ITEM 1. BUSINESS - ------- --------
GENERAL - -------
COMPANY - -------
Progress Energy, Inc. (Progress Energy, or the Company, which term includes consolidated subsidiaries unless otherwise indicated), is a registered holding company under the Public Utility Holding Company Act (PUHCA) of 1935. Both the Company and its subsidiaries are subject to the regulatory provisions of PUHCA. Progress Energy was initially formed as CP&L Energy, Inc. (CP&L Energy), which became the holding company for Carolina Power & Light Company (CP&L) on June 19, 2000. All shares of common stock of CP&L were exchanged for an equal number of shares of CP&L Energy common stock.
On July 1, 2000, CP&L distributed its ownership interest in the stock of North Carolina Natural Gas Corporation (NCNG), Strategic Resource Solutions Corp. (SRS), Monroe Power Company (Monroe Power) and Progress Ventures, Inc. to CP&L Energy. As a result, those companies became direct subsidiaries of CP&L Energy and are not included in CP&L's results of operations and financial position since that date.
Subsequent to the acquisition of Florida Progress Corporation (FPC) (see "Significant Transactions" below), the Company changed its name from CP&L Energy to Progress Energy, Inc. on December 4, 2000.
Through its wholly owned regulated subsidiaries, CP&L, Florida Power Corporation (Florida Power) and NCNG, Progress Energy is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina, South Carolina and Florida; and the transport, distribution and sale of natural gas in portions of North Carolina. Through the Progress Ventures business segment, Progress Energy is involved in merchant energy generation, coal and synthetic fuel operations and energy marketing and trading. Through other business units, Progress Energy engages in other non-regulated business areas including energy management and related services, rail services and telecommunications.
Progress Energy is a regional energy company focusing on the high-growth Southeast region of the United States. The Company has more than 20,000 megawatts of electric generation capacity and serves approximately 2.9 million electric and gas customers in portions of North Carolina, South Carolina and Florida. CP&L's and Florida Power's utility operations are complementary: CP&L has a summer peaking demand, while Florida Power has a winter peaking demand. In addition, CP&L's greater proportion of commercial and industrial customers combined with Florida Power's greater proportion of residential customers creates a more balanced customer base. The Company is dedicated to expanding the region's electric generation capacity and delivering reliable, competitively priced energy.
Progress Energy revenues for the year ended December 31, 2001, were $8.5 billion, and assets at year-end were $20.7 billion. Its principal executive offices are located at 410 South Wilmington Street, Raleigh, North Carolina 27601, telephone number (919) 546-6111. The Progress Energy home page on the Internet is located at http://www.progress-energy.com, the contents of which are not a part of this document. Progress Energy was incorporated on August 19, 1999.
The operations of Progress Energy and its subsidiaries are divided into five major segments: two electric utilities (CP&L and Florida Power), Progress Ventures, Rail Services and Other. Progress Energy's legal structure is not currently aligned with the functional management and financial reporting of its segments. Whether, and when, the legal and functional structures will converge depends upon legislative and regulatory action, which cannot currently be anticipated. The Other segment primarily includes natural gas operations, telecommunication services, energy management services, miscellaneous non-regulated activities, holding company operations and elimination entries. For information regarding the revenues, income and assets attributable to the Company's business segments, see Note 3 to the Progress Energy consolidated financial statements.
SIGNIFICANT TRANSACTIONS - ------------------------
Florida Progress Acquisition
On November 30, 2000, the Company completed its acquisition of FPC for an aggregate purchase price of approximately $5.4 billion. The Company paid cash consideration of approximately $3.5 billion and issued 46.5 million common shares valued at approximately $1.9 billion. In addition, the Company issued 98.6 million
contingent value obligations (CVO) valued at approximately $49.3 million. See Note 2A to the Progress Energy financial statements for additional discussion of the FPC acquisition.
FPC is a diversified, exempt electric utility holding company. Florida Power, FPC's largest subsidiary is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity. FPC also has diversified non-utility operations owned through Progress Capital Holdings, Inc. Included in diversified operations are Progress Fuels Corporation, an energy and transportation company, and Progress Telecommunications Corporation, a wholesale telecommunications service provider. As of the acquisition date, the primary segments of Progress Fuels were energy and related services, rail services, and inland marine transportation. During 2001, Progress Energy sold the inland marine transportation segment to AEP Resources, Inc., as more fully discussed below.
The FPC acquisition was accounted for using the purchase method of accounting and, accordingly, the results of operations for FPC have been included in the Company's consolidated financial statements since the date of acquisition. Identifiable assets acquired and liabilities assumed have been recorded at their fair values of $6.7 billion and $4.9 billion, respectively. The excess of the purchase price over the fair value of the net identifiable assets and liabilities acquired has been recorded as goodwill. The goodwill, of approximately $3.6 billion, was being amortized on a straight-line basis over a period of 40 years. Effective January 1, 2002, goodwill is no longer subject to amortization.
Sale of MEMCO Barge Line, Inc.
On July 23, 2001, Progress Energy announced the disposition of the Inland Marine Transportation segment of FPC, which was operated by MEMCO Barge Line, Inc. Inland Marine provided transportation of coal, agricultural and other dry-bulk commodities as well as fleet management services. On November 1, 2001, the Company completed the sale of the Inland Marine Transportation segment to AEP Resources, Inc., a wholly owned subsidiary of American Electric Power. See Note 4 to the Progress Energy consolidated financial statements for additional discussion of this transaction.
LG&E Energy Corp. Acquisition
During February 2002, Progress Ventures, Inc. completed the acquisition of two electric generating projects totaling nearly 1,100 megawatts in Georgia. See Item 7, "Other Matters" for additional discussion of this transaction.
Westchester Gas Company Acquisition
On January 11, 2002, Progress Energy announced that it had entered into a letter of intent with Westchester Gas Company to acquire approximately 215 producing natural gas wells, 52 miles of intrastate gas pipeline and 170 miles of gas-gathering systems. See Item 7, "Other Matters" for additional discussion of this transaction.
COMPETITION - -----------
GENERAL - -------
In recent years, the electric utility industry has experienced a substantial increase in competition at the wholesale level, caused by changes in federal law and regulatory policy. Several states have also decided to restructure aspects of retail electric service. The issue of retail restructuring and competition is being reviewed by a number of states and bills have been introduced in past sessions of Congress that sought to introduce such restructuring in all states.
Allowing increased competition in the generation and sale of electric power will require resolution of many complex issues. One of the major issues to be resolved is who would pay for stranded costs. Stranded costs are those costs and investments made by utilities in order to meet their statutory obligation to provide electric service, but which could not be recovered through the market price of electricity following industry restructuring. The amount of such stranded costs that the Company might experience would depend on the timing of, and the extent to which, direct competition is introduced, and the then-existing market price of energy. If both electric utilities and the gas utility were no longer subject to cost-based regulation and it was not possible to recover stranded costs, the financial position and results of operations of the Company could be adversely affected.
Several electric industry restructuring bills introduced during the 106th Congress died upon adjournment in 2000. During the 107th Congress, attention has turned more toward a comprehensive energy policy as opposed to restructuring of the electric industry. However, restructuring could eventually become part of any legislation and/or
specific electric industry restructuring legislation could be introduced and considered by Congress. The Company cannot predict the outcome of this matter.
As a result of the Public Utilities Regulatory Policies Act of 1978 (PURPA) and the Energy Policy Act of 1992 (EPA of 1992), competition in the wholesale electricity market has greatly increased, especially from non-utility generators of electricity. In 1996, the Federal Energy Regulatory Commission (FERC) issued new rules on transmission service to facilitate competition in the wholesale market on a nationwide basis. The rules give greater flexibility and more choices to wholesale power customers.
On December 20, 1999, FERC issued Order No. 2000 on Regional Transmission Organizations (RTO), which sets forth four minimum characteristics and eight functions for transmission entities, including independent system operators and transmission companies, that are required to become FERC-approved RTOs. The rule stated that public utilities that own, operate or control interstate transmission facilities had to have filed, by October 15, 2000, either a proposal to participate in an RTO or an alternative filing describing efforts and plans to participate in an RTO. The order provided guidance and specified minimum characteristics and functions required of an RTO and also stated that all RTOs should be operational by December 15, 2001. During 2001, the deadline for RTO's to be operational was extended. See PART I, ITEM 1, "Competition" of CP&L Electric and Florida Power Electric for a discussion of the development activities for the GridSouth RTO and GridFlorida RTO, respectively.
To date, many states have adopted legislation that would give retail customers the right to choose their electricity provider (retail choice) and most other states have, in some form, considered the issue.
The developments described above have created changing markets for energy. As a strategy for competing in these changing markets, the Company is becoming a total energy provider in the region by providing a full array of energy-related services to its current customers and expanding its market reach. The Company took a major step towards implementing this strategy through its acquisition of FPC.
See PART I, ITEM 1, "Competition" discussion under Electric-CP&L, Electric-Florida Power and Other for further discussion of competitive developments within these segments.
PUHCA - -----
As a result of the acquisition of FPC, Progress Energy is now a registered holding company subject to regulation by the Securities and Exchange Commission (SEC) under PUHCA. Therefore, Progress Energy and its subsidiaries are subject to the regulatory provisions of PUHCA, including provisions relating to the issuance of securities, sales and acquisitions of securities and utility assets, and services performed by Progress Energy Service Company LLC.
While various proposals have been introduced in Congress regarding PUHCA, the prospects for legislative reform or repeal are uncertain at this time.
ENVIRONMENTAL - -------------
GENERAL - -------
In the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes and other environmental matters, the Company is subject to regulation by various federal, state and local authorities. The Company considers itself to be in substantial compliance with those environmental regulations currently applicable to its business and operations and believes it has all necessary permits to conduct such operations. Environmental laws and regulations constantly evolve and the ultimate costs of compliance cannot always be accurately estimated. The capital costs associated with compliance with pollution control laws and regulations at the Company's existing fossil facilities that the Company expects to incur from 2002 through 2004 are included in the estimates under the "Investing Activities" discussion under PART II, ITEM 7, "Liquidity and Capital Resources."
CLEAN AIR LEGISLATION - ---------------------
The 1990 amendments to the Clean Air Act require substantial reductions in sulfur dioxide and nitrogen oxide emissions from fossil-fueled electric generating plants. The Clean Air Act required the Company to meet more stringent provisions effective January 1, 2000. The Company meets the sulfur dioxide emissions requirements by maintaining sufficient sulfur dioxide emission allowances. Installation of additional equipment was necessary to
reduce nitrogen oxide emissions. Increased operation and maintenance costs, including emission allowance expense, installation of additional equipment and increased fuel costs are not expected to be material to the consolidated financial position or results of operations of the Company.
The U.S. Environmental Protection Agency (EPA) has been conducting an enforcement initiative related to a number of coal-fired utility power plants in an effort to determine whether modifications at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. Both CP&L and Florida Power were asked to provide information to the EPA as part of this initiative and cooperated in providing the requested information. The EPA has initiated enforcement actions against other unaffiliated utilities as part of this initiative, some of which have resulted in settlement agreements calling for expenditures, ranging from $1.0 billion to $1.4 billion. A utility that was not subject to a civil enforcement action settled its New Source Review issues with the EPA for $300 million. These settlement agreements have generally called for expenditures to be made over extended time periods, and some of the companies may seek recovery of the related cost through rate adjustments. The Company cannot predict the outcome of this matter.
In 1998, the EPA published a final rule addressing the issue of regional transport of ozone. This rule is commonly known as the NOx SIP Call. The EPA's rule requires 23 jurisdictions, including North Carolina, South Carolina and Georgia, but not Florida, to further reduce nitrogen oxide emissions in order to attain a pre-set state NOx emission level by May 31, 2004. CP&L is evaluating necessary measures to comply with the rule and estimates its related capital expenditures could be approximately $370 million, which has not been adjusted for inflation. The Company spent approximately $46.3 million in 2001 related to these expenditures. Increased operation and maintenance costs relating to the NOx SIP Call are not expected to be material to the Company's results of operations. Further controls are anticipated as electricity demand increases. The Company cannot predict the outcome of this matter.
The EPA published a final rule approving petitions under Section 126 of the Clean Air Act, which requires certain sources to make reductions in nitrogen oxide emissions by May 1, 2003. The final rule also includes a set of regulations that affect nitrogen oxide emissions from sources included in the petitions. The North Carolina fossil-fueled electric generating plants are included in these petitions. Acceptable state plans under the NOx SIP Call can be approved in lieu of the final rules the EPA approved as part of the Section 126 petitions. CP&L, other utilities, trade organizations and other states participated in litigation challenging the EPA's action. On May 15, 2001, the District of Columbia Circuit Court of Appeals ruled in favor of the EPA, which will require North Carolina to make reductions in nitrogen oxide emissions by May 1, 2003. However, the Court in its May 15th decision rejected the EPA's methodology for estimating the future growth factors the EPA used in calculating the emissions limits for utilities. In August 2001, the court granted a request by CP&L and other utilities to delay the implementation of the Section 126 Rule for electric generating units pending resolution by the EPA of the growth factor issue. The Court's order tolls the three-year compliance period (originally set to end on May 1, 2003) for electric generating units as of May 15, 2001. On January 16, 2002, the EPA issued a memo to harmonize the compliance dates for the Section 126 Rule and the NOx SIP Call. The new compliance date for all affected sources is now May 31, 2004, rather than May 1, 2003, subject to the completion of the EPA's response to the related court decision on the growth factor issue. The Company cannot predict the outcome of this matter.
SUPERFUND - ---------
The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the clean up of hazardous waste sites. This statute imposes retroactive joint and several liability. Some states, including North and South Carolina, have similar types of legislation. There are presently several sites with respect to which the Company has been notified by the EPA, the State of North Carolina or the State of Florida of its potential liability, as described below in greater detail.
Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under various federal and state laws. The lead or sole regulatory agency that is responsible for a particular former coal tar site depends largely upon the state in which the site is located. There are several manufactured gas plant (MGP) sites to which both electric utilities and the gas utility have some connection. In this regard, both electric utilities and the gas utility, with other potentially responsible parties, are participating in investigating and, if necessary, remediating former coal tar sites with several regulatory agencies, including, but not limited to, the EPA, the Florida Department of Environmental Protection (DEP) and the North Carolina Department of Environment and Natural Resources, Division of Waste Management (DWM). Although the Company may incur costs at these sites
about which it has been notified, based upon current status of these sites, the Company does not expect those costs to be material to its consolidated financial position or results of operations.
Both electric utilities, the gas utility and Progress Ventures are periodically notified by regulators such as the EPA and various state agencies of their involvement or potential involvement in sites, other than MGP sites, that may require investigation and/or remediation. Although the Company's subsidiaries may incur costs at the sites about which they have been notified, based upon the current status of these sites, the Company does not expect those costs to be material to the consolidated financial position or results of operations of the Company.
OTHER ENVIRONMENTAL MATTERS - ---------------------------
On November 1, 2001, Progress Energy completed the sale of the Inland Marine Transportation segment to AEP Resources, Inc. In connection with the sale, Progress Energy entered into environmental indemnification provisions covering both unknown and known sites. Progress Energy has recorded an accrual to cover estimated probable future environmental expenditures. Progress Energy believes that it is reasonably possible that additional costs, which cannot be currently estimated, may be incurred related to the environmental indemnification provision beyond the amounts accrued. Progress Energy cannot predict the outcome of this matter.
Both electric utilities, the gas utility and Progress Ventures have filed claims with the Company's general liability insurance carriers to recover costs arising out of actual or potential environmental liabilities. Some claims have been settled and others are still pending. While management cannot predict the outcome of these matters, the outcome is not expected to have a material effect on the Company's consolidated financial position or results of operations.
EMPLOYEES - ---------
As of February 28, 2002, Progress Energy and its subsidiaries employed approximately 16,200 full-time employees. Of this total, approximately 2,100 employees at Florida Power are represented by the International Brotherhood of Electrical Workers. The current union contract was ratified in December 1999 and expires in December 2002. The Company and some of its subsidiaries have a non-contributory defined benefit retirement (pension) plan for substantially all full-time employees and an employee stock purchase plan among other employee benefits. The Company and some of its subsidiaries also provide contributory postretirement benefits, including certain health care and life insurance benefits, for substantially all retired employees.
As of February 28, 2002, CP&L employed approximately 5,600 full-time employees.
ELECTRIC - CP&L - ---------------
GENERAL - -------
CP&L is a public service corporation formed under the laws of North Carolina in 1926, and is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North and South Carolina. As of December 31, 2001, CP&L had a total summer generating capacity (including jointly-owned capacity) of approximately 12,040 megawatts (MW).
CP&L distributes and sells electricity in 57 of the 100 counties in North Carolina, and 14 counties in northeastern South Carolina. The territory served is an area of approximately 34,000 square miles, including a substantial portion of the coastal plain of North Carolina extending to the Atlantic coast between the Pamlico River and the South Carolina border, the lower Piedmont section of North Carolina, an area in northeastern South Carolina and an area in western North Carolina in and around the city of Asheville. The estimated total population of the territory served is more than 4.0 million. At December 31, 2001, CP&L was providing electric services, retail and wholesale, to approximately 1.3 million customers. CP&L is subject to the rules and regulations of FERC, the North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (SCPSC).
BILLED ELECTRIC REVENUES - ------------------------
CP&L's electric revenues billed by customer class, for the last three years, is shown as a percentage of total CP&L electric revenues in the table below:
BILLED ELECTRIC REVENUES
Revenue Class 2001 2000 1999 - ------------- ---- ---- ---- Residential 34% 33% 34% Commercial 23% 22% 22% Industrial 21% 23% 24% Wholesale (a) 19% 18% 18% Other retail 3% 4% 2%
(a) These revenues are managed by Progress Ventures on behalf of CP&L
Major industries in CP&L's service area include textiles, chemicals, metals, paper, food, rubber and plastics, wood products, and electronic machinery and equipment.
FUEL AND PURCHASED POWER - ------------------------
Sources of Generation
CP&L's total system generation (including the North Carolina Eastern Municipal Power Agency's (Power Agency) share) by primary energy source, along with purchased power, for the last three years is set forth below:
ENERGY MIX PERCENTAGES
2001 2000 1999 ---- ---- ---- Coal 49% 48% 48% Nuclear 41% 43% 42% Hydro 0% 1% 1% Oil/Gas 2% 1% 1% Purchased Power 8% 7% 8%
CP&L is generally permitted to pass the cost of recoverable fuel and purchased power to its customers through fuel adjustment clauses. The future prices for and availability of various fuels discussed in this report cannot be predicted with complete certainty. However, CP&L believes that its fuel supply contracts, as described below, will be adequate to meet its fuel supply needs.
CP&L's average fuel costs per million British thermal units (Btu) for the last three years were as follows:
AVERAGE FUEL COST (per million Btu)
2001 2000 1999 ---- ---- ---- Coal $1.78 $1.70 $1.70 Nuclear 0.44 0.45 0.46 Hydro -- -- -- Oil (a) 6.38 5.51 3.70 Gas (a) 4.69 5.41 3.37 Weighted Average 1.26 1.21 1.16
(a) Changes in the unit price for oil and gas are due to market conditions. Since these costs are primarily recovered through recovery clauses established by regulators, the fluctuation does not materially affect net income.
Coal
CP&L has short-term, intermediate and long-term agreements from which it expects to receive approximately 100% of its coal burn requirements in 2002. These agreements have expiration dates ranging from 2002 to 2006. All of the
coal that CP&L is currently purchasing under intermediate and long-term agreements is considered to be low sulfur coal by industry standards. The pending expiration of a railway contract on March 31, 2002, may result in increases in the freight rates for the shipment of coal.
Nuclear
Nuclear fuel is processed through four distinct stages. Stages I and II involve the mining and milling of the natural uranium ore to produce a concentrate and the conversion of this uranium concentrate into uranium hexafluoride. Stages III and IV entail the enrichment of the uranium hexafluoride and the fabrication of the enriched uranium hexafluoride into usable fuel assemblies.
CP&L expects to meet its future nuclear fuel requirements from inventory on hand and amounts received under contract. Although CP&L cannot predict the future availability of uranium and nuclear fuel services, CP&L does not currently expect to have difficulty obtaining uranium oxide concentrate and the services necessary for its conversion, enrichment and fabrication into nuclear fuel. For a discussion of CP&L's plans with respect to spent fuel storage, see PART I, ITEM 1, "Nuclear Matters" for CP&L Electric.
Hydro
Hydroelectric power is electric energy generated by the force of falling water. CP&L has four hydroelectric generating plants licensed by FERC: Walters, Tillery, Blewett and Marshall. The total installed capacity for these units is 218 MW.
Oil & Gas
Oil is purchased under contracts and in the spot market from several suppliers. The cost of CP&L's oil and gas is determined by market conditions. Management believes that CP&L has access to an adequate supply of oil for the reasonably foreseeable future. CP&L's natural gas supply is purchased under firm supply and delivery contracts as well as spot market purchases from numerous suppliers. CP&L believes that existing contracts for oil are sufficient to cover its requirements when natural gas is unavailable during the winter period for CP&L's combustion turbine peaker fleet.
Purchased Power
CP&L purchased 4,996,645 MWh in 2001, 4,467,802 MWh in 2000 and 4,730,657 MWh in 1999 of its system energy requirements (including Power Agency's share) and had available 1,756 MW in 2001, 1,036 MW in 2000, and 1,489 MW in 1999 of firm purchased capacity under contract at the time of peak load. CP&L may acquire purchased power capacity in the future to accommodate a portion of its system load needs.
COMPETITION - -----------
Electric Industry Restructuring
CP&L continues to monitor progress toward a more competitive environment and has actively participated in regulatory reform deliberations in North Carolina and South Carolina. Movement toward deregulation in these states has been affected by recent developments, including developments related to deregulation of the electric industry in California and other states.
. North Carolina. On January 23, 2001, the Commission on the Future of Electric Service in North Carolina announced that it would not recommend any new laws on electricity deregulation to the 2001 session of the North Carolina General Assembly, citing the commission's determination that more research is needed. The commission's initial report to the General Assembly, issued on May 16, 2000, had contained several proposals, including a recommendation that electric retail competition should begin in North Carolina by 2006. At its January 23, 2001, meeting, the commission requested that the NCUC consider regulatory changes to facilitate the construction of wholesale generation facilities by private companies, including the elimination of requirements that such companies provide proof of a committed customer base and need for additional power in order to obtain operating licenses. Subsequently on May 21, 2001, the NCUC adopted a revised rule that streamlined the certification process for wholesale merchant generating plants. The Company cannot predict the outcome of this matter.
. South Carolina. CP&L expects the South Carolina General Assembly will continue to monitor the experiences of states that have implemented electric restructuring legislation.
Regional Transmission Organizations
In October 2000, CP&L, along with Duke Energy Corporation and South Carolina Electric & Gas Company, filed with FERC an application for approval of a for-profit transmission company, currently named GridSouth. On July 12, 2001, FERC issued an order granting GridSouth RTO status and directing that certain modifications to the RTO documents be made and filed within 90 days. In February 2002, CP&L and the other GridSouth applicants withdrew the GridSouth application from the NCUC and SCPSC for purposes of making certain revisions to the GridSouth proposal. The GridSouth applicants plan to refile their application once those changes have been made.
See PART II, Item 7, "Other Matters," for additional discussion of GridSouth RTO.
Franchises
CP&L has nonexclusive franchises with varying expiration dates in most of the municipalities in which it distributes electric energy in North Carolina and South Carolina. Of these 239 franchises, 194 have expiration dates ranging from 2008 to 2061 and 45 of these have no specific expiration dates. All but ten of the 194 franchises with expiration dates have a term of sixty years. The exceptions include one franchise with a term of ten years, one with a term of twenty years, five with a term of thirty years, two with a term of forty years and one with a term of fifty years. However, CP&L also serves within a number of municipalities and in all of its unincorporated areas without existing franchise ordinances.
Wholesale Competition
Since passage of the EPA of 1992, competition in the wholesale electric utility industry has significantly increased due to a greater participation by traditional electricity suppliers, wholesale power marketers and brokers, and due to the trading of energy futures contracts on various commodities exchanges. This increased competition could affect CP&L's load forecasts, plans for power supply and wholesale energy sales and related revenues. The impact could vary depending on the extent to which additional generation is built to compete in the wholesale market, new opportunities are created for CP&L to expand its wholesale load, or current wholesale customers elect to purchase from other suppliers after existing contracts expire.
To assist in the development of wholesale competition, FERC, in 1996, issued standards for wholesale wheeling of electric power through its rules on open access transmission and stranded costs and on information systems and standards of conduct (Orders 888 and 889). The rules require all transmitting utilities to have on file an open access transmission tariff, which contains provisions for the recovery of stranded costs and numerous other provisions that could affect the sale of electric energy at the wholesale level. CP&L filed its open access transmission tariff with FERC in mid-1996. Several wholesale and retail customers filed protests challenging numerous aspects of CP&L's tariff and requesting that an evidentiary proceeding be held. In July 1997, CP&L filed an offer of settlement in this case which was certified by an administrative law judge in September 1997. In February 2000, FERC issued a basket order for several utilities including CP&L to file a compliance filing stating whether there were any remaining undisputed issues surrounding CP&L's open access transmission tariff. On May 1, 2000, CP&L made the compliance filing setting forth the remaining undisputed issues and a plan for settling those issues. On August 25, 2000, CP&L filed modifications to its open access transmission tariff as a result of settlement negotiations with the remaining intervenors. In November 2000 FERC approved the open access transmission tariff of CP&L with the settlement modifications.
In February 2000 CP&L filed a joint open access tariff to reflect the merger with FPC. FERC approved the joint tariff in July 2000 effective with completion of the merger, which occurred on November 30, 2000. In April 2001, CP&L and FPC each filed separate transmission tariffs as a result of FERC Order 614. FERC approved the CP&L transmission tariff in June 2001. In April 2001, CP&L filed changes to the Energy Imbalance provision of the transmission tariff. FERC has yet to issue a final order on this filing. CP&L cannot predict the outcome of this matter.
During 2001, legislation was introduced in South Carolina that would impose a moratorium on the certification and construction of merchant plants until 2003 and prohibit the transfer or sale of a merchant plant certificate. Hearings
have been held on these bills but no action has been taken. In addition, the Department of Health and Environmental Control of South Carolina has halted the issuance of any air permits for merchant plants applying for such permits. The SCPSC has contracted with a consulting firm to conduct a study on the impact of merchant plants in South Carolina which is scheduled to be completed in June of 2002. No new construction of merchant plants has begun. CP&L cannot predict the outcome of this matter.
REGULATORY MATTERS - ------------------
General
CP&L 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. In addition, CP&L is subject to regulation by FERC with respect to transmission and sales of wholesale power, accounting and certain other matters. The underlying concept of utility ratemaking is to set rates at a level that allows the utility to collect revenues equal to its cost of providing service including a reasonable rate of return on its equity. Increased competition, as a result of industry restructuring, may affect the ratemaking process.
Electric Retail Rates
The NCUC and the SCPSC authorize retail "base rates" that are designed to provide a utility with the opportunity to earn a specific rate of return on its "rate base", or investment in utility plant. These rates are intended to cover all reasonable and prudent expenses of utility operations and to provide investors with a fair rate of return. In its most recent rate cases in 1988, the NCUC and the SCPSC each authorized a return on equity of 12.75% for CP&L.
See Note 13B and Note 8B to the Progress Energy and CP&L consolidated financial statements, respectively, for additional discussion of CP&L's retail rate developments during 2001.
Wholesale Rate Matters
CP&L is subject to regulation by 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 FERC determines, accounting policies and practices. CP&L 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.
Other Rate Matters
With approval from the NCUC and the SCPSC, CP&L accelerated the cost recovery of its nuclear generating assets beginning January 1, 2000 and continuing through 2004. Also in 2000, CP&L received approval from the commissions to further accelerate the cost recovery of its nuclear generation facilities in 2000. The accelerated cost recovery of these assets resulted in additional depreciation expense of approximately $75 million and $275 million in 2001 and 2000, respectively. Recovering the costs of its nuclear generating assets on an accelerated basis will better position CP&L for the uncertainties associated with potential restructuring of the electric utility industry.
Fuel Cost Recovery
CP&L's operating costs not covered by the utility's base rates include fuel and purchased power. Each state commission allows electric utilities to recover certain of these costs through various cost recovery clauses, to the extent the respective commission determines in an annual hearing that such costs are prudent. Costs recovered by CP&L, by state, are as follows:
. North Carolina - fuel costs and the fuel portion of purchased power;
. South Carolina - fuel costs, purchased power costs, and emission allowance expense
Each state commission's determination results in the addition of a rider to a utility's base rates to reflect the approval of these costs and to reflect any past over- or under-recovery. Due to the regulatory treatment of these costs and the method allowed for recovery, changes from year to year have no material impact on operating results.
NUCLEAR MATTERS - ---------------
General
CP&L owns and operates four nuclear units, which are regulated by the U.S. Nuclear Regulatory Commission (NRC) under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974. 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. NRC operating licenses currently expire in December 2014 and September 2016 for Brunswick Units 2 and 1, respectively, in July 2010 for Robinson Unit No. 2 and in October 2026 for the Harris Plant. Plans are in place to request the extension of the Robinson and Brunswick operating licenses in 2002 and 2004, respectively. An extension will also be sought for the Harris Plant, but the submittal date has not been determined. A condition of the operating license for each unit requires an approved plan for decontamination and decommissioning. The nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, repairs and certain other modifications.
CP&L is currently evaluating and implementing power uprate projects at its nuclear facilities to increase electrical generation output. A power uprate was completed at the Harris Plant during 2001 and power uprates are in progress at the Brunswick and Robinson Nuclear Plants, which will be implemented in phases over the next several years following regulatory approval. The total increased generation from these projects is estimated to be approximately 250 megawatts.
The nuclear power industry faces uncertainties with respect to the cost and long-term availability of sites for disposal of spent nuclear fuel and other radioactive waste, compliance with changing regulatory requirements, nuclear plant operations, increased capital outlays for modifications, the technological and financial aspects of decommissioning plants at the end of their licensed lives and requirements relating to nuclear insurance.
In August 2001, the NRC issued Bulletin 2001-01, "Circumferential Cracking of Reactor Vessel Head Penetration Nozzles," requesting that all pressurized water reactors (PWR) provide their plans for inspecting the reactor vessel head for the conditions described in the bulletin. While performing this inspection, FirstEnergy Corp.'s Davis Besse plant in Ohio found three penetrations with evidence of leakage and further evidence of some wastage of the reactor vessel head around two of these penetrations. As a result of finding the wastage of the vessel head, the NRC issued Bulletin 2002-01, requesting licensees to assess previous inspections of the reactor head and determine the potential for the existence of conditions similar to that found at the Davis Besse plant.
The CP&L PWRs have completed the inspections requested by Bulletin 2001-01. Any indications of leakage have been inspected and repaired, and no wastage of the reactor vessel head has been observed at any of the plants. Based on these inspections, responses to Bulletin 2002-01 are being prepared. CP&L does not anticipate any adverse impact from this regulatory action.
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. CP&L will continue to maximize the use of spent fuel storage capability within its own facilities for as long as feasible. With certain modifications and additional approval by the NRC, CP&L's spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on CP&L's system through the expiration of the current operating licenses for all of CP&L's nuclear generating units. Subsequent to the expiration of these licenses, dry storage may be necessary.
On December 21, 2000, CP&L received permission from the NRC to increase its storage capacity for spent fuel rods in Wake County, North Carolina. The NRC's decision came two years after CP&L asked for permission to open two unused storage pools at the Harris Plant. The approval means CP&L can complete cooling systems and install
storage racks in its third and fourth storage pools at the Harris Plant. Counsel for the Board of Commissioners of Orange County, North Carolina, filed a petition for review of the staff's decision by the NRC, which was rejected, and then filed an appeal of the decision with the District of Columbia Circuit Court of Appeals. On March 1, 2001, the Atomic Safety and Licensing Board (ASLB) issued its order dismissing Orange County's contention that an environmental impact statement was required for the additional storage plan at the Harris plant, and ruling in CP&L's favor to permit CP&L to proceed with the pool storage plan. On March 16, 2001, the Orange County Commissioners petitioned the NRC for review of the ASLB order and filed a request for a stay of that order. CP&L and the NRC staff responded to the petition and the request for stay. CP&L cannot predict the outcome of this matter.
See PART II, ITEM 8, footnote 15 to the CP&L consolidated financial statements for a discussion of CP&L's contract with the U.S. Department of Energy (DOE) for spent nuclear waste.
Low-Level Radioactive Waste
Disposal costs for low-level radioactive waste that result from normal operation of nuclear units have increased significantly in recent years and are expected to continue to rise. Pursuant to the Low-Level Radioactive Waste Policy Act of 1980, as amended in 1985, each state is responsible for disposal of low-level waste generated in that state. States that do not have existing sites may join in regional compacts. The States of North 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. Effective July 1, 2000, South Carolina joined with the states of Connecticut and New Jersey to form the Atlantic Compact. With this action the South Carolina law prohibiting North Carolina's access to Barnwell was repealed. The new compact allows importation of out of region waste on a limited basis until 2008. This includes access for the Company's North Carolina nuclear plants, which had not had access to Barnwell since June 1995. CP&L's nuclear plant in South Carolina has access to the existing disposal site in South Carolina. In addition, the Envirocare disposal facility in Utah continues to accept lower activity low-level waste.
Although CP&L does not control the future availability of low-level waste disposal facilities, the cost of waste disposal or the development process, it supports the development of new facilities and is committed to a timely and cost-effective solution to low-level waste disposal. Although CP&L 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 its consolidated financial position or results of operations.
Decommissioning
In CP&L's retail jurisdictions, provisions for nuclear decommissioning costs are approved by the NCUC and the SCPSC and are based on site-specific estimates that include the costs for removal of all radioactive and other structures at the site. In the wholesale jurisdiction, the provisions for nuclear decommissioning costs are approved by FERC. See PART II, ITEM 8, footnote 1G to the CP&L consolidated financial statements for a discussion of CP&L's nuclear decommissioning costs.
Enrichment Facilities Decontamination
CP&L and a number of other utilities are involved in litigation against the United States challenging certain retroactive assessments imposed by the federal government on domestic nuclear power companies to fund the decommissioning and decontamination of the government's uranium enrichment facilities.
On March 21, 1997, CP&L filed suit against the U.S. Government in the U.S. Court of Claims alleging breach of contract and illegal taking of property without just compensation. In the alternative, CP&L alleges that the assessments are illegally exacted in violation of the Due Process Clause of the U.S. Constitution. CP&L also alleges that the assessments result in an unconstitutional taking of its contractual benefits.
The suit arises out of several contracts under which the government provided uranium enrichment services at fixed prices. After CP&L paid for enrichment services provided under the contracts, the government, through federal legislation enacted in 1992, imposed a retroactive price increase in order to fund the decontamination and
decommissioning of the government's gaseous diffusion uranium enrichment facilities. The government is collecting this increase through an annual "special assessment" levied upon all domestic utilities that had enrichment services contracts with the government. Collection of the special assessments began in 1992 and is scheduled to continue for a fifteen-year period.
To date, CP&L has paid over $57.6 million in special assessments, including Power Agency's share of $6.7 million, and if continued throughout the anticipated fifteen-year life, the special assessments would increase the cost of CP&L's contracts by more than $97 million. CP&L seeks an order declaring that all such special assessments are unlawful, an injunction prohibiting the government from collecting future special assessments, and a refund of the special assessments.
On February 9, 1999, the government moved to dismiss CP&L's complaint. Subsequently, CP&L requested an order to stay the Claims Court action, pending resolution of another case being heard in the Southern District of New York. Following oral argument, and without benefit of any discovery, the Claims Court denied CP&L's motion to stay, converted the government's motion to a motion for summary judgment, and ordered the parties to submit additional briefing regarding the motion for summary judgment. Following oral argument, on October 17, 2000, the Claims Court issued a decision granting the government's motion for summary judgment on all counts. The Claims Court decision was appealed to the Court of Appeals for the Federal Circuit on December 26, 2000. The Federal Circuit has stayed the consideration of the case pending a decision by the Supreme Court on a petition for writ of certiorari that was filed by Commonwealth Edison in their case against the government. CP&L cannot predict the outcome of this matter.
ELECTRIC - FLORIDA POWER - ------------------------
GENERAL - -------
Florida Power was incorporated in Florida in 1899, and is an operating public utility engaged in the generation, purchase, transmission, distribution and sale of electricity. At December 31, 2001, Florida Power had a total summer generating capacity (including jointly-owned capacity) of approximately 8,012 MW.
Florida Power provided electric service during 2001 to an average of 1.4 million customers in west central Florida. Its service area covers approximately 20,000 square miles and includes the densely populated areas around Orlando, as well as the cities of St. Petersburg and Clearwater. Florida Power is interconnected with 20 municipal and 9 rural electric cooperative systems. Major wholesale power sales customers include Seminole Electric Cooperative, Inc. (Seminole) and Florida Municipal Power Agency. Florida Power is subject to the rules and regulations of FERC and the Florida Public Service Commission (FPSC).
BILLED ELECTRIC REVENUES - ------------------------
Florida Power's electric revenues billed by customer class, for 2001 and 2000, is shown as a percentage of total Florida Power electric revenues in the table below:
BILLED ELECTRIC REVENUES
Revenue Class 2001 2000(a) - ------------- ---- ------- Residential 54% 53% Commercial 24% 24% Industrial 7% 8% Other retail 6% 5% Wholesale (b) 9% 10%
(a) These figures reflect Florida Power's billed electric for the full year ended December 31, 2000, which is generally representative of the period Progress Energy owned Florida Power. (b) These revenues are managed by Progress Ventures on behalf of Florida Power.
Important industries in Florida Power's territory include phosphate and rock mining and processing, electronics design and manufacturing and citrus and other food processing. Other important commercial activities are tourism, health care, construction and agriculture.
FUEL AND PURCHASED POWER - ------------------------
General
Florida Power's consumption of various types of fuel depends on several factors, the most important of which are the demand for electricity by Florida Power's customers, the availability of various generating units, the availability and cost of fuel and the requirements of federal and state regulatory agencies. Florida Power's energy mix for 2001 and 2000 is presented in the following table:
ENERGY MIX PERCENTAGES
Fuel Type 2001 2000 (a) - --------- ---- -------- Coal (b) 33% 34% Oil 16% 15% Nuclear 15% 15% Gas 14% 14% Purchased Power 22% 22%
(a) These figures reflect Florida Power's energy mix percentages for the full year ended December 31, 2000, which is generally representative of the period Progress Energy owned Florida Power. (b) Includes synthetic fuel from unrelated third parties and petroleum coke.
Florida Power is generally permitted to pass the cost of recoverable fuel and purchased power to its customers through fuel adjustment clauses. The future prices for and availability of various fuels discussed in this report cannot be predicted with complete certainty. However, Florida Power believes that its fuel supply contracts, as described below, will be adequate to meet its fuel supply needs.
Florida Power's average fuel costs per million Btu for 2001 and 2000 were as follows:
AVERAGE FUEL COST (per million Btu)
2001 2000 (a) ----- ------- Coal (b) (c) $2.16 $1.89 Oil (c) 3.81 4.15 Nuclear .47 .47 Gas (c) 4.52 4.32 Weighted Average 2.59 2.46
(a) These figures reflect Florida Power's average fuel cost for the year ended December 31, 2000, which is representative of the period Progress Energy owned Florida Power. (b) Includes synthetic fuel from unrelated third parties and petroleum coke. (c) Changes in the unit price for coal, oil and gas are due to market conditions. Since these costs are primarily recovered through recovery clauses established by regulators, the fluctuation does not materially affect net income.
Coal
Florida Power anticipates a combined requirement of approximately 5.5 million to 6.0 million tons of coal and synthetic fuel in 2002. Most of the coal is expected to be supplied from the Appalachian coal fields of the United States. Approximately two-thirds of the fuel is expected to be delivered by rail and the remainder by barge. The fuel is supplied by Progress Fuels, an affiliate of Progress Energy, pursuant to contracts between Florida Power and Progress Fuels.
For 2002, Progress Fuels has medium and long-term contracts with various sources for approximately 100% of the fuel requirements of Florida Power's coal units. These contracts have price adjustment provisions. All the coal to be purchased for Florida Power is considered to be low sulfur coal by industry standards.
Oil and Gas
Oil is purchased under contracts and in the spot market from several suppliers. The cost of Florida Power's oil and gas is determined by market conditions. Management believes that Florida Power has access to an adequate supply
of oil for the reasonably foreseeable future. Florida Power's natural gas supply is purchased under firm contracts and in the spot market from numerous suppliers and is delivered under firm, released firm and interruptible transportation contracts. Florida Power believes that existing contracts for oil are sufficient to cover its requirements when natural gas transmission purchased on an interruptible basis is not available.
Nuclear
Nuclear fuel is processed through four distinct stages. Stages I and II involve the mining and milling of the natural uranium ore to produce a concentrate and the conversion of this uranium concentrate into uranium hexafluoride. Stages III and IV entail the enrichment of the uranium hexafluoride and the fabrication of the enriched uranium hexafluoride into usable fuel assemblies.
Florida Power expects to meet its future nuclear fuel requirements from inventory on hand and amounts received under contract. Although Florida Power cannot predict the future availability of uranium and nuclear fuel services, Florida Power does not currently expect to have difficulty obtaining uranium oxide concentrate and the services necessary for its conversion, enrichment and fabrication into nuclear fuel.
Purchased Power
Florida Power, along with other Florida utilities, buys and sells economy power through the Florida energy brokering system. Florida Power also purchases 1,304 MW of firm power under a variety of purchase power agreements. As of December 31, 2001, Florida Power had long-term contracts for the purchase of about 460 MW of purchased power with other investor-owned utilities, including a contract with The Southern Company for approximately 400 MW. Florida Power also purchased 831 megawatts of its total capacity from certain qualifying facilities (QFs). The capacity currently available from QFs represents about 10% of Florida Power's total installed system capacity.
COMPETITION - -----------
Electric Industry Restructuring
Florida Power continues to monitor progress toward a more competitive environment and has actively participated in regulatory reform deliberations in Florida. Movement toward deregulation in this state has been affected by recent developments related to deregulation of the electric industry in California.
On January 31, 2001, the Florida 2020 Study Commission voted to forward a "proposed outline for wholesale restructuring" to the Florida legislature for its consideration in the 2001 session. The wholesale restructuring outline is intended to facilitate the evolution of a more robust wholesale marketplace in Florida. On December 11, 2001, the study commission issued its final report. The report covered a number of issues with recommendations in the areas of wholesale competition and reliability, efficiency, transmission infrastructure, environmental issues and new technologies. One key recommendation related to wholesale competition & reliability is to permit the transfer or sale of existing generation assets as follows:
. Sales and transfers of generation assets and the related timing are discretionary on the part of the investor-owned utility on a plant-by-plant basis.
. Transfers of generation assets are recorded at book value.
. Load-serving entities (LSE's) have the right to a 6-year cost based transition contract on all transferred capacity with unilateral cancellation rights and a share of the profits from off-system sales.
. Gains on sales of existing plants or those transferred and still under transition contracts must be shared 50/50 with customers.
. Losses on sales must be absorbed fully by shareholder.
. New units under construction and included in the company's 10-Year Site Plan are subject to 6-year transition contract requirement but not the gain/loss sharing.
. The FPSC has the authority to review LSE's decision to terminate transition contracts, including prior to actual termination.
Although the Company believes that the current system of regulation in Florida is working well, Florida Power has supported the study commission's efforts. While the Company does not see any compelling reason to change, the study commission's proposal is generally consistent with principles the Company believes any sound restructuring plan should adhere to if the state does decide to restructure.
The Florida legislature did not take any action on the proposed outline or final report during the 2001 session. There is no way for the Company to know what restructuring legislation will be enacted or if the Company would be able to support it in its final form.
Regional Transmission Organizations
In October 2000, Florida Power, along with Florida Power & Light Company and Tampa Electric Company filed with FERC an application for approval of a regional transmission organization, or RTO, for peninsular Florida, currently named GridFlorida. On March 28, 2001, FERC issued an order provisionally granting GridFlorida RTO status and directing the GridFlorida applicants to make certain changes in the RTO documents and to file such changes within 60 days. On May 29, 2001, the GridFlorida applicants made the compliance filing as directed by FERC, but FERC has not yet issued an order on that compliance filing.
See PART II, Item 7, "Other Matters," for a discussion of current developments of GridFlorida RTO.
Merchant Plants
In August 1998, Duke Energy filed a petition to build Florida's first merchant power plant, a 514-megawatt facility to be located in Volusia County, Florida. The plant would provide 30 megawatts of energy to the Utilities Commission of the City of New Smyrna Beach and the remaining capacity would be available for wholesale sales.
In a move Florida Power believes is contrary to existing state law, the Florida Public Service Commission (FPSC) granted Duke Energy's petition. Florida Power and other Florida utilities filed an appeal of the FPSC's decision with the Florida Supreme Court. In April 2000, the Florida Supreme Court ruled in favor of Florida Power and other utilities and reversed the FPSC's order. In December 2000, Duke Energy filed a petition for certiorari with the U.S. Supreme Court. On March 5, 2001, the U.S. Supreme Court denied Duke Energy's petition for certiorari.
Franchise Agreements
By virtue of municipal legislation, Florida Power holds franchises with varying expiration dates in most of the municipalities in which it distributes electric energy. However, Florida Power does serve within a number of municipalities and in all its unincorporated areas without existing franchise ordinances. The general effect of franchises is to provide for the manner in which Florida Power occupies rights-of-way in incorporated areas of municipalities for the purpose of constructing, operating and maintaining an energy transmission and distribution system.
Approximately 39% of Florida Power's total utility revenues for 2001 were from the incorporated areas of the 109 municipalities that had franchise ordinances during the year. Of the 18 franchises that expired during 2001, four municipalities have not yet renewed.
A new franchise ordinance was enacted during January 2002 with a municipality that did not previously have a franchise with Florida Power bringing the current number of existing franchises to 106. All but 17 of the existing franchises cover a 30-year period from the date enacted. The exceptions are 15 franchises each with a term of 10 years and expiring between 2011 and 2012; one 30-year franchise that was extended in 1999 for five years expiring in 2005; and one franchise with a term of 20 years expiring in 2020. Of the 106 franchises, 11 expire during 2002, 34 expire between January 1, 2003 and December 31, 2012 and 61 expire between January 1, 2013 and December 31, 2031.
Ongoing negotiations are taking place with the municipalities to reach agreement on franchise terms and to enact new franchise ordinances.
Stranded Costs
An important issue encompassed by industry restructuring is the recovery of "stranded costs." Stranded costs primarily include the generation assets of utilities whose value in a competitive marketplace would be less than their current book value, as well as above-market purchased power commitments to QFs. Thus far, all states that have passed restructuring legislation have provided for the opportunity to recover a substantial portion of stranded costs.
Assessing the amount of stranded costs for a utility requires various assumptions about future market conditions including the future price of electricity. For Florida Power, the single largest stranded cost exposure is its commitment to QFs. Since 1996, Florida Power has been seeking ways to address the impact of escalating payments from contracts it was obligated to sign under provisions of PURPA. These efforts have resulted in Florida Power successfully mitigating, through buy-outs and buy-downs of these contracts, more than 25 percent of its purchased power commitments to QFs.
REGULATORY MATTERS - ------------------
General
Florida Power is subject to the jurisdiction of the FPSC with respect to, among other things, retail rates and issuance of securities. In addition, Florida Power is subject to regulation by FERC with respect to transmission and sales of wholesale power, accounting and certain other matters. The underlying concept of utility ratemaking is to set rates at a level that allows the utility to collect revenues equal to its cost of providing service plus a reasonable rate of return on its equity. Increased competition, as a result of industry restructuring, may affect the ratemaking process.
Electric Retail Rates
The FPSC authorizes retail "base rates" that are designed to provide a utility with the opportunity to earn a specific rate of return on its "rate base", or average investment in utility plant. These rates are intended to cover all reasonable and prudent expenses of utility operations and to provide investors with a fair rate of return. The FPSC has authorized a return on equity range for Florida Power of 11-13% and its retail base rates are based on the mid-point of that range - 12%.
Florida Power previously operated under an agreement committing several parties not to seek any reduction in its base rates or authorized return on equity. That agreement expired on June 30, 2001. During 2001, the FPSC required Florida Power to submit minimum filing requirements, based on a 2002 projected test year, to initiate a rate proceeding regarding its future base rates.
On September 14, 2001, Florida Power submitted its required rate filing, including its revenue requirements and supporting testimony. Florida Power filed supplemental minimum filing requirements and testimony on November 15, 2001. Hearings were scheduled to begin on March 20, 2002, but were postponed to accommodate pending settlement negotiations between the parties.
On March 27, 2002, the parties entered into a Stipulation and Settlement Agreement (the Agreement) related to retail rate matters. The Agreement is to be effective from May 1, 2002 through 2005; provided, however, that if Florida Power's base rate earnings fall below a 10% return on equity, Florida Power may petition the FPSC to amend its base rates.
The Agreement provides that Florida Power will reduce its retail revenues from the sale of electricity by $125 million annually through 2005. The Agreement also provides that Florida Power will operate under a Revenue Sharing Incentive Plan (the Plan) that establishes revenue caps and sharing thresholds for the years 2002 through 2005. The Plan provides that retail base rate revenues between the sharing thresholds and the retail base rate revenue caps will be divided into two shares - a 1/3 share to be received by Florida Power's shareholders, and a 2/3 share to be refunded to Florida Power's retail customers; provided, however, that for the year 2002 only, the refund to customers will be limited to 67.1% of the 2/3 customer share. The retail base rate revenue sharing threshold amounts for 2002, 2003, 2004 and 2005 will be $1,296 million, $1,333 million, $1,370 million and $1,407 million, respectively. The Plan also provides that all retail base rate revenues above the retail base rate revenue caps established for the years 2003, 2004 and 2005 will be refunded to retail customers on an annual basis. For 2002, the refund to customers will be limited to 67.1% of the retail base rate revenues that exceed the 2002 cap. The retail base revenue caps for 2002, 2003, 2004 and 2005 will be $1,356 million, $1,393 million, $1,430 million and $1,467 million, respectively.
The Agreement also provides that beginning with the in-service date of Florida Power's Hines Unit 2 and continuing through December 31, 2005, Florida Power will be allowed to recover through the fuel cost recovery clause a return on average investment and depreciation expense for Hines Unit 2, to the extent such costs do not exceed the Unit's cumulative fuel savings over the recovery period.
Additionally, the Agreement provides that Florida Power will effect a mid-course correction of its fuel cost recovery clause to reduce the fuel factor by $50 million for the remainder of 2002. The fuel cost recovery clause will operate as it normally does, including, but not limited to any additional mid-course adjustments that may become necessary, and the calculation of true-ups to actual fuel clause expenses.
During the term of the Agreement, Florida Power will suspend accruals on its reserves for nuclear decommissioning and fossil dismantlement. Additionally, for each calendar year during the term of the Agreement, Florida Power
will record a $62.5 million depreciation expense reduction, and may, at its option, record up to an equal annual amount as an offsetting accelerated depreciation expense. In addition, Florida Power is authorized, at its discretion, to accelerate the amortization of certain regulatory assets over the term of the Agreement.
Under the terms of the Agreement, Florida Power agreed to continue the implementation of its four-year Commitment to Excellence Reliability Plan and expects to achieve a 20% improvement in its annual System Average Interruption Duration Index by no later than 2004. If this improvement level is not achieved for calendar years 2004 or 2005, Florida Power will provide a refund of $3 million for each year the level is not achieved to 10% of its total retail customers served by its worst performing distribution feeder lines.
The Agreement also provides that Florida Power will refund to customers $35 million of the $98 million in interim revenues Florida Power has collected subject to refund since March 13, 2001. No other interim revenues that were collected during that period will continue to be held subject to refund.
The Agreement was filed with the FPSC for approval on March 27, 2002. If the FPSC approves the Agreement, the new rates will take effect May 1, 2002. Progress Energy cannot predict the outcome of this matter.
Fuel Cost Recovery
Florida Power's operating costs not covered by the utility's base rates include increases in fuel, purchased power and energy conservation expenses. The state commission allows electric utilities to recover certain of these costs through various cost recovery clauses, to the extent the respective commission determines in an annual hearing that such costs are prudent. Costs recovered by Florida Power include fuel costs, purchased power costs and energy conservation expenses.
The state commission's determination results in the addition of a rider to a utility's base rates to reflect the approval of these costs and to reflect any past over- or under-recovery. Due to the regulatory treatment of these costs and the method allowed for recovery, changes from year to year have no material impact on operating results.
NUCLEAR MATTERS - ---------------
Florida Power has one nuclear generating plant, Crystal River Unit No. 3 (CR3), which is subject to regulation by the NRC. The NRC's jurisdiction encompasses broad supervisory and regulatory powers over the construction and operation of nuclear reactors, including matters of health and safety, antitrust considerations and environmental impact. Florida Power has a license to operate the nuclear plant through December 3, 2016. Florida Power currently has a 91.8% ownership interest in CR3.
Spent nuclear fuel is stored at CR3 pending disposal under a contract with the DOE. At the present time, Florida Power has facilities on site for the temporary storage of spent nuclear fuel generated through the year 2011. Florida Power expanded the capacity of its facilities on site in 2001, after obtaining regulatory approval, to allow for the temporary storage of spent nuclear fuel generated through the end of the license in 2016.
In August 2001, the NRC issued Bulletin 2001-01, "Circumferential Cracking of Reactor Vessel Head Penetration Nozzles," requesting that all pressurized water reactors (PWR) provide their plans for inspecting the reactor vessel head for the conditions described in the bulletin. While performing this inspection, FirstEnergy Corp.'s Davis Besse plant in Ohio found three penetrations with evidence of leakage and further evidence of some wastage of the reactor vessel head around two of these penetrations. As a result of finding the wastage of the vessel head, the NRC issued Bulletin 2002-01, requesting licensees to assess previous inspections of the reactor head and determine the potential for the existence of conditions similar to that found at the Davis Besse plant.
Florida Power's CR3 has completed the inspections requested by Bulletin 2001-01. Any indications of leakage have been inspected and repaired, and no wastage of the reactor vessel head has been observed. Based on these inspections, responses to Bulletin 2002-01 are being prepared. Florida Power does not anticipate any adverse impact from this regulatory action.
Enrichment Facilities Decontamination
Florida Power and a number of other utilities are involved in litigation against the United States challenging certain retroactive assessments imposed by the federal government on domestic nuclear power companies to fund the decommissioning and decontamination of the government's uranium enrichment facilities.
On November 1, 1996, Florida Power filed suit against the U.S. Government in the U.S. Court of Claims alleging breach of contract and illegal taking of property without just compensation. The suit arises out of several contracts under which the government provided uranium enrichment services at fixed prices. After Florida Power paid for all services provided under the contracts, the government, through federal legislation enacted in 1992, imposed a retroactive price increase in order to fund the decontamination and decommissioning of the government's gaseous diffusion uranium enrichment facilities. The government is collecting this increase through an annual "special assessment" levied upon all utilities that had enrichment services contracts with the government. Collection of the special assessments began in 1992 and is scheduled to continue for a fifteen-year period.
To date, Florida Power has paid more than $18 million in special assessments, including its co-owner's share of approximately $1.5 million, and if continued throughout the anticipated fifteen-year life, the special assessments would increase the cost of Florida Power's contracts by more than $23 million. Florida Power seeks an order declaring that all such special assessments are unlawful, and an injunction prohibiting the government from collecting future special assessments and damages.
In June 1998, Florida Power, Consolidated Edison Co. and 15 other utilities filed an action for declaratory judgement against the United States in the Southern District Court of New York, challenging the constitutionality of the $2.25 billion retroactive assessment imposed by the federal government on domestic nuclear power companies to fund the decommissioning and decontamination of the government's uranium enrichment facilities. In August 1998, the utilities filed an amended complaint adding several additional utilities as plaintiffs.
In February 1999, the court granted Florida Power's motion to stay the Claims Court action, pending resolution of the District Court case. In April 1999, the District Court ruled that it had subject matter jurisdiction, and denied the government's motion to transfer the action to the Claims Court. The government appealed the decision to the U.S. Court of Appeals for the Federal Circuit, which ultimately reversed the District Court's denial of the motion to transfer. The matter was stayed pending the utilities' petition for a writ of certiorari to the Supreme Court. The Supreme Court denied the utilities' petition for certiorari on December 3, 2001. Consequently, on December 22, 2001, the Federal Circuit issued a mandate remanding the case to the District Court with instructions to transfer the case to the Court of Federal Claims. The Company cannot predict the outcome of this matter.
PROGRESS VENTURES - -----------------
GENERAL - -------
The Progress Ventures business unit was created in 2000 to manage Progress Energy's wholesale energy marketing and trading, merchant generation and fuel properties, as well as an ocean barge partnership. The operations of the Progress Ventures business unit can be broken down into three key areas: 1) fuel extraction, manufacturing and delivery; 2) merchant generation ownership; and 3) energy marketing and trading.
FUEL EXTRACTION, MANUFACTURING AND DELIVERY - -------------------------------------------
The Progress Ventures business unit owns an array of assets that produce, transport and deliver fuel for the open market. The Progress Ventures business unit has subsidiaries that mine coal and others that produce synthetic coal-based fuel, a chemically changed product made from waste coal and coal byproducts. Because this process is accomplished through a significant chemical reaction, the resulting product has been classified as a synthetic fuel within the meaning of Section 29 of the Internal Revenue Code. Sales of synthetic fuel therefore qualify for tax credits. See Progress Energy's PART II, ITEM 7, "Other Matters" for a discussion of the synthetic fuel tax credits.
The combined assets of Progress Ventures which are involved in fuel extraction, manufacturing and delivery include:
. Three coal-mining complexes, producing about 3 million tons per year; . Seven synthetic fuel plants capable of producing 10 to 15 million tons per year; . Natural gas properties in Colorado producing about 5 billion cubic feet per year; . Six terminals on the Ohio River and its tributaries, part of the trucking, rail and barge network for coal delivery; . Part-ownership in a barge operation that moves coal from the mouth of the Mississippi River to the Crystal River facility in Florida.
MERCHANT GENERATION OWNERSHIP - -----------------------------
Merchant generation represents power plants whose capacity and energy are sold on the wholesale market outside the realm of retail regulation. A cornerstone of Progress Ventures' business plan is to own a portfolio of approximately 3,100 MW of merchant generation capacity by 2003. Much of this portfolio will be built by Progress Ventures. In addition, Progress Ventures is pursuing acquisitions and non-traditional ownership opportunities.
Progress Ventures had approximately 315 MW of merchant generation in commercial operation as of December 31, 2001. Construction, acquisition and transfers of generating assets from CP&L will increase this to approximately 3,100 MW over the next two years. See Progress Energy's PART I, ITEM 2, "Properties" for additional information on these planned additions. Progress Ventures has flexible plans around an additional 2,800 MW's subsequent to 2003. A newly established Progress Ventures function carefully examines competitive market data to determine the best locations for future merchant plants, including those planned subsequent to 2003.
ENERGY MARKETING AND TRADING - ----------------------------
Within this business function, the energy produced by the merchant plants as well as some capacity produced by the utility is sold under term contracts and in the spot market. This area is divided into two departments: Energy Trading and Term Marketing. Energy Trading markets and sells short-term contracts for power while Term Marketing markets and sells long-term contracts. Currently, Progress Ventures manages 5,300 MW of wholesale power contracts that primarily include those for CP&L and Florida Power.
In addition to power contracts, this business area also purchases fuel for both utility and merchant generation, and trades other sources of energy, such as natural gas, oil and, in the future, coal. Progress Ventures also uses financial instruments to manage the risks associated with fluctuating commodity prices and increase the value of the Company's power generation assets.
COMPETITION - -----------
Progress Ventures does not operate in the same environment as regulated utilities. It operates specifically on the wholesale market, which means competition is its primary driver. Progress Venture's synthetic fuel operations, coal operations and merchant generation plants compete in the eastern United States utility and industrial coal markets. Factors contributing to the success in these markets include a competitive cost structure and strategic locations. See PART II, ITEM 7, "Other Matters" for a discussion of risks associated with synthetic fuel tax credits. There are, however, numerous competitors in each of these markets, although no one competitor is dominant in any industry. The business of Progress Ventures, taken as a whole, is not subject to significant seasonal fluctuation.
RAIL SERVICES - -------------
The largest component of Rail Services is led by Progress Rail Services Corporation (Progress Rail). Progress Rail is one of the largest integrated and diversified suppliers of railroad and transit system products and services in North America and is headquartered in Albertville, Alabama. Rail Services' principal business functions include the Mechanical Group, Rail and Trackwork Group, and Recycling Group.
The Mechanical Group is primarily focused on railroad rolling stock that includes freight cars, transit cars and locomotives, the repair and maintenance of these units, and the manufacturing or reconditioning of major components for these units. The Rail and Trackwork Group focuses on rail and other track components, the infrastructure which supports the operation of rolling stock, as well as the equipment used in maintaining the railroad infrastructure and right-of-way. The Recycling Group supports the Mechanical and Rail and Trackwork Groups through its reclamation of reconditionable material. In addition, the Recycling Group is a major supplier of recyclable scrap metal to North American steel mills and foundries through its processing locations as well as its scrap brokerage operations.
Rail Services' key railroad industry customers are Class 1 railroads, regional and shortline railroads, major North American transit systems, major railcar and locomotive builders, and major railcar lessors. The U.S. operations are located in 26 states and include further geographic coverage through mobile crews on a selected basis. This coverage allows for Rail Services' customer base to be dispersed throughout the U.S., Canada and Mexico.
OTHER - -----
GENERAL - -------
The Other segment primarily includes the business of NCNG, SRS, Progress Telecom and Caronet.
NCNG - ----
General
NCNG transports, distributes and sells natural gas to over 107,400 residential customers, over 14,300 commercial and agricultural customers and 477 industrial and electric utility customers located in 110 towns and cities, primarily in eastern and south central North Carolina. NCNG also sells and transports natural gas to four municipal gas distribution systems that serve over 53,900 end users. Natural Gas operations are subject to the rules and regulations of the NCUC.
Natural Gas Supply
NCNG has long-term firm gas supply contracts with major producers and national natural gas marketers. During 2001, NCNG purchased 5,517,725 dekatherms (dt) of natural gas under its firm sales contracts with Transcontinental Gas Pipeline Corporation (Transco). NCNG also purchased 17,052,446 dt in the spot market or under long-term contracts with producers or natural gas marketers. Additionally, NCNG transported 29,872,334 dt of customer-owned gas in 2001. The outlook for natural gas supplies in NCNG's service area remains favorable, and many sources of gas are available on a firm basis.
Competition
The natural gas industry continues to evolve into a more competitive environment. NCNG has competed successfully with other forms of energy such as electricity, residual fuel, distillate fuel oil, propane and, to a lesser extent, coal. The principal competitive considerations have been price and accessibility. With the exception of four municipalities that operate municipal gas distribution systems within its service territory, NCNG is the sole distributor of natural gas in our franchised service territory.
Currently, NCNG's residential and commercial customers receive services under a bundled rate, which includes charges for both the cost of gas and its delivery to the customer. Unbundling of the services to commercial and residential customers could increase competition for commodity sales services, but not for the distribution of natural gas. Since NCNG does not earn any margin or income from the commodity sale of natural gas, separating the cost of gas from the cost of its delivery will not impact the operations. NCNG does not expect the NCUC to require further unbundling in the near future. NCNG has adopted a policy that requires that it have a balanced gas supply portfolio that provides security of supply at the lowest reasonable cost, as determined by the NCUC in all of the prior annual prudency reviews.
During 2001, approximately 55% of total throughput on NCNG's system was sold to customers having alternative fuel usage capabilities under interruptible rates, which allows NCNG to request that these customers discontinue gas service during periods of heavy demand so that NCNG is able to maintain its obligation to serve its firm market demand (residential and commercial). However, the purchased gas adjustment rider, which was part of NCNG's tariffs approved by the NCUC, allows NCNG to negotiate rates lower than the filed tariff rates and to recover the lost margin from the other core market customers to encourage industrial customers to remain on the system when the price of their alternative fuel is lower than the gas tariff rate. The purchased gas adjustment rider also sets forth NCNG's filing requirements with the NCUC, enables it to negotiate rates with customers and establishes the procedures governing the monthly and annual review of gas costs and corresponding rate changes.
Franchises
NCNG holds a certificate of public convenience and necessity granted by the NCUC to provide service to NCNG's current service area. Under North Carolina law, no company may construct or operate properties for the sale or distribution of natural gas without such a certificate, except that no certificate is required for construction in the ordinary course of business or for construction into territory contiguous to that already occupied by a company and not receiving similar service from another utility.
NCNG has nonexclusive franchises from 70 municipalities in which NCNG distributes natural gas. The expiration dates of those franchises that have specific expiration provisions range from 2004 to 2020. As of February 28, 2002,
NCNG is negotiating franchise agreements with two new towns, City of Whiteville and Village of Pinehurst. NCNG expects all negotiations to result in 10 or 20-year agreements. In the event that these franchise agreements cannot be negotiated, NCNG does not believe that it will experience any material adverse effect. None of the remaining franchise agreements are scheduled to expire within the next two years. The franchises are substantially uniform in nature. They contain no restrictions of a materially burdensome nature and are adequate for NCNG's business. In addition, NCNG serves 36 communities from which no franchises are required.
Regulatory Matters
The NCUC regulates NCNG's rates, service area, adequacy of service, safety standards, acquisition, extension and abandonment of facilities, accounting and sales of securities. NCNG operates only in North Carolina and is not subject to federal regulation as a "natural gas company" under the Natural Gas Act.
Retail Rates
On October 27, 1995, the NCUC issued an order that provides for a rate of return of 10.09%, but did not state separately the rate of return on common equity or the capital structure used to calculate revenue requirements. The order established several new rate schedules, including an economic development rate to assist in attracting new industry to NCNG's service area and a rate to provide standby, on-peak gas supply service to industrial and other customers whose gas service would otherwise be interrupted.
In conjunction with CP&L's acquisition of NCNG on July 15, 1999, NCNG signed a joint stipulation agreement with the NCUC in which NCNG agreed to cap margin rates for gas sales and transportation services, with limited exceptions, through November 1, 2003. The Company believes that this agreement will not have a material adverse effect on the results of operations, financial condition, or cash flows. In February 2002, NCNG filed a general rate case with the NCUC requesting an annual rate increase of $47.6 million, based upon its completion of major expansion projects. Progress Energy cannot predict the final outcome of this matter.
Expansion Projects
In March 2001, NCNG completed an 84-mile, 30-inch natural gas pipeline, named the Sandhills Pipeline, which extends from Iredell County to Richmond County in North Carolina. This pipeline cost approximately $100 million and will primarily be used to transport natural gas to an electric generating plant currently under construction in Richmond County by CP&L, an affiliate of NCNG.
In October 1999, CP&L and the Albemarle Pamlico Economic Development Corporation (APEC) announced their intention to build an 850-mile, $197.5 million, natural gas transmission and distribution system to the 14 currently unserved counties in eastern North Carolina that were previously franchised to NCNG, as discussed above. In furtherance of this project, Progress Energy and APEC formed Eastern North Carolina Natural Gas Co. (EasternNC, formerly reported as ENCNG). Progress Energy and APEC are joint owners of EasternNC, which is a public utility subject to the rules and regulations of the NCUC. EasternNC contracted with CP&L to construct, operate and maintain both the transmission and distribution systems. EasternNC contracted with APEC to provide various services as well, including but not limited to, managing all municipal and county franchise issues, marketing and economic development and ensuring that the new facilities are built in the most advantageous locations to promote development of the economic base in the region. In conjunction with this project, EasternNC filed a request with the NCUC for $186 million of a $200 million state bond package established for natural gas infrastructure to pay for the portion of the project that likely could not be recovered from future gas customers through rates. On June 15, 2000, the NCUC issued an order awarding EasternNC an exclusive franchise to all 14 counties and, in a further order issued on July 12, 2000, granted $38.7 million in state bond funding for phase one of the project. Phase one, which will cost a total of $50.5 million, will bring gas service to 6 of the 14 counties. By order issued June 7, 2001 the NCUC approved construction of phases 2-7 of the project which addresses the remaining 8 counties and awarded EasternNC an additional $149.6 million to finance the construction of the facilities associated with these phases. EasternNC has begun construction of phase one of the project and expects to complete construction of phase one in the summer of 2002. EasternNC has also begun marketing natural gas service to prospective customers in phase one. The schedule for the remaining phases calls for construction of phase two to begin in the summer of 2002, and for all phases to be completed by the summer of 2004.
Progress Energy has agreed to fund a portion of the project, which is currently estimated to be approximately $22 million.
SRS - ---
SRS offers a comprehensive suite of innovative solutions for energy management and building automation. SRS' portfolio of systems and services provides clients with tools to integrate and centrally manage their energy usage and facility needs. SRS delivers solutions for commercial, industrial, education and government clients. Progress Energy is refocusing the SRS business on energy services in the southeastern states.
PROGRESS TELECOM AND CARONET - ----------------------------
Progress Telecom has data fiber network transport capabilities that stretch from New York to Miami, Florida, with gateways to Latin America and conducts primarily a carrier's carrier business. Progress Telecom markets wholesale fiber-optic-based capacity service in the Eastern United States to long-distance carriers, internet service providers and other telecommunications companies. Progress Telecom also markets wireless structure attachments to wireless communication companies and governmental entities. Caronet, Inc. (Caronet) serves the telecommunications industry by providing fiber-optic telecommunications services. As of December 31, 2001, Progress Telecom owned and managed approximately 7,200 route miles and more than 130,000 fiber miles of fiber optic cable, which includes Caronet. In December 2001, Progress Telecom Corporation (Telecom) was formed. Assets, liabilities, and existing contracts of Progress Telecom and Caronet will be transferred to Telecom upon regulatory approval. Regulatory approval is expected during the first half of 2002.
Progress Telecom and Caronet compete with other providers of fiber-optic telecommunications services, including local exchange carriers and competitive access providers, in the Eastern United States.
OPERATING STATISTICS - PROGRESS ENERGY - --------------------------------------
(a) Represents co-owner's share of the energy supplied from the five generating facilities that are jointly owned. (b) Reflects the acquisition of NCNG on July 15, 1999 (c) For 2001 and 2000, this represents the combined summer non-coincident system net peaks for CP&L and Florida Power. (d) Net of the Company's purchases from jointly-owned plants. (e) Includes information for Florida Power since November 30, 2000, the date of acquisition.
OPERATING STATISTICS - CAROLINA POWER & LIGHT COMPANY - -----------------------------------------------------
(a) Represents Power Agency's share of the energy supplied from the four generating facilities that are jointly owned. (b) Net of CP&L's purchases from Power Agency. (c) Includes Rowan units that were transferred to Progress Ventures in February 2002.
ITEM 2.
ITEM 2. PROPERTIES - ------------------
The Company believes that its physical properties and those of its subsidiaries are adequate to carry on its and their businesses as currently conducted. The Company and its subsidiaries maintain property insurance against loss or damage by fire or other perils to the extent that such property is usually insured.
ELECTRIC - CP&L - ---------------
As of December 31, 2001, CP&L's nineteen generating plants represent a flexible mix of fossil, nuclear and hydroelectric resources in addition to combustion turbines and combined cycle units, with a total generating capacity (including Power Agency's share) of 12,040 megawatts (MW). CP&L's strategic geographic location facilitates purchases and sales of power with many other electric utilities, allowing CP&L to serve its customers more economically and reliably. At December 31, 2001, CP&L had the following generating facilities:
(a) Represents CP&L's net summer peak rating, gross of co-ownership interest in plant capacity (b) Facilities are jointly owned by CP&L and Power Agency, and the capacities shown include Power Agency's share (c) This facility was transferred from CP&L to Progress Ventures in February (d) On January 1, 2002, a successful power uprate increased the summer net capability of this facility to 900 MW
As of December 31, 2001, including both the total generating capacity of 12,040 MW and the total firm contracts for purchased power of approximately 1,586 MW, CP&L had total capacity resources of approximately 13,626 MW.
The 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 the Harris Plant and Mayo Unit No. 1. Otherwise, CP&L has good and marketable title to its principal plants and important units, subject to the lien of its mortgage and deed of trust, with minor exceptions, restrictions, and reservations in conveyances, as well as minor defects of the nature ordinarily found in properties of similar character and magnitude. CP&L also owns certain easements over private property on which transmission and distribution lines are located.
As of December 31, 2001, CP&L had 5,894 pole miles of transmission lines including 295 miles of 500 kilovolt (kV) lines and 3,033 miles of 230 kV lines, and distribution lines of approximately 44,530 pole miles of overhead lines and approximately 15,646 miles of underground lines. Distribution and transmission substations in service had a transformer capacity of approximately 31,104,000 kilovolt-ampere (kVA) in 2,234 transformers. Distribution line transformers numbered 488,064 with an aggregate 19,535,000 kVA capacity.
ELECTRIC - FLORIDA POWER - ------------------------
As of December 31, 2001, the total summer generating capacity (including jointly-owned capacity) of Florida Power's generating facilities was 8,012 MW. Florida Power's generating plants and their summer capacities gross of co-ownership interests at December 31, 2001, are as follows:
(a) Represents Florida Power's net summer peak rating, gross of co-ownership interest in plant capacity (b) Florida Power and Georgia Power Company ("Georgia Power") are co-owners of a 143 MW advanced combustion turbine located at Florida Power's Intercession City site. Georgia Power has the exclusive right to the output of this unit during the months of June through September. Florida Power has that right for the remainder of the year. (c) Represents 100% gross of co-owners total plant capacity. Florida Power's ownership percentage is approximately 91.8%.
As of December 31, 2001, including both the total generating capacity of 8,012 MW and the total firm contracts for purchased power of 1,304 MW, Florida Power had total capacity resources of approximately 9,316 MW.
Substantially all of Florida Power's utility plant is pledged as collateral for Florida Power's First Mortgage Bonds.
As of December 31, 2001, Florida Power distributed electricity through 358 substations with an installed transformer capacity of 50,800,000 kVA. Of this capacity, 37,243,000 kVA is located in transmission substations and 13,557,000 kVA in distribution substations. Florida Power has the second largest transmission network in Florida. Florida Power has 4,696 circuit miles of transmission lines, of which 2,577 circuit miles are operated at 500, 230, or 115 kV and the balance at 69 kV. Florida Power has 26,806 circuit miles of distribution lines, which operate at various voltages ranging from 2.4 to 25 kV.
PROGRESS VENTURES - -----------------
The Progress Ventures business unit controls, either directly or through subsidiaries, coal reserves located in eastern Kentucky and southwestern Virginia. Progress Ventures owns properties that contain estimated coal reserves of approximately 13 million tons and controls, through mineral leases, additional estimated coal reserves of approximately 20 million tons. The reserves controlled include substantial quantities of high quality, low sulfur coal that is appropriate for use at Florida Power's existing generating units. Progress Ventures' total production of coal during 2001 was approximately 3.1 million tons.
In connection with its coal operations, Progress Venture's subsidiaries own and operate an underground mining complex located in southeastern Kentucky and southwestern Virginia. Other subsidiaries own and operate surface and underground mines, coal processing and loadout facilities and a river terminal facility in eastern Kentucky, a railcar-to-barge loading facility in West Virginia, and three bulk commodity terminals: one on the Ohio River in Cincinnati, Ohio, and two on the Kanawha River near Charleston, West Virginia. Progress Ventures and its subsidiaries employ both company and contract miners in their mining activities. Through a joint venture, Progress Ventures has four oceangoing tug/barge units.
The Progress Ventures business unit, through direct and indirect subsidiaries, owns all of the interests in five entities and a minority interest in one entity that owns facilities that produce synthetic fuel. These entities own a total of nine facilities in seven different locations in West Virginia, Virginia and Kentucky.
A subsidiary of Progress Ventures has oil and gas leases on about 20,000 acres in Garfield and Mesa Counties, Colorado, containing proven natural gas net reserves of 67.5 billion cubic feet. This subsidiary currently operates 70 gas wells on the properties. Total natural gas production in 2001 was 4.7 billion cubic feet.
Another subsidiary of Progress Ventures owns and operates a manufacturing facility at the Florida Power Energy Complex in Crystal River, Florida. The manufacturing process utilizes the fly ash generated by the burning of coal as the major raw material in the production of lightweight aggregate used in construction building blocks.
As of December 31, 2001, Progress Ventures had the following merchant plants in service, planned for construction or planned to be acquired.
(a) Represents Progress Venture's summer rating. (b) Transferred from CP&L to Progress Ventures in February 2002 (c) Purchased from LG&E Energy Corp. in February 2002 (d) Expected commercial operation date
RAIL SERVICES - -------------
Progress Rail is one of the largest integrated processors of railroad materials in the United States, and is a leading supplier of new and reconditioned freight car parts, rail, rail welding and track work components, railcar repair facilities, railcar and locomotive leasing, maintenance-of-way equipment and scrap metal recycling. It has facilities in 26 states, Mexico and Canada.
Progress Rail owns and/or operates approximately 5,300 railcars and 100 locomotives that are used for the transportation and shipping of coal, steel and other bulk products.
OTHER - -----
NCNG - ----
NCNG owns and operates a liquefied natural gas storage plant which provides 97,200 dekatherms (dt) per day to NCNG's peak-day delivery capability.
NCNG owns approximately 1,225 miles of transmission pipelines of two to 30 inches in diameter which connect its distribution systems with the Texas-to-New York transmission system of Transco and the southern end of Columbia's transmission system. Transco delivers gas to NCNG at various points conveniently located with respect to its distribution area. Columbia delivers gas to one delivery point near the North Carolina - Virginia border. NCNG distributes natural gas through its 3,026 miles of distribution mains. These transmission pipelines and distribution mains are located primarily on rights-of-way held under easement, license or permit on lands owned by others.
In March 2001, construction of a 30-inch natural gas pipeline, named the Sandhills Pipeline, from Iredell County to Richmond County in North Carolina was completed. This 84-mile pipeline is primarily used to transport natural gas to an electric generating plant constructed in Richmond County by CP&L.
PROGRESS TELECOM AND CARONET - ----------------------------
Progress Telecom provides wholesale telecommunications services throughout the Southeastern United States. Progress Telecom incorporates more than 130,000 fiber miles in its network including over 150 Points-of-Presence, which includes Caronet.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS - ------ -----------------
Legal and regulatory proceedings are included in the discussion of the Company's business in PART I, ITEM 1 under "Environmental", "Regulatory Matters" and "Nuclear Matters" and incorporated by reference herein.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - ------ ---------------------------------------------------
NONE
EXECUTIVE OFFICERS OF THE REGISTRANTS -------------------------------------
* Indicates individual is an executive officer of Progress Energy, Inc., but not CP&L.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER - ------ ----------------------------------------------------------------- MATTERS - -------
Progress Energy's Common Stock is listed on the New York and Pacific Stock Exchanges. The high and low stock prices for CP&L (for periods prior to the consummation of the holding company restructuring on June 19, 2000) and for Progress Energy (for periods following the consummation of the holding company restructuring on June 19, 2000) for each quarter for the past two years, and the dividends declared per share are as follows:
2001 High Low Dividends Declared - ---- ------ ------ ------------------
First Quarter $49.25 $38.78 .530 Second Quarter 45.00 40.36 .530 Third Quarter 45.79 39.25 .530 Fourth Quarter 45.60 40.50 .545
2000 High Low Dividends Declared - ---- ------ ------ ------------------
First Quarter $37.00 $28.25 .515 Second Quarter 38.00 31.00 .515 Third Quarter 41.94 31.50 .515 Fourth Quarter 49.38 38.00 .530
The December 31 closing price of the Company's Common Stock was $45.03 in 2001 and $49.19 in 2000.
As of February 28, 2002, the Company had 218,727,139 holders of record of Common Stock.
Progress Energy holds all 159,608,055 shares outstanding of CP&L common stock and, therefore, no public trading market exists for the common stock of CP&L.
ITEM 6.
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA - ------ --------------------------------------
PROGRESS ENERGY, INC. - ---------------------
The selected consolidated financial data should be read in conjunction with the consolidated financial statements and the notes thereto included elsewhere in this report.
(a) Operating results and balance sheet data includes information for FPC since November 30, 2000, the date of acquisition. (b) Operating results and balance sheet data includes information for NCNG since July 15, 1999, the date of acquisition.
CAROLINA POWER & LIGHT COMPANY - ------------------------------
The selected consolidated financial data should be read in conjunction with the consolidated financial statements and the notes thereto included elsewhere in this report.
(a) Operating results and balance sheet data do not include information for NCNG, SRS, Monroe Power and Progress Ventures, Inc. subsequent to July 1, 2000, the date CP&L distributed its ownership interest in the stock of these companies to Progress Energy. (b) Operating results and balance sheet data includes information for NCNG since July 15, 1999, the date of acquisition.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS - ------ ------------------------------------------------------------------------ OF OPERATIONS - -------------
PROGRESS ENERGY, INC. - ---------------------
RESULTS OF OPERATIONS - --------------------- For 2001 as compared to 2000 and 2000 as compared to 1999
In this section, earnings and the factors affecting them are discussed. The discussion begins with a general overview, then separately discusses earnings by business segment.
Overview
Progress Energy, Inc. (Progress Energy or the Company) is a registered holding company under the Public Utility Holding Company Act of 1935, as amended (PUHCA). Both Progress Energy and its subsidiaries are subject to the regulatory provisions of PUHCA. Progress Energy was formed as a result of the reorganization of Carolina Power & Light Company (CP&L) into a holding company structure on June 19, 2000. All shares of common stock of CP&L were exchanged for an equal number of shares of CP&L Energy, Inc (CP&L Energy). On December 4, 2000, CP&L Energy changed its name to Progress Energy, Inc.
The Company's acquisition of Florida Progress Corporation (FPC) became effective on November 30, 2000. The acquisition was accounted for using the purchase method of accounting. As a result, the consolidated financial statements only reflect FPC's operations subsequent to November 30, 2000.
Through its wholly owned regulated subsidiaries, CP&L, Florida Power Corporation (Florida Power) and North Carolina Natural Gas Corporation (NCNG), Progress Energy is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina, South Carolina and Florida; and the transport, distribution and sale of natural gas in portions of North Carolina. Through the Progress Ventures business segment, Progress Energy is involved in merchant energy generation, coal and synthetic fuel operations and energy marketing and trading. Through other business units, Progress Energy engages in other non-regulated business areas including energy management and related services, rail services and telecommunications.
Progress Energy is a regional energy company focusing on the high-growth Southeast region of the United States. The Company has more than 20,000 megawatts of generation capacity and serves approximately 2.9 million electric and gas customers in portions of North Carolina, South Carolina and Florida. CP&L's and Florida Power's utility operations are complementary: CP&L has a summer peaking demand, while Florida Power has a winter peaking demand. In addition, CP&L's greater proportion of commercial and industrial customers combined with Florida Power's greater proportion of residential customers creates a more balanced customer base. The Company is dedicated to expanding the region's electric generation capacity and delivering reliable, competitively priced energy.
The operations of Progress Energy and its subsidiaries are divided into five major segments: two electric utilities (CP&L and Florida Power), Progress Ventures, Rail Services and Other. The Other segment includes natural gas operations, telecommunication services, energy management services, miscellaneous non-regulated activities, holding company operations and elimination entries.
In 2001, net income was $541.6 million, a 13.2% increase over $478.4 million in 2000. Net income increased in 2001 primarily due to a full year of FPC's operations being included in the 2001 results, as FPC contributed net income of $398.3 million for the year ended December 31, 2001. Other factors contributing to the increase in net income in 2001 include increases in tax credits from Progress Energy's share of synthetic fuel facilities, continued customer growth at the electric utilities and decreases in depreciation expense related to CP&L's accelerated cost recovery program. Partially offsetting these increases were impairment and one-time after-tax charges totaling $152.8 million primarily attributable to Strategic Resource Solutions Corp. (SRS) and the Company's investment in Interpath, as well as increases in interest expense and goodwill amortization related to the FPC acquisition. Basic earnings per share decreased from $3.04 per share in 2000 to $2.65 per share in 2001 due to the factors outlined above and also from an increase in the number of shares outstanding resulting from the FPC acquisition and an additional common stock issuance in August 2001.
In 2000, net income was $478.4 million, a 26.1% increase over $379.3 million in 1999. Basic earnings per share increased from $2.56 per share in 1999 to $3.04 per share in 2000. Continued customer growth, increased usage by CP&L Electric customers and tax credits from Progress Energy's share of synthetic fuel facilities positively affected earnings. Other significant events included the sale of a 10% limited partnership interest in BellSouth Carolinas PCS for a $121.1 million after-tax gain, additional accelerated depreciation of CP&L nuclear generation facilities for a
$192.5 million after-tax effect and the December operations of FPC, which contributed net income of $28.7 million for the month of December 2000.
Note 1 to the Progress Energy consolidated financial statements discusses the Company's significant accounting policies. The most critical accounting policies and estimates that impact the Company's financial statements are the economic impacts of utility regulation, which are described in more detail in Note 13 and the impact of synthetic fuel tax credits, which are described in more detail in Note 18 to the Progress Energy consolidated financial statements.
Electric Segments
The electric segments are primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North and South Carolina by CP&L and, since November 30, 2000, in portions of Florida by Florida Power. CP&L serves an area of approximately 34,000 square miles, with a population of more than 4.0 million. As of December 31, 2001, CP&L provided electricity to approximately 1.3 million customers. Florida Power serves an area of approximately 20,000 square miles, with a population of more than 5.0 million. As of December 31, 2001, Florida Power provided electricity to approximately 1.4 million customers.
The operating results of both electric utilities are primarily influenced by customer demand for electricity, the ability to control costs and the authorized regulatory return on equity. Annual demand for electricity is based on the number of customers and their annual usage, with usage largely impacted by weather. In addition, the current economic conditions in the service territories can impact the annual demand for electricity.
CP&L Electric - -------------
CP&L Electric operations contributed net income of $468.3 million, $373.8 million and $430.3 million in 2001, 2000 and 1999, respectively. Included in these amounts are energy marketing and trading activities, which are managed by Progress Ventures on behalf of CP&L, that had net income of $62.7 million, $84.0 million and $69.5 million in 2001, 2000 and 1999, respectively.
Revenues
CP&L's electric revenues for the years ended December 31, 2001, 2000 and 1999 and the percentage change by year by customer class are as follows (in millions):
CP&L electric energy sales for 2001, 2000 and 1999 and the percentage change by year by customer class are as follows (in thousands of mWh):
During 2001, residential and commercial sales reflected continued growth in the number of customers served by CP&L, partially offset by mild weather. CP&L added over 30,500 new customers in 2001. Cooler-than-normal weather in the summer and milder-than-normal weather in the fourth quarter of 2001 accounted for a decrease in retail sales for the year compared to 2000. Colder-than-normal weather in the fourth quarter of 2000 accounted for
an increase in retail sales for 2000 when compared to 1999. The 2000 favorable variances over 1999 were also attributable to customer growth and usage as CP&L added over 33,000 new customers in 2000.
Downturns in the economy during 2001 impacted energy usage throughout most of the industrial customer class. Total industrial sales fell during 2001 and the number of customers decreased due to slowdowns and plant closings. The decline was primarily due to a downturn in the textile industry, with other usage decreases noted in the chemical, rubber, and plastic industries. Energy used by the industrial class was relatively flat from 1999 to 2000. Total mWh sales to wholesale customers decreased in 2001 from 2000 primarily due to mild weather. However, revenues from wholesale customers increased in 2001 over 2000 due to the establishment of new long-term contracts and the receipt of a termination payment on a long-term contract in December 2001. In 2000, sales to wholesale customers were slightly higher than 1999 due to colder-than-normal weather and competitive prices in fourth quarter of 2000.
Expenses
CP&L Electric's fuel expense increased $19.8 million in 2001 when compared to $627.5 million in 2000 primarily due to increases in the price of coal, partially offset by decreases in generation. CP&L Electric's fuel expense increased $46.2 million in 2000 when compared to $581.3 million in 1999 primarily due to increases in generation and increases in fuel prices associated with gas and oil-fired units.
For 2001, purchased power increased $28.2 million when compared to $325.4 million in 2000 mainly due to favorable market conditions in the first quarter of 2001. For 2000, purchased power decreased $40.0 million when compared to $365.4 million in 1999 primarily due to the expiration of CP&L's long-term purchase power agreement with Duke Energy in mid-1999. Additionally, 2000 reflects a decrease in purchases from cogeneration facilities when compared to 1999.
Fuel and purchased power expenses are recovered primarily through cost recovery clauses and, as such, have no material impact on operating results.
CP&L Electric's other operation and maintenance expenses decreased $24.6 million in 2001 when compared to $726.3 million in 2000 primarily due to the absence of restoration costs associated with the severe winter storm and record-breaking snowfall in January 2000, as well as cost control efforts. These amounts were partially offset by increases in planned nuclear outage costs and transmission expenses in 2001. In 2000, other operation and maintenance expense increased $57.7 million when compared to $668.6 million in 1999 due to increases in benefit plan-related expenses and emission allowances. A total of $23 million of emission allowances was expensed in 2000.
Depreciation and amortization expense decreased $176.7 million in 2001 when compared to $698.6 million in 2000 and increased $204.7 million in 2000 when compared to $493.9 million in 1999. CP&L's accelerated cost recovery program for nuclear generating assets allows flexibility in recording accelerated depreciation expense. In 2001, CP&L recorded $75 million to depreciation expense, the minimum amount of accelerated depreciation allowed under the program. In 2000, as approved by regulators, CP&L recorded $275 million to depreciation expense under this program. See Note 1G to the Progress Energy consolidated financial statements for additional information about this program.
Net interest expense increased $19.6 million in 2001 when compared to $221.9 million in 2000 and increased $38.8 million in 2000 when compared to $183.1 million in 1999 primarily due to higher debt balances. Debt balances increased over these periods in order to fund construction programs.
Florida Power Electric - ----------------------
The results shown in the Progress Energy consolidated financial statements for the Florida Power Electric segment are not comparable to the prior year as the operating results of Florida Power have only been included in Progress Energy's results of operations since the date of acquisition, November 30, 2000. Therefore, the results of operations for 2000 only include one month of Florida Power operations and the results of operations for 2001 include a full year of Florida Power operations.
Florida Power Electric contributed net income of $309.6 million for the year ended December 31, 2001 and $21.8 million for the month of December 2000. Included in these amounts are energy marketing and trading activities, which are managed by Progress Ventures on behalf of Florida Power, that had net income of $24.0 million for the year ended December 31, 2001 and $1.7 million for the month of December 2000.
A comparison of the results of operations of Florida Power Electric for a full year 2001 compared to a full year 2000 follows.
Revenues
Florida Power's electric revenues for the years ended December 31, 2001 and 2000 and the percentage change by customer class are as follows (in millions):
- --------------------------------------------------------------------- Customer Class 2001 % Change 2000/(a)/ - --------------------------------------------------------------------- Residential $1,643 11.3% $1,476 Commercial 754 13.9 662 Industrial 223 5.2 212 Governmental 176 15.8 152 - ------------------------------------------ ------ Total Retail Revenues 2,796 11.8 2,502 Wholesale 288 4.3 276 Miscellaneous 129 37.2 94 - ------------------------------------------ ------ Total Electric Revenues $3,213 11.9% $2,872 - -------------------------------------------------------------------- (a) Florida Power electric revenues are included in the Company's results of operations since November 30, 2000, the date of acquisition.
Florida Power's electric energy sales for the years ended December 31, 2001 and 2000 and the percentage change by customer class are as follows (in thousands of mWh):
- --------------------------------------------------------------------- Customer Class 2001 % Change 2000/(a)/ - --------------------------------------------------------------------- Residential 17,604 2.9% 17,116 Commercial 11,061 2.3 10,813 Industrial 3,872 (8.9) 4,249 Governmental 2,726 2.7 2,654 - ------------------------------------------ ------ Total Retail Energy Sales 35,263 1.2 34,832 Wholesale 4,719 (9.4) 5,209 Unbilled (511) -- 344 - ------------------------------------------ ------ Total mWh sales 39,471 (2.3%) 40,385 - -------------------------------------------------------------------- (a) Florida Power electric energy sales are included in the Company's results of operations since November 30, 2000, the date of acquisition.
Residential and commercial sales increased in 2001 and reflected continued growth in the number of customers served by Florida Power, partially offset by milder-than-normal weather and a downturn in the Florida economy. Florida Power added over 35,000 new customers in 2001. Industrial sales declined due to weakness in the manufacturing sector and phosphate industry, which continue to be affected by the economic downturn. Sales to wholesale customers decreased for 2001, primarily due to the mild weather.
Expenses
Fuel used in generation and purchased power was $1.4 billion for the year ended December 31, 2001. Fuel used in generation increased $230.9 million when compared to 2000 primarily due to increases in coal prices and recovery of previously deferred fuel costs, and purchased power expense was consistent between 2000 and 2001. Fuel and purchased power expenses are recovered primarily through cost recovery clauses and, as such, have no material impact on operating results. Other operation and maintenance expense was $425.5 million for the year ended December 31, 2001 and decreased when compared to 2000 due primarily to merger-related costs recorded in the prior year. Excluding these costs, other operation and maintenance expense was consistent between years.
Depreciation and amortization expense was $453.0 million in 2001 and increased $50.3 million when compared to 2000. During 2001, Florida Power recorded additional amortization on the Tiger Bay regulatory asset, which was created as a result of the early termination of certain long-term cogeneration contracts. Florida Power amortizes the regulatory asset according to a plan approved by the Florida Public Service Commission in 1997. In 2001, $97 million of accelerated amortization was recorded on the Tiger Bay regulatory asset, of which $63 million was associated with deferred revenue from 2000 and had no impact on 2001 earnings.
Progress Ventures
The Progress Ventures segment operations include fuel extraction, manufacturing and delivery, synthetic fuels production, merchant generation, and energy marketing and trading activities on behalf of the utility operating
companies. Due to the creation of Progress Ventures in 2000 and the acquisition of Electric Fuels' subsidiaries (renamed Progress Fuels on January 2, 2002) through the FPC acquisition, the results of operations for the Progress Ventures segment are not comparable to the prior year.
Progress Ventures contributed segment income, including allocation of energy marketing and trading on behalf of the utilities, of $288.7 million, $125.6 million and $69.5 million for 2001, 2000 and 1999, respectively. Of these amounts, energy marketing and trading net income on behalf of the utilities was $86.7 million, $85.7 million and $69.5 million in 2001, 2000 and 1999, respectively.
The increase in earnings for this segment is primarily due to the tax credits generated by Progress Energy's synthetic fuel operations. The Progress Ventures segment sold 13.3 million tons of synthetic fuel for the year ended December 31, 2001, and 2.9 million tons for the year ended December 31, 2000. The production of synthetic fuel generates an operating loss and the sale of this alternative fuel qualifies for tax credits under Section 29 of the Internal Revenue Code (See "Synthetic Fuels" discussion under OTHER MATTERS below). These credits are determined by the BTU content of product sold to third parties and resulted in tax credits of $349.3 million and $83.6 million being recorded for 2001 and 2000, respectively. The Company is exploring the possible sale of an interest in its synthetic fuel facilities in order to optimize the total value of this line of business.
Progress Ventures' energy marketing and trading activities on behalf of CP&L generated net income of $62.7 million, $84.0 million, and $69.5 million for 2001, 2000 and 1999, respectively. Earnings from the term marketing operations were relatively flat across these periods. Earnings from the trading operations decreased in 2001 from 2000 primarily due to a decline in market prices and transfer of available trading volumes to long-term contracts. The fair value of the Company's open trading positions was less than $0.2 million at December 31, 2001. Earnings from the trading operations increased in 2000 from 1999 primarily due to trading profits and strong prices during periods when CP&L had unused capacity available for sale. Progress Ventures' energy marketing and trading activities on behalf of Florida Power for the year ended December 31, 2001 and month of December 2000 were $24.0 million and $1.7 million, respectively. On an annual basis, these earnings have increased over the prior year primarily due to increased term marketing sales to Seminole Electric Cooperative, Florida Power's largest wholesale customer.
The fuel extraction, manufacturing and delivery results are not comparable to the prior year due to the acquisition of FPC in November 2000. Merchant generation operations for the current year were consistent with the prior period results. Progress Energy expects earnings in merchant generation to increase in the future through the addition of a plant in Florida, transfer of generating assets in Rowan County from CP&L to Progress Ventures and additional acquisition and construction of electric generating projects. See OTHER MATTERS below for a detail of Progress Ventures' plant developments and acquisitions.
Rail Services
Rail Services' operations represent the activities of Progress Rail Services Corporation (Progress Rail) and include railcar repair, rail parts reconditioning and sales, scrap metal recycling and other rail related services. Rail Services' results for the year ended December 31, 2001, include Rail Services' cumulative revenues and net loss from the date of acquisition, November 30, 2000.
Due to the acquisition of Progress Rail through the FPC acquisition, the results of operations for the Rail Services segment are not comparable to the prior year. The current year net loss of $12.1 million was negatively affected by a decrease in rail service procurement by major railroads and the significant downturn in the domestic scrap market.
Other
Progress Energy's Other segment primarily includes the operations of NCNG, SRS, Progress Telecommunications Corporation (Progress Telecom) and Caronet, Inc. (Caronet). This segment also includes other non-regulated operations of CP&L and FPC as well as holding company results. The Other segment had a net loss of $426.2 million in 2001 and net income of $43.0 million in 2000. The decrease in earnings for 2001 when compared to 2000 is primarily due to one-time after-tax charges of $148.1 million from the assessment of the recoverability of the Interpath investment and certain assets in the SRS subsidiary, increases in after-tax interest expense for holding company debt of $159.0 million and goodwill amortization of $89.7 million resulting from the acquisition of FPC. In addition, the Other segment net income in 2000 includes a $121.1 million after-tax gain on sale of assets, as described more fully below.
In 1999, the Other segment had a net loss of $51.1 million. The increase in earnings in 2000 when compared to 1999 is primarily due to a $121.1 million after-tax gain on the sale of Caronet's 10% limited partnership interest in
BellSouth Carolinas PCS in September 2000. Caronet sold its interest for a pre-tax gain of $200 million, which was recorded as other income.
SRS is engaged in software sales and energy services to help industrial, commercial and institutional customers manage energy costs. Progress Energy is refocusing the business on energy services in the southeastern states and is consolidating remaining operations with other retail activities. SRS net losses, excluding after-tax impairments and other one-time charges discussed below, were $7.2 million, $0.8 million and $10.4 million for 2001, 2000 and 1999, respectively. Due to the historical and current year losses at SRS and the decline of the market value for technology companies, the company obtained a valuation study to help assess the recoverability of SRS's long-lived assets. Based on this assessment, the Company recorded after-tax asset impairments and other one-time charges of $40.7 million in the fourth quarter of 2001. In addition, the Company recorded after-tax investment impairments of $4.9 million for other-than-temporary declines in certain investments of SRS in the fourth quarter of 2001. These writedowns constitute a significant reduction in the book value of these assets, and the ongoing operations are expected to have a negligible impact on Progress Energy's net income.
Effective June 28, 2000, Caronet contributed the net assets used in its application service provider business to a newly formed company named Interpath Communications, Inc. (Interpath) for a 35% ownership interest (15% voting interest). Therefore, the application service provider revenues are not reflected in the Progress Energy consolidated financial statements subsequent to that date. Due to the decline in the market value for technology companies, Progress Energy obtained a valuation study to assess its investment in Interpath. Based on this valuation, the company recorded an after-tax impairment of $102.4 million for other-than-temporary declines in the fair value of its investment in Interpath.
NCNG had gross margins of $77.9 million and $70.5 million and net income of $2.5 million and $6.5 million for the years ended December 31, 2001 and 2000, respectively. The increase in margin is mainly attributable to the Sandhills pipeline that was completed in March 2001, which was partially offset by declines in industrial sales. The decrease in net income is primarily due to higher overall operating expenses. The operations from 2000 to 1999 are not comparative as NCNG was acquired on July 15, 1999. In February 2002, NCNG filed a general rate case with the North Carolina Utilities Commission (NCUC) requesting an annual rate increase of $47.6 million, based upon its completion of major expansion projects. Progress Energy cannot predict the final outcome of this matter.
Progress Telecom, acquired as part of the FPC acquisition, provides broadband capacity services, dark fiber and wireless services in Florida and the Eastern United States. Progress Telecom and certain assets and liabilities of Caronet will be combined into a new entity named Progress Telecom Corporation (Telecom) in the first half of 2002. All existing contracts for Progress Telecom and Caronet will be transferred to this entity in the first half of 2002, subject to regulatory approval. The combined operating losses for Progress Telecom and Caronet were $9.1 million in 2001.
The Other segment also includes Progress Energy's holding company results. As part of the acquisition of FPC, goodwill of approximately $3.6 billion was recorded, and amortization of $89.7 million in 2001 and $7.0 million in 2000 is included in the Other segment. See Note 1L to the Progress Energy consolidated financial statements for information on recent developments related to goodwill amortization. Interest expense of $265.1 million in 2001 and $28.0 million in 2000, primarily related to the debt used to finance the acquisition of FPC, is also included in these results.
Progress Energy issued 98.6 million contingent value obligations (CVOs) in connection with the FPC acquisition. Each CVO represents the right to receive contingent payments based on the performance of four synthetic fuel facilities owned by Progress Energy. The payments, if any, are based on the net after-tax cash flows the facilities generate. At December 31, 2001, the CVOs had a fair market value of approximately $41.9 million. Progress Energy recorded an unrealized loss of $1.5 million for the year ended December 31, 2001, and an unrealized gain of $8.9 million for the month ended December 31, 2000, to record the change in fair value of CVOs.
LIQUIDITY AND CAPITAL RESOURCES - -------------------------------
Overview
Progress Energy is a registered holding company and, as such, has no operations of its own. The ability to meet its obligations is primarily dependent on the earnings and cash flows of its two electric utilities and the ability of those subsidiaries to pay dividends or to advance or repay funds to Progress Energy.
Progress Energy continues to focus on its strategy of becoming a diversified electric and gas holding company. The cash requirements of Progress Energy arise primarily from the capital intensive nature of its electric utility operations as well as the expansion of its diversified businesses, primarily those of Progress Ventures.
Progress Energy relies upon its operating cash flow, commercial paper facilities and its ability to access long-term capital markets for its liquidity needs. Since a substantial majority of Progress Energy's operating costs are related to its two regulated electric utilities, a significant portion of these costs are recovered from customers through fuel and energy cost recovery clauses.
Progress Energy expects its operating cash flow to exceed its projected capital expenditures beginning in 2003. Due to the significant portion of cash flows derived from its regulated businesses and an excess of operating cash flow over capital expenditures beginning in 2003, Progress Energy expects its liquidity resources to be sufficient to fund its current business plans. Risk factors associated with commercial paper back up credit facilities and credit ratings are discussed below.
The following discussion of Progress Energy's liquidity and capital resources is on a consolidated basis.
Cash Flows from Operations
Cash from operations is the primary source used to meet operating requirements and capital expenditures. The increase in cash from operating activities for 2001 when compared with 2000 is largely the result of the November 30, 2000, acquisition of FPC. The prior year results reflected one month's cash from operations of FPC.
Progress Energy's two electric utilities produced approximately 125% of consolidated cash from operations in 2001. This is expected to continue over the next several years as its non-regulated investments, primarily generation assets, are placed into service and begin generating operating cash flows. In addition, Progress Venture's synthetic fuel operations do not currently produce positive operating cash flow primarily due to the difference in timing of when tax credits are recognized for financial reporting purposes and when tax credits are realized for tax purposes.
Total cash from operations of $1.4 billion provided the funding for approximately 86% of the Company's property additions, nuclear fuel expenditures and diversified business property additions during 2001. For 2002, it is expected that approximately 80% of capital expenditures will be funded internally, which is a decrease from 2001 due to increases in projected non-regulated capital expenditures. For 2003 and 2004, cash from operations is expected to be up to 140% of the Company's projected capital expenditures.
Investing Activities
Cash used in investing was $1.7 billion in 2001, up $603 million when compared with 2000 after adjusting for the acquisition of FPC. The increase is due primarily to the expansion of Progress Ventures' generation portfolio and the absence of proceeds from the sale in 2000 of the BellSouth Carolinas PCS limited partnership interest.
Capital expenditures for Progress Energy's regulated operations were $1.2 billion or approximately 78% of consolidated capital expenditures in 2001. As shown in the table below, the Company anticipates that the proportion of non-regulated capital spending to total capital expenditures will increase substantially in 2002, primarily due to generation and other additions at Progress Ventures (See OTHER MATTERS below for a detail of these projects). Subsequent to 2002, the Company expects its proportion of regulated capital expenditures to range between 70% and 90% of total capital expenditures.
(Amounts in millions):
Actual Forecasted ------ ------------------------ 2001 2002 2003 2004 ------ ------ ------ ------ Regulated capital expenditures $1,216 $1,145 $1,043 $1,169 Nuclear fuel expenditures 116 62 108 60 AFUDC (18) (28) (52) (36) Non-regulated capital expenditures 350 1,033 407 202 ------ ------ ------ ------ Total $1,664 $2,212 $1,506 $1,395 ====== ====== ====== ======
The table includes expenditures from 2002 through 2004 of approximately $230 million expected to be incurred at regulated fossil-fueled electric generating facilities to comply with the Clean Air Act.
All projected capital and investment expenditures are subject to periodic review and revision and may vary significantly depending on a number of factors including, but not limited to, industry restructuring, regulatory constraints, market volatility and economic trends.
Financing Activities
Cash provided by financing activities decreased approximately $3.4 billion over 2000, primarily due to the November 30, 2000 acquisition of FPC, which was funded from the sale of short-term commercial paper. This funding was converted to long-term debt during 2001. Excluding the effect of the acquisition financing, cash from financing activities increased slightly in 2001 when compared with 2000, primarily due to the expansion of Progress Energy's non-regulated operations.
In February 2001, Progress Energy issued $3.2 billion of senior unsecured notes with maturities ranging from three to thirty years. These notes were issued with a weighted-average coupon rate of 7.06%. Proceeds from the issuance were used to retire commercial paper and other short-term indebtedness issued in connection with the FPC acquisition.
In April 2001, CP&L issued $300 million of medium-term notes due 2008 with a coupon of 6.65%. Proceeds from the issuance were primarily used to retire commercial paper.
In July 2001, Florida Power issued $300 million of first mortgage bonds due 2011 with a coupon of 6.65%. Proceeds from the issuance were primarily used to retire commercial paper.
In August 2001, Progress Energy issued 12.65 million shares of common stock at $40 per share for net proceeds of $488 million. Proceeds from the issuance were primarily used to retire commercial paper, including amounts issued in connection with the FPC acquisition.
In October 2001, Progress Energy issued $400 million of senior unsecured notes due 2008 with a coupon of 5.85% and $400 million of senior secured notes due 2031 with a coupon of 7.00%. Approximately $600 million of the proceeds from this issuance were used to retire commercial paper outstanding at Progress Capital Holdings, Inc. (PCH). PCH is the holding company for certain non-regulated businesses of FPC. In November 2001, the Company terminated the PCH commercial paper program.
In November 2001, CP&L redeemed $125 million of 8.55% quarterly income capital securities at 100% of the principal amount of such securities. The redemption was funded primarily through the issuance of commercial paper.
In March 2002, Progress Ventures obtained a $440 million bank facility that will be used exclusively for expansion of its non-regulated generation portfolio. Borrowings under this facility will be non-recourse to Progress Energy; however, the Company entered into certain support and guarantee agreements to ensure performance under generation construction and operating agreements.
Progress Energy uses interest rate derivative instruments to manage the fixed and variable rate debt components of its debt portfolio. The Company's long-term objective is to maintain a debt portfolio mix of approximately 30 percent variable rate debt with the balance fixed rate. As of December 31, 2001, Progress Energy's variable rate and fixed rate debt comprised 15 percent and 85 percent, respectively.
During March 2002, Progress Energy converted $800 million of fixed rate debt into variable rate debt by executing interest rate derivative agreements with a group of five banks. This increased the amount of variable rate debt in its portfolio to 27 percent. Under the terms of the agreements, Progress Energy will receive a fixed rate of 4.87% and will pay a floating rate based on three-month LIBOR. These instruments were designated as fair value hedges for accounting purposes.
As a registered holding company under PUHCA, Progress Energy obtains approval from the SEC for the issuance and sale of securities as well as the establishment of intracompany extensions of credit. In January 2002, Progress Energy requested an increase of $2.5 billion in its authority to issue long-term securities, increasing the limit from $5 billion to $7.5 billion. Upon the approval of this increase, Progress Energy will have authority to issue approximately $3 billion of long-term securities.
At December 31, 2001, the Company and its subsidiaries had committed lines of credit totaling $1.945 billion. These lines of credit support the Company's commercial paper borrowings. The following table summarizes the Company's credit facilities:
Subsidiary Description Short-term Long-term Total - ------------------------------------------------------------------------------ Progress Energy 364-Day $550 $ -- $ 550 Progress Energy 3-Year (3 years remaining) -- 450 450 CP&L 364-Day -- 200 200 CP&L 5-Year (2 years remaining) -- 375 375 Florida Power 364-Day 170 -- 170 Florida Power 5-Year (2 years remaining) -- 200 200 ------------------------------- $720 $1,225 $1,945 ===============================
The Company's financial policy precludes issuing commercial paper in excess of its supporting lines of credit. At December 31, 2001, the total amount of commercial paper outstanding was $942 million, leaving approximately $1 billion available for issuance. The Company is required to pay minimal annual commitment fees to maintain its credit facilities.
In addition, these credit agreements contain various terms and conditions that could affect the Company's ability to borrow under these facilities. These include a maximum debt to total capital ratio, a material adverse change clause and a cross-default provision.
All of the credit facilities include a maximum total debt to total capital ratio. As of December 31, 2001, the calculated ratio for these three companies, pursuant to the terms of the agreement, was as follows:
- ------------------------------------------------------ Company Maximum Ratio Actual Ratio - ------------------------------------------------------ Progress Energy, Inc. 70% 63.1% CP&L 65% 53.2% Florida Power 65% 44.6% - ------------------------------------------------------
Progress Energy's and Florida Power's credit facilities include a provision under which lenders could refuse to advance funds in the event of a material adverse change in the borrower's financial condition. CP&L's credit facilities do not contain this provision.
Each of these credit agreements contains a cross-default provision for defaults of indebtedness in excess of $10 million. Under these provisions, if the applicable borrower or certain subsidiaries fail to pay various debt obligations in excess of $10 million the lenders could accelerate payment of any outstanding borrowing and terminate their commitments to the credit facility.
Additionally, certain of Progress Energy's long-term debt indentures contain cross-default provisions for defaults of indebtedness in excess of $25 million; these provisions apply only to other obligations of Progress Energy, not its subsidiaries. In the event that these provisions are triggered, debt holders could accelerate the payment of approximately $4 billion in long-term debt.
The Company has on file with the SEC a shelf registration statement under which senior notes, junior debentures, common and preferred stock and other trust preferred securities are available for issuance by the Company. As of December 31, 2001, the Company had $500 million available under this shelf registration. In 2002, the Company filed an additional shelf registration with the SEC and now has approximately $2.5 billion of senior notes, junior debentures, common and preferred stock and other trust preferred securities available for issuance.
Florida Power and PCH have two uncommitted bank bid facilities authorizing them to borrow and re-borrow, and have loans outstanding at any time, up to $100 million and $300 million, respectively. At December 31, 2001, there were no outstanding loans against these facilities.
CP&L currently has on file with the SEC a shelf registration statement under which it can issue up to $1 billion of various long-term securities. Florida Power currently has filed registration statements under which it can issue an aggregate of $700 million of various long-term debt securities.
The following table shows Progress Energy's capital structure as of December 31, 2001 and 2000:
2001 2000 ---- ---- Common Stock 36.7% 34.9% Preferred Stock 0.6% 0.6% Total Debt 62.7% 64.5%
The amount and timing of future sales of Company securities will depend on market conditions, operating cash flow, asset sales and the specific needs of the Company. The Company may from time to time sell securities beyond the amount needed to meet capital requirements in order to allow for the early redemption of long-term debt, the redemption of preferred stock, the reduction of short-term debt or for other general corporate purposes.
Credit Ratings
As of December 31, 2001, the major credit rating agencies rated the Company's securities as follows:
Moody's ------- Investors Service Standard and Poor's ----------------- ------------------- Progress Energy, Inc. Corporate Credit Rating Baa1 BBB+/A-2 Senior Unsecured Baa1 BBB Commercial Paper P-2 A-2 Carolina Power & Light Company Corporate Credit Rating Baa1 BBB+ Commercial Paper P-2 A-2 Senior Secured Debt A3 BBB+ Senior Unsecured Debt Baa1 BBB+ Subordinate Debt Baa2 BBB Preferred Stock Baa3 BBB- Florida Power Corporation Corporate Credit Rating A2 BBB+/A-2 Commercial Paper P-1 A-2 Senior Secured Debt A1 BBB+ Senior Unsecured Debt A2 BBB+ Preferred Stock Baa1 BBB- FPC Capital I Preferred Stock* A3 BBB- Progress Capital Holdings, Inc. Senior Unsecured Debt* A3 BBB *Guaranteed by Florida Progress Corporation
These ratings reflect the current views of these rating agencies and no assurances can be given that these ratings will continue for any given period of time. However, the Company monitors its financial condition as well as market conditions that could ultimately affect its credit ratings. The Company is committed to maintaining its current credit ratings.
Neither the Company's debt indentures nor its credit agreements contain any "ratings triggers" which would cause the acceleration of interest and principal payments in the event of a ratings downgrade. However, in the event of a downgrade the Company and/or its subsidiaries may be subject to increased interest costs on the credit facilities backing up the commercial paper programs. The Company and its subsidiaries have certain contracts which have provisions that are triggered by a ratings downgrade. These contracts include counterparty trade agreements, derivative contracts and various types of third party purchase agreements. None of these contracts would require any action on the part of Progress Energy or its subsidiaries unless the ratings downgrade results in a rating below investment grade.
Future Commitments
The following tables reflect Progress Energy's contractual cash obligations and other commercial commitments in the respective periods in which they are due.
Information on the Company's contractual obligations at December 31, 2001, is included in the notes to the Progress Energy consolidated financial statements. Future debt maturities and lease obligations are included in Note 6 and Note 10, respectively. The Company's fuel, purchased power and purchase obligations are included in Note 20A and Note 20B to the Progress Energy consolidated financial statements.
FUTURE OUTLOOK - --------------
The results of operations for the past three years are not necessarily indicative of future earnings potential. The level of Progress Energy's future earnings depends on numerous factors. See SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS for a discussion of factors to be considered with regard to forward-looking statements.
The traditional business of the electric and gas utilities is providing electricity and natural gas to customers within their service areas in the Carolinas and Florida. Prices for electricity and natural gas provided to retail customers are set by the state regulatory commissions under cost-based regulatory principles. See Note 13 to the Progress Energy consolidated financial statements for additional information about these and other regulatory matters.
Future earnings for the electric and gas utilities will depend upon growth in electric energy and gas sales, which is subject to a number of factors. These factors include weather, customer growth, competition, energy conservation practiced by customers, the elasticity of demand and the rate of economic growth in the traditional service area.
Regulatory issues facing Progress Energy are discussed in the "Current Regulatory Environment" discussion under OTHER MATTERS below.
Progress Energy's longer-term strategic focus will encompass four lines of business: Upstream Energy, Transmission, Downstream Energy and Telecom. In support of these strategic lines of business, credit quality and a strong balance sheet will remain a priority. The Company will strive to reduce consolidated leverage through asset divestitures, synergy realization, and controlled capital spending. Progress Energy's legal structure is not currently aligned with the future functional management of these lines of business. Whether, and when, the legal and functional structures will converge depends upon legislative and regulatory action, which cannot currently be anticipated.
Upstream Energy will focus on both regulated and non-regulated generation expansion, energy marketing and trading, and fuel extraction, manufacturing and delivery. The Energy Supply function of Upstream Energy will manage our regulated and non-regulated generation fleet. The Company will continue to prepare for deregulation as it grows Progress Energy's generation fleet. Additional generation capacity is planned to serve the growth expected in the Company's service territories, to increase capacity reserve margins at the regulated subsidiaries, and to take advantage of merchant generation opportunities.
The Progress Ventures business unit of Upstream Energy will manage the Company's competitive energy businesses and certain functions on behalf of the utilities, including wholesale contracts and fuel procurement. Non-regulated generation opportunities will be focused in the Southeast. Progress Ventures expects to have 3,100 MW of merchant generation by the end of 2003 and flexible plans are in place for an additional 2,800 MW of merchant generation subsequent to 2003. The energy marketing and trading activities include 5,300 MW of wholesale contracts currently, primarily on behalf of the utilities, and will include additional contracts for non-regulated generation in the future.
Transmission will focus on meeting FERC's commitment for regional transmission organizations ("RTO"). The Company has already participated in the preliminary development of the GridSouth RTO with Duke Energy and South Carolina Electric and Gas and the GridFlorida RTO with Florida Power & Light and Tampa Electric. Progress Energy continues to assess the structural options that may be available to optimize the value of the Company's transmission assets. Please refer to the "Current Regulatory Environment" section under OTHER MATTERS below for further discussion of transmission and the Company's compliance with FERC Order No. 2000.
Downstream Energy will focus on both the distribution and retail components and will continue to deliver a high level of customer service while offering products and services, both regulated and non-regulated, to the Company's customers. Progress Energy will continue to grow its customer base and focus on value-added services and technologies to enhance customer relationships. Downstream Energy will operate within the electric utilities as an integrated delivery business until any potential restructuring of the utility business occurs.
Telecom will transport voice and data for major carriers, and will focus its expansion on the "local loop" within the Company's existing service territories. While Telecom's long-haul backbone is essentially complete, it will continue its metro expansion into second and third tier cities and provide customers in those areas with access to the world's primary telecommunication centers on the East Coast.
Compliance costs related to current and future environmental laws and regulations could affect earnings if such costs are not fully recovered. The Clean Air Act and other important environmental items are discussed in "Environmental Matters" under OTHER MATTERS below.
As regulated entities, both electric utilities and the gas utility are subject to the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." Accordingly, the utilities record 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. The utilities' ability to continue to meet the criteria for application of SFAS No. 71 may be affected in the future by competitive forces and restructuring in the electric utility industry. In the event that SFAS No. 71 no longer applied to a separable portion of the utilities' operations, related regulatory assets and liabilities would be eliminated unless an appropriate regulatory recovery mechanism is provided. Additionally, these factors could result in an impairment of utility plant assets as determined pursuant to SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." Effective January 1, 2002, the Company adopted SFAS No. 144, which supersedes SFAS No. 121 (See Note 1L).
OTHER MATTERS - -------------
Progress Ventures - Generation
In July 2001, Progress Ventures announced that it is building a plant to include two 160 MW combustion turbine peaking generators at a site in DeSoto County, Florida, about 50 miles east of Sarasota. Plant capacity has been sold to another utility through May 2005. Environmental permits and zoning have been approved for the plant site, and construction is under way. The plant is expected to be completed in June 2002.
In June 2001, the NCUC held a hearing concerning Progress Energy's application to transfer certificates granted for generating units in Rowan County, N.C., from the regulated electric utility, CP&L, to Progress Ventures. In October 2001, the NCUC approved the transfer of three combustion turbine generators and related generation infrastructure at the Rowan County facility from CP&L to Progress Ventures. These assets were transferred in February 2002. The generating units were completed in May 2001 and the majority of their output is sold under long-term wholesale contracts.
During February 2002, Progress Ventures, Inc. completed the acquisition of two electric generating projects totaling nearly 1,100 megawatts in Georgia from LG&E Energy Corp., a subsidiary of Powergen plc, for a total cash consideration of $345 million. The two projects consist of 1) the Walton project in Monroe, Georgia, a 460 MW natural gas-fired plant placed in service in June 2001 and 2) the Washington project in Washington County, Georgia,
a planned 600 MW natural gas-fired plant expected to be operational by June 2003. The transaction included a power purchase agreement with LG&E Marketing for both projects through December 31, 2004. In addition, there is a project management completion agreement with LG&E whereby Progress Ventures assumed certain liabilities to facilitate buildout of the Washington project. The estimated costs to complete the Washington project are approximately $165 million.
Progress Ventures - Fuel Acquisition
On January 11, 2002, Progress Energy announced that it had entered into a letter of intent with Westchester Gas Company to acquire approximately 215 producing natural gas wells, 52 miles of intrastate gas pipeline and 170 miles of gas-gathering systems. The properties are located within a 25-mile radius of Jonesville, Texas, on the Texas-Louisiana border. This will add 140 billion cubic feet (Bcf) of gas reserves to Progress Ventures' fuel business, which more than doubles its gas reserves and potential annual production levels. Total consideration of $153 million is expected to include $135 million in Company common stock and $18 million in cash. This transaction is expected to be completed in the first half of 2002.
Natural Gas Activities
The Eastern North Carolina Natural Gas Co. (EasternNC) is a corporation formed equally between the Albemarle Pamlico Economic Development Corporation (APEC) and Progress Energy to build an 850-mile natural gas pipeline system to serve 14 eastern North Carolina counties. EasternNC has begun surveying, designing, engineering and environmental permitting for the first phase of the project. The initial phase consists of about 125 miles of transmission (6- to 12-inch diameter) pipeline and about 75 miles of distribution (2- to 6-inch diameter) pipe. Construction of the first phase began in October 2001 and is scheduled to be completed by mid-summer 2002. The entire project is expected to be completed by the end of 2004.
Progress Energy has agreed to fund a portion of the project, currently estimated to be approximately $22 million. EasternNC plans to obtain additional capital through funding from general obligation bonds issued by the State of North Carolina. The NCUC approved $38.7 million from bond funds for Phase I of the project in July 2000. On March 20, 2001, EasternNC filed its amended application for approval of the route design for Phases 2-7 of the project and additional bond funds of $149.6 million to construct this system. By order issued June 7, 2001, the NCUC approved construction of Phases 2-7 of the project which addresses the remaining counties and awarded EasternNC an additional $149.6 million in bond funds to finance the construction of the facilities associated with these phases.
Current Regulatory Environment
General
The Company's electric and gas utility operations in North Carolina, South Carolina and Florida are regulated by the NCUC, the Public Service Commission of South Carolina (SCPSC) and the Florida Public Service Commission (FPSC), respectively. The electric businesses are also subject to regulation by the Federal Energy Regulatory Commission (FERC), the U.S. Nuclear Regulatory Commission (NRC) and other federal and state agencies common to the utility business. In addition, the Company is subject to regulation by the U.S. Securities and Exchange Commission (SEC) as a registered holding company under PUHCA. As a result of regulation, many of the fundamental business decisions, as well as the rate of return the electric utilities and the gas utility are permitted to earn, are subject to the approval of governmental agencies.
Electric Industry Restructuring
CP&L and Florida Power continue to monitor progress toward a more competitive environment and have actively participated in regulatory reform deliberations in North Carolina, South Carolina and Florida. Movement toward deregulation in these states has been affected by recent developments, including developments related to deregulation of the electric industry in California and other states.
. North Carolina. On January 23, 2001, the Commission on the Future of Electric Service in North Carolina announced that it would not recommend any new laws on electricity deregulation to the 2001 session of the North Carolina General Assembly, citing the commission's determination that more research is needed. The commission's initial report to the General Assembly, issued on May 16, 2000, had contained several proposals, including a recommendation that electric retail competition should begin in North Carolina by 2006. At its January 23, 2001, meeting, the commission requested that the NCUC consider regulatory changes to facilitate the construction of wholesale generation facilities by private companies, including the elimination of requirements that such companies provide proof of a committed customer base and need for
additional power in order to obtain operating licenses. On May 21, 2001, the NCUC adopted a revised rule which streamlined the certification process for wholesale merchant generating plants.
. South Carolina. The Company expects the South Carolina General Assembly will continue to monitor the experiences of states that have implemented electric restructuring legislation.
. Florida. On January 31, 2001, the Florida 2020 Study Commission voted to forward a "proposed outline for wholesale restructuring" to the Florida legislature for its consideration in the 2001 session. The wholesale restructuring outline is intended to facilitate the evolution of a more robust wholesale marketplace in Florida. On December 11, 2001 the study commission issued its final report. The report covered a number of issues with recommendations in the areas of wholesale competition and reliability, efficiency, transmission infrastructure, environmental issues and new technologies. A key recommendation related to wholesale competition and reliability permits the transfer or sale of existing generation at book value and on a plant-by-plant basis, with the sale and transfer being at the discretion of the investor-owned utility. The Florida legislature did not take any action on the proposed outline or final report during the 2001 session.
The Company cannot anticipate when, or if, any of these states will move to increase competition in the electric industry.
Florida Retail Rate Proceeding
Florida Power previously operated under an agreement committing several parties not to seek any reduction in its base rates or authorized return on equity. That agreement expired on June 30, 2001. During 2001, the FPSC required Florida Power to submit minimum filing requirements, based on a 2002 projected test year, to initiate a rate proceeding regarding its future base rates.
On September 14, 2001, Florida Power submitted its required rate filing, including its revenue requirements and supporting testimony. Florida Power filed supplemental minimum filing requirements and testimony on November 15, 2001. Hearings were scheduled to begin on March 20, 2002, but were postponed to accommodate pending settlement negotiations between the parties.
On March 27, 2002, the parties entered into a Stipulation and Settlement Agreement (the Agreement) related to retail rate matters. The Agreement is to be effective from May 1, 2002 through 2005; provided, however, that if Florida Power's base rate earnings fall below a 10% return on equity, Florida Power may petition the FPSC to amend its base rates.
The Agreement provides that Florida Power will reduce its retail revenues from the sale of electricity by $125 million annually through 2005. The Agreement also provides that Florida Power will operate under a Revenue Sharing Incentive Plan (the Plan) that establishes revenue caps and sharing thresholds for the years 2002 through 2005. The Plan provides that retail base rate revenues between the sharing thresholds and the retail base rate revenue caps will be divided into two shares - a 1/3 share to be received by Florida Power's shareholders, and a 2/3 share to be refunded to Florida Power's retail customers; provided, however, that for the year 2002 only, the refund to customers will be limited to 67.1% of the 2/3 customer share. The retail base rate revenue sharing threshold amounts for 2002, 2003, 2004 and 2005 will be $1,296 million, $1,333 million, $1,370 million and $1,407 million, respectively. The Plan also provides that all retail base rate revenues above the retail base rate revenue caps established for the years 2003, 2004 and 2005 will be refunded to retail customers on an annual basis. For 2002, the refund to customers will be limited to 67.1% of the retail base rate revenues that exceed the 2002 cap. The retail base revenue caps for 2002, 2003, 2004 and 2005 will be $1,356 million, $1,393 million, $1,430 million and $1,467 million, respectively.
The Agreement also provides that beginning with the in-service date of Florida Power's Hines Unit 2 and continuing through December 31, 2005, Florida Power will be allowed to recover through the fuel cost recovery clause a return on average investment and depreciation expense for Hines Unit 2, to the extent such costs do not exceed the Unit's cumulative fuel savings over the recovery period.
Additionally, the Agreement provides that Florida Power will effect a mid-course correction of its fuel cost recovery clause to reduce the fuel factor by $50 million for the remainder of 2002. The fuel cost recovery clause will operate as it normally does, including, but not limited to any additional mid-course adjustments that may become necessary, and the calculation of true-ups to actual fuel clause expenses.
During the term of the Agreement, Florida Power will suspend accruals on its reserves for nuclear decommissioning and fossil dismantlement. Additionally, for each calendar year during the term of the Agreement, Florida Power will record a $62.5 million depreciation expense reduction, and may, at its option, record up to an equal annual amount as an offsetting accelerated depreciation expense. In addition, Florida Power is authorized, at its discretion, to accelerate the amortization of certain regulatory assets over the term of the Agreement.
Under the terms of the Agreement, Florida Power agreed to continue the implementation of its four-year Commitment to Excellence Reliability Plan and expects to achieve a 20% improvement in its annual System Average Interruption Duration Index by no later than 2004. If this improvement level is not achieved for calendar years 2004 or 2005, Florida Power will provide a refund of $3 million for each year the level is not achieved to 10% of its total retail customers served by its worst performing distribution feeder lines.
The Agreement also provides that Florida Power will refund to customers $35 million of the $98 million in interim revenues Florida Power has collected subject to refund since March 13, 2001. No other interim revenues that were collected during that period will continue to be held subject to refund.
The agreement was filed with the FPSC for approval on March 27, 2002. If the FPSC approves the Agreement, the new rates will take effect May 1, 2002. Progress Energy cannot predict the outcome of this matter.
Other Retail Rate Matters
See Note 13B to the Progress Energy consolidated financial statements for additional information on the Company's other retail rate matters.
Regional Transmission Organizations
In October 2000, Florida Power, along with Florida Power & Light Company and Tampa Electric Company filed with FERC an application for approval of a regional transmission organization, or RTO, for peninsular Florida, currently named GridFlorida. On March 28, 2001, FERC issued an order provisionally granting GridFlorida RTO status and directing the GridFlorida applicants to make certain changes in the RTO documents and to file such changes within 60 days. On May 29, 2001, the GridFlorida applicants made the compliance filing as directed by FERC, but FERC has not yet issued an order on that compliance filing.
On May 16, 2001, the FPSC initiated dockets to review the prudence of the GridFlorida applicants' decision to form and participate in the GridFlorida RTO. The GridFlorida applicants have announced that they will hold GridFlorida development activities in abeyance. On June 27, 2001, the FPSC issued an order establishing a two-phase process for addressing these GridFlorida RTO issues in the context of Florida Power's pending rate case. In the first phase, the FPSC will address the general issues associated with the prudence of the GridFlorida RTO on an expedited basis. FPSC hearings were held in October 2001 on the phase one issues, and the FPSC issued an order in December 2001. The order states, among other things, that the GridFlorida applicants acted prudently in moving to establish an RTO for Florida. However, the order also directs the GridFlorida applicants to make certain changes to the proposed GridFlorida structure and refile with the FPSC within 90 days of the order. The GridFlorida applicants made the required changes to GridFlorida and refiled the application with the FPSC on March 20, 2002. The second phase will address ratemaking issues and will be decided as part of the general rate proceeding. Progress Energy cannot predict the outcome or impact of these matters.
In October 2000, CP&L, along with Duke Energy Corporation and South Carolina Electric & Gas Company filed with FERC an application for approval of a for-profit transmission company, currently named GridSouth. On July 12, 2001, FERC issued an order granting GridSouth RTO status and directing that certain modifications to the RTO documents be made and filed within 90 days.
CP&L has applied to the NCUC and the SCPSC for permission to transfer operational control of its transmission assets to GridSouth. On June 21, 2001, the Public Staff of the NCUC filed a motion asking the NCUC to hold the GridSouth docket in abeyance until the U.S. Supreme Court had ruled on the appeal of FERC's Order No. 888. That appeal addresses the scope of FERC's jurisdiction over transmission service used to serve retail customers. The appeal of Order No. 888 was heard by the Court on October 3, 2001, with a decision anticipated in the summer of 2002. The NCUC issued an order holding that CP&L's and Duke Energy Corporation's petition to transfer operational control of their transmission assets to GridSouth shall be held in abeyance pending further order. In February 2002, CP&L and the other GridSouth applicants withdrew the GridSouth application from the NCUC and
SCPSC for purposes of making certain revisions to the GridSouth proposal. The GridSouth applicants plan to refile their application once those changes have been made. Progress Energy cannot predict the outcome of this matter.
On July 12, 2001, FERC issued an order requiring certain parties, including CP&L, Duke Energy Corporation, South Carolina Electric & Gas Company, Southern Company and Entergy to engage in a mediation to develop a plan for a single RTO for the Southeast. The GridFlorida applicants and the parties to the GridFlorida docket before FERC were encouraged to participate, but were not required to do so. Florida Power and CP&L participated in the mediation. On September 10, 2001, the presiding administrative law judge of the mediation submitted a mediation report to FERC. The report, which has not yet been acted on by FERC, recommended adoption of a for-profit transmission company RTO model. FERC held a discussion on the mediation report on November 24, 2001. In January 2002, FERC stated that it would issue orders on the RTO formations for the Southeast during the first half of 2002 after the development of a standardized market design for the wholesale electricity market. Progress Energy cannot predict the outcome of these matters or the effect that it may have on the GridFlorida proceedings currently ongoing before the FERC and the FPSC or the GridSouth proceedings currently ongoing before FERC, the SCPSC or the NCUC.
Franchise Litigation
Five cities, with a total of approximately 36,000 customers, have sued Florida Power in various circuit courts in Florida. The lawsuits principally seek 1) a declaratory judgment that the cities have the right to purchase Florida Power's electric distribution system located within the municipal boundaries of the cities, 2) a declaratory judgment that the value of the distribution system must be determined through arbitration, and 3) injunctive relief requiring Florida Power to continue to collect from Florida Power's customers and remit to the cities, franchise fees during the pending litigation, and as long as Florida Power continues to occupy the cities' rights-of-way to provide electric service, notwithstanding the expiration of the franchise ordinances under which Florida Power had agreed to collect such fees. Three circuit courts have entered orders requiring arbitration to establish the purchase price of Florida Power's electric distribution facilities within three cities. One appellate court has held that one city has the right to determine the value of Florida Power's facilities within the city through arbitration. To date, no city has attempted to actually exercise the right to purchase any portion of Florida Power's electric distribution system, nor has there been any proceeding to determine the value at which such a purchase could be made. Arbitration has been scheduled for two of the cases in the third quarter of 2002. Progress Energy cannot predict the outcome of these matters.
Nuclear
In the Company's retail jurisdictions, provisions for nuclear decommissioning costs are approved by the NCUC, the SCPSC and the FPSC and are based on site-specific estimates that include the costs for removal of all radioactive and other structures at the site. In the wholesale jurisdictions, the provisions for nuclear decommissioning costs are approved by FERC. See Note 1I to the Progress Energy consolidated financial statements for a discussion of the Company's nuclear decommissioning costs.
On December 21, 2000, CP&L received permission from the NRC to increase its storage capacity for spent fuel rods in Wake County, North Carolina. The NRC's decision came two years after CP&L asked for permission to open two unused storage pools at the Shearon Harris Nuclear Plant (Harris Plant). The approval means CP&L can complete cooling systems and install storage racks in its third and fourth storage pools at the Harris Plant.
Orange County, North Carolina appealed the NRC license amendment to expand spent fuel storage capacity at the Harris Plant. On May 31, 2001, Orange County filed a petition for review in the U.S. Court of Appeals for the District of Columbia, and on June 1, 2001, filed a request for stay and expedition of the case with the court.
On June 29, 2001, U.S. Court of Appeals denied Orange County's motion for a stay and rejected the request for an expedited schedule for the appeal. The court is expected to issue a briefing schedule for the case sometime in early 2002. Progress Energy cannot predict the outcome of this matter.
As required under the Nuclear Waste Policy Act of 1982, CP&L and Florida Power each entered into a contract with the U.S. Department of Energy (DOE) under which the DOE agreed to begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract. See Note 20D2 to the Progress Energy consolidated financial statements for a discussion of recent spent nuclear fuel and DOE developments.
Several projects, commonly referred to as power uprate projects, are currently being evaluated and implemented at CP&L's nuclear facilities to increase electrical generation output. A power uprate was completed at the Harris Plant during 2001 and power uprates are in progress at the Brunswick and Robinson Nuclear Plants, which will be
implemented in phases over the next several years following regulatory approval. The total increased generation from these projects is estimated to be approximately 250 megawatts.
In August 2001, the NRC issued Bulletin 2001-01, "Circumferential Cracking of Reactor Vessel Head Penetration Nozzles," requesting that all pressurized water reactors (PWR) provide their plans for inspecting the reactor vessel head for the conditions described in the bulletin. While performing this inspection, FirstEnergy Corp.'s Davis Besse plant in Ohio found three penetrations with evidence of leakage and further evidence of some wastage of the reactor vessel head around two of these penetrations. As a result of finding the wastage of the vessel head, the NRC issued Bulletin 2002-01, requesting licensees to assess previous inspections of the reactor head and determine the potential for the existence of conditions similar to that found at the Davis Besse plant.
The Progress Energy PWRs have completed the inspections requested by Bulletin 2001-01. Any indications of leakage have been inspected and repaired, and no wastage of the reactor vessel head has been observed at any of the plants. Based on these inspections, responses to Bulletin 2002-01 are being prepared. The Company does not anticipate any adverse impact from this regulatory action.
Synthetic Fuels
Progress Energy, through its subsidiaries, is a majority owner in five entities and a minority owner in one entity that own facilities that produce synthetic fuel, as defined under the Internal Revenue Service Code (Code). The production and sale of the synthetic fuel from these facilities qualifies for tax credits under Section 29 of the Code (Section 29) if certain requirements are satisfied, including a requirement that the synthetic fuel differs significantly in chemical composition from the coal used to produce such synthetic fuel. All entities have received private letter rulings (PLR's) from the Internal Revenue Service (IRS) with respect to their synthetic fuel operations. The PLR's do not limit the production on which synthetic fuel tax credits may be claimed.
Should the tax credits be denied on future audits, and Progress Energy fails to prevail through the IRS or legal process, there could be a significant tax liability owed for previously taken Section 29 credits, with a significant impact on earnings and cash flows. In management's opinion, Progress Energy is complying with all the necessary requirements to be allowed such credits under Section 29 and believes it is probable, although it cannot provide certainty, that it will prevail if challenged by the IRS on any credits taken.
Environmental Matters
The Company is subject to federal, state and local regulations addressing air and water quality, hazardous and solid waste management and other environmental matters.
Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. The lead or sole regulatory agency that is responsible for a particular former coal tar site depends largely upon the state in which the site is located. There are several manufactured gas plant (MGP) sites to which both electric utilities and the gas utility have some connection. In this regard, both electric utilities and the gas utility, with other potentially responsible parties, are participating in investigating and, if necessary, remediating former coal tar sites with several regulatory agencies, including, but not limited to, the U.S. Environmental Protection Agency (EPA), the Florida Department of Environmental Protection (FDEP) and the North Carolina Department of Environment and Natural Resources, Division of Waste Management (DWM). Although the electric utilities and gas utility may incur costs at these sites about which it has been notified, based upon current status of these sites, the Company does not expect those costs to be material to its consolidated financial position or results of operations. The Company has accrued amounts to address known costs at certain of these sites.
Both electric utilities, the gas utility and Progress Ventures are periodically notified by regulators such as the EPA and various state agencies of their involvement or potential involvement in sites, other than MGP sites, that may require investigation and/or remediation. Although Progress Energy's subsidiaries may incur costs at the sites about which they have been notified, based upon the current status of these sites, Progress Energy does not expect those costs to be material to the consolidated financial position or results of operations of the Company.
There has been and may be further proposed federal legislation requiring reductions in air emissions for nitrogen oxides, sulfur dioxide and mercury setting forth national caps and emission levels over an extended period of time. This national multi-pollutant approach would have significant costs which could be material to the Company's consolidated financial position or results of operations. Some companies may seek recovery of the related cost through rate adjustments or similar mechanisms. Progress Energy cannot predict the outcome of this matter.
The EPA has been conducting an enforcement initiative related to a number of coal-fired utility power plants in an effort to determine whether modifications at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. Both CP&L and Florida Power were asked to provide information to the EPA as part of this initiative and cooperated in providing the requested information. The EPA has initiated civil enforcement actions against other unaffiliated utilities as part of this initiative, some of which have resulted in settlement agreements calling for expenditures ranging from $1.0 billion to $1.4 billion. A utility that was not subject to a civil enforcement action settled its New Source Review issues with the EPA for $300 million. These settlement agreements have generally called for expenditures to be made over extended time periods, and some of the companies may seek recovery of the related cost through rate adjustments or similar mechanisms. Progress Energy cannot predict the outcome of this matter.
In 1998, the EPA published a final rule addressing the issue of regional transport of ozone. This rule is commonly known as the NOx SIP Call. The EPA's rule requires 23 jurisdictions, including North Carolina, South Carolina and Georgia, but not Florida, to further reduce nitrogen oxide emissions in order to attain a pre-set state NOx emission level by May 31, 2004. CP&L is evaluating necessary measures to comply with the rule and estimates its related capital expenditures to meet these measures in North and South Carolina could be approximately $370 million, which has not been adjusted for inflation. A portion of this amount that is committed to be spent from 2002 to 2004 is discussed in the "Investing Activities" section under LIQUIDITY AND CAPITAL RESOURCES above. Increased operation and maintenance costs relating to the NOx SIP Call are not expected to be material to Progress Energy's results of operations. Further controls are anticipated as electricity demand increases. Progress Energy cannot predict the outcome of this matter.
In July 1997, the EPA issued final regulations establishing a new eight-hour ozone standard. In October 1999, the District of Columbia Circuit Court of Appeals ruled against the EPA with regard to the federal eight-hour ozone standard. The U.S. Supreme Court has upheld, in part, the District of Columbia Circuit Court of Appeals decision. Further litigation and rulemaking are anticipated. North Carolina adopted the federal eight-hour ozone standard and is proceeding with the implementation process. North Carolina has promulgated final regulations, which will require CP&L to install nitrogen oxide controls under the State's eight-hour standard. The cost of those controls are included in the cost estimate of $370 million set forth above.
The EPA published a final rule approving petitions under Section 126 of the Clean Air Act, which requires certain sources to make reductions in nitrogen oxide emissions by May 1, 2003. The final rule also includes a set of regulations that affect nitrogen oxide emissions from sources included in the petitions. The North Carolina fossil-fueled electric generating plants are included in these petitions. Acceptable state plans under the NOx SIP Call can be approved in lieu of the final rules the EPA approved as part of the 126 petitions. CP&L, other utilities, trade organizations and other states participated in litigation challenging the EPA's action. On May 15, 2001, the District of Columbia Circuit Court of Appeals ruled in favor of the EPA, which will require North Carolina to make reductions in nitrogen oxide emissions by May 1, 2003. However, the Court in its May 15th decision rejected the EPA's methodology for estimating the future growth factors the EPA used in calculating the emissions limits for utilities. In August 2001, the Court granted a request by CP&L and other utilities to delay the implementation of the 126 Rule for electric generating units pending resolution by the EPA of the growth factor issue. The Court's order tolls the three-year compliance period (originally set to end on May 1, 2003) for electric generating units as of May 15, 2001. On January 16, 2002, the EPA issued a memo to harmonize the compliance dates for the Section 126 Rule and the NOx SIP Call. The new compliance date for all affected sources is now May 31, 2004, rather than May 1, 2003, subject to the completion of the EPA's response to the related court decision on the growth factor issue. Progress Energy cannot predict the outcome of this matter.
On November 1, 2001, Progress Energy completed the sale of the Inland Marine Transportation segment to AEP Resources, Inc. In connection with the sale, Progress Energy entered into environmental indemnification provisions covering both unknown and known sites. Progress Energy has recorded an accrual to cover estimated probable future environmental expenditures. Progress Energy believes that it is reasonably possible that additional costs, which cannot be currently estimated, may be incurred related to the environmental indemnification provision beyond the amounts accrued. Progress Energy cannot predict the outcome of this matter.
Both electric utilities, the gas utility and Progress Ventures have filed claims with the Company's general liability insurance carriers to recover costs arising out of actual or potential environmental liabilities. Some claims have been settled and others are still pending. While management cannot predict the outcome of these matters, the outcome is not expected to have a material effect on the consolidated financial position or results of operations.
New Accounting Standards
See Note 1L to the Progress Energy consolidated financial statements for a discussion of the impact of new accounting standards.
CAROLINA POWER & LIGHT COMPANY - ------------------------------
The information required by this item is incorporated herein by reference to the following portions of Progress Energy's Management's Discussion and Analysis of Financial Condition and Results of Operations, insofar as they relate to CP&L: RESULTS OF OPERATIONS; LIQUIDITY AND CAPITAL RESOURCES; FUTURE OUTLOOK and OTHER MATTERS.
RESULTS OF OPERATIONS - ---------------------
Note 1 to the CP&L consolidated financial statements discusses its significant accounting policies. The most critical accounting policies and estimates that impact CP&L's financial statements are the economic impacts of utility regulation, which are described in more detail in Note 8 to the CP&L consolidated financial statements.
On July 1, 2000, CP&L distributed its ownership interest in the stock of NCNG, SRS, Monroe Power and Progress Ventures, Inc. to Progress Energy. Prior to that date, the consolidated operations of CP&L and Progress Energy were substantially the same. Subsequent to that date, the operations of these subsidiaries are no longer included in CP&L's results of operations and financial position.
The results of operations for CP&L and Progress Energy are substantially the same for 1999. Additionally, the results of operations for the CP&L Electric segment are identical between CP&L and Progress Energy for all periods presented. The primary difference between the results of operations of the CP&L Electric segment and the consolidated CP&L results of operations for the 1999, 2000 and 2001 comparison period relate to the non-electric operations.
CP&L's non-electric operations for 2000 include a full year of operations for Caronet. Therefore, the $121.1 million after-tax gain from the sale of the BellSouth PCS assets in September 2000 (see Note 2B to the CP&L consolidated financial statements) is included in CP&L's results of operations. However, CP&L's other segment only includes six months of operations for NCNG, SRS, Monroe Power and Progress Ventures, Inc. and therefore a comparison to the prior period is not meaningful.
CP&L's non-electric operations for 2001 include an after-tax impairment of $102.4 million for other than temporary declines in CP&L's investment in Interpath.
LIQUIDITY AND CAPITAL RESOURCES - -------------------------------
The statement of cash flows for CP&L does not include amounts related to NCNG, SRS, Monroe Power and Progress Ventures, Inc. after July 1, 2000. Additionally, the CP&L statement of cash flows does not include any amounts related to the acquisition of FPC and the issuance of debt to consummate the transaction.
CP&L's estimated capital requirements for 2002, 2003 and 2004 are $688 million, $676 million and $745 million, respectively, and primarily reflect construction expenditures to add regulated generation and upgrade existing facilities.
See Note 5 to the CP&L consolidated financial statements for information on CP&L's available credit facilities at December 31, 2001, and the discussion above for Progress Energy under "Financing Activities" for information regarding CP&L's financing activities.
The following tables reflect CP&L's contractual cash obligations and other commercial commitments in the respective periods in which they are due.
Information on the CP&L's contractual obligations at December 31, 2001, is included in the notes to the CP&L consolidated financial statements. Future debt maturities and lease obligations are included in Note 5 and Note 6, respectively. The Company's fuel and purchased power obligations are included in Note 15A to the CP&L consolidated financial statements.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK - -------------------------------------------------------------------
PROGRESS ENERGY, INC. - ---------------------
Market risk represents the potential loss arising from adverse changes in market rates and prices. Certain market risks are inherent in the Company's financial instruments, which arise from transactions entered into in the normal course of business. The Company's primary exposures are changes in interest rates with respect to its long-term debt and commercial paper, and fluctuations in the return on marketable securities with respect to its nuclear decommissioning trust funds. The Company manages its market risk in accordance with its established risk management policies, which may include entering into various derivative transactions.
These financial instruments are held for purposes other than trading. The fair value of the Company's open trading positions was less than $0.2 million at December 31, 2001. The risks discussed below do not include the price risks associated with non-financial instrument transactions and positions associated with the Company's operations, such as purchase and sales commitments and inventory.
Interest Rate Risk
The Company manages its interest rate risks through the use of a combination of fixed and variable rate debt. Variable rate debt has rates that adjust in periods ranging from daily to monthly. Interest rate derivative instruments may be used to adjust interest rate exposures and to protect against adverse movements in rates.
The following tables provide information as of December 31, 2001 and 2000, about the Company's interest rate risk sensitive instruments. The tables present principal cash flows and weighted-average interest rates by expected maturity dates for the fixed and variable rate long-term debt, commercial paper, FPC obligated mandatorily redeemable securities of trust, and other short-term indebtedness. The tables also include estimates of the fair value of the Company's interest rate risk sensitive instruments based on quoted market prices for these or similar issues. For interest-rate swaps and interest-rate forward contracts, the tables present notional amounts and weighted-average interest rates by contractual maturity dates. Notional amounts are used to calculate the contractual cash flows to be exchanged under the interest-rate swaps and the settlement amounts under the interest-rate forward contracts.
/(a)/ Fair value includes accrued interest /(b)/ Excludes short-term commercial paper /(c)/ Receives floating rate based on three-month LIBOR and pays fixed rate of 7.17%. Designated as a hedge of interest payments on $500 million of Extendible notes. /(d)/ In March 2002, $800 million of fixed rate debt was converted into variable rate debt through interest rate derivative agreements that receives fixed rate of 4.87% and pays floating rate based on three-month LIBOR.
/(a)/ Fair value includes accrued interest /(b)/ Excludes short-term commercial paper /(c)/ Receives floating rate based on three-month LIBOR and pays fixed rate of 7.17%. Designated as a hedge of interest payments on $500 million of Extendible notes. /(d)/ Receives floating rate based on three-month LIBOR and pays weighted-average fixed rates of approximately 6.77%
Marketable Securities Price Risk
The Company's electric utility subsidiaries maintain trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning their nuclear plants. These funds are primarily invested in stocks, bonds and cash equivalents, which are exposed to price fluctuations in equity markets and to changes in interest rates. The fair value of these funds was $822.8 million and $812.0 million at December 31, 2001 and 2000, respectively. Of these amounts, $416.7 million and $411.3 million, respectively, relate to CP&L. The Company actively monitors its portfolio by benchmarking the performance of its investments against certain indices and by maintaining, and periodically reviewing, target allocation percentages for various asset classes. The accounting for nuclear decommissioning recognizes that the Company's regulated electric rates provide for recovery of these costs net of any trust fund earnings and, therefore, fluctuations in trust fund marketable security returns do not affect the earnings of the Company.
CVO Market Value Risk
In connection with the acquisition of FPC, the Company issued 98.6 million CVOs. Each CVO represents the right to receive contingent payments based on the performance of four synthetic fuel facilities purchased by subsidiaries of FPC in October 1999. The payments, if any, are based on the net after-tax cash flows the facilities generate. These CVOs are recorded at fair value and unrealized gains and losses from changes in fair value are recognized in earnings. At December 31, 2001, the fair value of these CVOs was $41.9 million. A hypothetical 10% decrease in market price would result in a $4.2 million decrease in the fair value of the CVOs.
CAROLINA POWER & LIGHT COMPANY - ------------------------------
The information required by this item is incorporated herein by reference to the Progress Energy Quantitative and Qualitative Disclosures About Market Risk insofar as it relates to CP&L.
The following tables provide information as of December 31, 2001 and 2000, about CP&L's interest rate risk sensitive instruments.
/(a)/ Fair value includes accrued interest
/(b)/Receives floating rate based on three-month LIBOR and pays fixed rate of 7.17%. Designated as a hedge on $500 million of Extendible notes.
/(a)/ Fair value includes accrued interest /(b)/ Receives floating rate based on three-month LIBOR and pays fixed rate of 7.17%. Designated as a hedge on $500 million of Extendible notes.
ITEM 8.
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - ------ --------------------------------------------------------
The following consolidated financial statements, supplementary data and consolidated financial statement schedules are included herein:
All other schedules have been omitted as not applicable or not required or because the information required to be shown is included in the Consolidated Financial Statements or the accompanying Notes to the Consolidated Financial Statements.
INDEPENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.
We have audited the accompanying consolidated balance sheets of Progress Energy, Inc. and its subsidiaries (the Company) as of December 31, 2001 and 2000, and the related consolidated statements of income, changes in common stock equity and cash flows for each of the three years in the period ended December 31, 2001. Our audits also included the financial statement schedule listed in the Index at Item 8. These financial statements and the financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We did not audit the financial statements of Florida Progress Corporation (a consolidated subsidiary since November 30, 2000) for the year ended December 31, 2000, which statements reflect total assets constituting 31% of the related consolidated total assets at December 31, 2000. Those financial statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Florida Progress Corporation as of December 31, 2000, is based solely on the report of such other auditors.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 and the report of the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other auditors, such financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP Raleigh, North Carolina February 15, 2002
Independent Auditors' Report
To the Board of Directors of Florida Progress Corporation:
We have audited the consolidated balance sheet and schedule of capitalization of Florida Progress Corporation and subsidiaries as of December 31, 2000 (not separately presented herein). These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America. 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 audit provides a reasonable basis for our opinion.
The consolidated financial statements referred to in the introductory paragraph have been prepared based on the Company's historical cost basis and do not include any "push down" of Progress Energy, Inc.'s acquisition cost basis as a result of Progress Energy, Inc.'s acquisition of the Company on November 30, 2000.
In our opinion, the consolidated balance sheet and schedule of capitalization present fairly, in all material respects, the financial position of Florida Progress Corporation and subsidiaries as of December 31, 2000, in conformity with accounting principles generally accepted in the United States of America.
/s/KPMG LLP St. Petersburg, Florida February 15, 2001
PROGRESS ENERGY, INC. CONSOLIDATED STATEMENTS of INCOME - ---------------------------------
See Notes to Progress Energy, Inc. consolidated financial statements.
PROGRESS ENERGY, INC. CONSOLIDATED BALANCE SHEETS - ---------------------------
See Notes to Progress energy, Inc. consolidated financial statements.
PROGRESS ENERGY, INC. CONSOLIDATED STATEMENTS of CASH FLOWS - -------------------------------------
Noncash Activities
. On July 15, 1999, the Company purchased all outstanding shares of North Carolina Natural Gas Corporation (NCNG) through the issuance of approximately $360 million in common stock. . On June 28, 2000, Caronet, a wholly owned subsidiary of the Company, contributed net assets in the amount of $93.0 million in exchange for a 35% ownership interest (15% voting interest) in a newly formed company. . On November 30, 2000, the Company purchased all outstanding shares of Florida Progress Corporation (FPC). In conjunction with the purchase of FPC, the Company issued approximately $1.9 billion in common stock and approximately $49.3 million in contingent value obligations.
See Notes to Progress Energy, Inc. consolidated financial statements.
PROGRESS ENERGY, INC. CONSOLIDATED STATEMENTS of CHANGES IN COMMON STOCK EQUITY ---------------------------------------------------------
CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED) -------------------------------------------------
(a) In the opinion of management, all adjustments necessary to fairly present amounts shown for interim periods have been made. Results of operations for an interim period may not give a true indication of results for the year. (b) Includes gain on sale of BellSouth Carolinas PCS Partnership interest. (c) Includes approved further accelerated depreciation of $125 million on nuclear generating assets. (d) Includes impairment and other one-time charges relating to SRS and Interpath of $152.8 million, after tax. (e) Includes seven months of revenue related to Progress Rail Services due to reversal of Net Assets Held for Sale accounting treatment.
See Notes to Progress Energy, Inc. consolidated financial statements.
PROGRESS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
A. Organization
Progress Energy, Inc. (the Company) is a registered holding company under the Public Utility Holding Company Act (PUHCA) of 1935, as amended. Both the Company and its subsidiaries are subject to the regulatory provisions of the PUHCA. The Company was formed as a result of the reorganization of Carolina Power & Light Company (CP&L) into a holding company structure on June 19, 2000. All shares of common stock of CP&L were exchanged for an equal number of shares of the Company. On December 4, 2000, the Company changed its name from CP&L Energy, Inc. to Progress Energy, Inc. Through its wholly owned subsidiaries, CP&L, Florida Power Corporation (Florida Power) and North Carolina Natural Gas Corporation (NCNG), the Company is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina, South Carolina and Florida and the transport, distribution and sale of natural gas in portions of North Carolina. Through the Progress Ventures business unit, the Company is involved in merchant energy generation, coal and synthetic fuel operations and energy marketing and trading. Through other business units, the Company engages in other non-regulated business areas, including energy management and related services, rail services and telecommunications.
The Company's results of operations include the results of Florida Progress Corporation for the periods subsequent to November 30, 2000, and of North Carolina Natural Gas Corporation for the periods subsequent to July 15, 1999 (See Note 2).
B. Basis of Presentation
The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America and include the activities of the Company and its majority-owned subsidiaries. Significant intercompany balances and transactions have been eliminated in consolidation except as permitted by Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," which provides that profits on intercompany sales to regulated affiliates are not eliminated if the sales price is reasonable and the future recovery of the sales price through the rate making process is probable. The accounting records of CP&L, Florida Power and NCNG (collectively, "the utilities") are maintained in accordance with uniform systems of accounts prescribed by the Federal Energy Regulatory Commission (FERC), the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (SCPSC) and the Florida Public Service Commission (FPSC). Certain amounts for 2000 and 1999 have been reclassified to conform to the 2001 presentation.
Unconsolidated investments in companies over which the Company does not have control, but have the ability to exercise influence over operating and financial policies (generally, 20% - 50% ownership) are accounted for under the equity method of accounting. Other investments are stated principally at cost. These investments, which total approximately $160 million at December 31, 2001, are included as miscellaneous other property and investments in the Consolidated Balance Sheets.
C. Use of Estimates and Assumptions
In preparing consolidated financial statements that conform with accounting principles generally accepted in the United States of America, 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 consolidated financial statements and amounts of revenues and expenses reflected during the reporting period. Actual results could differ from those estimates.
D. Inventory
Inventory is carried at average cost. As of December 31, 2001 and 2000, inventory was comprised of (in thousands):
2001 2000 -------- --------
Fuel $305,858 $150,786 Rail equipment and parts 200,697 -- Materials and supplies 354,587 269,546 Other 25,605 653 -------- -------- Inventory $886,747 $420,985 ======== ========
E. Utility Plant
The cost of additions, including betterments and replacements of units of property, is charged to utility plant. Maintenance and repairs of property, and replacements and renewals of items determined to be less than units of property, are charged to maintenance expense. The cost of units of property replaced, renewed or retired, plus removal or disposal costs, less salvage, is charged to accumulated depreciation. Subsequent to the acquisitions of Florida Progress Corporation and NCNG, the utility plants of these entities continue to be presented on a gross basis to reflect the treatment of such plant in cost-based regulation. Generally, electric utility plant other than nuclear fuel is pledged as collateral for the first mortgage bonds of CP&L and Florida Power. Gas utility plant is not currently pledged as collateral for such bonds.
The balances of utility plant in service at December 31 are listed below (in thousands), with a range of depreciable lives for each:
2001 2000 ----------- ----------- Electric Production plant (7-33 years) $10,670,717 $10,014,635 Transmission plant (30-75 years) 2,013,243 1,964,652 Distribution plant (12-50 years) 5,767,788 5,292,134 General plant and other (8-75 years) 724,273 852,615 ----------- ----------- Total electric utility plant 19,176,021 18,124,036 Gas plant (10-40 years) 491,903 378,464 ----------- -----------
Utility plant in service $19,667,924 $18,502,500 =========== ===========
As prescribed in the regulatory uniform systems of accounts, an allowance for the cost of borrowed and equity funds used to finance utility plant construction (AFUDC) is charged to the cost of the plant. Regulatory authorities consider AFUDC an appropriate charge for inclusion in the rates charged to customers by the utilities 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 total equity funds portion of AFUDC was $10.9 million, $15.5 million and $3.9 million in 2001, 2000 and 1999, respectively. The composite AFUDC rate for CP&L's electric utility plant was 6.2%, 8.2% and 6.4% in 2001, 2000 and 1999, respectively. The composite AFUDC rate for Florida Power's electric utility plant was 7.8% in both 2001 and 2000. The composite AFUDC rate for NCNG's gas utility plant was 10.09% in 2001, 2000 and 1999.
F. Diversified Business Property
The following is a summary of diversified business property (in thousands):
2001 2000 ---------- ---------
Equipment $ 184,353 $ 109,080 Land and mineral rights 154,728 96,803 Buildings and plants 291,550 231,219 Telecommunications equipment 266,603 192,727 Railcars 56,044 -- Marine equipment 78,868 73,289 Computers, office equipment and software 14,150 23,065 Construction work in progress 342,830 234,689 Accumulated depreciation (316,080) (231,210) ---------- ---------
Diversified business property, net $1,073,046 $ 729,662 ========== =========
Diversified business property is stated at cost. Depreciation is computed on a straight-line basis using the following estimated useful lives: equipment, buildings and plants - 3 to 40 years; telecommunications equipment - 5 to 20 years; computers, office equipment and software - 3 to 10 years; railcars - 3 to 20 years; and marine equipment - 3 to 35 years. Depletion of mineral rights is provided on the units-of-production method based upon the estimates of recoverable amounts of clean mineral.
G. Depreciation and Amortization
For financial reporting purposes, substantially all 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 1I) and excluding accelerated cost recovery of nuclear generating assets, as a percent of average depreciable property other than nuclear fuel, were approximately 4.0%, 4.1% and 3.9% in 2001, 2000 and 1999, respectively. Total depreciation provisions were $821.2 million, $721.0 million and $409.6 million in 2001, 2000 and 1999, respectively.
Depreciation and amortization expense also includes amortization of deferred operation and maintenance expenses associated with Hurricane Fran, which struck significant portions of CP&L's service territory in September 1996. In 1996, the NCUC authorized CP&L to defer these expenses (approximately $40 million) with amortization over a 40-month period, which expired in December 1999.
With approval from the NCUC and the SCPSC, CP&L accelerated the cost recovery of its nuclear generating assets beginning January 1, 2000 and continuing through 2004. Also in 2000, CP&L received approval from the commissions to further accelerate the cost recovery of its nuclear generation facilities in 2000. The accelerated cost recovery of these assets resulted in additional depreciation expense of approximately $75 million and $275 million in 2001 and 2000, respectively (See Note 13B). Pursuant to authorizations from the NCUC and the SCPSC, CP&L accelerated the amortization of certain regulatory assets over a three-year period beginning January 1997 and expiring December 1999. The accelerated amortization of these regulatory assets resulted in additional depreciation and amortization expenses of approximately $68 million in 1999.
Amortization of nuclear fuel costs, including disposal costs associated with obligations to the U.S. Department of Energy (DOE) and costs associated with obligations to the DOE for the decommissioning and decontamination of enrichment facilities, is computed primarily on the unit-of-production method and charged to fuel expense. The total of these costs for the years ended December 31, 2001, 2000 and 1999 were $130.1 million, $114.6 million and $110.8 million, respectively.
Goodwill, the excess of purchase price over fair value of net assets of businesses acquired, is being amortized on a straight-line basis over primarily 40 years. Goodwill amortization expense was $96.8 million, $16.7 million, and $4.0 million in 2001, 2000 and 1999, respectively. Accumulated amortization was $119.0 million and $24.2 million at December 31, 2001 and 2000, respectively. Effective January 1, 2002, goodwill will no longer be subject to amortization over its estimated useful life, but instead, will be subject to an annual test for impairment (See Note 1L).
H. Diversified Business Expenses
The major components of diversified business expenses for the years ended December 31, 2001, 2000 and 1999 are as follows (in thousands):
2001 2000 1999 ---------- -------- --------
Cost of sales $1,403,434 $ 80,744 $100,776 Depreciation and amortization 86,741 33,139 17,051 General and administrative expenses 279,115 234,132 56,692 Impairment of assets (Note 1J) 44,800 -- -- Other 11,230 4,977 70 ---------- -------- -------- Diversified Business Expenses $1,825,320 $352,992 $174,589 ========== ======== ========
I. Decommissioning and Dismantlement Provisions
In the Company's retail jurisdictions, provisions for nuclear decommissioning costs are approved by the NCUC, the SCPSC and the FPSC and are based on site-specific estimates that include the costs for removal of all radioactive and other structures at the site. In the wholesale jurisdictions, the provisions for nuclear decommissioning costs are approved by FERC. Decommissioning cost provisions, which are included in depreciation and amortization expense, were $38.5 million, $32.5 million and $33.3 million in 2001, 2000 and 1999, respectively. In January 2002, Florida Power received regulatory approval from the FPSC to decrease its retail provision for nuclear decommissioning from approximately $20.5 million annually to approximately $7.7 million annually, effective January 1, 2001.
Accumulated decommissioning costs, which are included in accumulated depreciation, were approximately $1.0 billion at both December 31, 2001 and 2000. These costs include amounts retained internally and amounts funded
in externally managed decommissioning trusts. Trust earnings increase the trust balance with a corresponding increase in the accumulated decommissioning balance. These balances are adjusted for net unrealized gains and losses related to changes in the fair value of trust assets.
CP&L's most recent site-specific estimates of decommissioning costs were developed in 1998, using 1998 cost factors, and are based on prompt dismantlement decommissioning, which reflects the cost of removal of all radioactive and other structures currently at the site, with such removal occurring shortly after operating license expiration. These estimates, in 1998 dollars, are $281.5 million for Robinson Unit No. 2, $299.6 million for Brunswick Unit No. 1, $298.7 million for Brunswick Unit No. 2 and $328.1 million for the Harris Plant. The estimates are subject to change based on a variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning and changes in federal, state or local regulations. The cost estimates exclude the portion attributable to North Carolina Eastern Municipal Power Agency (Power Agency), which holds an undivided ownership interest in the Brunswick and Harris nuclear generating facilities. Operating licenses for CP&L'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.
Florida Power's most recent site-specific estimate of decommissioning costs for the Crystal River Nuclear Plant (CR3) was developed in 2000 based on prompt dismantlement decommissioning. The estimate, in 2000 dollars, is $490.9 million and is subject to change based on the same factors as discussed above for CP&L's estimates. The cost estimate excludes the portion attributable to other co-owners of CR3. CR3's operating license expires in 2016.
Management believes that the decommissioning costs being recovered through rates by CP&L and Florida Power, when coupled with reasonable assumed after-tax fund earnings rates, are currently sufficient to provide for the costs of decommissioning.
Florida Power maintains a reserve for fossil plant dismantlement. At December 31, 2001 and 2000, this reserve was approximately $140.5 million and $134.6 million, respectively, and was included in accumulated depreciation. The provision for fossil plant dismantlement was previously suspended per a 1997 FPSC settlement agreement, but resumed mid-2001. The current annual provision, approved by the FPSC, is $8.8 million.
The Financial Accounting Standards Board (FASB) has issued SFAS No. 143, "Accounting for Asset Retirement Obligations" that will impact the accounting for decommissioning and dismantlement provisions (See Note 1L).
J. Impairment of Long-lived Assets and Investments
SFAS No. 121 " Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to Be Disposed Of" requires review of long-lived assets and certain intangibles for impairment when events or circumstances indicate that the carrying value of an asset may not be recoverable. Any impairment losses are reported in the period in which the recognition criteria are first applied based on the fair value of the asset. Due to historical and current year losses at Strategic Resource Solutions, Inc. (SRS) and the decline in the market value for technology companies, the Company has evaluated the long-lived assets of SRS. Fair value was generally determined based on discounted cash flows. As a result of this review, the Company recorded asset impairments, primarily goodwill, and other one-time charges totaling $44.8 million on a pre-tax basis during the fourth quarter of 2001 related to SRS. Asset write-downs resulting from this review were charged to diversified business expenses on the Consolidated Statements of Income.
The Company continually reviews its investments to determine whether a decline in fair value below the cost basis is other-than-temporary. Effective June 28, 2000, a subsidiary of the Company contributed the net assets used in its application service provider business to a newly formed company (Interpath) for a 35% ownership interest (15% voting interest). The Company obtained a valuation study to assess its investment in Interpath based on current valuations in the technology sector. As a result, the Company has recorded investment impairments for other-than-temporary declines in the fair value of its investment in Interpath. Investment impairments were also recorded related to certain investments of SRS. Investment write-downs totaled $164.2 million on a pre-tax basis for the year ended December 31, 2001.
K. Other Policies
The Company recognizes electric utility revenues as service is rendered to customers. Operating revenues include unbilled electric utility revenues earned when service has been delivered but not billed by the end of the accounting period. Diversified business revenues are generally recognized at the time products are shipped or as services are rendered. Leasing activities are accounted for in accordance with SFAS No. 13, "Accounting for Leases."
Fuel expense includes fuel costs or recoveries that are deferred through fuel clauses established by the electric utilities' regulators. These clauses allow the utilities to recover fuel costs and portions of purchased power costs
through surcharges on customer rates. NCNG is also allowed to recover the costs of gas purchased for resale through customer rates.
Operations of Progress Rail Services Corporation and certain other diversified operations are recognized one-month in arrears.
The Company maintains an allowance for doubtful accounts receivable, which totaled approximately $40.7 million and $28.1 million at December 31, 2001 and 2000, respectively. Long-term debt premiums, discounts and issuance expenses for the utilities 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 by the utilities are amortized over the remaining life of the original debt using the straight-line method. The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents.
L. Impact of New Accounting Standards
Effective January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138. SFAS No. 133, as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 requires that an entity recognize all derivatives as assets or liabilities in the balance sheet and measure those instruments at fair value.
As a result of the adoption of SFAS No. 133, the Company recorded a transition adjustment as a cumulative effect of a change in accounting principle of $23.6 million, net of tax, which increased accumulated other comprehensive loss as of January 1, 2001. This amount relates to several derivatives used to hedge cash flows related to interest on long-term debt (See Note 14). The net derivative losses will be reclassified into earnings consistent with hedge designations, primarily over the life of the related debt instruments, which principally range from three to ten years. The Company estimates that approximately $15.5 million of the net losses at December 31, 2001 will be reclassified into earnings during 2002. There was no transition adjustment affecting the Consolidated Statements of Income as a result of the adoption of SFAS No. 133.
During the second quarter of 2001, the FASB issued interpretations of SFAS No. 133 indicating that options in general cannot qualify for the normal purchases and sales exception, but provided an exception that allows certain electricity contracts, including certain capacity-energy contracts, to be excluded from the mark-to-market requirements of SFAS No. 133. The interpretations were effective July 1, 2001. Those interpretations did not require the Company to mark-to-market any of its electricity capacity-energy contracts currently outstanding. In December 2001, the FASB revised the criteria related to the exception for certain electricity contracts, with the revision to be effective April 1, 2002. The Company does not expect the revised interpretation to change its assessment of mark-to-market requirements for its current contracts. If an electricity or fuel supply contract in its regulated businesses is subject to mark-to-market accounting, there would be no income statement effect of the mark-to-market because the contract's mark-to-market gain or loss will be recorded as a regulatory asset or liability. Any mark-to-market gains or losses in its non-regulated businesses will affect income unless those contracts qualify for hedge accounting treatment.
The application of the new rules is still evolving, and further guidance from the FASB is expected, which could additionally impact the Company's financial statements.
Effective January 1, 2002, the Company adopted SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets." These statements require that all business combinations initiated after June 30, 2001 be accounted for using the purchase method of accounting and clarifies the criteria for recording of other intangible assets separately from goodwill. Effective January 1, 2002, goodwill is no longer subject to amortization over its estimated useful life. Instead, goodwill is subject to at least an annual assessment for impairment by applying a fair-value based test. This assessment could result in periodic impairment charges. The Company has not yet determined whether its goodwill is impaired under the initial impairment test required.
The FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" in July 2001. This statement provides accounting requirements for retirement obligations associated with tangible long-lived assets and is effective January 1, 2003. This statement requires that the present value of retirement costs for which the Company has a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The Company is currently assessing the effects this statement may ultimately have on the Company's accounting for decommissioning, dismantlement and other retirement costs.
Effective January 1, 2002, the Company adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 provides guidance for the accounting and reporting of impairment or disposal of long-lived assets. The statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." It also supersedes the accounting and reporting provisions of APB Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" related to the disposal of a segment of a business. Adoption of this statement did not have a material effect on the Company's financial statements.
2. Acquisitions and Dispositions
A. Florida Progress Corporation
On November 30, 2000, the Company completed its acquisition of Florida Progress Corporation (FPC) for an aggregate purchase price of approximately $5.4 billion. The Company paid cash consideration of approximately $3.5 billion and issued 46.5 million common shares valued at approximately $1.9 billion. In addition, the Company issued 98.6 million contingent value obligations (CVO) valued at approximately $49.3 million (See Note 8). The purchase price includes $20.1 million in direct transaction costs.
FPC is a diversified, exempt electric utility holding company. Florida Power, FPC's largest subsidiary is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity. FPC also has diversified non-utility operations owned through Progress Capital Holdings, Inc. Included in diversified operations are Progress Fuels Corporation, an energy and transportation company, and Progress Telecommunications Corporation, a wholesale telecommunications service provider. As of the acquisition date, the primary segments of Progress Fuels Corporation were energy and related services, rail services and inland marine transportation.
The acquisition was accounted for using the purchase method of accounting and, accordingly, the results of operations for FPC have been included in the Company's consolidated financial statements since the date of acquisition. Identifiable assets acquired and liabilities assumed have been recorded at their fair values of $6.7 billion and $4.9 billion, respectively. The excess of the purchase price over the fair value of the net identifiable assets and liabilities acquired has been recorded as goodwill. The goodwill, of approximately $3.6 billion, was being amortized on a straight-line basis over a period of 40 years. Effective January 1, 2002, goodwill is no longer subject to amortization (See Note 1L).
The fair values of FPC's rate-regulated net assets acquired were considered to be equivalent to book value since book value represents the amount that will be recoverable through regulated rates. Initially, the allocation of the purchase price included estimated amounts expected to be realized from the sale of FPC's Rail Services ("Rail Services") and Inland Marine Transportation business segments which were classified as net assets held for sale. During 2001, the Company announced its intention to retain the Rail Services segment within the allocation period and, therefore, these assets were reclassified to operating assets. Accordingly, the Company has made adjustments to the purchase price allocation to remove Rail Services from net assets held for sale and reflect the net realizable value from the disposition of FPC's Inland Marine Transportation business segment (See Note 4). An SEC order approving the merger requires the Company to divest of Rail Services and certain immaterial, non-regulated investments of FPC by November 30, 2003.
The company made adjustments during 2001 to the purchase price allocation for changes in preliminary assumptions and analyses, based on receipt of the following additional information:
. final actuarial valuations of pension plan obligations . proceeds realized from the disposition of assets held for sale . valuations of non-regulated businesses and individual assets and liabilities
The original allocation of purchase price included the assumption of liabilities associated with change in control payments triggered by the acquisition and executive termination benefits, totaling approximately $50.8 million. Substantially all change in control and executive termination payments were paid as of December 31, 2000. During 2000, the Company began the implementation of a plan to combine operations of the companies resulting in an original non-executive involuntary termination cost accrual of approximately $52.2 million. Approximately $41.8 million was attributable to Florida Power employees and was reflected as part of the purchase price allocation, while approximately $10.4 million attributable to the acquiring company's employees was charged to operating results in 2000. During 2001, the Company finalized the plan to combine operations of the companies with final termination payments occurring in 2002.
The activity for the non-executive involuntary termination costs is detailed in the table below:
(in millions) 2001 ------ Balance at January 1 $ 52.2 Payments (33.1) Adjustments credited to operating results (4.8) Adjustments credited to purchase price allocation (6.1) ------ Balance at December 31 $ 8.2 ======
Actuarial valuations resulted in adjustments to increase the other postretirement benefits liability by $16.8 million and the prepaid pension asset by $283.4 million. These adjustments were substantially offset by the establishment of a regulatory asset for other postretirement benefits of approximately $15.9 million and a pension regulatory liability of $258.4 million. In addition, an adjustment increased the supplementary defined benefit retirement plan liability by $24.4 million.
The following unaudited pro forma combined results of operations have been prepared assuming the acquisition of FPC had occurred at the beginning of each period. The pro forma results are provided for information only. The pro forma results include the effect of 2001 purchase price allocation adjustments and, therefore, differ from previously reported pro forma results for the same periods. The results are not necessarily indicative of the actual results that would have been realized had the acquisition occurred on the indicated date, nor are they necessarily indicative of future results of operations of the combined companies.
(in thousands, except per share data) 2000 1999 ---------- ---------- Revenues $8,098,356 $7,083,641 Net income 575,112 451,455 Basic earnings per share 2.88 2.32 Diluted earnings per share 2.87 2.32 Average shares - Basic 199,722 194,591 Average shares - Diluted 200,177 194,966
B. North Carolina Natural Gas Corporation
On July 15, 1999, the Company completed the acquisition of NCNG for an aggregate purchase price of approximately $364 million, resulting in the issuance of approximately 8.3 million shares. The acquisition was accounted for as a purchase and, accordingly, the operating results of NCNG were included in the Company's consolidated financial statements beginning with the date of acquisition. The excess of the aggregate purchase price over the fair value of net assets acquired, approximately $240 million, was recorded as goodwill of the acquired business and is being amortized primarily over a period of 40 years. Effective January 1, 2002, goodwill will no longer be subject to amortization (See Note 1L).
C. BellSouth Carolinas PCS Partnership Interest
In September 2000, Caronet, Inc., a wholly owned subsidiary of CP&L, sold its 10% limited partnership interest in BellSouth Carolinas PCS for $200 million. The sale resulted in an after-tax gain of $121.1 million.
3. Financial Information by Business Segment
The Company currently provides services through the following business segments: CP&L Electric, Florida Power Electric, Progress Ventures, Rail Services and Other. Prior periods have been restated to reflect the current operating segments.
FPC's operations are not included in the Company's results of operations prior to the acquisition date of November 30, 2000.
The CP&L Electric and Florida Power Electric segments are engaged in the generation, transmission, distribution, and sale of electric energy in portions of North Carolina, South Carolina and Florida. Electric operations are subject to the rules and regulations of FERC, the NCUC, the SCPSC and the FPSC.
The Progress Ventures segment is primarily engaged in merchant energy generation and coal and synthetic fuel operations. Management reviews the operations of this segment after allocating energy marketing and trading activity to Progress Ventures. The energy marketing and trading activity is currently performed by Progress Ventures on behalf of the regulated utilities, CP&L and Florida Power, and includes wholesale sales on behalf of
these utilities. Electric wholesale operations are subject to the rules and regulations of FERC, the NCUC, the SCPSC and the FPSC.
The Rail Services segment operations include railcar repair, rail parts reconditioning and sales, railcar leasing and sales, providing rail and track material, and scrap metal recycling.
The Other segment is primarily made up of natural gas, other diversified businesses and holding company operations, which includes the transportation, distribution and sale of natural gas in portions of North Carolina, telecommunication services, energy management services, miscellaneous non-regulated activities and elimination entries.
For reportable segments presented in the accompanying table, segment income includes intersegment revenues accounted for at prices representative of unaffiliated party transactions. Intersegment revenues that are not eliminated represent natural gas sales to the CP&L Electric and the Florida Power Electric segments.
(a) Includes allocation of energy trading and marketing net income managed by Progress Ventures on behalf of the electric utilities.
(b) Amounts for the year ended December 31, 2001 reflect cumulative operating results of Rail Services since the acquisition date of November 30, 2000. As of December 31, 2000, the Rail Services segment was included as Net Assets Held for Sale and therefore no assets are reflected for this segment as of that date.
Segment totals for depreciation and amortization expense include expenses related to the Progress Ventures, Rail Services and the Other segment that are included in diversified business expenses on the Consolidated Statements of Income. Segment totals for interest expense exclude immaterial expenses related to the Progress Ventures, Rail Services and the Other segment that are included in other, net on the Consolidated Statements of Income.
4. Net Assets Held for Sale
The estimated amounts reported for the expected sale of FPC's Rail Services and Inland Marine Transportation business segments, $679.1 million and $68.6 million, respectively, were classified as net assets held for sale as of December 31, 2000. During 2001, the Company announced its intention to retain the Rail Services segment within the allocation period and, therefore, reclassified Rail Services' to operating assets. During 2001, the Company recorded an after-tax charge of $3.2 million reflecting the reversal of net assets held for sale accounting.
During 2001, the Company completed the sale of the Inland Marine Transportation segment and related investments to AEP Resources, Inc., a wholly owned subsidiary of American Electric Power, for a sales price of $270 million. Of the $270 million purchase price, $230 million was used to pay early termination of certain off-balance sheet arrangements for assets leased by the business segment. In connection with the sale, the Company entered into environmental indemnification provisions covering both known and unknown sites (See Note 20D).
The Company adjusted the FPC purchase price allocation to reflect a $15.0 million negative net realizable value of the Inland Marine business segment (See Note 2A). The Company's results of operations exclude Inland Marine Transportation segment net income of $9.1 million for 2001 and $1.8 million for the month of December 2000. These earnings were included in the determination of net realizable value for purchase price allocation. As a result of the change in net realizable value, the Company recorded interest expense in 2001, net of tax, of $0.3 million to reverse the interest allocated during 2000.
5. Related Party Transactions
Prior to the acquisition of FPC, the Company purchased a 90% membership interest in two synthetic fuel related limited liability companies from a wholly owned subsidiary of FPC. Interest expense incurred during the pre-acquisition period was approximately $3.3 million. Subsequent to the acquisition date, intercompany amounts have been eliminated in consolidation.
NCNG sells natural gas to both CP&L and Florida Power. For the years ended December 31, 2001, 2000 and 1999 sales of natural gas to CP&L and Florida Power that were not eliminated in consolidation were $18.7 million, $5.9 million and $1.0 million, respectively.
The Company and its subsidiaries have guarantees, surety bonds and stand by letters of credit of approximately $140.0 million at December 31, 2001 relating to prompt performance payments, lease obligations, self-insurance and other payments subject to certain contingencies. As of December 31, 2001, management does not believe conditions are likely for performance under these agreements.
6. Debt and Credit Facilities
At December 31, 2001 and 2000 the Company's long-term debt consisted of the following (maturities and weighted-average interest rates as of December 31, 2001):
At December 31, 2001, the Company had committed lines of credit totaling $1.945 billion, all of which are used to support its commercial paper borrowings. The Company is required to pay minimal annual commitment fees to maintain its credit facilities. The following table summarizes the Company's credit facilities:
As of December 31, 2001, there were no loans outstanding under these facilities. CP&L's 364-day revolving credit agreement is considered a long-term commitment due to an option to convert to a one-year term loan at the expiration date.
Based on the available balances on the long-term facilities, commercial paper of approximately $865 million has been reclassified to long-term debt at December 31, 2001. Commercial paper of approximately $986 million was reclassified to long-term debt at December 31, 2000. As of December 31, 2001 and 2000, the Company had an
additional $78 million and $4 billion, respectively, of outstanding commercial paper and other short-term debt classified as short-term obligations. The weighted-average interest rates of such short-term obligations at December 31, 2001 and 2000 were 2.95% and 7.40%, respectively.
Florida Power and Progress Capital Holdings, Inc. (Progress Capital), subsidiaries of FPC, have two uncommitted bank bid facilities authorizing them to borrow and re-borrow, and have loans outstanding at any time, up to $100 million and $300 million, respectively. These bank bid facilities were not drawn as of December 31, 2001.
The combined aggregate maturities of long-term debt for 2002 through 2006 are approximately $688 million, $698 million, $1.3 billion, $348 million, and $909 million, respectively.
7. FPC-Obligated Mandatorily Redeemable Preferred Securities of a Subsidiary Holding Solely FPC Guaranteed Notes
In April 1999, FPC Capital I (the Trust), an indirect wholly owned subsidiary of FPC, issued 12 million shares of $25 par cumulative FPC-obligated mandatorily redeemable preferred securities (Preferred Securities) due 2039, with an aggregate liquidation value of $300 million and a quarterly distribution rate of 7.10%. Currently, all 12 million shares of the Preferred Securities that were issued are outstanding. Concurrent with the issuance of the Preferred Securities, the Trust issued to Florida Progress Funding Corporation (Funding Corp.) all of the common securities of the Trust (371,135 shares) for $9.3 million. Funding Corp. is a direct wholly owned subsidiary of FPC.
The Preferred Securities are included in long-term debt on the Consolidated Balance Sheets (See Note 6). During 2001, an adjustment was recorded to the book value of the preferred securities resulting from fair value adjustments recorded under the purchase method of accounting. The fair value adjustment decreased the carrying value of these securities by $30.5 million.
The existence of the Trust is for the sole purpose of issuing the Preferred Securities and the common securities and using the proceeds thereof to purchase from Funding Corp. its 7.10% Junior Subordinated Deferrable Interest Notes (subordinated notes) due 2039, for a principal amount of $309.3 million. The subordinated notes and the Notes Guarantee (as discussed below) are the sole assets of the Trust. Funding Corp.'s proceeds from the sale of the subordinated notes were advanced to Progress Capital and used for general corporate purposes including the repayment of a portion of certain outstanding short-term bank loans and commercial paper.
FPC has fully and unconditionally guaranteed the obligations of Funding Corp. under the subordinated notes (the Notes Guarantee). In addition, FPC has guaranteed the payment of all distributions required to be made by the Trust, but only to the extent that the Trust has funds available for such distributions (Preferred Securities Guarantee). The Preferred Securities Guarantee, considered together with the Notes Guarantee, constitutes a full and unconditional guarantee by FPC of the Trust's obligations under the Preferred Securities.
The subordinated notes may be redeemed at the option of Funding Corp. beginning in 2004 at par value plus accrued interest through the redemption date. The proceeds of any redemption of the subordinated notes will be used by the Trust to redeem proportional amounts of the Preferred Securities and common securities in accordance with their terms. Upon liquidation or dissolution of Funding Corp., holders of the Preferred Securities would be entitled to the liquidation preference of $25 per share plus all accrued and unpaid dividends thereon to the date of payment.
8. Contingent Value Obligations
In connection with the acquisition of FPC during 2000, the Company issued 98.6 million CVOs. Each CVO represents the right to receive contingent payments based on the performance of four synthetic fuel facilities purchased by subsidiaries of FPC in October 1999. The payments, if any, would be based on the net after-tax cash flows the facilities generate. The initial liability recorded at the acquisition date was approximately $49.3 million. The CVO liability is adjusted to reflect market price fluctuations. The liability, included in other liabilities and deferred credits, at December 31, 2001 and 2000, was $41.9 million and $40.4 million, respectively.
9. Preferred Stock of Subsidiaries - Not Subject to Mandatory Redemption
All of the Company's preferred stock at December 31, 2001 and 2000 was issued by its subsidiaries and was not subject to mandatory redemption. Preferred stock outstanding of subsidiaries consisted of the following (in thousands, except share data):
10. Leases
The Company leases office buildings, computer equipment, vehicles, railcars and other property and equipment with various terms and expiration dates. Some rental payments for transportation equipment include minimum rentals plus contingent rentals based on mileage. Contingent rentals are not significant. Rent expense (under operating leases) totaled $62.6 million, $26.8 million and $21.3 million for 2001, 2000 and 1999, respectively.
Assets recorded under capital leases at December 31 consist of (in thousands):
2001 2000 ------- ------- Buildings $27,626 $27,626 Equipment 12,170 9,366 Less: Accumulated amortization (8,975) (8,018) ------- ------- $30,821 $28,974 ------- -------
Minimum annual rental payments, excluding executory costs such as property taxes, insurance and maintenance, under long-term noncancelable leases as of December 31, 2001 are (in thousands):
The Company is also a lessor of land, buildings, railcars and other types of properties it owns under operating leases with various terms and expiration dates. The leased buildings and railcars are depreciated under the same terms as other buildings and railcars included in diversified business property. Minimum rentals receivable under noncancelable leases as of December 31, 2001, are (in thousands):
Amounts ------- 2001 $12,190 2002 7,904 2003 5,591 2004 4,741 2005 3,766 Thereafter 9,222 ------- $43,414
11. Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents and short-term obligations approximate fair value due to the short maturities of these instruments. At December 31, 2001 and 2000, there were miscellaneous investments, consisting primarily of investments in company-owned life insurance, with carrying amounts of approximately $124.3 million and $187.8 million, respectively, included in miscellaneous other property and investments. The carrying amount of these investments approximates fair value due to the short maturity of certain instruments and certain instruments are presented at fair value. The carrying amount of the Company's long-term debt, including current maturities, was $10.2 billion and $6.1 billion at December 31, 2001 and 2000, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $10.6 billion and $6.0 billion at December 31, 2001 and 2000, respectively.
External funds have been established as a mechanism to fund certain costs of nuclear decommissioning (See Note 1I). These nuclear decommissioning trust funds are invested in stocks, bonds and cash equivalents. Nuclear decommissioning trust funds are presented on the Consolidated Balance Sheets at amounts that approximate fair value. Fair value is obtained from quoted market prices for the same or similar investments.
12. Common Stock
In August 2001, the Company issued 12.65 million shares of common stock at $40 per share for net cash proceeds of $488 million. Proceeds from the issuance were primarily used to retire commercial paper. During 2000 and 1999, the Company issued common stock in conjunction with the FPC and NCNG acquisitions, respectively (See Note 2).
As of December 31, 2001, the Company had 38,549,922 shares of common stock authorized by the board of directors that remained unissued and reserved, primarily to satisfy the requirements of the Company's stock plans. The Company intends, however, to meet the requirements of these stock plans with issued and outstanding shares presently held by the Trustee of the Progress Energy 401(k) Savings and Stock Ownership Plan (previously known as the Stock Purchase-Savings Plan) or with open market purchases of common stock shares, as appropriate.
There are various provisions limiting the use of retained earnings for the payment of dividends under certain circumstances. As of December 31, 2001, there were no significant restrictions on the use of retained earnings.
13. Regulatory Matters
A. Regulatory Assets and Liabilities
As regulated entities, the utilities are subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Accordingly, the utilities record 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. The utilities' ability to continue to meet the criteria for application of SFAS No. 71 may be affected in the future by competitive forces and restructuring in the electric utility industry. In the event that SFAS No. 71 no longer applied to a separable portion of the Company's operations, related regulatory assets and liabilities would be eliminated unless an appropriate regulatory recovery mechanism is provided. Additionally, these factors could result in an impairment of utility plant assets as determined pursuant to SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (See Note 1L).
At December 31, 2001 and 2000, the balances of the utilities' regulatory assets (liabilities) were as follows (in thousands):
Except for portions of deferred fuel, all regulatory assets earn a return or the cash has not yet been expended, in which case, the assets are offset by liabilities that do not incur a carrying cost.
B. Retail Rate Matters
The NCUC and SCPSC approved proposals to accelerate cost recovery of CP&L's nuclear generating assets beginning January 1, 2000, and continuing through 2004. The accelerated cost recovery began immediately after the 1999 expiration of the accelerated amortization of certain regulatory assets (See Note 1G). Pursuant to the orders, the accelerated depreciation expense for nuclear generating assets was set at a minimum of $106 million with a maximum of $150 million per year. In late 2000, CP&L received approval from the NCUC and the SCPSC to further accelerate the cost recovery of its nuclear generation facilities by $125 million in 2000. This additional depreciation allowed CP&L to reduce the minimum accelerated annual depreciation in 2001 through 2004 to $75 million. The resulting total accelerated depreciation was $75 million in 2001 and $275 million in 2000. Recovering the costs of its nuclear generating assets on an accelerated basis will better position CP&L for the uncertainties associated with potential restructuring of the electric utility industry.
In compliance with a regulatory order, Florida Power accrues a reserve for maintenance and refueling expenses anticipated to be incurred during scheduled nuclear plant outages.
On May 30, 2001, the NCUC issued an order allowing CP&L to offset a portion of its annual accelerated cost recovery of nuclear generating assets by the amount of sulfur dioxide (SO2) emission allowance expense. CP&L did not offset accelerated depreciation expense in 2001 against emission allowance expense. CP&L is allowed to recover emission allowance expense through the fuel clause adjustment in its South Carolina retail jurisdiction. Florida Power is also allowed to recover its emission allowance expenses through the fuel adjustment clause in its retail jurisdiction.
In conjunction with the acquisition of NCNG, CP&L agreed to cap base retail electric rates in North Carolina and South Carolina through December 2004. The cap on base retail electric rates in South Carolina was extended to December 2005 in conjunction with regulatory approval to form a holding company. NCNG also agreed to cap its North Carolina margin rates for gas sales and transportation services, with limited exceptions, through November 1, 2003. In February 2002, NCNG filed a general rate case with the NCUC requesting an annual rate increase of $47.6 million, based upon its completion of major expansion projects. The Company cannot predict the final outcome of this matter.
In conjunction with the FPC merger, CP&L reached a settlement with the Public Staff of the NCUC in which it agreed to reduce rates to all of its non-real time pricing customers by $3 million in 2002, $4.5 million in 2003, $6
million in 2004 and $6 million in 2005. CP&L also agreed to write off and forego recovery of $10 million of unrecovered fuel costs in each of its 2000 NCUC and SCPSC fuel cost recovery proceedings.
At December 31, 2000, Florida Power, with the approval of the FPSC, had established a regulatory liability to defer $63 million of revenues. In 2001, Florida Power applied the deferred revenues, plus accrued interest, to offset its regulatory asset related to deferred purchased power termination costs. In addition, Florida Power recorded accelerated amortization of $34.0 million to further offset this regulatory asset during 2001.
Florida Power previously operated under an agreement committing several parties not to seek any reduction in its base rates or authorized return on equity. During 2001, the FPSC required Florida Power to submit minimum filing requirements, based on a 2002 projected test year, to initiate a rate proceeding regarding its future base rates. The FPSC required that annual revenues of $98 million be held subject to refund to its customers. The FPSC may allow Florida Power to reduce the amount subject to refund if it is successful in recovering certain expenses incurred during 2001.
On September 14, 2001, Florida Power submitted its required rate filing, including its revenue requirements and supporting testimony. Under the filing, Florida Power customers would receive a $5 million annual credit rate for 15 years, or $75 million in total, from net synergies of its merger with the Company. Additionally, the filing provides that the regulatory asset (approximately $95 million at December 31, 2001) related to the purchase of Tiger Bay cogeneration facility in 1997 would be fully amortized by the end of 2003, which would provide customers with a further rate reduction of $37 million annually beginning in 2004. Also included in the filing is an incentive regulatory plan, which would provide for additional rate reductions through efficiencies derived as a result of Florida Power's ability to lower the future costs of its utility operations. Florida Power filed supplemental minimum filing requirements and testimony on November 15, 2001. Hearings are scheduled to begin March 20, 2002, with a final decision expected in July 2002. The FPSC has encouraged its staff, Florida Power and other parties to negotiate a settlement, if possible. The Company cannot predict the outcome or impact of these matters.
C. Plant-Related Deferred Costs
In 1988 rate orders, CP&L was ordered to remove from rate base and treat as abandoned plant certain costs related to the Harris Plant. Abandoned plant amortization related to the 1988 rate orders was completed in 1998 for the wholesale and North Carolina retail jurisdictions and in 1999 for the South Carolina retail jurisdiction. Amortization of plant abandonment costs is included in depreciation and amortization expense and totaled $15.0 million in 1999.
14. Risk Management Activities and Derivatives Transactions
The Company uses a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk if the counterparty fails to perform under the contract. The Company minimizes such risk by performing credit reviews using, among other things, publicly available credit ratings of such counterparties. Potential non-performance by counterparties is not expected to have a material effect on the consolidated financial position or consolidated results of operations of the Company.
The Company engages in limited energy trading activities to optimize the value of electricity and fuel contracts, as well as generating facilities. These activities are accounted for at fair value.
A. Commodity Derivatives - Non-Trading
The Company enters into certain forward contracts involving cash settlements or physical delivery that reduce the exposure to market fluctuations relative to the price and delivery of electric products. During 2001, 2000 and 1999, the Company principally sold electricity forward contracts, which can reduce price risk on the Company's available but unsold generation. While such contracts are deemed to be economic hedges, the Company no longer designates such contracts as hedges for accounting purposes; therefore, these contracts are carried on the balance sheet at fair value, with changes in fair value recognized in earnings. Gains and losses from such contracts were not material during 2001, 2000 and 1999. Also, the Company did not have material outstanding positions in such contracts at December 31, 2001 or 2000. Most of the Company's commodity contracts either are not derivatives pursuant to SFAS No. 133 or qualify as normal purchases or sales pursuant to SFAS No. 133. Therefore, such contracts are not recorded at fair value.
B. Commodity Derivatives - Trading
The Company from time to time engages in the trading of electricity commodity derivatives and, therefore, experiences net open positions. The Company manages open positions with strict policies which limit its exposure to market risk and require daily reporting to management of potential financial exposures. When such instruments are entered into for trading purposes, the instruments are carried on the balance sheet at fair value, with changes in fair value recognized in earnings. The net results of such contracts have not been material in any year and the Company did not have material outstanding positions in such contracts at December 31, 2001 or 2000.
C. Other Derivative Instruments
The Company may from time to time enter into derivative instruments to hedge interest rate risk or equity securities risk.
The Company has interest rate swap agreements to hedge its exposure on variable rate debt positions. The agreements, with a total notional amount of $500 million, were effective in July 2000 and mature in July 2002. Under these agreements, the Company receives a floating rate based on the three-month London Interbank Offered Rate (LIBOR) and pays a weighted-average fixed rate of approximately 7.17%. The fair value of the swaps was a $18.5 million liability position at December 31, 2001. Interest rate swaps are carried on the balance sheet at fair value with the unrealized gains or losses adjusted through other comprehensive income. As such, payments or receipts on interest rate swap agreements are recognized as adjustments to interest expense.
During 2000, the Company entered into forward starting swap agreements to hedge its exposure to interest rates with regard to future issuances of fixed-rate debt. The fair value of the swaps was a $37.5 million liability position at December 31, 2000. During February 2001, as part of the issuance of $3.2 billion of senior unsecured notes, the Company terminated the forward starting swaps. The Company realized a $45.3 million loss on these contracts, designated as cash flow hedges, that is deferred through accumulated other comprehensive loss and amortized over the life of the associated debt instruments.
The notional amounts of the interest rate swaps are not exchanged and do not represent exposure to credit loss. In the event of default by a counterparty, the risk in these transactions is the cost of replacing the agreements at current market rates.
15. Stock-Based Compensation
The Company accounts for stock-based compensation in accordance with the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations as permitted under SFAS No. 123, "Accounting for Stock-Based Compensation.
A. Employee Stock Ownership Plan
The Company sponsors the Progress Energy 401(k) Savings and Stock Ownership Plan (401(k)) for which substantially all full-time non-bargaining unit employees and certain part-time non-bargaining unit employees within participating subsidiaries are eligible. Participating subsidiaries within the Company as of January 1, 2002 were CP&L, NCNG, Florida Power, Progress Telecom, Progress Fuels (Corporate) and Progress Energy Service Company. The 401(k), which has Company matching and incentive goal features, encourages systematic savings by employees and provides a method of acquiring Company common stock and other diverse investments. The 401(k), as amended in 1989, is an Employee Stock Ownership Plan (ESOP) that can enter into acquisition loans to acquire Company common stock to satisfy 401(k) common share needs. Qualification as an ESOP did not change the level of benefits received by employees under the 401(k). Common stock acquired with the proceeds of an ESOP loan is held by the 401(k) Trustee in a suspense account. The common stock is released from the suspense account and made available for allocation to participants as the ESOP loan is repaid. Such allocations are used to partially meet common stock needs related to Company matching and incentive contributions and/or reinvested dividends. All or a portion of the dividends paid on ESOP suspense shares and on ESOP shares allocated to participants may be used to repay ESOP acquisition loans. To the extent used to repay such loans, the dividends are deductible for income tax purposes.
There were 5,199,388 and 5,782,376 ESOP suspense shares at December 31, 2001 and 2000, respectively, with a fair value of $234.1 million and $284.4 million, respectively. ESOP shares allocated to plan participants totaled 14,088,173 and 13,732,670 at December 31, 2001 and 2000, respectively. The Company's matching and incentive goal compensation cost under the 401(k) is determined based on matching percentages and incentive goal attainment as defined in the plan. Such compensation cost is allocated to participants' accounts in the form of Company
common stock, with the number of shares determined by dividing compensation cost by the common stock market value at the time of allocation. The Company currently meets common stock share needs with open market purchases and with shares released from the ESOP suspense account. Matching and incentive cost met with shares released from the suspense account totaled approximately $18.2 million, $15.6 million and $16.3 million for the years ended December 31, 2001, 2000 and 1999, respectively. The Company has a long-term note receivable from the 401(k) Trustee related to the purchase of common stock from the Company in 1989. The balance of the note receivable from the 401(k) Trustee is included in the determination of unearned ESOP common stock, which reduces common stock equity. ESOP shares that have not been committed to be released to participants' accounts are not considered outstanding for the determination of earnings per common share. Interest income on the note receivable and dividends on unallocated ESOP shares are not recognized for financial statement purposes.
B. Stock Option Agreements
Pursuant to the Company's 1997 Equity Incentive Plan, Amended and Restated as of September 26, 2001, the Company may grant options to purchase shares of common stock to officers and eligible employees. Generally, options granted vest one-third per year with 100 percent vesting at the end of year three. The options expire 10 years from the date of grant. All option grants have an exercise price equal to the fair market value of the Company's common stock on the grant date. In October 2001, a grant of approximately 2.4 million options was made at an exercise price of $43.49. There has been no other significant stock option activity.
Compensation cost is measured for stock options as the difference between the market price of the Company's common stock and the exercise price of the option at the grant date. Accordingly, no compensation expense has been recognized for the stock option granted.
Pro forma information regarding net income and earnings per share is required by SFAS No. 123. Under this statement, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the vesting period. The pro forma amounts have been determined as if the Company had accounted for its employee stock options under SFAS No. 123. The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions:
----- Risk-free interest rate (%) 4.83% Dividend yield (%) 5.21% Volatility factor (%) 26.47% Weighted-average expected life of the options (in years) 10
The option valuation model requires the input of highly subjective assumptions, primarily stock price volatility, changes in which can materially affect the fair value estimate. The weighted-average fair value of stock options granted during 2001 was approximately $8.00.
For purposes of the pro forma disclosures required by SFAS No. 123, the estimated fair value of the options is amortized to expense over the options vesting period. Compensation expense would have been $2.9 million in 2001 under SFAS No. 123. The Company's pro forma information is as follows (in thousands, except per share data):
-------- Net income: As reported $541,610 Pro forma $539,845
Basic earnings per common share: As reported $ 2.65 Pro forma $ 2.64 Diluted earnings per common share: As reported $ 2.64 Pro forma $ 2.63
The effects of applying SFAS No. 123 in this pro forma disclosure are not likely to be representative of effects on reported net income for future years.
The number of options outstanding as of December 31, 2001, was 2.3 million with a weighted-average remaining contractual life of 9.75 years and a weighted-average exercise price of $43.49. No options were exercisable as of December 31, 2001.
C. Other Stock-Based Compensation Plans
The Company has additional compensation plans for officers and key employees of the Company that are stock-based in whole or in part. The two primary programs are the Performance Share Sub-Plan (PSSP) and the Restricted Stock Awards program (RSA), both of which were established pursuant to the Company's 1997 Equity Incentive Plan.
Under the terms of the PSSP, officers and key employees of the Company are granted performance shares that vest over a three-year consecutive period. Each performance share has a value that is equal to, and changes with, the value of a share of the Company's common stock, and dividend equivalents are accrued on, and reinvested in, the performance shares. The PSSP has two equally weighted performance measures, both of which are based on the Company's results as compared to a peer group of utilities. Compensation expense is recognized over the vesting period based on the expected ultimate cash payout. Compensation expense is reduced by any forfeitures.
The RSA allows the Company to grant shares of restricted common stock to officers and key employees of the Company. The restricted shares vest on a graded vesting schedule over a minimum of three years. Compensation expense, which is based on the fair value of common stock at the grant date, is recognized over the applicable vesting period, with corresponding increases in common stock equity. The weighted average price of restricted shares at the grant date was $41.86, $36.97 and $37.63 in 2001, 2000 and 1999, respectively. Compensation expense is reduced by any forfeitures. Restricted shares are not included as shares outstanding in the basic earnings per share calculation until the shares are no longer forfeitable. Changes in restricted stock shares outstanding were:
2001 2000 1999 ------- ------- -------
Beginning balance 653,344 331,900 265,300 Granted 113,651 359,844 66,600 Vested (21,722) -- -- Forfeited (70,762) (38,400) -- ---------------------------------------- Ending balance 674,511 653,344 331,900 ========================================
The total amount expensed for other stock-based compensation plans was $14.3 million, $15.6 million and $2.2 million in 2001, 2000 and 1999, respectively.
16. Postretirement Benefit Plans
The Company and some of its subsidiaries have a non-contributory defined benefit retirement (pension) plan for substantially all full-time employees. The Company also has supplementary defined benefit pension plans that provide benefits to higher-level employees.
The components of net periodic pension benefit for the years ended December 31 are (in thousands):
2001 2000 1999 --------- -------- -------- Expected return on plan assets $(169,329) $(87,628) $(75,124) Service cost 31,863 22,123 20,467 Interest cost 96,200 56,924 46,846 Amortization of transition obligation 125 125 106 Amortization of prior service benefit (1,325) (1,314) (1,314) Amortization of actuarial gain (4,989) (5,721) (3,932) --------- -------- --------
Net periodic pension benefit $ (47,455) $(15,491) $(12,951) ========= ======== ========
In addition to the net periodic benefit reflected above, in 2000 the Company recorded a charge of approximately $21.5 million to adjust one of its supplementary defined benefit pension plans. The effect of the adjustment for this plan is reflected in the actuarial loss (gain) line in the pension obligation reconciliation below.
Prior service costs and benefits are amortized on a straight-line basis over the average remaining service period of active participants. Actuarial gains and losses in excess of 10% of the greater of the pension obligation or the market-related value of assets are amortized over the average remaining service period of active participants.
Reconciliations of the changes in the plan's benefit obligations and the plan's funded status are (in thousands):
The net prepaid pension cost of $404.2 million at December 31, 2001 is recognized in the accompanying Consolidated Balance Sheets as prepaid pension cost of $489.6 million and accrued benefit cost of $85.4 million, which is included in other liabilities and deferred credits. The net prepaid pension cost of $291.6 million at December 31, 2000 is recognized in the accompanying Consolidated Balance Sheets as prepaid pension cost of $373.2 million and accrued benefit cost of $81.6 million, which is included in other liabilities and deferred credits. The aggregate benefit obligation for those plans where the accumulated benefit obligation exceeded the fair value of plan assets was $85.4 million and $83.6 million at December 31, 2001 and 2000, respectively, and those plans have no plan assets.
Reconciliations of the fair value of pension plan assets are (in thousands):
The weighted-average discount rate used to measure the pension obligation was 7.5% in 2001 and 2000. The weighted-average rate of increase in future compensation for non-bargaining unit employees used to measure the pension obligation was 4.0% in 2001 and 2000 and 4.2% in 1999. The corresponding rate of increase in future compensation for bargaining unit employees was 3.5% in 2001 and 2000. The expected long-term rate of return on pension plan assets used in determining the net periodic pension cost was 9.25% in 2001, 2000 and 1999.
In addition to pension benefits, the Company and some of its subsidiaries provide contributory other postretirement benefits (OPEB), including certain health care and life insurance benefits, for retired employees who meet specified criteria.
The components of net periodic OPEB cost for the years ended December 31 are (in thousands):
2001 2000 1999 ------- ------- -------
Expected return on plan assets $(4,651) $(4,045) $(3,378)
Service cost 13,231 10,067 7,936 Interest cost 28,414 15,446 13,914 Amortization of prior service cost 319 107 -- Amortization of transition obligation 4,701 5,878 5,760 Amortization of actuarial gain (592) (819) (1) ------- ------- -------
Net periodic OPEB cost $41,422 $26,634 $24,231 ======= ======= =======
Prior service costs and benefits are amortized on a straight-line basis over the average remaining service period of active participants. Actuarial gains and losses in excess of 10% of the greater of the OPEB obligation or the market-related value of assets are amortized over the average remaining service period of active participants.
Reconciliations of the changes in the plan's benefit obligations and the plan's funded status are (in thousands):
2001 2000 --------- ---------
OPEB obligation at January 1 $ 374,923 $ 213,488 Interest cost 28,414 15,446 Service cost 13,231 10,067 Benefit payments (17,207) (7,258) Actuarial gain 27,428 (12,590) Plan amendment (25,845) -- Acquisitions -- 155,770 --------- ---------
OPEB obligation at December 31 $ 400,944 $ 374,923
Fair value of plan assets at December 31 55,529 54,642 --------- ---------
Funded status $(345,415) $(320,281)
Unrecognized transition obligation 33,129 70,715
Unrecognized prior service cost 7,675 955
Unrecognized actuarial loss (gain) 6,429 (25,060) --------- --------- Accrued OPEB cost at December 31 $(298,182) $(273,671) ========= =========
Reconciliations of the fair value of OPEB plan assets are (in thousands):
2001 2000 -------- --------
Fair value of plan assets at January 1 $ 54,642 $ 43,235 Actual return on plan assets (444) 124 Acquisition -- 11,283 Employer contribution 18,538 7,258 Benefits paid (17,207) (7,258) -------- -------- Fair value of plan assets at December 31 $ 55,529 $ 54,642 ======== ========
The assumptions used to measure the OPEB obligation and determine the net periodic OPEB cost are:
The medical cost trend rates were assumed to decrease gradually from the initial rates to the ultimate rates. Assuming a 1% increase in the medical cost trend rates, the aggregate of the service and interest cost components of the net periodic OPEB cost for 2001 would increase by $5.6 million, and the OPEB obligation at December 31, 2001, would increase by $35.3 million. Assuming a 1% decrease in the medical cost trend rates, the aggregate of the service and interest cost components of the net periodic OPEB cost for 2001 would decrease by $4.8 million and the OPEB obligation at December 31, 2001, would decrease by $32.3 million.
During 1999, the Company completed the acquisition of NCNG (See Note 2B). During 2000, the Company completed the acquisition of FPC (See Note 2A). NCNG's and FPC's pension and OPEB liabilities, assets and net periodic costs are reflected in the above information as appropriate. Effective January 1, 2000, NCNG's benefit plans were merged with those of the Company. Certain of FPC's non-bargaining unit benefit plans were merged with those of the Company effective January 1, 2002.
Florida Power continues to recover qualified plan pension costs and OPEB costs in rates as if the acquisition had not occurred. Accordingly, a portion of the prepaid pension cost and a portion of the accrued OPEB cost reflected in the tables above have a corresponding regulatory liability and regulatory asset, respectively (See Note 2A). In addition, pursuant to its rate treatment, for 2001 Florida Power recognized additional periodic pension credit of $16.5 million and additional periodic OPEB cost of $3.5 million, as compared to the amounts included in the net periodic information above.
17. Earnings Per Common Share
Basic earnings per common share is based on the weighted-average of common shares outstanding. Diluted earnings per share includes the effect of the non-vested portion of restricted stock awards. The stock options outstanding as of December 31, 2001 were anti-dilutive and therefore are not included in diluted earnings per share. Restricted stock awards and contingently issuable shares had a dilutive effect on earnings per share for all three years and increased the weighted-average number of common shares outstanding for dilutive purposes by 664,403 in 2001, 454,924 in 2000 and 290,474 in 1999. The weighted-average number of common shares outstanding for dilutive purposes was 205.3 million, 157.6 million and 148.6 million for 2001, 2000 and 1999, respectively.
ESOP shares that have not been committed to be released to participants' accounts are not considered outstanding for the determination of earnings per common share. The weighted-average of these shares totaled 5.4 million, 5.7 million and 6.5 million for the years ended December 31, 2001, 2000 and 1999, respectively.
18. Income Taxes
Deferred income taxes are provided for temporary differences between book and tax bases of assets and liabilities. Investment tax credits related to regulated operations are amortized over the service life of the related property. A regulatory asset or liability has been recognized for the impact of tax expenses or benefits that are recovered or refunded in different periods by the utilities pursuant to rate orders.
Accumulated deferred income tax (assets) liabilities at December 31 are (in thousands):
2001 2000 ---------- ---------- Accelerated depreciation and property cost differences $1,812,743 $2,054,509 Deferred costs, net 82,566 63,085 Income tax credit carry forward (306,497) (103,754) Miscellaneous other temporary differences, net (157,343) (150,969) Valuation allowance 31,492 10,868 ---------- ---------- Net accumulated deferred income tax liability $1,462,961 $1,873,739 ========== ==========
Total deferred income tax liabilities were $2.68 billion and $2.79 billion at December 31, 2001 and 2000, respectively. Total deferred income tax assets were $1.22 billion and $919 million at December 31, 2001 and 2000, respectively. The net of deferred income tax liabilities and deferred income tax assets is included on the Consolidated Balance Sheets under the captions other current liabilities and accumulated deferred income taxes.
The Company established a valuation allowance of $10.9 million in 2000 and established additional valuation allowances of $20.5 million during 2001 due to the uncertainty of realizing future tax benefits from certain state net operating loss carryforwards.
Reconciliations of the Company's effective income tax rate to the statutory federal income tax rate are:
Income tax expense (benefit) is comprised of (in thousands):
The Company, through its subsidiaries, is a majority owner in five entities and a minority owner in one entity that own facilities that produce synthetic fuel as defined under the Internal Revenue Service Code (Code). The production and sale of the synthetic fuel from these facilities qualifies for tax credits under Section 29 of the Code (Section 29) if certain requirements are satisfied, including a requirement that the synthetic fuel differs significantly in chemical composition from the coal used to produce such synthetic fuel. All entities have received private letter rulings (PLR's) from the Internal Revenue Service (IRS) with respect to their synthetic fuel operations. The PLR's do not limit the production on which synthetic fuel credits may be claimed. Should the tax credits be denied on future audits, and the Company fails to prevail through the IRS or legal process, there could be a significant tax liability owed for previously taken Section 29 credits, with a significant impact on earnings and cash flows. In
management's opinion, the Company is complying with all the necessary requirements to be allowed such credits under Section 29 and believes it is probable, although it cannot provide certainty, that it will prevail on any credits taken.
19. Joint Ownership of Generating Facilities
CP&L and Florida Power hold undivided ownership interests in certain jointly owned generating facilities, excluding related nuclear fuel and inventories. Each is 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. CP&L's and Florida Power's share of expenses for the jointly owned facilities is included in the appropriate expense category.
CP&L's and Florida Power's ownership interests in the jointly owned generating facilities are listed below with related information as of December 31, 2001 (dollars in thousands):
In the table above, plant investment and accumulated depreciation are not reduced by the regulatory disallowances related to the Harris Plant.
20. Commitments and Contingencies
A. Fuel and Purchased Power
Pursuant to the terms of the 1981 Power Coordination Agreement, as amended, between CP&L and Power Agency, CP&L is obligated to purchase a percentage of Power Agency's ownership capacity of, and energy from, the Harris Plant. In 1993, CP&L and Power Agency entered into an agreement to restructure portions of their contracts covering power supplies and interests in jointly owned units. Under the terms of the 1993 agreement, CP&L 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 capacity costs, total approximately $32 million. These contractual purchases totaled $33.3 million, $33.9 million and $36.5 million for 2001, 2000 and 1999, respectively. In 1987, the NCUC ordered CP&L 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. At December 31, 2001 and 2000, CP&L had deferred purchased capacity costs, including carrying costs accrued on the deferred balances, of $32.5 million and $44.8 million, respectively. Increased purchases (which are not being deferred for future recovery) resulting from the 1993 agreement with Power Agency were approximately $29 million, $26 million and $23 million for 2001, 2000 and 1999, respectively.
CP&L has a long-term agreement for the purchase of power and related transmission services from Indiana Michigan Power Company's Rockport Unit No. 2 (Rockport). The agreement provides for the purchase of 250 megawatts of capacity through 2009 with minimum annual payments of approximately $31 million, representing capital-related capacity costs. Total purchases (including transmission use charges) under the Rockport agreement amounted to $62.8 million, $61.0 million and $59.2 million for 2001, 2000 and 1999, respectively.
Effective June 1, 2001, CP&L executed a long-term agreement for the purchase of power from Skygen Energy LLC's Broad River facility (Broad River). The agreement provides for the purchase of approximately 500 megawatts of capacity through 2021 with an original minimum annual payment of approximately $16 million, primarily representing capital-related capacity costs. The minimum annual payments will be indexed for inflation. Total purchases under the Broad River agreement amounted to $35.9 million in 2001. A separate long-term agreement for additional power from Broad River will commence June 1, 2002. This agreement will provide for the purchase of approximately 300 megawatts of capacity through 2022 with an original minimum annual payment of
approximately $16 million representing capital-related capacity costs. The minimum annual payments will be indexed for inflation.
Florida Power has long-term contracts for approximately 460 megawatts of purchased power with other utilities, including a contract with The Southern Company for approximately 400 megawatts of purchased power annually through 2010. Florida Power can lower these purchases to approximately 200 megawatts annually with a three-year notice. Total purchases under these agreements amounted to $111.7 million and $104.5 million for 2001 and 2000, respectively. Minimum purchases under these contracts, representing capital-related capacity costs, are approximately $50 million annually through 2003 and $30 million annually through 2006.
Both CP&L and Florida Power have ongoing purchased power contracts with certain cogenerators (qualifying facilities) with expiration dates ranging from 2002 to 2025. These purchased power contracts generally provide for capacity and energy payments. Energy payments for the Florida Power contracts are based on actual power taken under these contracts. Minimum expected future capacity payments under these contracts as of December 31, 2001 are $235.7 million, $244.3 million, $255.4 million, $267.9 million and $279.1 million for 2002-2006, respectively. CP&L has various pay-for-performance contracts with qualifying facilities for approximately 300 megawatts of capacity expiring at various times through 2009. Payments for both capacity and energy are contingent upon the qualifying facilities' ability to generate. Payments made under these contracts were $145.1 million in 2001, $168.4 million in 2000 and $178.7 million in 1999.
Florida Power and CP&L have entered into various long-term contracts for coal, gas and oil requirements of its generating plants. Estimated annual payments for firm commitments of fuel purchases and transportation costs under these contracts are approximately $1.5 billion, $1.2 billion, $992.8 million, $942.4 million and $944.4 million for 2002 through 2006, respectively.
B. Other Commitments
The Company has certain future commitments related to four synthetic fuel facilities purchased that provide for contingent payments (royalties) of up to $11.4 million on sales from each plant annually through 2007. The related agreements were amended in December 2001 to require the payment of minimum annual royalties of approximately $6.6 million for each plant through 2007. As a result of the amendment, the Company recorded a liability (included in other liabilities and deferred credits on the Consolidated Balance Sheets) and a deferred cost asset (included in other assets and deferred debits in the Consolidated Balance Sheets) of approximately $134.0 million at December 31, 2001, representing the minimum amounts due through 2007, discounted at 6.05%. As of December 31, 2001, the portion of the asset and liability recorded that was classified as current was $25.8 million. The deferred cost asset will be amortized to expense each year as synthetic fuel sales are made. The maximum amounts payable under these agreements remain unchanged. Actual amounts accrued under these agreements were approximately $45.8 million in 2001 and $43.1 million in 2000.
The Company has entered into a joint venture to build an 850-mile natural gas pipeline system to serve 14 eastern North Carolina counties. The Company has agreed to fund approximately $22.0 million of the project. The entire project is expected to be completed by the end of 2004.
During February 2002, Progress Ventures completed the acquisition of two electric generating projects totaling approximately 1,100 megawatts for total cash consideration of $345 million. The transaction included a power purchase agreement with the seller through December 31, 2004. In addition, there is a project management completion agreement whereby the Company assumed certain liabilities to facilitate buildout of one of the projects.
In January 2002, Progress Ventures entered into a letter of intent to acquire approximately 215 natural gas wells, 52 miles of intrastate gas pipeline and 170 miles of gas-gathering systems. Total consideration of $153 million is expected to include $135 million in Company common stock and $18 million in cash. This transaction is expected to be completed during the first quarter of 2002.
C. Insurance
CP&L and Florida Power are members of Nuclear Electric Insurance Limited (NEIL), which provides primary and excess insurance coverage against property damage to members' nuclear generating facilities. Under the primary program, each company is insured for $500 million at each of its respective nuclear plants. In addition to primary coverage, NEIL also provides decontamination, premature decommissioning and excess property insurance with limits of $2.0 billion on the Brunswick and Harris Plants, and $1.1 billion on the Robinson and CR3 Plants.
Insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at nuclear generating units is also provided through membership in NEIL. Both CP&L and Florida Power are insured
thereunder, following a twelve-week deductible period, for 52 weeks in the amount of $3.5 million per week at each of the nuclear units. An additional 110 weeks of coverage is provided at 80% of the above weekly amount. For the current policy period, the companies are subject to retrospective premium assessments of up to approximately $31.4 million with respect to the primary coverage, $32.4 million with respect to the decontamination, decommissioning and excess property coverage, and $22.1 million for the incremental replacement power costs coverage, in the event covered losses at insured facilities exceed premiums, reserves, reinsurance and other NEIL resources. Pursuant to regulations, each company's property damage insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and stable condition after an accident and, second, to decontamination costs, before any proceeds can be used for decommissioning, plant repair or restoration. Each company is responsible to the extent losses may exceed limits of the coverage described above.
Both CP&L and Florida Power are insured against public liability for a nuclear incident up to $9.54 billion per occurrence. Under the current provisions of the Price Anderson Act, which limits liability for accidents at nuclear power plants, each company, as an owner of nuclear units, can be assessed for a portion of any third-party liability claims arising from an accident at any commercial nuclear power plant in the United States. In the event that public liability claims from an insured nuclear incident exceed $200 million (currently available through commercial insurers), each company would be subject to pro rata assessments of up to $88.1 million for each reactor owned per occurrence. Payment of such assessments would be made over time as necessary to limit the payment in any one year to no more than $10 million per reactor owned. The Price Anderson Act expires August 1, 2002. There are several renewal proposals before Congress which include possible increased limits and retroactive premiums. The final outcome of this matter cannot be predicted at this time.
There have been recent revisions made to the nuclear property and nuclear liability insurance policies regarding the maximum recoveries available for multiple terrorism occurrences. Under the NEIL policies, if there were multiple terrorism losses occurring within one year after the first loss from terrorism, NEIL would make available one industry aggregate limit of $3.2 billion, along with any amounts it recovers from reinsurance, government indemnity or other sources up to the limits for each claimant. If terrorism losses occurred beyond the one-year period, a new set of limits and resources would apply. For nuclear liability claims arising out of terrorist acts, the primary level available through commercial insurers is now subject to an industry aggregate limit of $200.0 million. The second level of coverage obtained through the assessments discussed above would continue to apply to losses exceeding $200.0 million and would provide coverage in excess of any diminished primary limits due to the terrorist acts aggregate.
CP&L and Florida Power self-insure their transmission and distribution lines against loss due to storm damage and other natural disasters. Florida Power accrues $6 million annually to a storm damage reserve pursuant to a regulatory order and may defer losses in excess of the reserve (Note 13B).
D. Claims and uncertainties
1. The Company is subject to federal, state and local regulations addressing air and water quality, hazardous and solid waste management and other environmental matters.
Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. The lead or sole regulatory agency that is responsible for a particular former coal tar site depends largely upon the state in which the site is located. There are several manufactured gas plant (MGP) sites to which both electric utilities and the gas utility have some connection. In this regard, both electric utilities and the gas utility, with other potentially responsible parties, are participating in investigating and, if necessary, remediating former coal tar sites with several regulatory agencies, including, but not limited to, the U.S. Environmental Protection Agency (EPA), the Florida Department of Environmental Protection (FDEP) and the North Carolina Department of Environment and Natural Resources, Division of Waste Management (DWM). Although the electric utilities and gas utility may incur costs at these sites about which it has been notified, based upon current status of these sites, the Company does not expect those costs to be material to its consolidated financial position or results of operations. The Company has accrued probable costs at certain of these sites.
Both electric utilities, the gas utility and Progress Ventures are periodically notified by regulators such as the EPA and various state agencies of their involvement or potential involvement in sites, other than MGP sites, that may require investigation and/or remediation. Although The Company's subsidiaries may incur costs at the sites about which they have been notified, based upon the current status of these sites, the Company does not expect those costs to be material to the consolidated financial position or results of operations of the Company.
There has been and may be further proposed federal legislation requiring reductions in air emissions for nitrogen oxides, sulfur dioxide and mercury setting forth national caps and emission levels over an extended period of time. This national multi-pollutant approach would have significant costs which could be material to CP&L's consolidated financial position or results of operations. Some companies may seek recovery of the related cost through rate adjustments or similar mechanisms. The Company cannot predict the outcome of this matter.
The EPA has been conducting an enforcement initiative related to a number of coal-fired utility power plants in an effort to determine whether modifications at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. Both CP&L and Florida Power were asked to provide information to the EPA as part of this initiative and cooperated in providing the requested information. The EPA has initiated civil enforcement actions against other unaffiliated utilities as part of this initiative, some of which have resulted in settlement agreements calling for expenditures, ranging from $1.0 billion to $1.4 billion. A utility that was not subject to a civil enforcement action settled its New Source Review issues with the EPA for $300 million. These settlement agreements have generally called for expenditures to be made over extended time periods, and some of the companies may seek recovery of the related cost through rate adjustments or similar mechanisms. The Company cannot predict the outcome of this matter.
In 1998, the EPA published a final rule addressing the issue of regional transport of ozone. This rule is commonly known as the NOx SIP Call. The EPA's rule requires 23 jurisdictions, including North Carolina, South Carolina and Georgia, but not Florida, to further reduce nitrogen oxide emissions in order to attain a pre-set state NOx emission level by May 31, 2004. CP&L is evaluating necessary measures to comply with the rule and estimates its related capital expenditures to meet these measures in North and South Carolina could be approximately $370 million, which has not been adjusted for inflation. Increased operation and maintenance costs relating to the NOx SIP Call are not expected to be material to the Company's results of operations. Further controls are anticipated as electricity demand increases. The Company cannot predict the outcome of this matter.
In July 1997, the EPA issued final regulations establishing a new eight-hour ozone standard. In October 1999, the District of Columbia Circuit Court of Appeals ruled against the EPA with regard to the federal eight-hour ozone standard. The U.S. Supreme Court has upheld, in part, the District of Columbia Circuit Court of Appeals decision. Further litigation and rulemaking are anticipated. North Carolina adopted the federal eight-hour ozone standard and is proceeding with the implementation process. North Carolina has promulgated final regulations, which will require CP&L to install nitrogen oxide controls under the State's eight-hour standard. The cost of those controls are included in the cost estimate of $370 million set forth above.
The EPA published a final rule approving petitions under Section 126 of the Clean Air Act, which requires certain sources to make reductions in nitrogen oxide emissions by May 1, 2003. The final rule also includes a set of regulations that affect nitrogen oxide emissions from sources included in the petitions. The North Carolina fossil-fueled electric generating plants are included in these petitions. Acceptable state plans under the NOx SIP Call can be approved in lieu of the final rules the EPA approved as part of the 126 petitions. CP&L, other utilities, trade organizations and other states participated in litigation challenging the EPA's action. On May 15, 2001, the District of Columbia Circuit Court of Appeals ruled in favor of the EPA which will require North Carolina to make reductions in nitrogen oxide emissions by May 1, 2003. However, the Court in its May 15th decision rejected the EPA's methodology for estimating the future growth factors the EPA used in calculating the emissions limits for utilities. In August 2001, the Court granted a request by CP&L and other utilities to delay the implementation of the 126 Rule for electric generating units pending resolution by the EPA of the growth factor issue. The Court's order tolls the three-year compliance period (originally set to end on May 1, 2003) for electric generating units as of May 15, 2001. On January 16, 2002, the EPA issued a memo to harmonize the compliance dates for the Section 126 Rule and the NOx SIP Call. The new compliance date for all affected sources is now May 31, 2004, rather than May 1, 2003, subject to the completion of the EPA's response to the related court decision on the growth factor issue. The Company cannot predict the outcome of this matter.
On November 1, 2001, the Company completed the sale of the Inland Marine Transportation segment to AEP Resources, Inc. In connection with the sale, the Company entered into environmental indemnification provisions covering both unknown and known sites. The Company has recorded an accrual to cover estimated probable future environmental expenditures. The Company believes that it is reasonably possible that additional costs, which cannot be currently estimated, may be incurred related to the environmental indemnification provision beyond the amounts accrued. The Company cannot predict the outcome of this matter.
CP&L, Florida Power, Progress Ventures and NCNG have filed claims with the Company's general liability insurance carriers to recover costs arising out of actual or potential environmental liabilities. Some claims have
been settled and others are still pending. While management cannot predict the outcome of these matters, the outcome is not expected to have a material effect on the consolidated financial position or results of operations.
2. As required under the Nuclear Waste Policy Act of 1982, CP&L and Florida Power each entered into a contract with the Department of Energy (DOE) under which the DOE agreed to begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract.
In April 1995, the DOE issued a final interpretation that it did not have an unconditional obligation to take spent nuclear fuel by January 31, 1998. In Indiana & Michigan Power v. DOE, the Court of Appeals vacated the DOE's ------------------------------- final interpretation and ruled that the DOE had an unconditional obligation to begin taking spent nuclear fuel. The Court did not specify a remedy because the DOE was not yet in default.
After the DOE failed to comply with the decision in Indiana & Michigan ------------------ Power v. DOE, a group of utilities petitioned the Court of Appeals in ------------ Northern States Power (NSP) v. DOE, seeking an order requiring the DOE to ---------------------------------- begin taking spent nuclear fuel by January 31, 1998. The DOE took the position that their delay was unavoidable, and the DOE was excused from performance under the terms and conditions of the contract. The Court of Appeals found that the delay was not unavoidable, but did not order the DOE to begin taking spent nuclear fuel, stating that the utilities had a potentially adequate remedy by filing a claim for damages under the contract.
After the DOE failed to begin taking spent nuclear fuel by January 31, 1998, a group of utilities filed a motion with the Court of Appeals to enforce the mandate in NSP v. DOE. Specifically, this group of utilities ---------- asked the Court to permit the utilities to escrow their waste fee payments, to order the DOE not to use the waste fund to pay damages to the utilities, and to order the DOE to establish a schedule for disposal of spent nuclear fuel. The Court denied this motion based primarily on the grounds that a review of the matter was premature, and that some of the requested remedies fell outside of the mandate in NSP v. DOE. ----------
Subsequently, a number of utilities each filed an action for damages in the Court of Claims. In a recent decision, the U.S. Circuit Court of Appeals (Federal Circuit) ruled that utilities may sue the DOE for damages in the Federal Court of Claims instead of having to file an administrative claim with DOE. CP&L and Florida Power are in the process of evaluating whether they should each file a similar action for damages.
CP&L and Florida Power also continue to monitor legislation that has been introduced in Congress which might provide some limited relief. CP&L and Florida Power cannot predict the outcome of this matter.
With certain modifications, CP&L's spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on CP&L's system through the expiration of the current operating licenses for all of CP&L's nuclear generating units. Subsequent to the expiration of these licenses, dry storage may be necessary. CP&L obtained NRC approval to use additional storage space at the Harris Plant in December 2000. Florida Power currently is storing spent nuclear fuel onsite in spent fuel pools. If Florida Power does not seek renewal of the CR3 operating license, CR3 will have sufficient storage capacity in place for fuel consumed through the end of the expiration of the license in 2016. If Florida Power extends the CR3 operating license, dry storage may be necessary.
3. The Company and its subsidiaries are involved in various litigation matters in the ordinary course of business, some of which involve substantial amounts. Where appropriate, accruals have been made in accordance with SFAS No. 5, "Accounting for Contingencies," to provide for such matters. In the opinion of management, the final disposition of pending litigation would not have a material adverse effect on the Company's consolidated results of operations or financial position.
21. Subsequent Event (Unaudited)
On March 27, 2002, the parties in Florida Power's rate case entered into a Stipulation and Settlement Agreement (the Agreement) related to retail rate matters. The Agreement is to be effective from May 1, 2002 through 2005; provided, however, that if Florida Power's base rate earnings fall below a 10% return on equity, Florida Power may petition the FPSC to amend its base rates.
The Agreement provides that Florida Power will reduce its retail revenues from the sale of electricity by $125 million annually through 2005. The Agreement also provides that Florida Power will operate under a Revenue Sharing Incentive Plan (the Plan) that establishes revenue caps and sharing thresholds for the years 2002 through 2005. The Plan provides that retail base rate revenues between the sharing thresholds and the retail base rate revenue caps will be divided into two shares - a 1/3 share to be received by Florida Power's shareholders, and a 2/3 share to be refunded to Florida Power's retail customers; provided, however, that for the year 2002 only, the refund to
customers will be limited to 67.1% of the 2/3 customer share. The retail base rate revenue sharing threshold amounts for 2002, 2003, 2004 and 2005 will be $1,296 million, $1,333 million, $1,370 million and $1,407 million, respectively. The Plan also provides that all retail base rate revenues above the retail base rate revenue caps established for the years 2003, 2004 and 2005 will be refunded to retail customers on an annual basis. For 2002, the refund to customers will be limited to 67.1% of the retail base rate revenues that exceed the 2002 cap. The retail base revenue caps for 2002, 2003, 2004 and 2005 will be $1,356 million, $1,393 million, $1,430 million and $1,467 million, respectively.
The Agreement also provides that beginning with the in-service date of Florida Power's Hines Unit 2 and continuing through December 31, 2005, Florida Power will be allowed to recover through the fuel cost recovery clause a return on average investment and depreciation expense for Hines Unit 2, to the extent such costs do not exceed the Unit's cumulative fuel savings over the recovery period.
Additionally, the Agreement provides that Florida Power will effect a mid-course correction of its fuel cost recovery clause to reduce the fuel factor by $50 million for the remainder of 2002. The fuel cost recovery clause will operate as it normally does, including, but not limited to any additional mid-course adjustments that may become necessary, and the calculation of true-ups to actual fuel clause expenses.
During the term of the Agreement, Florida Power will suspend accruals on its reserves for nuclear decommissioning and fossil dismantlement. Additionally, for each calendar year during the term of the Agreement, Florida Power will record a $62.5 million depreciation expense reduction, and may, at its option, record up to an equal annual amount as an offsetting accelerated depreciation expense. In addition, Florida Power is authorized, at its discretion, to accelerate the amortization of certain regulatory assets over the term of the Agreement.
Under the terms of the Agreement, Florida Power agreed to continue the implementation of its four-year Commitment to Excellence Reliability Plan and expects to achieve a 20% improvement in its annual System Average Interruption Duration Index by no later than 2004. If this improvement level is not achieved for calendar years 2004 or 2005, Florida Power will provide a refund of $3 million for each year the level is not achieved to 10% of its total retail customers served by its worst performing distribution feeder lines.
The Agreement also provides that Florida Power will refund to customers $35 million of the $98 million in interim revenues Florida Power has collected subject to refund since March 13, 2001. No other interim revenues that were collected during that period will continue to be held subject to refund.
The Agreement was filed with the FPSC for approval on March 27, 2002. If the FPSC approves the Agreement, the new rates will take effect May 1, 2002. Progress Energy cannot predict the outcome of this matter.
INDEPENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS AND SHAREHOLDER OF CAROLINA POWER & LIGHT COMPANY:
We have audited the accompanying consolidated balance sheets and schedules of capitalization of Carolina Power & Light Company and its subsidiaries (CP&L) as of December 31, 2001 and 2000, and the related consolidated statements of income and comprehensive income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2001. Our audits also included the financial statement schedule listed in the Index at Item 8. These financial statements and the financial statement schedule are the responsibility of CP&L's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, based on our audits, such consolidated financial statements present fairly, in all material respects, the financial position of CP&L at December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP Raleigh, North Carolina February 15, 2002
CAROLINA POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS of INCOME and COMPRHENSIVE INCOME - ---------------------------------------------------------
See Notes to Carolina Power & Light Company consolidated financial statements.
CAROLINA POWER & LIGHT COMPANY CONSOLIDATED BALANCE SHEETS - ---------------------------
See Notes to Carolina Power & Light Company consolidated financial statements.
CAROLINA POWER & LIGHT COMPANY CONSOLIDATED STATEMENTS of CASH FLOWS - -------------------------------------
Noncash Activities . On July 15, 1999, CP&L purchased all outstanding shares of North Carolina Natural Gas Corporation (NCNG). In conjunction with the purchase of NCNG, CP&L issued approximately $360 million in common stock. . On June 28, 2000, Caronet, a wholly owned subsidiary of CP&L, contributed net assets in the amount of $93.0 million in exchange for a 35% ownership interest (15% voting interest) in a newly formed company. . On July 1, 2000, CP&L distributed its ownership interest in the stock of North Carolina Natural Gas Corporation, Strategic Resource Solutions Corp., Monroe Power Company and Progress Ventures, Inc. to Progress Energy, Inc. This resulted in a noncash dividend to its parent of approximately $555.9 million. . In January 2001, CP&L transferred certain assets, through a noncash dividend to parent in the amount of $19.1 million, to Progress Energy Service Company, LLC
See Notes to Carolina Power & Light Company consolidated financial statements.
CAROLINA POWER & LIGHT COMPANY CONSOLIDATED SCHEDULES of CAPITALIZATION - ----------------------------------------
CONSOLIDATED STATEMENTS of RETAINED EARNINGS - --------------------------------------------
CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED) - -------------------------------------------------
(a) In the opinion of management, all adjustments necessary to fairly present amounts shown for interim periods have been made. Results of operations for an interim period may not give a true indication of results for the year. (b) Includes gain on sale of BellSouth Carolinas PCS Partnership interest. (c) Includes approved further accelerated depreciation of $125 million on nuclear generating assets. (d) Includes impairment and other one-time charges relating to Interpath of $107.2 million, after tax.
See Notes to Carolina Power & Light Company consolidated financial statements.
CAROLINA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
A. Organization
Carolina Power & Light Company (CP&L) is a public service corporation primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. CP&L is a wholly owned subsidiary of Progress Energy, Inc. (the Company or Progress Energy), which was formed as a result of the reorganization of CP&L into a holding company structure on June 19, 2000. All shares of common stock of CP&L were exchanged for an equal number of shares of the Company. On December 4, 2000, the Company changed its name from CP&L Energy, Inc. to Progress Energy, Inc. The Company is a registered holding company under the Public Utility Holding Company Act (PUHCA) of 1935. Both the Company and its subsidiaries are subject to the regulatory provisions of the PUHCA.
On July 1, 2000, CP&L distributed its ownership interest in the stock of North Carolina Natural Gas (NCNG), Strategic Resource Solutions Corp. (SRS), Monroe Power Company (Monroe Power) and Progress Ventures, Inc. to the Company. As a result, those companies are direct subsidiaries of Progress Energy, Inc. and are not included in CP&L's results of operations and financial position since that date.
CP&L's results of operations include the results of NCNG for the periods subsequent to July 15, 1999 (See Note 2A) and prior to July 1, 2000.
B. Basis of Presentation
The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America and include the activities of CP&L and its majority-owned subsidiaries. Significant intercompany balances and transactions have been eliminated in consolidation except as permitted by Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," which provides that profits on intercompany sales to regulated affiliates are not eliminated if the sales price is reasonable and the future recovery of the sales price through the rate making process is probable. The accounting records are maintained in accordance with uniform systems of accounts prescribed by the Federal Energy Regulatory Commission (FERC), the North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (SCPSC). Certain amounts for 2000 and 1999 have been reclassified to conform to the 2001 presentation.
Unconsolidated investments in companies over which CP&L does not have control, but has the ability to exercise influence over operating and financial policies (generally, 20% - 50% ownership) are accounted for under the equity method of accounting. Effective June 28, 2000, a subsidiary of CP&L contributed the net assets used in its application service provider business to a newly formed company (Interpath) for a 35% ownership interest (15% voting interest) which is accounted for on a cost basis because CP&L does not exercise significant influence over those operations. Other investments are stated principally at cost. These investments, which total approximately $121 million at December 31, 2001, are included as miscellaneous other property and investments in the Consolidated Balance Sheets.
C. Use of Estimates and Assumptions
In preparing consolidated financial statements that conform with accounting principles generally accepted in the United States of America, 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 consolidated financial statements and amounts of revenues and expenses reflected during the reporting period. Actual results could differ from those estimates.
D. Utility Plant
The cost of additions, including betterments and replacements of units of property, is charged to utility plant. Maintenance and repairs of property, and replacements and renewals of items determined to be less than units of property, are charged to maintenance expense. The cost of units of property replaced, renewed or retired, plus removal or disposal costs, less salvage, is charged to accumulated depreciation. Generally, electric utility plant, other than nuclear fuel is pledged as collateral for the first mortgage bonds of CP&L.
The balances of utility plant in service at December 31 are listed below (in thousands), with a range of depreciable lives for each:
2001 2000 ----------- ----------- Electric Production plant (7-33 years) $ 7,301,225 $ 6,659,111 Transmission plant (30-75 years) 1,092,024 1,060,080 Distribution plant (12-50 years) 3,063,753 2,869,104 General plant and other (8-75 years) 567,289 537,606 ----------- ----------- Utility plant in service $12,024,291 $11,125,901 =========== ===========
As prescribed in the regulatory uniform systems of accounts, an allowance for the cost of borrowed and equity funds used to finance utility plant construction (AFUDC) is charged to the cost of the plant. Regulatory authorities consider AFUDC an appropriate charge for inclusion in the rates charged to customers by the utilities 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 total equity funds portion of AFUDC was $8.8 million, $14.5 million and $3.9 million in 2001, 2000 and 1999, respectively. The composite AFUDC rate for CP&L's electric utility plant was 6.2%, 8.2% and 6.4% in 2001, 2000 and 1999, respectively. The composite AFUDC rate for NCNG's gas utility plant was 10.09% in 2000 and 1999, respectively.
E. Diversified Business Property
The following is a summary of diversified business property (in thousands):
2001 2000 -------- -------- Telecommunications equipment $ 94,164 $ 76,694 Other equipment 11,657 8,368 Construction work in progress 21,622 25,603 Accumulated depreciation (15,641) (8,371) -------- -------- Diversified business property, net $111,802 $102,294 ======== ========
Diversified business property is stated at cost. Depreciation is computed on a straight-line basis using the following estimated useful lives: telecommunications equipment - 5 to 20 years and computers, office equipment and software - 3 to 10 years.
F. Depreciation and Amortization
For financial reporting purposes, substantially all 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 1G) and excluding accelerated cost recovery of nuclear generating assets, as a percent of average depreciable property other than nuclear fuel, were approximately 3.8% in 2001 and 2000 and 3.9% in 1999. Depreciation provisions totaled $504.9 million, $688.8 million and $409.6 million in 2001, 2000 and 1999, respectively.
Depreciation and amortization expense also includes amortization of deferred operation and maintenance expenses associated with Hurricane Fran, which struck significant portions of CP&L's service territory in September 1996. In 1996, the NCUC authorized CP&L to defer these expenses (approximately $40 million) with amortization over a 40-month period, which expired in December 1999.
With approval from the NCUC and the SCPSC, CP&L accelerated the cost recovery of its nuclear generating assets beginning January 1, 2000 and continuing through 2004. Also in 2000, CP&L received approval from the commissions to further accelerate the cost recovery of its nuclear generation facilities in 2000. The accelerated cost recovery of these assets resulted in additional depreciation expense of approximately $75 million and $275 million in 2001 and 2000, respectively (See Note 8B). Pursuant to authorizations from the NCUC and the SCPSC, CP&L accelerated the amortization of certain regulatory assets over a three-year period beginning January 1997 and expiring December 1999. The accelerated amortization of these regulatory assets resulted in additional depreciation and amortization expenses of approximately $68 million in 1999.
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. The total of these costs for the years ended December 31, 2001, 2000 and 1999 were $101.0 million, $112.1 million and $110.8 million, respectively.
G. Decommissioning Provisions
In CP&L's retail jurisdictions, provisions for nuclear decommissioning costs are approved by the NCUC and the SCPSC, and are based on site-specific estimates that include the costs for removal of all radioactive and other structures at the site. In the wholesale jurisdictions, the provisions for nuclear decommissioning costs are approved by FERC. Decommissioning cost provisions, which are included in depreciation and amortization expense, were $30.7 million in 2001 and 2000 and $33.3 million in 1999.
Accumulated decommissioning costs, which are included in accumulated depreciation, were $604.8 million and $599.3 million at December 31, 2001 and 2000, respectively. These costs include amounts retained internally and amounts funded in externally managed decommissioning trusts. Trust earnings increase the trust balance with a corresponding increase in the accumulated decommissioning balance. These balances are adjusted for net unrealized gains and losses related to changes in the fair value of trust assets.
CP&L's most recent site-specific estimates of decommissioning costs were developed in 1998, using 1998 cost factors, and are based on prompt dismantlement decommissioning, which reflects the cost of removal of all radioactive and other structures currently at the site, with such removal occurring shortly after operating license expiration. These estimates, in 1998 dollars, are $281.5 million for Robinson Unit No. 2, $299.6 million for Brunswick Unit No. 1, $298.7 million for Brunswick Unit No. 2 and $328.1 million for the Harris Plant. The estimates are subject to change based on a variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning and changes in federal, state or local regulations. The cost estimates exclude the portion attributable to North Carolina Eastern Municipal Power Agency (Power Agency), which holds an undivided ownership interest in the Brunswick and Harris nuclear generating facilities. Operating licenses for CP&L'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.
Management believes that the decommissioning costs being recovered through rates by CP&L, when coupled with reasonable assumed after-tax fund earnings rates, are currently sufficient to provide for the costs of decommissioning.
The Financial Accounting Standards Board has issued SFAS No. 143, "Accounting for Asset Retirement Obligations" that will impact the accounting for decommissioning and dismantlement provisions (See Note 1J).
H. Other Policies
CP&L recognizes electric utility revenues as service is rendered to customers. Operating revenues include unbilled electric utility revenues earned when service has been delivered but not billed by the end of the accounting period.
Fuel expense includes fuel costs or recoveries that are deferred through fuel clauses established by CP&L's regulators. These clauses allow CP&L to recover fuel costs and portions of purchased power costs through surcharges on customer rates.
CP&L maintains an allowance for doubtful accounts receivable, which totaled approximately $12.2 million and $17.0 million at December 31, 2001 and 2000, respectively. Inventory, which includes fuel and materials and supplies is carried at average cost. Long-term debt premiums, discounts and issuance expenses for the utilities 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 by the utilities are amortized over the remaining life of the original debt using the straight-line method. CP&L considers all highly liquid investments with original maturities of three months or less to be cash equivalents.
I. Impairment of Long-lived Assets and Investments
SFAS No. 121 " Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to Be Disposed Of" requires review of long-lived assets and certain intangibles for impairment when events or circumstances indicate that the carrying value of an asset may not be recoverable. Any impairment losses are reported in the period in which the recognition criteria are first applied based on the fair value of the asset.
Write-downs of investments are charged against earnings when a decline in fair value is determined to be other-than-temporary. CP&L continually reviews its investments to determine whether a decline in fair value below the
cost basis is other-than-temporary. During 2001, CP&L obtained a valuation study to assess its investment in Interpath based on current valuations in the technology sector. As a result, CP&L has recorded an investment impairment of $156.7 million on a pre-tax basis for other-than-temporary declines in the fair value of its investment in Interpath.
J. Impact of New Accounting Standards
Effective January 1, 2001, CP&L adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138. SFAS No. 133, as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 requires that an entity recognize all derivatives as assets or liabilities in the balance sheet and measure those instruments at fair value.
As a result of the adoption of SFAS No. 133, CP&L recorded a transition adjustment as a cumulative effect of a change in accounting principle of $0.7 million, net of tax, which increased accumulated other comprehensive loss as of January 1, 2001. This amount relates to several derivatives used to hedge cash flows related to interest on long-term debt. The net derivative losses will be reclassified into earnings consistent with hedge designations, primarily over the life of the related debt instruments, which principally range from three to ten years. CP&L estimates that approximately $10.7 million of the net losses at December 31, 2001 will be reclassified into earnings during 2002. There was no transition adjustment affecting the Consolidated Statement of Income as a result of the adoption of SFAS No. 133.
During the second quarter of 2001, the FASB issued interpretations of SFAS No. 133 indicating that options in general cannot qualify for the normal purchases and sales exception, but provided an exception that allows certain electricity contracts, including certain capacity-energy contracts, to be excluded from the mark-to-market requirements of SFAS No. 133. The interpretations were effective July 1, 2001. Those interpretations did not require CP&L to mark-to-market any of its electricity capacity-energy contracts currently outstanding. In December 2001, the FASB revised the criteria related to the exception for certain electricity contracts, with the revision to be effective April 1, 2002. CP&L does not expect the revised interpretation to change its assessment of mark-to-market requirements for its current contracts. If an electricity or fuel supply contract in its regulated businesses is subject to mark-to-market accounting, there would be no income statement effect of the mark-to-market because the contract's mark-to-market gain or loss will be recorded as a regulatory asset or liability. Any mark-to-market gains or losses in its non-regulated businesses will affect income unless those contracts qualify for hedge accounting treatment.
The application of the new rules is still evolving, and further guidance from the FASB is expected, which could additionally impact CP&L's financial statements.
The FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" in July 2001. This statement provides accounting requirements for retirement obligations associated with tangible long-lived assets and is effective January 1, 2003. This statement requires that the present value of retirement costs for which CP&L has a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. CP&L is currently assessing the effects this statement may ultimately have on accounting for decommissioning, dismantlement and other retirement costs.
Effective January 1, 2002, CP&L adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 provides guidance for the accounting and reporting of impairment or disposal of long-lived assets. The statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." It also supersedes the accounting and reporting provisions of APB Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" related to the disposal of a segment of a business. Adoption of this statement did not have a material effect on CP&L's financial statements.
2. Acquisitions and Dispositions
A. North Carolina Natural Gas Corporation
On July 15, 1999, CP&L completed the acquisition of NCNG for an aggregate purchase price of approximately $364 million, resulting in the issuance of approximately 8.3 million shares. The acquisition was accounted for as a purchase and, accordingly, the operating results of NCNG were included in CP&L's consolidated financial statements beginning with the date of acquisition. The excess of the aggregate purchase price over the fair value of
net assets acquired, approximately $240 million, was recorded as goodwill of the acquired business and is amortized primarily over a period of 40 years. Effective July 1, 2000, CP&L distributed its ownership in NCNG stock to its parent. As of that date, the results of NCNG are no longer included in CP&L's Consolidated Statements of Income and NCNG's assets and liabilities are no longer included in CP&L's Consolidated Balance Sheets.
B. BellSouth Carolinas PCS Partnership Interest
In September 2000, Caronet, Inc., a wholly owned subsidiary of CP&L, sold its 10% limited partnership interest in BellSouth Carolinas PCS for $200 million. The sale resulted in an after-tax gain of $121.1 million.
3. Financial Information by Business Segment
As described in Note 1A, on July 1, 2000, CP&L distributed its ownership interest in the stock of NCNG, SRS, Monroe Power and Progress Ventures, Inc. to Progress Energy. As a result, those companies are direct subsidiaries of Progress Energy and are not included in CP&L's results of operations and financial position since that date.
Through June 30, 2000, the business segments, operations and assets of Progress Energy and CP&L were substantially the same. Subsequent to July 1, 2000, CP&L's operations consist primarily of the CP&L Electric segment, the investment impairment described in Note 1I and the gain on sale of assets described in Note 2B. Subsequent to July 1, 2000, CP&L has no other material segments.
The financial information for the CP&L Electric segment for the years ended December 31, 2001, 2000 and 1999 is as follows:
The primary differences between the CP&L Electric segment and CP&L consolidated financial information relate to other non-electric operations and elimination entries.
4. Related Party Transactions
CP&L participates in an internal money pool, operated by the Company, to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Subsidiaries which invest in the money pool earn interest on a basis proportionate to their average monthly investment. The interest rate used to calculate earnings approximates external interest rates. Funds may be withdrawn from or repaid to the pool at any time without prior notice. At December 31, 2001, CP&L had $1.8 million of amounts receivable from the money pool that are included in receivables from affiliated companies on the Consolidated Balance Sheets and $49.7 million of amounts payable to the money pool that are included in payables to affiliated companies on the Consolidated Balance Sheets. At December 31, 2000, CP&L had $30.5 million of amounts receivable from the money pool that are included in receivables from affiliated companies on the Consolidated Balance Sheets. CP&L recorded $1.6 million of interest income and $1.7 million of interest expense related to the money pool for 2001. Amounts recorded for interest income and interest expense related to the money pool for 2000 were not significant.
During 2000, the Company formed Progress Energy Service Company, LLC (PESC) to provide specialized services, at cost, to the Company and its subsidiaries, as approved by the Securities and Exchange Commission. CP&L has an agreement with PESC under which services, including purchasing, accounting, treasury, tax, marketing, legal and human resources, are rendered to CP&L at cost. Amounts billed to CP&L by PESC for these services during 2001 and 2000 amounted to $173.9 million and $52.4 million, respectively. At December 31, 2001 and 2000, CP&L had net payables of $46.0 million and $250.7 million, respectively, to PESC that are included in payables to affiliated
companies on the Consolidated Balance Sheets. Subsidiaries of CP&L had amounts receivable from PESC of $13.7 million at December 31, 2001.
During the years ended December 31, 2001, 2000 and the period from July 15, 1999 to December 31, 1999, gas sales from NCNG to CP&L amounted to $14.7 million, $5.9 million and $1.0 million, respectively.
For the year ended December 31, 2001 and the period from July 1, 2000 to December 31, 2000, the Consolidated Statements of Income contain interest income received from NCNG in the amount of $4.8 million and $4.1 million, respectively. Prior to July 1, 2000, the interest income received from NCNG was eliminated in consolidation. At December 31, 2001 and 2000, CP&L had $6.2 million and $135.9 million, respectively, of notes receivable from NCNG that are included in receivables from affiliated companies on the Consolidated Balance Sheets.
At December 31, 2001, CP&L had a payable to Progress Energy in the amount of $40.2 million related to a short-term cash advance. This amount was repaid during February 2002.
See Note 11C related to restricted stock purchases for affiliated companies.
The remaining amounts of receivables and payables with affiliated companies at December 31, 2001 and 2000 represent intercompany amounts generated through CP&L's normal course of operations.
5. Debt and Credit Facilities
At December 31, 2001, CP&L had committed lines of credit totaling $575 million, all of which are used to support its commercial paper borrowings. CP&L is required to pay minimal annual commitment fees to maintain its credit facilities. The following table summarizes CP&L's credit facilities used to support the issuance of commercial paper (in millions):
Description Short-term Long-term Total ----------------------------------------------------------- 364-Day $-- $200 $200 5-Year (2 years remaining) -- 375 375 ----------------------------- $-- $575 $575 =============================
There were no loans outstanding under these facilities at December 31, 2001. CP&L's 364-day revolving credit agreement is considered a long-term commitment due to an option to convert to a one-year term loan at the expiration date.
Based on the available balances on the long-term facilities, commercial paper of approximately $261 million and $486 million has been reclassified to long-term debt at December 31, 2001 and 2000 respectively. The weighted average interest rate of such short-term obligations was 3.1% at December 31, 2001, and 7.40% at December 31, 2000.
The combined aggregate maturities of long-term debt for 2002 through 2005 are approximately $600 million, $268 million, $300 million, and $300 million, respectively. There are no maturities of long-term debt during 2006.
6. Leases
CP&L leases office buildings, computer equipment, vehicles, and other property and equipment with various terms and expiration dates. Rent expense (under operating leases) totaled $21.7 million, $13.8 million and $15.7 million for 2001, 2000 and 1999, respectively.
Assets recorded under capital leases consist of (in thousands):
2001 2000 ------- ------- Buildings $27,626 $27,626 Less: Accumulated amortization (8,752) (8,018) ------- ------- $18,874 $19,608 ======= =======
Minimum annual rental payments, excluding executory costs such as property taxes, insurance and maintenance, under long-term noncancelable leases as of December 31, 2001 are (in thousands):
Capital Operating -------- --------- Leases Leases -------- -------- 2002 $ 2,159 $18,832 2003 2,159 14,046 2004 2,159 10,059 2005 2,159 8,107 2006 2,159 6,074 Thereafter 22,431 29,041 -------- ------- $ 33,226 $86,159 ======= Less amount representing imputed interest (14,352) -------- Present value of net minimum lease payments under capital leases $ 18,874 ========
7. Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents and short-term obligations approximate fair value due to the short maturities of these instruments. At December 31, 2001 and 2000, there were miscellaneous investments consisting primarily of investments in company-owned life insurance and other benefit plan assets with carrying amounts of approximately $50.0 million and $93.3 million, respectively, included in miscellaneous other property and investments. The carrying amount of these investments approximates fair value due to the short maturity of certain instruments and certain instruments are presented at fair value. The carrying amount of CP&L's long-term debt, including current maturities, was $3.6 billion at December 31, 2001 and 2000. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $3.7 billion and $3.6 billion at December 31, 2001 and 2000, respectively.
External funds have been established as a mechanism to fund certain costs of nuclear decommissioning (See Note 1G). These nuclear decommissioning trust funds are invested in stocks, bonds and cash equivalents. Nuclear decommissioning trust funds are presented at amounts that approximate fair value. Fair value is obtained from quoted market prices for the same or similar investments.
8. Regulatory Matters
A. Regulatory Assets and Liabilities
As a regulated entity, CP&L is subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Accordingly, CP&L 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. CP&L's ability to continue to meet the criteria for application of SFAS No. 71 may be affected in the future by competitive forces and restructuring in the electric utility industry. In the event that SFAS No. 71 no longer applied to a separable portion of CP&L's operations, related regulatory assets and liabilities would be eliminated unless an appropriate regulatory recovery mechanism is provided. Additionally, these factors could result in an impairment of utility plant assets as determined pursuant to SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets."
At December 31, 2001 and 2000, the balances of the CP&L's regulatory assets (liabilities) were as follows (in thousands):
2001 2000 --------- -------- Deferred fuel (included in current assets) $ 131,505 $119,853 ----------------------
Income taxes recoverable through future rates 208,702 210,571 Harris Plant deferred costs 32,476 44,813 Loss on reacquired debt 5,801 -- Deferred DOE enrichment facilities-related costs 30,571 36,027 ---------------------- Total long-term regulatory assets 277,550 291,411 ----------------------
Emission allowance gains (7,494) -- ---------------------- Total long-term regulatory liabilities (7,494) -- ----------------------
Net regulatory assets $ 401,561 $411,264 ======================
Except for portions of deferred fuel, all regulatory assets earn a return or the cash has not yet been expended, in which case, the assets are offset by liabilities that do not incur a carrying cost.
B. Retail Rate Matters
The NCUC and the SCPSC approved proposals to accelerate cost recovery of CP&L's nuclear generating assets beginning January 1, 2000, and continuing through 2004. The accelerated cost recovery began immediately after the 1999 expiration of the accelerated amortization of certain regulatory assets (See Note 1F). Pursuant to the orders, the accelerated depreciation expense for nuclear generating assets was set at a minimum of $106 million with a maximum of $150 million per year. In late 2000, CP&L received approval from the NCUC and the SCPSC to further accelerate the cost recovery of its nuclear generation facilities by $125 million in 2000. This additional depreciation will allow CP&L to reduce the minimum accelerated annual depreciation in 2001 through 2004 to $75 million. The resulting total accelerated depreciation was $75 million and $275 million in 2001 and 2000, respectively. Recovering the costs of its nuclear generating assets on an accelerated basis will better position CP&L for the uncertainties associated with potential restructuring of the electric utility industry.
On May 30, 2001, the NCUC issued an order allowing CP&L to offset a portion of its annual accelerated cost recovery of nuclear generating assets by the amount of sulfur dioxide (SO2) emission allowance expense. CP&L did not offset accelerated depreciation expense in 2001 against emission allowance expense. CP&L is allowed to recover emission allowance expense through the fuel clause adjustment in its South Carolina retail jurisdiction.
In conjunction with the acquisition of NCNG, CP&L agreed to cap base retail electric rates in North Carolina and South Carolina through December 2004. The cap on base retail electric rates in South Carolina was extended to December 2005 in conjunction with regulatory approval to form a holding company. Management is of the opinion that this agreement will not have a material effect on CP&L's consolidated results of operations or financial position.
In conjunction with the Company's merger with Florida Progress Corporation, CP&L reached a settlement with the Public Staff of the NCUC in which it agreed to reduce rates to all of its non-real time pricing customers by $3 million in 2002, $4.5 million in 2003, $6 million in 2004 and $6 million in 2005. CP&L also agreed to write off and forego recovery of $10 million of unrecovered fuel costs in each of its 2000 NCUC and SCPSC fuel cost recovery proceedings.
C. Plant-Related Deferred Costs
In 1988 rate orders, CP&L was ordered to remove from rate base and treat as abandoned plant certain costs related to the Harris Plant. Abandoned plant amortization related to the 1988 rate orders was completed in 1998 for the wholesale and the North Carolina retail jurisdictions and in 1999 for the South Carolina retail jurisdiction. Amortization of plant abandonment costs is included in depreciation and amortization expense and totaled $15.0 million in 1999.
9. Risk Management Activities and Derivatives Transactions
CP&L uses a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk if the counterparty fails to perform under the contract. CP&L minimizes such risk by performing credit reviews using, among other things, publicly available credit ratings of such counterparties. Potential non-performance by counterparties is not expected to have a material effect on the consolidated financial position or consolidated results of operations of CP&L.
A. Commodity Derivatives - Non-Trading
CP&L enters into certain forward contracts involving cash settlements or physical delivery that reduce the exposure to market fluctuations relative to the price and delivery of electric products. During 2001, 2000 and 1999, CP&L principally sold electricity forward contracts, which can reduce price risk on CP&L's available but unsold generation. While such contracts are deemed to be economic hedges, CP&L no longer designates such contracts as hedges for accounting purposes; therefore, these contracts are carried on the balance sheet at fair value, with changes in fair value recognized in earnings. Gains and losses from such contracts were not material during 2001, 2000 and 1999. Also, CP&L did not have material outstanding positions in such contracts at December 31, 2001 or 2000. Most of the CP&L commodity contracts either are not derivatives pursuant to SFAS No. 133 or qualify as normal purchases or sales pursuant to SFAS No. 133. Therefore, such contracts are not recorded at fair value.
B. Commodity Derivatives - Trading
CP&L from time to time engages in the trading of electricity commodity derivatives and, therefore, experiences net open positions. CP&L manages open positions with strict policies which limit its exposure to market risk and require daily reporting to management of potential financial exposures. When such instruments are entered into for trading purposes, the instruments are carried on the balance sheet at fair value, with changes in fair value recognized in earnings. The net results of such contracts have not been material in any year, and CP&L did not have material outstanding positions in such contracts at December 31, 2001 or 2000.
C. Other Derivative Instruments
CP&L may from time to time enter into derivative instruments to hedge interest rate risk or equity securities risk.
CP&L has interest rate swap agreements to hedge its exposure on variable rate debt positions. The agreements, with a total notional amount of $500 million, were effective in July 2000 and mature in July 2002. Under these agreements, CP&L receives a floating rate based on the three-month London Interbank Offered Rate (LIBOR) and pays a weighted-average fixed rate of approximately 7.17%. The fair value of the swaps was a $18.5 million liability position at December 31, 2001 and is included in other current liabilities in the accompanying Consolidated Balance Sheets. Interest rate swaps are carried on the balance sheet at fair value with unrealized gains or losses adjusted through other comprehensive income. As such, payments or receipts on interest rate swap agreements are recognized as adjustments to interest expense.
The notional amounts of the interest rate swaps are not exchanged and do not represent exposure to credit loss. In the event of default by a counterparty, the risk in these transactions is the cost of replacing the agreements at current market rates.
10. Capitalization
As of December 31, 2001, CP&L was authorized to issue up to 200,000,000 shares. All shares issued and outstanding are held by the Company effective with the share exchange on June 19, 2000 (See Note 1A).
There are various provisions limiting the use of retained earnings for the payment of dividends under certain circumstances. As of December 31, 2001, there were no significant restrictions on the use of retained earnings.
11. Stock-Based Compensation Plans
CP&L accounts for stock-based compensation in accordance with the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations as permitted under SFAS No. 123, "Accounting for Stock-Based Compensation (SFAS No. 123).
A. Employee Stock Ownership Plan
Progress Energy sponsors the Progress Energy 401(k) Savings and Stock Ownership Plan (401(k)) for which substantially all full-time non-bargaining unit employees and certain part-time non-bargaining employees within participating subsidiaries are eligible. CP&L participates in the 401(k). The 401(k), which has matching and incentive goal features, encourages systematic savings by employees and provides a method of acquiring Progress Energy common stock and other diverse investments. The 401(k), as amended in 1989, is an Employee Stock Ownership Plan (ESOP) that can enter into acquisition loans to acquire Progress Energy common stock to satisfy 401(k) common share needs. Qualification as an ESOP did not change the level of benefits received by employees under the 401(k). Common stock acquired with the proceeds of an ESOP loan is held by the 401(k) Trustee in a suspense account. The common stock is released from the suspense account and made available for allocation to participants as the ESOP loan is repaid. Such allocations are used to partially meet common stock needs related to Progress Energy matching and incentive contributions and/or reinvested dividends.
There were 5,199,388 and 5,782,376 ESOP suspense shares at December 31, 2001 and 2000, respectively, with a fair value of $234.1 million and $284.4 million, respectively. CP&L's matching and incentive goal compensation cost under the 401(k) is determined based on matching percentages and incentive goal attainment as defined in the plan. Such compensation cost is allocated to participants' accounts in the form of Progress Energy common stock, with the number of shares determined by dividing compensation cost by the common stock market value at the time of allocation. The 401(k) common stock share needs are met with open market purchases and with shares released from the ESOP suspense account. CP&L's matching and incentive cost met with shares released from the suspense
account totaled approximately $12.7 million, $14.7 million and $16.3 million for the years ended December 31, 2001, 2000 and 1999, respectively. CP&L has a long-term note receivable from the 401(k) Trustee related to the purchase of common stock from CP&L in 1989 (now Progress Energy common stock). The balance of the note receivable from the 401(k) Trustee is included in the determination of unearned ESOP common stock, which reduces common stock equity. Interest income on the note receivable is not recognized for financial statement purposes.
B. Stock Option Agreements
Pursuant to Progress Energy's 1997 Equity Incentive Plan, Amended and Restated as of September 26, 2001, Progress Energy may grant options to purchase shares of common stock to officers and eligible employees. During 2001, approximately 2.4 million common stock options were granted to officers and eligible employees of Progress Energy. Of this amount, approximately 1.0 million were granted to officers and eligible employees of CP&L. No compensation expense was recognized under the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees and related Interpretations." Had compensation expense been measured based on the fair value of the options on the date of grant, calculated under the provisions of SFAS No. 123, CP&L's allocated share of such compensation expense would have reduced reported net income in 2001 by approximately $1.2 million. This expense includes approximately $0.4 million of after-tax expense allocated to CP&L for PESC employees.
C. Other Stock-Based Compensation Plans
Progress Energy has compensation plans for officers and key employees that are stock-based in whole or in part. CP&L participates in these plans. The two primary active stock-based compensation programs are the Performance Share Sub-Plan (PSSP) and the Restricted Stock Awards program (RSA), both of which were established pursuant to Progress Energy's 1997 Equity Incentive Plan.
Under the terms of the PSSP, officers and key employees are granted performance shares on an annual basis that vest over a three-year consecutive period. Each performance share has a value that is equal to, and changes with, the value of a share of Progress Energy's common stock, and dividend equivalents are accrued on, and reinvested in, the performance shares. The PSSP has two equally weighted performance measures, both of which are based on Progress Energy's results as compared to a peer group of utilities. Compensation expense is recognized over the vesting period based on the expected ultimate cash payout. Compensation expense is reduced by any forfeitures.
The RSA allows Progress Energy to grant shares of restricted common stock to key employees. As a result of CP&L's reorganization into a holding company structure, restricted common stock is common stock of Progress Energy, Inc. (See Note 1A). The restricted shares vest on a graded vesting schedule over a minimum of three years. The weighted average price of restricted shares at the grant date was $40.70, $34.14 and $37.63 in 2001, 2000 and 1999, respectively. Changes in restricted stock outstanding for key employees of CP&L were:
2001 2000 1999 -------- -------- -------
Beginning balance 254,200 331,900 265,300 Granted 43,600 207,000 66,600 Transfers -- (256,700) -- Forfeited -- (28,000) -- Vested (30,796) -- -- ----------------------------------------- Ending balance 267,004 254,200 331,900 =========================================
The transfers line item reflects the distribution of CP&L's ownership interest in NCNG to Progress Energy and the transfer of certain employees to PESC.
At December 31, 2000, the unearned restricted stock balance reflected in the Consolidated Schedules of Capitalization included amounts for restricted stock for CP&L employees, as well as restricted stock purchased by CP&L on behalf of affiliate companies in the amount of $10.4 million. During 2001, Progress Energy reimbursed CP&L for all the outstanding restricted stock and therefore, CP&L no longer has unearned restricted stock recorded as a reduction to equity. Compensation expense, which is based on the fair value of common stock at the grant date, is recognized over the applicable vesting period and is reduced by forfeitures. Subsequent to reimbursement by Progress Energy to CP&L, CP&L is allocated expense based on the restricted shares outstanding for CP&L employees The total amount expensed by CP&L for other stock-based compensation plans was $5.9 million, $9.8 million and $2.2 million in 2001, 2000 and 1999, respectively.
12. Postretirement Benefit Plans
CP&L and some of its subsidiaries have a non-contributory defined benefit retirement (pension) plan for substantially all eligible employees. CP&L also has a supplementary defined benefit pension plan that provides benefits to higher-level employees.
The components of net periodic pension cost are (in thousands):
2001 2000 1999 -------- -------- --------
Expected return on plan assets $(71,955) $(76,508) $(75,124) Service cost 16,960 18,804 20,467 Interest cost 46,729 49,821 46,846 Amortization of transition obligation 116 121 106 Amortization of prior service benefit (1,230) (1,282) (1,314) Amortization of actuarial gain (4,352) (5,607) (3,932) -------- -------- --------
Net periodic pension benefit $(13,732) $(14,651) $(12,951) ======== ======== ========
In addition to the net periodic benefit reflected above, in 2000 CP&L recorded a charge of approximately $14.1 million to adjust its supplementary defined benefit pension plan. The effect of the adjustment for this plan is reflected in the actuarial loss line in the pension obligation reconciliation below.
Prior service costs and benefits are amortized on a straight-line basis over the average remaining service period of active participants. Actuarial gains and losses in excess of 10% of the greater of the pension obligation or the market-related value of assets are amortized over the average remaining service period of active participants.
Reconciliations of the changes in the plan's benefit obligations and the plan's funded status are (in thousands):
2001 2000 -------- --------- Pension obligation
Pension obligation at January 1 $638,067 $ 688,124 Interest cost 46,729 49,821 Service cost 16,960 18,804 Benefit payments (43,636) (50,770) Actuarial loss 5,621 27,990 Plan amendments 18,248 -- Transfers -- (95,902) -------- --------- Pension obligation at December 31 $681,989 $ 638,067
Fair value of plan assets at December 31 716,799 777,435 -------- --------- Funded status $ 34,810 $ 139,368
Unrecognized transition obligation 338 454
Unrecognized prior service cost (benefit) 4,123 (15,355)
Unrecognized actuarial gain (28,416) (128,504) -------- ---------
Prepaid (accrued) pension cost at December 31, net $ 10,855 $ (4,037) ======== =========
The net prepaid pension cost of $10.9 million at December 31, 2001 is included in the accompanying Consolidated Balance Sheets as prepaid pension cost of $25.7 million, which is included in other assets and deferred debits, and accrued benefit cost of $14.8 million, which is included in other liabilities and deferred credits. The net accrued pension cost of $4.0 million at December 31, 2000, is included in the accompanying Consolidated Balance Sheets as prepaid pension cost of $10.4 million, which is included in other assets and deferred debits, and accrued benefit cost of $14.4 million, which is included in other liabilities and deferred credits. The aggregate benefit obligation for the
plan where the accumulated benefit obligation exceeded the fair value of plan assets was $16.0 million at December 31, 2001, and the plan has no plan assets.
Reconciliations of the fair value of pension plan assets are (in thousands):
2001 2000 -------- --------- Fair value of plan assets at January 1 $777,435 $ 947,143 Actual return on plan assets (18,160) (1,007) Benefit payments (43,636) (50,770) Employer contributions 1,160 1,160 Transfers -- (119,091) -------- --------- Fair value of plan assets at December 31 $716,799 $ 777,435 ======== =========
The weighted-average discount rate used to measure the pension obligation was 7.5% in 2001 and 2000. The assumed rate of increase in future compensation used to measure the pension obligation was 4.0% in 2001 and 2000. The expected long-term rate of return on pension plan assets used in determining the net periodic pension cost was 9.25% in 2001, 2000 and 1999.
In addition to pension benefits, CP&L and some of its subsidiaries provide contributory postretirement benefits (OPEB), including certain health care and life insurance benefits, for retired employees who meet specified criteria.
The components of net periodic OPEB cost are (in thousands):
2001 2000 1999 ------- ------- ------- Expected return on plan assets $(3,676) $(3,852) $(3,378)
Service cost 7,374 8,868 7,936 Interest cost 14,191 13,677 13,914 Amortization of prior service cost -- 54 -- Amortization of transition obligation 4,298 5,551 5,760 Amortization of actuarial gain (531) (779) (1) ------- ------- -------
Net periodic OPEB cost $21,656 $23,519 $24,231 ======= ======= =======
Prior service costs and benefits are amortized on a straight-line basis over the average remaining service period of active participants. Actuarial gains and losses in excess of 10% of the greater of the OPEB obligation or the market-related value of assets are amortized over the average remaining service period of active participants.
Reconciliations of the changes in the plan's benefit obligations and the plan's funded status are (in thousands):
2001 2000 --------- --------- OPEB obligation
OPEB obligation at January 1 $ 187,563 $ 213,488 Interest cost 14,191 13,677 Service cost 7,374 8,868 Benefit payments (7,137) (6,425) Actuarial loss (gain) 19,242 (14,739) Plan amendment (29,145) -- Transfers -- (27,306) --------- --------- OPEB obligation at December 31 $ 192,088 $ 187,563
Fair value of plan assets at December 31 38,182 39,048 --------- ---------
Funded status $(153,906) $(148,515)
Unrecognized transition obligation 28,263 61,706
Unrecognized actuarial gain (1,284) (25,600) --------- ---------
Accrued OPEB cost at December 31 $(126,927) $(112,409) ========= =========
Reconciliations of the fair value of OPEB plan assets are (in thousands):
2001 2000 ------- -------
Fair value of plan assets at January 1 $39,048 $43,235 Actual return on plan assets (866) (191) Transfers -- (3,996) Employer contribution 7,137 6,425 Benefits paid (7,137) (6,425) ------- ------- Fair value of plan assets at December 31 $38,182 $39,048 ======= =======
The assumptions used to measure the OPEB obligation are:
2001 2000 ---- ---- Weighted-average discount rate 7.50% 7.50% Initial medical cost trend rate for pre-Medicare benefits 7.50% 7.50% Initial medical cost trend rate for post-Medicare benefits 7.50% 7.50% Ultimate medical cost trend rate 5.00% 5.00% Year ultimate medical cost trend rate is achieved 2008 2007
The expected weighted-average long-term rate of return on plan assets used in determining the net periodic OPEB cost was 9.25% in 2001, 2000 and 1999. The medical cost trend rates were assumed to decrease gradually from the initial rates to the ultimate rates. Assuming a 1% increase in the medical cost trend rates, the aggregate of the service and interest cost components of the net periodic OPEB cost for 2001 would increase by $3.8 million, and the OPEB obligation at December 31, 2001, would increase by $21.3 million. Assuming a 1% decrease in the medical cost trend rates, the aggregate of the service and interest cost components of the net periodic OPEB cost for 2001 would decrease by $3.1 million and the OPEB obligation at December 31, 2001, would decrease by $19.2 million.
During 1999, CP&L completed the acquisition of NCNG. Effective January 1, 2000, NCNG's benefit plans were merged with those of CP&L. On July 1, 2000, CP&L distributed its ownership interest in the stock of NCNG to Progress Energy. In addition, on August 1, 2000, Progress Energy established Progress Energy Service Company, LLC. The effects of the acquisition of NCNG, the transfer of ownership interest in NCNG and the transfer of employees to Progress Energy Service Company, LLC are reflected as appropriate in the pension and OPEB liabilities, assets and net periodic costs presented above.
13. Income Taxes
Deferred income taxes are provided for temporary differences between book and tax bases of assets and liabilities. Investment tax credits related to regulated operations are amortized over the service life of the related property. A regulatory asset or liability has been recognized for the impact of tax expenses or benefits that are recovered or refunded in different periods by the utilities pursuant to rate orders.
Net accumulated deferred income tax liabilities at December 31 are (in thousands):
2001 2000 ---------- ---------- Accelerated depreciation and property cost differences $1,359,083 $1,474,167 Deferred costs, net 42,688 51,549 Miscellaneous other temporary differences, net (20,100) 30,749 Income tax credit carryforward (640) -- Valuation allowance 3,767 -- ---------- ----------
Net accumulated deferred income tax liability $1,384,798 $1,556,465 ========== ==========
Total deferred income tax liabilities were $2.05 billion and $2.12 billion at December 31, 2001 and 2000, respectively. Total deferred income tax assets were $ 661 million and $559 million at December 31, 2001 and 2000,
respectively. The net of deferred income tax liabilities and deferred income tax assets is included on the consolidated balance sheets under the captions other current liabilities and accumulated deferred income taxes. CP&L established a valuation allowance of $3.8 million in 2001 due to the uncertainty of realizing future tax benefits from certain state net operating loss carryforwards.
Reconciliations of CP&L's effective income tax rate to the statutory federal income tax rate are:
2001 2000 1999 ---- ---- ----
Effective income tax rate 38.0% 38.6% 40.3% State income taxes, net of federal benefit (3.2) (4.5) (4.6) Investment tax credit amortization 2.5 3.7 1.6 Other differences, net (2.3) (2.8) (2.3) ---- ---- ----
Statutory federal income tax rate 35.0% 35.0% 35.0% ==== ==== ====
The provisions for income tax expense are comprised of (in thousands):
2001 2000 1999 --------- -------- -------- Income tax expense (credit): Current - federal $ 348,921 $328,982 $253,140 state 39,135 62,228 48,075 Deferred - federal (140,486) (71,929) (30,011) state (9,409) (11,625) (2,484) Investment tax credit (14,928) (17,385) (10,299) --------- -------- --------
Total income tax expense $ 223,233 $290,271 $258,421 ========= ======== ========
14. Joint Ownership of Generating Facilities
CP&L holds undivided ownership interests in certain jointly owned generating facilities, excluding related nuclear fuel and inventories. CP&L is entitled to shares of the generating capability and output of each unit equal to their respective ownership interests. CP&L also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. CP&L's share of expenses for the jointly owned facilities is included in the appropriate expense category.
CP&L's ownership interest in the jointly owned generating facilities is listed below with related information as of December 31, 2001 (dollars in thousands):
In the table above, plant investment and accumulated depreciation are not reduced by the regulatory disallowances related to the Harris Plant.
15. Commitments and Contingencies
A. Fuel and Purchased Power
Pursuant to the terms of the 1981 Power Coordination Agreement, as amended, between CP&L and Power Agency, CP&L is obligated to purchase a percentage of Power Agency's ownership capacity of, and energy from, the Harris Plant. In 1993, CP&L and Power Agency entered into an agreement to restructure portions of their contracts covering power supplies and interests in jointly owned units. Under the terms of the 1993 agreement, CP&L 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 capacity costs, total approximately $32 million. These contractual purchases, totaled $33.3
million, $33.9 million and $36.5 million for 2001, 2000 and 1999, respectively. In 1987, the NCUC ordered CP&L to reflect the recovery of the capacity portion of these costs on a levelized basis over the original 15-year buyback period, thereby deferring for future recovery the difference between such costs and amounts collected through rates. In 1988, the SCPSC ordered similar treatment, but with a 10-year levelization period. At December 31, 2001 and 2000, CP&L had deferred purchased capacity costs, including carrying costs accrued on the deferred balances, of $32.5 million and $44.8 million, respectively. Increased purchases (which are not being deferred for future recovery) resulting from the 1993 agreement with Power Agency were approximately $29 million, $26 million and $23 million for 2001, 2000 and 1999, respectively.
CP&L has a long-term agreement for the purchase of power and related transmission services from Indiana Michigan Power Company's Rockport Unit No. 2 (Rockport). The agreement provides for the purchase of 250 megawatts of capacity through 2009 with estimated minimum annual payments of approximately $31 million, representing capital-related capacity costs. Total purchases (including transmission use charges) under the Rockport agreement amounted to $62.8 million, $61.0 million and $59.2 million for 2001, 2000 and 1999, respectively.
Effective June 1, 2001, CP&L executed a long-term agreement for the purchase of power from Skygen Energy LLC's Broad River facility (Broad River). The agreement provides for the purchase of approximately 500 megawatts of capacity through 2021 with an original minimum annual payment of approximately $16 million, primarily representing capital-related capacity costs. The minimum annual payments will be indexed for inflation. Total purchases under the Broad River agreement amounted to $35.9 million in 2001. A separate long-term agreement for additional power from Broad River will commence June 1, 2002. This agreement will provide for the purchase of approximately 300 megawatts of capacity through 2022 with an original minimum annual payment of approximately $16 million representing capital-related capacity costs. The minimum annual payments will be indexed for inflation.
CP&L has various pay-for-performance purchased power contracts with certain cogenerators (qualifying facilities) for approximately 300 megawatts of capacity expiring at various times through 2009. These purchased power contracts generally provide for capacity and energy payments. Payments for both capacity and energy are contingent upon the qualifying facilities' ability to generate. Payments made under these contracts were $145.1 million in 2001, $168.4 million in 2000 and $178.7 million in 1999.
CP&L has entered into various long-term contracts for coal, gas and oil requirements of its generating plants. Estimated annual payments for firm commitments of fuel purchases and transportation costs under these contracts are approximately $538 million, $403 million, $345 million, $270 million and $286 million for 2002 through 2006, respectively.
B. Insurance
CP&L is a member of Nuclear Electric Insurance Limited (NEIL), which provides primary and excess insurance coverage against property damage to members' nuclear generating facilities. Under the primary program, CP&L is insured for $500 million at each of its nuclear plants. In addition to primary coverage, NEIL also provides decontamination, premature decommissioning and excess property insurance with limits of $2.0 billion on the Brunswick and Harris Plants and $1.1 billion on the Robinson Plant.
Insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at nuclear generating units is also provided through membership in NEIL. CP&L is insured thereunder, following a twelve-week deductible period, for 52 weeks in the amount of $3.5 million per week at each of the nuclear units. An additional 110 weeks of coverage is provided at 80% of the above weekly amount. For the current policy period, CP&L is subject to retrospective premium assessments of up to approximately $24.1 million with respect to the primary coverage, $25.7 million with respect to the decontamination, decommissioning and excess property coverage, and $17.4 million for the incremental replacement power costs coverage, in the event covered losses at insured facilities exceed premiums, reserves, reinsurance and other NEIL resources. Pursuant to regulations of the NRC, CP&L's property damage insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and stable condition after an accident and, second, to decontamination costs, before any proceeds can be used for decommissioning, plant repair or restoration. CP&L is responsible to the extent losses may exceed limits of the coverage described above.
CP&L is insured against public liability for a nuclear incident up to $9.54 billion per occurrence. Under the current provisions of the Price Anderson Act, which limits liability for accidents at nuclear power plants, CP&L, as an owner of nuclear units, can be assessed for a portion of any third-party liability claims arising from an accident at
any commercial nuclear power plant in the United States. In the event that public liability claims from an insured nuclear incident exceed $200 million (currently available through commercial insurers), the company would be subject to pro rata assessments of up to $88.1 million for each reactor owned per occurrence. Payment of such assessments would be made over time as necessary to limit the payment in any one year to no more than $10 million per reactor owned. The Price Anderson Act expires August 1, 2002. There are several renewal proposals before Congress which include possible increased limits and retroactive premiums. The final outcome of this matter cannot be predicted at this time.
There have been recent revisions made to the nuclear property and nuclear liability insurance policies regarding the maximum recoveries available for multiple terrorism occurrences. Under the NEIL policies, if there were multiple terrorism losses occurring within one year after the first loss from terrorism, NEIL would make available one industry aggregate limit of $3.2 billion, along with any amounts it recovers from reinsurance, government indemnity or other sources up to the limits for each claimant. If terrorism losses occurred beyond the one-year period, a new set of limits and resources would apply. For nuclear liability claims arising out of terrorist acts, the primary level available through commercial insurers is now subject to an industry aggregate limit of $200.0 million. The second level of coverage obtained through the assessments discussed above would continue to apply to losses exceeding $200.0 million and would provide coverage in excess of any diminished primary limits due to the terrorist acts aggregate.
CP&L self-insures its transmission and distribution lines against loss due to storm damage and other natural disasters.
C. Claims and Uncertainties
1. CP&L is subject to federal, state and local regulations addressing air and water quality, hazardous and solid waste management and other environmental matters.
Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. The lead or sole regulatory agency that is responsible for a particular former coal tar site depends largely upon the state in which the site is located. There are several manufactured gas plant (MGP) sites to which CP&L has some connection. In this regard, CP&L, with other potentially responsible parties, are participating in investigating and, if necessary, remediating former coal tar sites with several regulatory agencies, including, but not limited to, the U.S. Environmental Protection Agency (EPA) and the North Carolina Department of Environment and Natural Resources, Division of Waste Management (DWM). Although CP&L may incur costs at these sites about which it has been notified, based upon current status of these sites, CP&L does not expect those costs to be material to its consolidated financial position or results of operations.
CP&L is periodically notified by regulators such as the EPA and various state agencies of their involvement or potential involvement in sites, other than MGP sites, that may require investigation and/or remediation. Although CP&L may incur costs at the sites about which they have been notified, based upon the current status of these sites, CP&L does not expect those costs to be material to its consolidated financial position or results of operations.
There has been and may be further proposed federal legislation requiring reductions in air emissions for nitrogen oxides, sulfur dioxide and mercury setting forth national caps and emission levels over an extended period of time. This national multi-pollutant approach would have significant costs which could be material to CP&L's consolidated financial position or results of operations. Some companies may seek recovery of the related cost through rate adjustments or similar mechanisms. CP&L cannot predict the outcome of this matter.
The EPA has been conducting an enforcement initiative related to a number of coal-fired utility power plants in an effort to determine whether modifications at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. CP&L has been asked to provide information to the EPA as part of this initiative and cooperated in providing the requested information. The EPA has initiated enforcement actions against other unaffiliated utilities as part of this initiative, some of which have resulted in settlement agreements calling for expenditures ranging from $1.0 billion to $1.4 billion. A utility that was not subject to a civil enforcement action settled its New Source Review issues with the EPA for $300 million. These settlement agreements have generally called for expenditures to be made over extended time periods, and some of the utilities may seek recovery of the related cost through rate adjustments. CP&L cannot predict the outcome of this matter.
In 1998, the EPA published a final rule addressing the issue of regional transport of ozone. This rule is commonly known as the NOx SIP Call. The EPA's rule requires 23 jurisdictions, including North Carolina and South Carolina,
to further reduce nitrogen oxide emissions in order to attain a pre-set state NOx emission level by May 31, 2004. CP&L is evaluating necessary measures to comply with the rule and estimates its related capital expenditures could be approximately $370 million, which has not been adjusted for inflation. Increased operation and maintenance costs relating to the NOx SIP Call are not expected to be material to CP&L's results of operations. Further controls are anticipated as electricity demand increases. CP&L cannot predict the outcome of this matter.
In July 1997, the EPA issued final regulations establishing a new eight-hour ozone standard. In October 1999, the District of Columbia Circuit Court of Appeals ruled against the EPA with regard to the federal eight-hour ozone standard. The U.S. Supreme Court has upheld, in part, the District of Columbia Circuit Court of Appeals decision. Further litigation and rulemaking are anticipated. North Carolina adopted the federal eight-hour ozone standard and is proceeding with the implementation process. North Carolina has promulgated final regulations, which will require CP&L to install nitrogen oxide controls under the State's eight-hour standard. The cost of those controls are included in the cost estimate of $370 million set forth above.
The EPA published a final rule approving petitions under Section 126 of the Clean Air Act, which requires certain sources to make reductions in nitrogen oxide emissions by 2003. The final rule also includes a set of regulations that affect nitrogen oxide emissions from sources included in the petitions. The North Carolina fossil-fueled electric generating plants are included in these petitions. Acceptable state plans under the NOx SIP Call can be approved in lieu of the final rules the EPA approved as part of the 126 petitions. CP&L, other utilities, trade organizations and other states are participating in litigation challenging the EPA's action. On May 15, 2001, the District of Columbia Circuit Court of Appeals ruled in favor of the EPA which will require North Carolina to make reductions in nitrogen oxide emissions by May 1, 2003. However, the Court in its May 15th decision rejected the EPA's methodology for estimating the future growth factors the EPA used in calculating the emissions limits for utilities. In August 2001, the court granted a request by CP&L and other utilities to delay the implementation of the 126 Rule for electric generating units pending resolution by the EPA of the growth factor issue. The court's order tolls the three-year compliance period (originally set to end on May 1, 2003) for electric generating units as of May 15, 2001. On January 16, 2002, the EPA issued a memo to harmonize the compliance dates for the Section 126 Rule and the NOx SIP Call. The new compliance date for all affected sources is now May 31, 2004, rather than May 1, 2003, subject to the completion of the EPA's response to the related court decision on the growth factor issue. CP&L cannot predict the outcome of this matter.
CP&L has filed claims with its general liability insurance carriers to recover costs arising out of actual or potential environmental liabilities. Some claims have settled and others are still pending. While management cannot predict the outcome of these matters, the outcome is not expected to have a material effect on the consolidated financial position or results of operations.
2. As required under the Nuclear Waste Policy Act of 1982, CP&L entered into a contract with the DOE under which the DOE agreed to begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract.
In April 1995, the DOE issued a final interpretation that it did not have an unconditional obligation to take spent nuclear fuel by January 31, 1998. In Indiana & Michigan Power v. DOE, the Court of Appeals vacated the DOE's ------------------------------- final interpretation and ruled that the DOE had an unconditional obligation to begin taking spent nuclear fuel. The Court did not specify a remedy because the DOE was not yet in default.
After the DOE failed to comply with the decision in Indiana & Michigan ------------------ Power v. DOE, a group of utilities petitioned the Court of Appeals in ------------ Northern States Power (NSP) v. DOE, seeking an order requiring the DOE to ---------------------------------- begin taking spent nuclear fuel by January 31, 1998. The DOE took the position that their delay was unavoidable, and the DOE was excused from performance under the terms and conditions of the contract. The Court of Appeals did not order the DOE to begin taking spent nuclear fuel, stating that the utilities had a potentially adequate remedy by filing a claim for damages under the contract.
After the DOE failed to begin taking spent nuclear fuel by January 31, 1998, a group of utilities filed a motion with the Court of Appeals to enforce the mandate in NSP v. DOE. Specifically, this group of utilities ---------- asked the Court to permit the utilities to escrow their waste fee payments, to order the DOE not to use the waste fund to pay damages to the utilities, and to order the DOE to establish a schedule for disposal of spent nuclear fuel. The Court denied this motion based primarily on the grounds that a review of the matter was premature, and that some of the requested remedies fell outside of the mandate in NSP v. DOE. -----------
Subsequently, a number of utilities each filed an action for damages in the Court of Claims. In a recent decision, the U.S. Circuit Court of Appeals (Federal Circuit) ruled that utilities may sue the DOE for damages in the Federal Court of Claims instead of having to file an administrative claim with DOE. CP&L is in the process of evaluating whether they should file a similar action for damages.
CP&L also continues to monitor legislation that has been introduced in Congress which might provide some limited relief. CP&L cannot predict the outcome of this matter.
With certain modifications and additional approval by the NRC, CP&L's spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on its system through the expiration of the current operating licenses for all of its nuclear generating units. Subsequent to the expiration of these licenses, dry storage may be necessary. CP&L obtained NRC approval to use additional storage space at the Harris Plant in December 2000.
3. CP&L is involved in various litigation matters in the ordinary course of business, some of which involve substantial amounts. Where appropriate, accruals have been made in accordance with SFAS No. 5, "Accounting for Contingencies," to provide for such matters. In the opinion of management, the final disposition of pending litigation would not have a material adverse effect on CP&L's consolidated results of operations or financial position.
PROGRESS ENERGY, INC. Schedule II - Valuation and Qualifying Accounts For the Years Ended December 31, 2001, 2000, and 1999
a. Represents the reclassification of Rail Services from Net Assets Held for Sale b. Represents write-off of uncollectible accounts, net of recoveries. c. Represents acquisition of FPC on November 30, 2000. d. Represents acquisition of NCNG on July 15, 1999.
CAROLINA POWER & LIGHT COMPANY Schedule II - Valuation and Qualifying Accounts For the Years Ended December 31, 2001, 2000, and 1999
a. Represents write-off of uncollectible accounts, net of recoveries. b. Represents transfer of uncollectible account balances for SRS, NCNG, Monroe Power and Progress Ventures, Inc. to Progress Energy on July 1, 2000 of $2,846,873 as well as write-off of uncollectible accounts, net of recoveries of $9,436,799. c. Represents acquisition of NCNG on July 15, 1999.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND ------ --------------------------------------------------------------- FINANCIAL DISCLOSURE --------------------
As a result of the acquisition of Florida Progress Corporation (FPC) and Florida Power Corporation (Florida Power) by Progress Energy. Inc. (Progress Energy), management decided to retain Deloitte & Touche LLP (D&T) as its independent public accountants. D&T has served as the independent public accountants for Progress Energy for over fifty years. On March 21, 2001, the Audit Committee of the Board of Directors approved this recommendation and formally elected to (i) engage D&T as the independent accountants for FPC and Florida Power and (ii) dismiss KPMG LLP (KPMG) as such independent accountants.
KPMG's reports on FPC's and Florida Power's financial statements for 2000 and 1999 (the last two fiscal years of KPMG's engagement) contained no adverse opinion or a disclaimer of opinion, and were not qualified or modified as to uncertainty, audit scope or accounting principles. D&T became FPC's and Florida Power's independent accountants upon the completion of the 2000 audit and issuance of the related financial statements.
During FPC's and Florida Power's last two fiscal years and the subsequent interim period to the date hereof, there were no disagreements between FPC and Florida Power and KPMG on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of KPMG, would have caused them to make reference to the subject matter of the disagreements in connection with their report on the financial statements for such years.
KPMG furnished a letter addressed to the Securities and Exchange Commission stating that it agreed with the above statements made by Progress Energy in this Form 10-K.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ------- --------------------------------------------------
a) Information on Progress Energy, Inc.'s directors is set forth in the Progress Energy 2001 definitive proxy statement dated April 1, 2002, and incorporated by reference herein. Information on Carolina Power & Light Company's directors is set forth in the CP&L 2001 definitive proxy statement dated April 1, 2002, and incorporated by reference herein.
b) Information on both Progress Energy's and CP&L's executive officers is set forth in PART I and incorporated by reference herein.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION ------- ----------------------
Information on Progress Energy, Inc.'s executive compensation is set forth in the Progress Energy 2001 definitive proxy statement dated April 1, 2002, and incorporated by reference herein. Information on Carolina Power & Light Company's executive compensation is set forth in the CP&L 2001 definitive proxy statement dated April 1, 2002, and incorporated by reference herein.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT ------- --------------------------------------------------------------
a) Progress Energy knows of no person who is a beneficial owner of more than five (5%) percent of any class of the Company's voting securities.
b) Information on security ownership of the Progress Energy's and Carolina Power & Light Company's management is set forth in the Progress Energy and Carolina Power & Light Company 2001 definitive proxy statements dated April 1, 2002, and incorporated by reference herein.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ------- ----------------------------------------------
Information on certain relationships and related transactions is set forth in the Progress Energy and CP&L 2001 definitive proxy statement dated April 1, 2002, and incorporated by reference herein.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. ------- -----------------------------------------------------------------
a) The following documents are filed as part of the report:
1. Consolidated Financial Statements Filed:
See ITEM 8 - Consolidated Financial Statements and Supplementary Data.
2. Consolidated Financial Statement Schedules Filed:
See ITEM 8 - Consolidated Financial Statements and Supplementary Data
3. Exhibits Filed: --------------
See EXHIBIT INDEX
b) Reports on Form 8-K or Form 8-K/A filed during or with respect to the last quarter of 2001 and the portion of the first quarter of 2002 prior to the filing of this Form 10-K:
Progress Energy, Inc. ---------------------
Financial Item Statements Reported Included Date of Event Date Filed -------- ---------- ----------------- -----------------
5 Yes November 30, 2000 October 23, 2001 5 Yes October 24, 2001 October 24, 2001 5 No October 24, 2001 October 24, 2001 9 No October 30, 2001 October 30, 2001 5 No October 30, 2001 November 2, 2001 9 No November 28, 2001 November 28, 2001 9 No January 11, 2002 January 11, 2002 5 No December 12, 2001 January 17, 2002 5 Yes January 23, 2002 February 6, 2002 7 Yes February 26, 2002 February 26, 2002
Carolina Power & Light Company ------------------------------
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.
PROGRESS ENERGY, INC. --------------------- CAROLINA POWER & LIGHT COMPANY ------------------------------ Date: March 28, 2002 (Registrants)
By: /s/ Peter M. Scott III ---------------------- Executive Vice President and Chief Financial Officer
By: /s/ Robert H. Bazemore, Jr. -------------------------- Vice President and Controller (Chief Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
Signature Title Date --------- ----- ----
/s/ William Cavanaugh III Principal Executive March 20, 2002 -------------------------- Officer and Director (William Cavanaugh III, Chairman, President and Chief Executive Officer)
/s/ Edwin B. Borden Director March 20, 2002 ------------------- (Edwin B. Borden)
/s/ David L. Burner Director March 20, 2002 ------------------- (David L. Burner)
/s/ Charles W. Coker Director March 20, 2002 -------------------- (Charles W. Coker)
/s/ Richard L. Daugherty Director March 20, 2002 ------------------------ (Richard L. Daugherty)
/s/ W.D. Frederick, Jr. Director March 20, 2002 ---------------------- (W.D. Frederick, Jr.)
/s/ William O. McCoy Director March 20, 2002 -------------------- (William O. McCoy)
/s/ E. Marie McKee Director March 20, 2002 ------------------ (E. Marie McKee)
/s/ John H. Mullin, III Director March 20, 2002 ----------------------- (John H. Mullin, III)
/s/ Richard A. Nunis Director March 20, 2002 -------------------- (Richard A. Nunis)
/s/ Carlos A. Saladrigas Director March 20, 2002 ------------------------ (Carlos A. Saladrigas)
/s/ J. Tylee Wilson Director March 20, 2002 ------------------- (J. Tylee Wilson)
/s/ Jean Giles Wittner Director March 20, 2002 ---------------------- (Jean Giles Wittner)
EXHIBIT INDEX
Progress Number Exhibit Energy, Inc. CP&L ------------ ---- *2(a) Agreement and Plan of Merger By and Among X Carolina Power & Light Company, North Carolina Natural Gas Corporation and Carolina Acquisition Corporation, dated as of November 10, 1998 (filed as Exhibit No. 2(b) to Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1998, File No. 1-3382.)
*2(b) Agreement and Plan of Merger by and among X Carolina Power & Light Company, North Carolina Natural Gas Corporation and Carolina Acquisition Corporation, Dated as of November 10, 1998, as Amended and Restated as of April 22, 1999 (filed as Exhibit 2 to Quarterly Report on Form 10-Q for the quarterly period ended March 31, 1999, File No. 1-3382).
*2(c) Agreement and Plan of Exchange, dated as of X X August 22, X X 1999, by and among Carolina Power & Light Company, Florida Progress Corporation and CP&L Holdings, Inc. (filed as Exhibit 2.1 to Current Report on Form 8-K dated August 22, 1999, File No. 1-3382).
*2(d) Amended and Restated Agreement and Plan of X X Exchange, by and among Carolina Power & Light Company, Florida Progress Corporation and CP&L Energy, Inc., dated as of August 22, 1999, amended and restated as of March 3, 2000 (filed as Annex A to Joint Preliminary Proxy Statement of Carolina Power & Light Company and Florida Progress Corporation dated March 6, 2000, File No. 1-3382).
*3a(1) Restated Charter of Carolina Power & Light X 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).
*3a(2) Restated Charter of Carolina Power & Light X Company as amended on May 10, 1996 (filed as Exhibit No. 3(i) to Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1997, File No. 1-3382).
*3a(3) Amended and Restated Articles of X Incorporation of CP&L Energy, Inc., as amended and restated on June 15, 2000 (filed as Exhibit No. 3a(1) to Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2000, File No. 1-15929 and No. 1-3382).
3b(1) Amended and Restated Articles of X Incorporation of CP&L Energy, Inc., as amended and restated on December 4, 2000.
3b(2) By-Laws of Carolina Power & Light Company, as X amended on X December 12, 2001.
*3b(3) By-Laws of Progress Energy, Inc., as amended X and restated December 12, 2000 (filed as Exhibit No. 3 to Current Report on Form 8-K dated January 17, 2002, File No. 1-15929).
*4a(1) Resolution of Board of Directors, dated X December 8, 1954, authorizing the issuance of, and establishing the series designation, dividend rate and redemption prices for CP&L's Serial Preferred Stock, $4.20 Series (filed as Exhibit 3(c), File No. 33-25560).
*4a(2) Resolution of Board of Directors, dated X January 17, 1967, authorizing the issuance of, and establishing the series designation, dividend rate and redemption prices for CP&L's Serial Preferred Stock, $5.44 Series (filed as Exhibit 3(d), File No. 33-25560).
*4a(3) Statement of Classification of Shares dated X January 13, 1971, relating to the authorization of, and establishing the series designation, dividend rate and redemption prices for CP&L's Serial Preferred Stock, $7.95 Series (filed as Exhibit 3(f), File No. 33-25560).
*4a(4) Statement of Classification of Shares dated X September 7, 1972, relating to the authorization of, and establishing the series designation, dividend rate and redemption prices for CP&L's Serial Preferred Stock, $7.72 Series (filed as Exhibit 3(g), File No. 33-25560).
*4b(1) Mortgage and Deed of Trust dated as of May 1, X 1940 X between CP&L and The Bank of New York (formerly, Irving Trust Company) and Frederick G. Herbst (Douglas J. MacInnes, Successor), Trustees and the First through Fifth Supplemental Indentures thereto (Exhibit 2(b), File No. 2-64189); the Sixth through Sixty-sixth Supplemental Indentures (Exhibit 2(b)-5, File No. 2-16210; Exhibit 2(b)-6, File No. 2-16210; Exhibit 4(b)-8, File No. 2-19118; Exhibit 4(b)-2, File No. 2-22439; Exhibit 4(b)-2, File No. 2-24624; Exhibit 2(c), File No. 2-27297; Exhibit 2(c), File No. 2-30172; Exhibit 2(c), File No. 2-35694; Exhibit 2(c), File No. 2-37505; Exhibit 2(c), File No. 2-39002; Exhibit 2(c), File No. 2-41738; Exhibit 2(c), File No. 2-43439; Exhibit 2(c), File No. 2-47751; Exhibit 2(c), File No. 2-49347; Exhibit 2(c), File No. 2-53113; Exhibit 2(d), File No. 2-53113; Exhibit 2(c), File No. 2-59511; Exhibit 2(c), File No. 2-61611; Exhibit 2(d), File No. 2-64189; Exhibit 2(c), File No. 2-65514; Exhibits 2(c) and 2(d), File No. 2-66851; Exhibits 4(b)-1, 4(b)-2, and 4(b)-3, File No. 2-81299; Exhibits 4(c)-1 through 4(c)-8, File No. 2-95505; Exhibits 4(b) through 4(h), File No. 33-25560; Exhibits 4(b) and 4(c), File No. 33-33431; Exhibits 4(b) and 4(c), File No. 33-38298; Exhibits 4(h) and 4(i), File No. 33-42869; Exhibits 4(e)-(g), File No. 33-48607; Exhibits 4(e) and
4(f), File No. 33-55060; Exhibits 4(e) and 4(f), File No. 33-60014; Exhibits 4(a) and 4(b) to Post-Effective Amendment No. 1, File No. 33-38349; Exhibit 4(e), File No. 33-50597; Exhibit 4(e) and 4(f), File No. 33-57835; Exhibit to Current Report on Form 8-K dated August 28, 1997, File No. 1-3382; Form of Carolina Power & Light Company First Mortgage Bond, 6.80% Series Due August 15, 2007 filed as Exhibit 4 to Form 10-Q for the period ended September 30, 1998, File No. 1-3382; Exhibit 4(b), File No. 333-69237; and Exhibit 4(c) to Current Report on Form 8-K dated March 19, 1999, File No. 1-3382.); and the Sixty-eighth Supplemental Indenture (Exhibit No. 4(b) to Current Report on Form 8-K dated April 20, 2000, File No. 1-3382; and the Sixty-ninth Supplemental Indenture (Exhibit No. 4b(2) to Annual Report on Form 10-K dated March 29, 2001, File No. 1-3382); and the Seventieth Supplemental Indenture, (Exhibit 4b(3) to Annual Report on Form 10-K dated March 29, 2001, File No. 1-3382).
4b(2) Seventy-first Supplemental Indenture, dated X as of February 1, 2002, to Carolina Power & Light Company's Mortgage and Deed of Trust, dated May 1, 1940, between Carolina Power & Light Company and The Bank of New York and Douglas J. MacInnes, as Trustees.
*4c(1) Indenture, dated as of March 1, 1995, between X CP&L and Bankers Trust Company, as Trustee, with respect to Unsecured Subordinated Debt Securities (filed as Exhibit No. 4(c) to Current Report on Form 8-K dated April 13, 1995, File No. 1-3382).
*4c(2) Resolutions adopted by the Executive X 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).
*4d Indenture (for Senior Notes), dated as of X March 1, 1999 X between Carolina Power & Light Company and The Bank of New York, as Trustee, (filed as Exhibit No. 4(a) to Current Report on Form 8-K dated March 19, 1999, File No. 1-3382), and the First and Second Supplemental Senior Note Indentures thereto (Exhibit No. 4(b) to Current Report on Form 8-K dated March 19, 1999, File No. 1-3382); Exhibit No. 4(a) to Current Report on Form 8-K dated April 20, 2000, File No. 1-3382).
*4e Indenture (For Debt Securities), dated as of X October 28, 1999 between Carolina Power & Light Company and The Chase Manhattan Bank, as Trustee (filed as Exhibit 4(a) to Current Report on Form 8-K dated November 5, 1999, File No. 1-3382), and an Officer's Certificate issued pursuant thereto, dated as of October 28, 1999, authorizing the issuance and sale of Extendible Notes due October 28, 2009 (Exhibit 4(b) to Current Report on Form 8-K dated November 5, 1999, File No. 1-3382).
*4f Contingent Value Obligation Agreement, dated X as of November 30, 2000, between CP&L Energy, Inc. and The Chase Manhattan Bank, as Trustee (Exhibit 4.1 to Current Report on Form 8-K dated December 12, 2000, File No. 1-3382).
*10a(1) Purchase, Construction and Ownership X Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency, amending letter dated February 18, 1982, and amendment dated February 24, 1982 (filed as Exhibit 10(a), File No. 33-25560).
*10a(2) Operating and Fuel Agreement dated July 30, X 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency, amending letters dated August 21, 1981 and December 15, 1981, and amendment dated February 24, 1982 (filed as Exhibit 10(b), File No. 33-25560).
*10a(3) Power Coordination Agreement dated July 30, X 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency and amending letter dated January 29, 1982 (filed as Exhibit 10(c), File No. 33-25560).
*10a(4) Amendment dated December 16, 1982 to X Purchase, Construction and Ownership Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Eastern Municipal Power Agency (filed as Exhibit 10(d), File No. 33-25560).
*10a(5) Agreement Regarding New Resources and Interim X Capacity X between Carolina Power & Light Company and North Carolina Eastern Municipal Power Agency dated October 13, 1987 (filed as Exhibit 10(e), File No. 33-25560).
*10a(6) Power Coordination Agreement - 1987A between X 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).
10b(1) Carolina Power & Light Company $375,000,000 X 5-Year X Revolving Credit Agreement dated as of June 30, 1998.
10b(2) Carolina Power & Light Company $375,000,000 X 364-Day X Revolving Credit Agreement dated as of June 30, 1998.
10b(3) Amendment and Restatement dated June 29, 1999 X to
Carolina X Power & Light Company $375,000,000 364-Day Revolving Credit Agreement dated as of June 30, 1998.
10b(4) Notice to Administrative Agent from Carolina X Power & Light Company to request a reduction in the Commitments of the Lenders of $175,000,000 to the Revolving Credit Agreement dated June 30, 1998 and Amended and Restated June 29, 1999.
10b(5) Progress Energy, Inc. $500,000,000 364-Day X Revolving Credit Agreement dated as of November 13, 2001.
10b(6) Progress Energy, Inc. $450,000,000 3-Year X Revolving Credit Agreement dated November 13, 2001.
10b(7) Amendment, dated February 13, 2002, to X Progress Energy, Inc. $500,000,000 364-Day Revolving Credit Agreement dated as of November 13, 2001.
10b(8) Amendment, dated February 13, 2002, to X Progress Energy, Inc. $450,000,000 3-Year Revolving Credit Agreement dated November 13, 2001.
- -+*10c(1) Directors Deferred Compensation Plan X effective January 1, X 1982 as amended (filed as Exhibit 10(g), File No. 33-25560).
- -+*10c(2) Retirement Plan for Outside Directors (filed X as Exhibit 10(i), File No. 33-25560).
- -+*10c(3) Key Management Deferred Compensation Plan X (filed as Exhibit 10(k), File No. 33-25560).
+*10c(4) Resolutions of the Board of Directors, dated X March 15, X 1989, amending the Key Management Deferred Compensation Plan (filed as Exhibit 10(a), File No. 33-48607).
- -+*10c(5) Resolutions of the Board of Directors dated X X May 8, 1991, amending the CP&L Directors Deferred Compensation Plan (filed as Exhibit 10(b), File No. 33-48607).
+*10c(6) Resolutions of Board of Directors dated July X 9, 1997, X amending the Deferred Compensation Plan for Key Management Employees of Carolina Power & Light Company.
+*10c(7) Carolina Power & Light Company Non-Employee X X Director Stock Unit Plan, effective January 1, 1998.
- -+*10c(8) Carolina Power & Light Company Restricted X X Stock Agreement, as approved January 7, 1998, pursuant to the Company's 1997 Equity Incentive Plan (filed as Exhibit No. 10 to Quarterly Report on Form 10-Q for the quarterly period ended March 31, 1998, File No. 1-3382.)
- -+10c(9) Carolina Power & Light Company Restoration X X Retirement Plan, as amended January 1, 2000.
- -+*10c(10)Amended and Restated Supplemental Senior X X Executive Retirement Plan of Carolina Power & Light Company, effective January 1, 1984, as last amended March 15, 2000 (filed as Exhibit 10b(24) to Annual Report on Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3382).
- -+10c(11) Performance Share Sub-Plan of the 1997 Equity X X Incentive Plan, as amended January 1, 2001.
+*10c(12) 1997 Equity Incentive Plan, Amended and X X Restated as of X X September 26, 2001 (filed as Exhibit 4.3 to Progress Energy Form S-8 dated September 27, 2001, File No. 1-3382).
+*10c(13) Progress Energy, Inc. Form of Stock Option X Agreement (filed as Exhibit 4.4 to Form S-8 dated September 27, 2001, File No. 333-70332).
+*10c(14) Progress Energy, Inc. Form of Stock Option X Award (filed as Exhibit 4.5 to Form S-8 dated September 27, 2001, File No. 333-70332).
- -+10c(15) Amended Management Incentive Compensation X X Plan of Progress Energy, Inc., as amended and restated January 1, 2002.
- -+10c(16) Progress Energy, Inc. Management Deferred X X Compensation Plan, amended and restated as of January 1, 2002.
+*10c(17) Agreement dated April 27, 1999 between X Carolina Power & Light Company and Sherwood H. Smith, Jr. (filed as Exhibit 10b, File No. 1-3382).
+*10c(18) Employment Agreement dated August 1, 2000 X between CP&L Service Company LLC and William Cavanaugh III (filed as Exhibit 10(i) to Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2000, File No. 1-15929 and No. 1-3382).
+*10c(19) Employment Agreement dated August 1, 2000 X between Carolina Power & Light Company and William S. "Skip" Orser (filed as Exhibit 10(ii) to Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2000, File No. 1-15929 and No. 1-3382).
+*10c(20) Employment Agreement dated August 1, 2000 X between X Carolina Power & Light Company and Tom Kilgore (filed as Exhibit 10(iii) to Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2000, File No. 1-15929 and No. 1-3382).
+*10c(21) Employment Agreement dated August 1, 2000 X between CP&L Service Company LLC and Robert McGehee (filed as Exhibit 10(iv) to Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2000, File No. 1-
15929 and No. 1-3382).
+*10c(22) Form of Employment Agreement dated August 1, X X 2000 (i) X X between Carolina Power & Light Company and Don K. Davis; and (ii) between CP&L Service Company LLC and Peter M. Scott III and William D. Johnson (filed as Exhibit 10(v) to Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2000, File No. 1-15929 and No. 1-3382).
+*10c(23) Form of Employment Agreement dated August 1, X X 2000 (i) between Carolina Power & Light Company and Fred Day IV, C.S. "Scotty" Hinnant and E. Michael Williams; and (ii) between CP&L Service Company LLC and Bonnie V. Hancock and Cecil L. Goodnight (filed as Exhibit 10(vi) to Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2000, File No. 1-15929 and No. 1-3382).
+*10c(24) Employment Agreement dated November 30, 2000 X between Carolina Power & Light Company, Florida Power Corporation and H. William Habermeyer, Jr. (filed as Exhibit 10.(b)(32) to Florida Progress Corporation and Florida Power Corporation Annual Reports on Form 10-K for the year ended December 31, 2000).
12 Computation of Ratio of Earnings to Fixed X X Charges and Ratio of Earnings to Fixed Charges Preferred Dividends Combined.
21 Subsidiaries of Progress Energy, Inc. X
23(a) Consent of Deloitte & Touche LLP. X X
23(b) Consent of KPMG LLP. X
*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.
- -Sponsorship of this management contract or compensation plan or arrangement was transferred from Carolina Power & Light Company to Progress Energy, Inc., effective August 1, 2000.