occurrence, which is the maximum limit on public liability claims pursuant to the Price-Anderson Act. In the event that public liability claims from an insured nuclear incident exceed $200 million, the Company would be subject to a pro rata assessment of up to $75.5 million, plus a 5% surcharge, for each reactor owned for each incident. Payment of such assessment would be made over time as necessary to limit the payment in any one year to no more than $10 million per reactor owned. Power Agency would be responsible for its ownership share of the assessment on jointly-owned nuclear units.
C. 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 continues to investigate the identities of parties connected to MGP sites in North Carolina, 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 expect costs associated with these sites to be material to the results of operations of the Company.
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 1996 definitive proxy statement dated March 29, 1996, 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 1996 definitive proxy statement dated March 29, 1996, 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, 1995, owned 9,511,913 shares of Common Stock (6.2% of Class) as Trustee of the Company's Stock Purchase-Savings Plan.
b) Information on security ownership of the Company's management is set forth in the Company's 1996 definitive proxy statement dated March 29, 1996, 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 1996 definitive proxy statement dated March 29, 1996, and incorporated by reference herein.
PART IV
ITEM 14. EXHIBITS, CONSOLIDATED FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. ___________________________________________________________________
a) 1. Consolidated Financial Statements Filed:
See ITEM 8 - Consolidated Financial Statements and Supplementary Data.
2. Consolidated Financial Statement Schedules Filed:
See ITEM 8 - Consolidated Financial Statements and Supplementary Data.
3. Exhibits Filed:
Exhibit No. *3a(1) Restated Charter of the Company, as amended May 10, 1995 (filed as Exhibit No. 3(i) to quarterly report on Form 10-Q for the quarterly period ended June 30, 1995, File No. 1-3382).
Exhibit No. *3a(2) By-laws of the Company, as amended May 10, 1995 (filed as Exhibit No. 3(ii) to quarterly report on Form 10-Q for the quarterly period ended June 30, 1995, File No. 1-3382).
Exhibit No. *4a(1) Resolution of Board of Directors, dated December 8, 1954, authorizing the issuance of, and establishing the series designation, dividend rate and redemption prices for the Company's Serial Preferred Stock, $4.20 Series (filed as Exhibit 3(c), File No.33-25560).
Exhibit No. *4a(2) Resolution of Board of Directors, dated January 17, 1967, authorizing the issuance of, and establishing the series designation, dividend rate and redemption prices for the Company's Serial Preferred Stock, $5.44 Series (filed as Exhibit 3(d), File No. 33-25560).
Exhibit No. *4a(3) Statement of Classification of Shares dated January 13, 1971, relating to the authorization of, and establishing the series designation, dividend rate and redemption prices for the Company's Serial Preferred Stock, $7.95 Series (filed as Exhibit 3(f), File No. 33-25560).
Exhibit No. *4a(4) Statement of Classification of Shares dated September 7, 1972, relating to the authorization of, and establishing the series designation, dividend rate and redemption prices for the Company's Serial Preferred Stock, $7.72 Series (filed as Exhibit 3(g), File No. 33-25560).
Exhibit No. *4b Mortgage and Deed of Trust dated as of May 1, 1940 between the Company and The Bank of New York (formerly, Irving Trust Company) and Frederick G. Herbst (W.T. Cunningham, Successor), Trustees and the First through Fifth Supplemental Indentures thereto (Exhibit 2(b), File No. 2-64189); and the Sixth through Sixty-third Supplemental Indentures (Exhibit 2(b)-5, File No. 2-16210; Exhibit 2(b)-6, File No. 2-16210; Exhibit 4(b)-8, File No. 2-19118; 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. *4c(1) Indenture, dated as of March 1, 1995, between the Company and Bankers Trust Company, as Trustee, with respect to Unsecured Subordinated Debt Securities (filed as Exhibit No. 4(c) to Current Report on Form 8-K dated April 13, 1995, File No. 1-3382).
Exhibit No. *4c(2) Resolutions adopted by the Executive Committee of the Board of Directors at a meeting held on April 13, 1995, establishing the terms of the 8.55% Quarterly Income Capital Securities (Series A Subordinated Deferrable Interest Debentures) (filed as Exhibit 4(b) to Current Report on Form 8-K dated April 13, 1995, File No. 1-3382).
Exhibit No. *10a(1) Purchase, Construction and Ownership Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency, amending letter dated February 18, 1982, and amendment dated February 24, 1982 (filed as Exhibit 10(a), File No. 33-25560).
Exhibit No. *10a(2) Operating and Fuel Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency, amending letters dated August 21, 1981 and December 15, 1981, and amendment dated February 24, 1982 (filed as Exhibit 10(b), File No. 33-25560).
Exhibit No. *10a(3) Power Coordination Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency and amending letter dated January 29, 1982 (filed as Exhibit 10(c), File No. 33-25560).
Exhibit No. *10a(4) Amendment dated December 16, 1982 to Purchase, Construction and Ownership Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Eastern Municipal Power Agency (filed as Exhibit 10(d), File No. 33-25560).
Exhibit No. *10a(5) Agreement Regarding New Resources and Interim Capacity between Carolina Power & Light Company and North Carolina Eastern Municipal Power Agency dated October 13, 1987 (filed as Exhibit 10(e), File No. 33-25560).
Exhibit No. *10a(6) Power Coordination Agreement - 1987A between North Carolina Eastern Municipal Power Agency and Carolina Power & Light Company for Contract Power From New Resources Period 1987-1993 dated October 13, 1987 (filed as Exhibit 10(f), File No. 33-25560).
+Exhibit No. *10b(1) Directors Deferred Compensation Plan effective January 1, 1982 as amended (filed as Exhibit 10(g), File No. 33-25560).
+Exhibit No. *10b(2) Supplemental Executive Retirement Plan effective January 1, 1984 (filed as Exhibit 10(h), File No. 33-25560).
+Exhibit No. *10b(3) Retirement Plan for Outside Directors (filed as Exhibit 10) (i), File No. 33-25560).
+Exhibit No. *10b(4) Executive Deferred Compensation Plan effective May 1, 1982 as amended (filed as Exhibit 10(j), File No. 33-25560).
+Exhibit No. *10b(5) Key Management Deferred Compensation Plan (filed as Exhibit 10(k), File No. 33-25560).
+Exhibit No. *10b(6) Resolutions of the Board of Directors, dated March 15, 1989, amending the Key Management Deferred Compensation Plan (filed as Exhibit 10(a), File No. 33-48607).
+Exhibit No. *10b(7) Resolutions of the Board of Directors dated May 8, 1991, amending the Directors Deferred Compensation Plan(filed as Exhibit 10(b), File No. 33-48607).
+Exhibit No. *10b(8) Resolutions of the Board of Directors dated May 8, 1991, amending the Executive Deferred Compensation Plan (filed as Exhibit 10(c), File No. 33-48607).
Exhibit No. 12 Computation of Ratio of Earnings to Fixed Charges and Preferred Dividends Combined and Ratio of Earnings to Fixed Charges.
Exhibit No. 23(a) Consent of Deloitte & Touche LLP.
Exhibit No. 23(b) Consent of Richard E. Jones.
Exhibit No. 27 Financial Data Schedule
Exhibit No. 18 Letter re: Change in Accounting Principles
*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 1995 and the portion of the first quarter of 1996 prior to the filing of this 10-K:
Date of Report Item Reported ______________ _____________
NONE
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 25th day of March, 1996.
CAROLINA POWER & LIGHT COMPANY (Registrant)
By /s/ Glenn E. Harder Executive Vice President and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Signature Title Date _________ _____ ____
/s/ Sherwood H. Smith, Jr. Principal Executive (Chairman and Chief Executive Officer and Director Officer)
/s/ Glenn E. Harder Principal Financial (Executive Vice President and Officer Chief Financial Officer)
/s/ Leslie M. Baker, Jr. Director
/s/ Edwin B. Borden Director March 25, 1996
/s/ Felton J. Capel Director
/s/ William Cavanaugh III Director (President and Chief Operating Officer)
/s/ George H. V. Cecil Director
/s/ Charles W. Coker Director
/s/ Richard L. Daugherty Director
/s/ J. R. Bryan Jackson Director
/s/ Robert L. Jones Director
/s/ Estell C. Lee Director
/s/ J. Tylee Wilson Director