-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, IJ/WzzmGVDZB5kGcliGLQmBuTzIGlYROuzwx1LskL8lfRKo3Bk91OUDICtjeuMsH tY1P7YSbzkMqW9Lfb2rQtw== 0001094093-04-000069.txt : 20040312 0001094093-04-000069.hdr.sgml : 20040312 20040312094629 ACCESSION NUMBER: 0001094093-04-000069 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20031231 FILED AS OF DATE: 20040312 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CAROLINA POWER & LIGHT CO CENTRAL INDEX KEY: 0000017797 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 560165465 STATE OF INCORPORATION: NC FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03382 FILM NUMBER: 04664297 BUSINESS ADDRESS: STREET 1: 411 FAYETTEVILLE ST CITY: RALEIGH STATE: NC ZIP: 27601 BUSINESS PHONE: 9195466111 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PROGRESS ENERGY INC CENTRAL INDEX KEY: 0001094093 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 562155481 STATE OF INCORPORATION: NC FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-15929 FILM NUMBER: 04664296 BUSINESS ADDRESS: STREET 1: 410 S WILMINGTON ST CITY: RALEIGH STATE: NC ZIP: 27601 BUSINESS PHONE: 9195466463 MAIL ADDRESS: STREET 1: 410 S WILMINGTON ST CITY: RALEIGH STATE: NC ZIP: 27601 FORMER COMPANY: FORMER CONFORMED NAME: CP&L ENERGY INC DATE OF NAME CHANGE: 20000314 FORMER COMPANY: FORMER CONFORMED NAME: CP&L HOLDINGS INC DATE OF NAME CHANGE: 19990830 10-K 1 pei_pgnpec10k-.txt 2003 PGN/PEC FORM 10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) [ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2003 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Exact name of registrants as specified in their Commission charters, state of incorporation, address of principal I.R.S. Employer File Number executive offices, and telephone number Identification Number 1-15929 Progress Energy, Inc. 56-2155481 410 South Wilmington Street Raleigh, North Carolina 27601-1748 Telephone: (919) 546-6111 State of Incorporation: North Carolina 1-3382 Carolina Power & Light Company 56-0165465 d/b/a Progress Energy Carolinas, Inc. 410 South Wilmington Street Raleigh, North Carolina 27601-1748 Telephone: (919) 546-6111 State of Incorporation: North Carolina SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Title of each class Name of each exchange on which registered Progress Energy, Inc.: Common Stock (Without Par Value) New York Stock Exchange SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: Progress Energy, Inc.: None Carolina Power & Light Company: $100 par value Preferred Stock, Cumulative $100 par value Serial Preferred Stock, Cumulative
Indicate by check mark whether the registrants (1) have filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X . No . Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of each registrant's knowledge, in definitive proxy or information statements incorporated by reference in PART III of this Form 10-K or any amendment to this Form 10-K. [ ] Indicate by check mark whether Progress Energy, Inc. is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes X . No . Indicate by check mark whether Carolina Power & Light Company is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes . No X . As of June 30, 2003, the aggregate market value of the voting and non-voting common equity of Progress Energy, Inc. held by non-affiliates was $10,586,386,401. As of June 30, 2003, the aggregate market value of the common equity of Carolina Power & Light Company held by non-affiliates was $0. All of the common stock of Carolina Power & Light Company is owned by Progress Energy, Inc. 1 As of January 30, 2004, each registrant had the following shares of common stock outstanding: Registrant Description Shares ---------- ----------- ------ Progress Energy, Inc. Common Stock (Without Par Value) 245,640,831 Carolina Power & Light Company Common Stock (Without Par Value) 159,608,055
DOCUMENTS INCORPORATED BY REFERENCE Portions of the Progress Energy and PEC definitive proxy statements dated March 31, 2004 are incorporated into PART III, ITEMS 10, 11, 12 , 13 and 14 hereof. This combined Form 10-K is filed separately by two registrants: Progress Energy, Inc. (Progress Energy) and Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC). Information contained herein relating to either individual registrant is filed by such registrant solely on its own behalf. 2 TABLE OF CONTENTS GLOSSARY OF TERMS SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS PART I ITEM 1. BUSINESS ITEM 2. PROPERTIES ITEM 3. LEGAL PROCEEDINGS ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS EXECUTIVE OFFICERS OF THE REGISTRANTS PART II ITEM 5. MARKET FOR THE REGISTRANTS' COMMON EQUITY AND RELATED SHAREHOLDER MATTERS ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE ITEM 9A. CONTROLS AND PROCEDURES PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS ITEM 11. EXECUTIVE COMPENSATION ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K PROGRESS ENERGY, INC. RISK FACTORS CAROLINA POWER & LIGHT COMPANY RISK FACTORS 3 GLOSSARY OF TERMS The following abbreviations or acronyms used in the text of this combined Form 10-K are defined below: TERM DEFINITION 401(k) Progress Energy 401(k) Savings and Stock Ownership Plan AFUDC Allowance for funds used during construction the Agreement Stipulation and Settlement Agreement related to retail rate matters AHI Affordable Housing investment ARO Asset Retirement Obligation Bcf Billion cubic feet Broad River Skygen Energy LLC's Broad River Facility Btu British thermal units Caronet Caronet, Inc. CCO Competitive Commercial Operations business segment CERCLA or Superfund Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended Code Internal Revenue Code Colona Colona Synfuel Limited Partnership, L.L.L.P. the Company Progress Energy, Inc. and subsidiaries CP&L Carolina Power & Light Company CR3 Progress Energy Florida's nuclear generating plant, Crystal River Unit No. 3 CVO Contingent value obligation DOE United States Department of Energy DWM North Carolina Department of Environment and Natural Resources, Division of Waste Management ENCNG Eastern North Carolina Natural Gas Company, formerly referred to as EasternNC EITF Emerging Issues Task Force E&TW Engineering and Trackwork EPA United States Environmental Protection Agency EPA of 1992 Energy Policy Act of 1992 EPIK EPIK Communications, Inc. ESOP Employee Stock Ownership Plan FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission FDEP Florida Department of Environment and Protection FIN No. 46 FASB Interpretation No. 46, "Consolidation of Variable Interest Entities - an Interpretation of ARB No. 51" FIN No. 46R December 2003 revision of FIN No. 46 Florida Progress or FPC Florida Progress Corporation FPSC Florida Public Service Commission Fuels Fuels business segment Funding Corp. Florida Progress Funding Corporation Genco Progress Genco Ventures LLC Georgia Power Georgia Power Company Global U.S. Global LLC Harris Plant Shearon Harris Nuclear Plant Interpath Interpath Communications, Inc. IBEW International Brotherhood of Electrical Workers IRS Internal Revenue Service ISO Independent System Operator Jackson Jackson Electric Membership Corporation kV Kilovolt kVA Kilovolt-ampere LIBOR London Inter Bank Offering Rate LRS Locomotive and Railcar Services LSEs Load-serving entities MACT Maximum Achievable Control Technology MDC Maximum Dependable Capability MGP Manufactured Gas Plant MW Megawatt 4 MWh Megawatt-hour NCNG North Carolina Natural Gas Corporation NCUC North Carolina Utilities Commission NEIL Nuclear Electric Insurance Limited NOx Nitrogen oxide NOx SIP Call EPA rule which requires 22 states including North and South Carolina to further reduce nitrogen oxide emissions. NRC United States Nuclear Regulatory Commission Nuclear Waste Act Nuclear Waste Policy Act of 1982 OPEB Postretirement benefits other than pensions Odyssey Odyssey Telecorp, Inc. P11 Intercession Unit P11 PEC Progress Energy Carolinas, Inc. PESC Progress Energy Service Company, LLC PFA IRS Prefiling Agreement the Plan Revenue Sharing Incentive Plan PLR Private Letter Ruling Power Agency North Carolina Eastern Municipal Power Agency PCH Progress Capital Holdings, Inc. Progress Energy Progress Energy, Inc. Progress Fuels Progress Fuels Corporation, formerly Electric Fuels Corporation Progress Rail Progress Rail Services Corporation Progress Ventures Business unit of Progress Energy primarily made up of nonregulated energy generation and marketing activities, as well as gas, coal and synthetic fuel operations Preferred Securities FPC-obligated mandatorily redeemable preferred securities of FPC Capital I PRP Potentially responsible party, as defined in CERCLA PSSP Performance Share Sub-Plan PTC Progress Telecommunications Corporation PTC LLC Progress Telecom, LLC PUHCA Public Utility Holding Company Act of 1935, as amended PURPA Public Utilities Regulatory Policies Act of 1978 PVI Progress Ventures, Inc. (formerly referred to as CPL Energy Ventures, Inc.) PWR Pressurized water reactor QF Qualifying facilities Rail Services Rail Services business segment Rockport Indiana Michigan Power Company's Rockport Unit No. 2 RSA Restricted Stock Awards program RTO Regional Transmission Organization SCPSC Public Service Commission of South Carolina SEC United States Securities and Exchange Commission Section 29 Section 29 of the Internal Revenue Service Code SFAS Statement of Financial Accounting Standards SFAS No. 5 Statement of Financial Accounting Standards No. 5, "Accounting for Contingencies" SFAS No. 71 Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" SFAS No. 87 Statement of Financial Accounting Standards No. 87, "Employers' Accounting for Pensions" SFAS No. 121 Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" SFAS No. 123 Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" SFAS No. 133 Statement of Financial Accounting Standards No. 133, "Accounting for Derivative and Hedging Activities" SFAS No. 138 Statement of Financial Accounting Standards No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - an Amendment of FASB Statement No. 133" SFAS No. 142 Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" 5 SFAS No. 143 Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" SFAS No. 144 Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" SFAS No. 148 Statement of Financial Accounting Standards No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - An Amendment of FASB Statement No. 123" SFAS No. 150 Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" SMD NOPR Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission and Standard Market Design SO2 Sulfur dioxide SRS Strategic Resource Solutions Corp. Tax Agreement Intercompany Income Tax Allocation Agreement the Trust FPC Capital I Westchester Westchester Gas Company
6 SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS The matters discussed throughout this Form 10-K that are not historical facts are forward-looking and, accordingly, involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. In addition, examples of forward-looking statements discussed in this Form 10-K, include a) PART II, ITEM 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" including, but not limited to, statements under the following headings: 1) "Liquidity and Capital Resources" about operating cash flows, estimated capital requirements through the year 2006 and future financing plans 2) "Strategy" about Progress Energy's strategy and 3) "Other Matters" about the effects of new environmental regulations, nuclear decommissioning costs and the effect of electric utility industry restructuring, and b) statements made in the "Risk Factors" sections. Any forward-looking statement speaks only as of the date on which such statement is made, and neither Progress Energy nor PEC undertakes any obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made. Examples of factors that you should consider with respect to any forward-looking statements made throughout this document include, but are not limited to, the following: the impact of fluid and complex government laws and regulations, including those relating to the environment; the impact of recent events in the energy markets that have increased the level of public and regulatory scrutiny in the energy industry and in the capital markets; deregulation or restructuring in the electric industry that may result in increased competition and unrecovered (stranded) costs; the uncertainty regarding the timing, creation and structure of regional transmission organizations; weather conditions that directly influence the demand for electricity; recurring seasonal fluctuations in demand for electricity; fluctuations in the price of energy commodities and purchased power; economic fluctuations and the corresponding impact on Progress Energy, Inc. and subsidiaries' (the Company) commercial and industrial customers; the ability of the Company's subsidiaries to pay upstream dividends or distributions to it; the impact on the facilities and the businesses of the Company from a terrorist attack; the inherent risks associated with the operation of nuclear facilities, including environmental, health, regulatory and financial risks; the ability to successfully access capital markets on favorable terms; the impact that increases in leverage may have on the Company; the ability of the Company to maintain its current credit ratings; the impact of derivative contracts used in the normal course of business by the Company; investment performance of pension and benefit plans and the ability to control costs; the availability and use of Internal Revenue Code Section 29 (Section 29) tax credits by synthetic fuel producers, and the Company's continued ability to use Section 29 tax credits related to its coal and synthetic fuel businesses; the Company's ability to successfully integrate newly acquired assets, properties or businesses into its operations as quickly or as profitably as expected; the Company's ability to manage the risks involved with the operation of its nonregulated plants, including dependence on third parties and related counter-party risks, and a lack of operating history; the Company's ability to manage the risks associated with its energy marketing operations; and unanticipated changes in operating expenses and capital expenditures. Many of these risks similarly impact the Company's subsidiaries. These and other risk factors are detailed from time to time in the Company's United States Securities and Exchange Commission (SEC) reports. Many, but not all of the factors that may impact actual results are discussed in the "Risk Factors" sections of this report. You should carefully read the "Risk Factors" sections of this report. All such factors are difficult to predict, contain uncertainties that may materially affect actual results and may be beyond the control of Progress Energy and PEC. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor can it assess the effect of each such factor on Progress Energy and PEC. 7 PART I ITEM 1. BUSINESS GENERAL COMPANY Progress Energy, Inc. (Progress Energy or the Company, which includes consolidated subsidiaries unless otherwise indicated) is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA) and is an integrated energy company located principally in the southeast region of the United States. Both the Company and its subsidiaries are subject to the regulatory provisions of PUHCA. Progress Energy was incorporated on August 19, 1999. The Company 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. Effective January 1, 2003, CP&L, Florida Power Corporation and Progress Ventures, Inc. began doing business under the names Progress Energy Carolinas, Inc. (PEC), Progress Energy Florida, Inc. (PEF) and Progress Energy Ventures, Inc. (Progress Ventures), respectively. The legal names of these entities have not changed and there was no restructuring of any kind related to the name change. The current corporate and business unit structure remains unchanged. Through its wholly-owned regulated subsidiaries PEC and PEF, Progress Energy is primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina, South Carolina and Florida. Through its Competitive Commercial Operations (CCO) business segment, Progress Energy is involved in nonregulated electricity generation operations. Through its Fuels business segment (Fuels), Progress Energy is involved in natural gas drilling and production, coal terminal services, coal mining, synthetic fuel production, fuel transportation and delivery. Both CCO and Fuels are involved in limited energy trading activities. Through its Rail Services business segment (Rail Services), Progress Energy engages in various rail and railcar related services. The Other Businesses segment primarily includes telecommunication services, miscellaneous nonregulated activities, and holding company operations. For information regarding the revenues, income and assets attributable to the Company's business segments, see PART II, ITEM 8, Note 19 to the Progress Energy Consolidated Financial Statements. The Company has more than 24,000 megawatts (MW) of electric generation capacity and serves more than 2.8 million retail electric customers in portions of North Carolina, South Carolina and Florida. PEC's and PEF's utility operations are complementary: PEC has a summer peaking demand, while PEF has a winter peaking demand. In addition, PEC's greater proportion of commercial and industrial customers combined with PEF's greater proportion of residential customers creates a 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, 2003 were $8.7 billion and assets at year-end were $26.2 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 and shall not be deemed a part of this document or any other U.S. Securities and Exchange Commission (SEC) filing. The Company makes available free of charge on its website its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. SIGNIFICANT TRANSACTIONS Progress Telecommunications Corporation Business Combination In December 2003, Progress Telecommunications Corporation (PTC) and Caronet, Inc. (Caronet), both wholly-owned subsidiaries of Progress Energy, and EPIK Communications, Inc. (EPIK), a wholly-owned subsidiary of Odyssey Telecorp, Inc. (Odyssey), contributed substantially all of their assets and transferred certain liabilities to Progress Telecom, LLC (PTC LLC), a subsidiary of PTC. Subsequently, the stock of Caronet was sold to an affiliate of Odyssey for $2 million in cash and Caronet became a wholly-owned subsidiary of Odyssey. Following consummation of all the transactions described above, PTC holds a 55 percent ownership interest in, and is the parent of PTC LLC. See PART II, ITEM 8, Note 4A to the Progress Energy Consolidated Financial Statements. 8 Mesa Hydrocarbons, Inc. Divestiture In October 2003, the Company sold certain gas-producing properties owned by Mesa Hydrocarbons, LLC, a wholly-owned subsidiary of Progress Fuels Corporation (Progress Fuels), which is included in the Fuels segment. Net proceeds of approximately $97 million were used to reduce debt. See PART II, ITEM 8, Note 3C to the Progress Energy Consolidated Financial Statements. NCNG Divestiture On September 30, 2003, the Company completed the sale of North Carolina Natural Gas Corporation (NCNG) and the Company's equity investment in Eastern North Carolina Natural Gas Company (ENCNG) to Piedmont Natural Gas Company, Inc. As a result of this action, the operating results of NCNG were reclassified to discontinued operations for all reportable periods. Net proceeds from the sale of NCNG and ENCNG of approximately $450 million were used to reduce debt. See PART II, ITEM 8, Note 3A to the Progress Energy Consolidated Financial Statements. Natural Gas Reserves Acquisition During 2003, Progress Fuels entered into several independent transactions to acquire approximately 200 natural gas-producing wells with proven reserves of approximately 190 billion cubic feet (Bcf) from Republic Energy, Inc. and three other privately-owned companies, all headquartered in Texas. The total cash purchase price for the transactions was approximately $168 million. See PART II, ITEM 8, Note 4B to the Progress Energy Consolidated Financial Statements. Wholesale Energy Contract Acquisition In May 2003, PVI entered into a definitive agreement with Williams Energy Marketing and Trading, a subsidiary of The Williams Companies, Inc., to acquire a long-term full-requirements power supply agreement at fixed prices with Jackson Electric Membership Corporation (Jackson), for $188 million. See PART II, ITEM 8, Note 4C to the Progress Energy Consolidated Financial Statements. Railcar Ltd. Divestiture In December 2002, the Progress Energy Board of Directors adopted a resolution approving the sale of the majority of the assets of Railcar Ltd., a leasing subsidiary included in the Rail Services segment. An estimated impairment on assets held for sale was recognized in December 2002 to write-down the assets to fair value less the costs to sell. In March 2003, the Company signed a letter of intent to sell the majority of Railcar Ltd. assets to The Andersons, Inc. The asset purchase agreement was signed in November 2003, and the transaction closed on February 12, 2004. Net proceeds from the sale were approximately $82 million. See PART II, ITEM 8, Note 3B to the Progress Energy Consolidated Financial Statements. Westchester Acquisition In April 2002, Progress Fuels acquired 100% of Westchester Gas Company (Westchester). The acquisition included approximately 215 natural gas-producing wells, 52 miles of intrastate gas pipeline and 170 miles of gas-gathering systems. The aggregate purchase price was approximately $153 million. See PART II, ITEM 8, Note 4E to the Progress Energy Consolidated Financial Statements. Generation Acquisition In February 2002, PVI acquired 100% of two electric generating projects in Georgia from LG&E Energy Corp., a subsidiary of Powergen plc. for a total cash purchase price of approximately $348 million. The transaction included tolling agreements and two power purchase agreements with LG&E Energy Marketing, Inc. See PART II, ITEM 8, Note 4D to the Progress Energy Consolidated Financial Statements. 9 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. The 108th Congress spent much of 2003 working on a comprehensive energy bill. While that legislation passed the House, the Senate failed to pass the legislation in 2003. There will probably be an effort to resurrect the legislation in 2004. The legislation would have further clarified the Federal Energy Regulatory Commission's (FERC) role with respect to Standard Market Design and mandatory Regional Transmission Organizations (RTOs) and would have repealed PUHCA. 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 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. In 2000, the FERC issued Order No. 2000 on RTOs, which set minimum characteristics and eight functions for transmission entities, including independent system operators (ISOs) 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 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 RTOs to be operational was extended. In July 2002, the FERC issued its Notice of Proposed Rulemaking in Docket No. RM01-12-000 Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). The proposed rules set forth in the SMD NOPR would require, among other things, that 1) all transmission-owning utilities transfer control of their transmission facilities to an independent third party; 2) transmission service to bundled retail customers be provided under the FERC-regulated transmission tariff, rather than state-mandated terms and conditions; 3) new terms and conditions for transmission service be adopted nationwide, including provisions for pricing transmission in the event of transmission congestion; 4) new energy markets be established for the buying and selling of electric energy; and 5) load-serving entities (LSEs) be required to meet minimum criteria for generating reserves. In 2003, the FERC released a White Paper on the Wholesale Market Platform. The White Paper provides an overview of what the FERC intends to include in a final rule in the SMD NOPR docket. The White Paper retains the fundamental and most protested aspects of SMD NOPR, including mandatory RTOs and the FERC's assertion of jurisdiction over certain aspects of retail service. The FERC has not yet issued a final rule on SMD NOPR. 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. There is currently no proposed legislation in North Carolina, South Carolina or Florida that would introduce retail choice. 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 Florida Progress Corporation (FPC) in November 2000. 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 PEC and PEF's load forecasts, plans for power supply and wholesale energy sales and related revenues. The impact could 10 vary depending on the extent to which additional generation is built to compete in the wholesale market, new opportunities are created for PEC and PEF to expand their wholesale load, or current wholesale customers elect to purchase from other suppliers after existing contracts expire. An 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 qualifying facilities (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. In November 2003, the FERC adopted new standards of conduct that apply uniformly to interstate natural gas pipelines and public utilities. The new standards of conduct govern the relationship between transmission providers and their energy affiliates in a manner that prevents market power and preferential treatment. Each utility was required to submit a plan and schedule for compliance with the new rules by February 2004. All utilities must be in compliance with the new rules no later than June 2004. PEC and PEF have submitted their plans and schedules for timely compliance. See PART I, ITEM 1, "Competition" of Electric-PEC and Electric-PEF for discussions of franchises as they relate to PEC and PEF. See PART I, ITEM 1, "Competition," under Electric-PEC, Electric-PEF 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 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, including the 2003 energy bill, have been introduced in Congress regarding PUHCA, the prospects for legislative reform or repeal are uncertain at this time. REGULATORY MATTERS GENERAL PEC and PEF are subject to regulation in North Carolina by the North Carolina Utilities Commission (NCUC), in South Carolina by the Public Service Commission of South Carolina (SCPSC) and in Florida by the Florida Public Service Commission (FPSC) with respect to, among other things, rates and service for electric energy sold at retail, retail service territory and issuances of securities. In addition, PEC and PEF are subject to regulation by the 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. NUCLEAR MATTERS GENERAL PEC owns and operates four nuclear units and PEF owns and operates one nuclear generating unit which are regulated by the United States 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, shut down a nuclear unit, or some combination of these, depending upon its assessment of the severity of the situation, until compliance is achieved. The nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, repairs and certain other modifications. 11 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. NRC operating licenses held by PEC currently expire in July 2010 for Robinson Unit No. 2, in December 2014 and September 2016 for Brunswick Units 2 and 1, respectively and in October 2026 for the Shearon Harris Nuclear Plant (Harris Plant). An application to extend the Robinson license 20 years was submitted in June 2002 and a similar application is expected to be made for the Brunswick Plant in December 2004 and for the Harris Plant in 2006. According to the NRC schedule, the Company expects to receive the new license extension for Robinson in April 2004. A condition of the operating license for each unit requires an approved plan for decontamination and decommissioning. In addition, PEC will request to have its license for the Independent Spent Fuel Storage Installation at the Robinson Plant extended 20 years with an exemption request for an additional 20-year extension during the first quarter of 2004. Its current license is due to expire in August 2006. PEC expects to receive this extension. PEF has a license to operate its Crystal River Unit No. 3 (CR3) nuclear generating plant through December 3, 2016. On February 20, 2003, PEF notified the NRC of its intent to submit an application to extend the plant license in the first quarter of 2009. PRESSURIZED WATER REACTORS In 2002, the NRC sent a bulletin to companies that hold licenses for pressurized water reactors (PWRs) requiring information on the structural integrity of the reactor vessel head and a basis for concluding that the vessel head will continue to perform its function as a coolant pressure boundary. Inspections of the vessel heads at the Company's PWR plants had been performed during previous outages. At the Robinson and Harris Plants, inspections were completed in 2001 and there was no degradation of the reactor vessel heads. The Company's Brunswick Plant has a different design and is not affected by the issue. Inspection of the vessel head at CR3 was performed during a previous outage and no degradation of the reactor vessel head was identified. In 2002, the NRC issued an additional bulletin dealing with head leakage due to cracks near the control rod nozzles, asking licensees to commit to high inspection standards to ensure the more susceptible plants have no cracks. The Robinson Plant is in this category and had a refueling outage in 2002. The Company completed a series of examinations in 2002 of the entire reactor pressure vessel head and found no indications of control rod drive mechanism cracking and no corrosion of the head itself. During the outage, a walkdown of the reactor coolant pressure boundary was also completed and no corrosion was found. The Company currently plans to re-inspect the Robinson Plant reactor head during its next refueling outage in 2004 and replace the head in 2005. The Harris Plant is ranked in the lowest susceptibility classification. PEF replaced the vessel head at CR3 during its regularly scheduled refueling outage in 2003. In 2003, the NRC issued an order requiring specific inspections of the reactor pressure vessel head and associated penetration nozzles at PWRs. The Company responded, stating that it intended to comply with the provisions of the Order. No adverse impact is anticipated. The NRC also issued a bulletin requesting PWR licensees to address inspection plans for reactor pressure vessel lower head penetrations. The Company plans to perform bare metal visual inspections of Robinson during the next regularly scheduled refueling outages in 2004. The Company completed a bare metal visual inspection of the vessel bottom at Harris and CR3 during their 2003 outages and found no signs of corrosion or leakage at either unit. The Company plans to do additional, more detailed inspections as part of the next scheduled 10-year in-service inspections. In February 2004, the NRC issued a revised Order for inspection requirements for reactor pressure vessel heads at PWRs. The Company is in the process of reviewing the Order. No adverse impact is anticipated. 12 SECURITY The NRC has issued various orders since September 2001 with regard to security at nuclear plants. These orders include additional restrictions on access, increased security measures and closer coordination with the Company's partners in intelligence, military, law enforcement and emergency response at the federal, state and local levels. The Company is completing the requirements as outlined in the orders by the established deadlines. As the NRC, other governmental entities and the industry continue to consider security issues, it is possible that more extensive security plans could be required. SPENT FUEL AND OTHER HIGH-LEVEL RADIOACTIVE WASTE The Nuclear Waste Policy Act of 1982 (Nuclear Waste Act) provides the framework for development by the federal government of interim storage and permanent disposal facilities for high-level radioactive waste materials. The Nuclear Waste Act promotes increased usage of interim storage of spent nuclear fuel at existing nuclear plants. The Company will continue to maximize the use of spent fuel storage capability within its own facilities for as long as feasible. With certain modifications and additional approval by the NRC including the installation of onsite dry storage facilities at Robinson (2005) and Brunswick (2008), PEC's spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on PEC's system through the expiration of the current operating licenses for all of PEC's nuclear generating units. PEF currently is storing spent nuclear fuel onsite in spent fuel pools. PEF will seek renewal of the CR3 operating license and currently, CR3 has sufficient storage capacity in place for fuel consumed through the end of the expiration of the current license in 2016. If PEF receives approval of the CR3 operating license renewal, dry storage may be necessary. See PART II, ITEM 8, Note 21E to the Progress Energy Consolidated Financial Statements and Note 16D to the PEC Consolidated Financial Statements for a discussion of the Company's contract with the U.S. Department of Energy (DOE) for spent nuclear waste. DECOMMISSIONING In PEC's and PEF'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 jurisdiction, the provisions for nuclear decommissioning costs are approved by the FERC. See PART II, ITEM 8, Note 5D to the Progress Energy Consolidated Financial Statements and Note 3D to the PEC Consolidated Financial Statements for a discussion of PEC and PEF's nuclear decommissioning costs. 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 estimated 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 2004 through 2006 are included in the "Investing Activities" discussion under PART II, ITEM 7, "Liquidity and Capital Resources". AIR QUALITY Amendments to the Federal Clean Air Act require substantial reductions in sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions from fossil-fueled electric generating plants. The Company meets the SO2 emissions requirements by maintaining sufficient SO2 emission allowances. Installation of additional equipment was necessary to reduce NOx emissions. Increased operation and maintenance costs, including emission allowance expense, installation of additional equipment and increased fuel costs are not material to the consolidated financial position or results of operations of the Company. 13 There has been and may be further proposed federal legislation requiring reductions in air emissions for NOx, SO2, carbon dioxide and mercury. Some of these proposals establish nationwide caps and emission rates over an extended period of time. This national multi-emission approach to air pollution control could involve significant capital costs which could be material to the Company's financial operations. Some companies may seek recovery of the related costs through rate adjustments or similar mechanisms. Control equipment that will be installed on North Carolina fossil generating facilities as part of the North Carolina law discussed below may address some of the issues outlined above. However, the Company cannot predict the outcome of this matter. The U.S. Environmental Protection Agency (EPA) is 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 PEC and PEF were asked to provide information to the EPA as part of this initiative and cooperated in providing the requested information. The EPA 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 or similar mechanisms. The Company cannot predict the outcome of this matter. In 2003, the EPA published a final rule addressing routine equipment replacement under the New Source Review program. The rule defines routine equipment replacement and the types of activities that are not subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The rule was challenged in federal court and its implementation has been stayed. The Company cannot predict the outcome of this matter. In 1998, the EPA published a final rule at Section 110 of the Clean Air Act addressing the issue of regional transport of ozone (NOx SIP Call). The EPA's rule requires 23 jurisdictions, including North Carolina, South Carolina and Georgia, but not Florida, to further reduce NOx emissions in order to attain a pre-set state emission level during each year's "ozone season," beginning May 31, 2004. PEC is currently installing controls necessary to comply with the rule and expects to be in compliance as required by the final rule. Capital expenditures to meet these measures in North Carolina and South Carolina could reach approximately $370 million, which has not been adjusted for inflation. The Company has spent approximately $258 million to date 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. 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. This rule, as originally promulgated, required certain sources to make reductions in NOx emissions by May 1, 2003. The final rule also includes a set of regulations that affect NOx emissions from sources included in the petitions. The North Carolina coal-fired 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. In April 2002, the EPA published a final rule harmonizing the 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. The EPA has approved North Carolina's NOx SIP Call rule and has indicated it will rescind the Section 126 rule in a future rulemaking. In June 2002, legislation was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of NOx and SO2 from coal-fired power plants. Operation and maintenance costs will increase due to the additional personnel, materials and general maintenance associated with the equipment. Operation and maintenance expenses are recoverable through base rates, rather than as part of this program. The legislation also freezes the utilities' base rates for five years unless there are extraordinary events beyond the control of the utilities or unless the utilities persistently earn a return substantially in excess of the rate of return established and found reasonable by the NCUC in the utilities' last general rate case. See PART II, ITEM 8, Note 21E to the Progress Energy Consolidated Financial Statements and Note 16D to the Progress Energy Carolinas Consolidated Financial Statements for further discussion. 14 In 1997, the EPA's Mercury Study Report and Utility Report to Congress conveyed that mercury is not a risk to the average American and expressed uncertainty about whether reductions in mercury emissions from coal-fired power plants would reduce human exposure. Nevertheless, the EPA determined in 2000 that regulation of mercury emissions from coal-fired power plants was appropriate. In December 2003, the EPA proposed and solicited comment on two alternative control plans that would limit mercury emissions from coal-fired power plants. The agency has indicated that it will choose one of the alternatives as the final rule, which is expected to be promulgated in December 2004. Achieving compliance with either proposal could involve significant capital costs. The Company cannot predict the outcome of this matter. In conjunction with the proposed mercury rule, the EPA proposed a Maximum Achievable Control Technology (MACT) standard to regulate nickel emissions from residual oil-fired units. The agency estimates the proposal will reduce national nickel emissions to approximately 103 tons. The rule is expected to become final in December 2004. The company cannot predict the outcome of this matter. In December 2003, the EPA released its proposed Interstate Air Quality Rule (commonly known as the Fine Particulate Transport Rule and/or the Regional Transport Rule). The EPA's proposal requires 28 jurisdictions, including North Carolina, South Carolina, Georgia and Florida, to further reduce NOx and SO2 emissions in order to attain pre-set state NOx and SO2 emissions levels (which have not yet been determined). The rule is expected to become final in 2004. The installation of controls necessary to comply with the rule could involve significant capital costs. The Company cannot predict the outcome of this matter. WATER QUALITY As a result of the operation of certain control equipment needed to address the air quality issues outlined above, new wastewater streams may be generated. Integration of these new wastewater streams into existing wastewater treatment processes may result in permitting, construction and water treatment challenges to the Company in the immediate and extended future. After many years of litigation and settlement negotiations the EPA published final regulations in February 2004 for the implementation of Section 316(b) of the Clean Water Act. The purpose of these regulations is to minimize any adverse environmental impact caused by cooling water intake structures and intake systems located at existing facilities. Over the next several years these regulations may require the facilities to mitigate the effects to aquatic organisms by undertaking intake modifications or other restorative activities. Substantial costs could be incurred by the facilities in order to comply with the new regulations. The Company cannot predict the outcome and impacts to the facilities at this time or its cost to comply with any new regulations. 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 liabilities. 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 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 have some connection. In this regard, both electric utilities, with other potentially responsible parties (PRP), 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 (FDEP) 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 the current status of these sites, the Company cannot predict the outcome of this matter. 15 Both electric utilities, Progress Fuels and Progress Rail Services Corporation (Progress Rail) 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 cannot predict the outcome of this matter. EMPLOYEES As of January 31, 2004, Progress Energy and its subsidiaries employed approximately 15,300 full-time employees. Of this total, approximately 2,200 employees at PEF are represented by the International Brotherhood of Electrical Workers (IBEW). PEF and the IBEW reached agreement in December 2002 on a new three-year labor contract. 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 January 31, 2004, PEC employed approximately 5,200 full-time employees. ELECTRIC - PEC GENERAL PEC 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. At December 31, 2003, PEC had a total summer generating capacity (including jointly-owned capacity) of approximately 12,416 MW. PEC distributes and sells electricity in 56 of the 100 counties in North Carolina and 15 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, 2003, PEC was providing electric services, retail and wholesale, to approximately 1.3 million customers. Major wholesale power sales customers include North Carolina Eastern Municipal Power Agency (Power Agency) and North Carolina Electric Membership Corporation. PEC is subject to the rules and regulations of the FERC, the NCUC and the SCPSC. BILLED ELECTRIC REVENUES PEC's electric revenues billed by customer class, for the last three years, are shown as a percentage of total PEC electric revenues in the table below: BILLED ELECTRIC REVENUES Revenue Class 2003 2002 2001 ------------- ---- ---- ---- Residential 35% 35% 34% Commercial 24% 24% 23% Industrial 18% 18% 19% Wholesale 19% 19% 19% Other retail 4% 4% 5% Major industries in PEC's service area include textiles, chemicals, metals, paper, food, rubber and plastics, wood products and electronic machinery and equipment. 16 FUEL AND PURCHASED POWER Sources of Generation PEC's total system generation (including jointly-owned capacity) by primary energy source, along with purchased power, for the last three years is set forth below: ENERGY MIX PERCENTAGES 2003 2002 2001 ---- ---- ---- Coal 46% 46% 49% Nuclear 44% 42% 41% Hydro 1% 1% 0% Oil/Gas 2% 3% 2% Purchased power 7% 8% 8% PEC 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, PEC believes that its fuel supply contracts, as described below, will be adequate to meet its fuel supply needs. PEC's average fuel costs per million British thermal units (Btu) for the last three years were as follows: AVERAGE FUEL COST (per million Btu) 2003 2002 2001 ---- ---- ---- Coal $ 2.00 $ 1.93 $ 1.78 Nuclear 0.43 0.43 0.44 Hydro - - - Oil 6.69 5.48 6.38 Gas 8.32 5.31 4.69 Weighted-average 1.43 1.38 1.26 Changes in the unit price for oil and gas are due to market conditions. Changes in the unit price for coal between 2001 and 2002 are primarily due to transportation costs. Changes in the unit price for coal between 2002 and 2003 are being driven by increases in market prices for coal in 2003. Since these costs are primarily recovered through recovery clauses established by regulators, fluctuations do not materially affect net income. Coal PEC anticipates a requirement of approximately 11.3 million to 11.6 million tons of coal in 2004. Almost all of the coal will be supplied from Appalachian coal sources in the United States and is primarily delivered by rail. For 2004, PEC has short-term, intermediate and long-term agreements from various sources for approximately 83% of its burn requirements of its coal units. Two of these contracts are index priced and the remainder are annually fixed price. The contracts have expiration dates ranging from 2004 to 2008. PEC will continue to sign contracts of various lengths, terms and quality to meet its expected burn requirements. All of the coal that PEC has purchased under intermediate and long-term agreements is considered to be low sulfur coal by industry standards. 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 uranium oxide concentrate and the conversion of this 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. 17 PEC has sufficient uranium, conversion, enrichment and fabrication contracts to meet its near-term nuclear fuel requirement needs. PEC typically contracts for all of its enrichment services and fabrication needs with contract durations ranging from five to ten years. Recent shutdown of a major North American conversion facility and increased uncertainty of uranium supply has raised the risk of supply disruption. As a result, Progress Energy has adjusted its nuclear fuel inventory and procurement strategy accordingly to offset increased supply disruption risk by increasing planned delivery lead times and strategic inventory stockpiles. For a discussion of PEC's plans with respect to spent fuel storage, see PART I, ITEM 1, "Nuclear Matters." Hydroelectric Hydroelectric power is electric energy generated by the force of falling water. PEC has three hydroelectric generating plants licensed by the FERC: Walters, Tillery and Blewett. PEC also owns the Marshall Plant which has a license exemption. The total maximum dependable capacity for these units is 218 MW. PEC is seeking to relicense its Tillery and Blewett Plants. These plants' licenses currently expire in April 2008. The Walters Plant license will expire in 2034. Oil & Gas Natural gas and oil supply for PEC's generation fleet is purchased under term and spot contracts from several suppliers. The cost of PEC's oil and gas is determined by market prices as reported in certain industry publications. PEC believes that it has access to an adequate supply of oil for the reasonably foreseeable future. PEC's natural gas transportation is purchased under term firm transportation contracts with interstate pipelines. PEC also purchases capacity on a seasonal basis from numerous shippers for its peaking load requirements. PEC believes that existing contracts for oil are sufficient to cover its requirements if natural gas is unavailable during a normal winter period for PEC's combustion turbine and combined cycle fleet. Purchased Power PEC purchased approximately 4.5 million MWh in 2003, approximately 5.2 million MWh in 2002 and approximately 5.3 million MWh in 2001 of its system energy requirements and had available 1,810 MW in 2003, 1,737 MW in 2002 and 1,756 MW in 2001 of firm purchased capacity under contract at the time of peak load. PEC may acquire purchased power capacity in the future to accommodate a portion of its system load needs. COMPETITION Electric Industry Restructuring PEC continues to monitor any developments that occur toward a more competitive environment and has actively participated in regulatory reform deliberations in North Carolina and South Carolina. PEC expects that both the North Carolina and South Carolina General Assemblies will continue to monitor the experiences of states that have implemented electric restructuring legislation. Regional Transmission Organizations In October 2000, as a result of Order 2000, PEC, along with Duke Energy Corporation and South Carolina Electric & Gas Company, filed an application with the FERC for approval of a GridSouth RTO. In July 2001, the FERC issued an order provisionally approving GridSouth. However, in July 2001, the FERC issued orders recommending that companies in the southeast engage in a mediation to develop a plan for a single RTO for the Southeast. PEC participated in the mediation. The FERC has not issued an order specifically on this mediation. See PART II, ITEM 7, "Other Matters" for additional discussion of current developments of GridSouth RTO. Standard Market Design See PART I, ITEM 1, "General," under Competition for further discussion of Standard Market Design developments. 18 Franchises PEC 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 13 of the 194 franchises with expiration dates have a term of sixty years. The exceptions include three franchises with terms of ten years, one with a term of twenty years, six with terms of thirty years, two with terms of forty years and one with a term of fifty years. PEC also serves within a number of municipalities and in all of its unincorporated areas without franchise agreements. Wholesale Competition See PART I, ITEM 1, "General," under Competition for a discussion of wholesale competition. Stranded Costs See PART I, ITEM 1, "General," under Competition for a discussion of stranded costs. REGULATORY MATTERS Retail Rate Matters 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 PEC's most recent rate cases in 1988, the NCUC and the SCPSC each authorized a return on equity of 12.75% for PEC. Legislation enacted in North Carolina in 2002 freezes PEC's base retail rates for five years unless there are extraordinary events beyond the control of PEC, in which case PEC can petition for a rate increase. See PART II, ITEM 8, Note 21E to the Progress Energy Consolidated Financial Statements and Note 16D to the PEC Consolidated Financial Statements for further discussion of PEC's rate freeze. See PART II, ITEM 8, Note 7B to the Progress Energy Consolidated Financial Statements and Note 5B to the PEC Consolidated Financial Statements for further discussion of PEC's retail rate developments during 2003. Wholesale Rate Matters PEC is subject to regulation by the FERC with respect to rates for transmission and sale of electric energy at wholesale, the interconnection of facilities in interstate commerce (other than interconnections for use in the event of certain emergency situations), the licensing and operation of hydroelectric projects and, to the extent the FERC determines, accounting policies and practices. PEC 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. Fuel Cost Recovery PEC'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 PEC, by state, are as follows: o North Carolina - fuel costs and the fuel portion of purchased power o South Carolina - fuel costs, certain 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. 19 NUCLEAR MATTERS PEC is currently 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 at the Robinson Nuclear Plant in 2002. Power uprates are also in progress at the Brunswick Plant. Brunswick Unit 1 increased its capacity by 52 MW in 2002 and Brunswick 2 increased its capacity by 89 MW in 2003. Additional increases will be implemented in phases over the next couple of years. The total increased generation from all these projects is estimated to be approximately 290 MW. See PART I, ITEM 1, "Nuclear Matters," for further discussion of these and other nuclear matters. ENVIRONMENTAL MATTERS There are nine former MGP sites and other sites associated with PEC that have required or are anticipated to require investigation and/or remediation costs. In September 2003, the Company sold NCNG to Piedmont Natural Gas Company, Inc. As part of the sales agreement, the Company retained responsibility to remediate five former NCNG MGP sites to state standards pursuant to an Administrative Order by consent. At the time of the sale, the liability for these costs and the related accrual was transferred to PEC. Presently, PEC cannot determine the total costs that may be incurred in connection with the remediation of any of these MGP sites. See PART II, ITEM 8, Note 21E to the Progress Energy Consolidated Financial Statements and Note 16D to the PEC Consolidated Financial Statements for further discussion of these environmental matters. ELECTRIC - PEF GENERAL PEF 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, 2003, PEF had a total summer generating capacity (including jointly-owned capacity) of approximately 8,544 MW. PEF provided electric service during 2003 to an average of 1.5 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. PEF is interconnected with 20 municipal and nine rural electric cooperative systems. Major wholesale power sales customers include Seminole Electric Cooperative, Inc., Florida Municipal Power Agency, Florida Power & Light Company and Tampa Electric Company. PEF is subject to the rules and regulations of the FERC and the FPSC. BILLED ELECTRIC REVENUES PEF's electric revenues billed by customer class for the last three years, are shown as a percentage of total PEF electric revenues in the table below: BILLED ELECTRIC REVENUES Revenue Class 2003 2002 2001 ------------- ---- ---- ---- Residential 55% 55% 54% Commercial 24% 24% 24% Industrial 7% 7% 7% Others 6% 6% 6% Wholesale 8% 8% 9% Important industries in PEF's territory include phosphate 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. 20 FUEL AND PURCHASED POWER General PEF's consumption of various types of fuel depends on several factors, the most important of which are the demand for electricity by PEF's customers, the availability of various generating units, the availability and cost of fuel and the requirements of federal and state regulatory agencies. PEF's energy mix for the last three years is presented in the following table: ENERGY MIX PERCENTAGES Fuel Type 2003 2002 2001 --------- ---- ---- ---- Coal (a) 36% 33% 33% Oil 16% 16% 16% Nuclear 14% 15% 15% Gas 13% 15% 14% Purchased Power 21% 21% 22% (a) Amounts include synthetic fuel from unrelated third parties and petroleum coke. PEF 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, PEF believes that its fuel supply contracts, as described below, will be adequate to meet its fuel supply needs. PEF's average fuel costs per million Btu for the last three years were as follows: AVERAGE FUEL COST (per million Btu) 2003 2002 2001 ------ ------ ------ Coal (a) $ 2.42 $ 2.43 $ 2.16 Oil 4.38 3.77 3.81 Nuclear 0.50 0.46 0.47 Gas 5.98 4.06 4.52 Weighted-average 3.07 2.60 2.59 (a) Amounts include synthetic fuel from unrelated third parties and petroleum coke. 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, fluctuations do not materially affect net income. Coal PEF anticipates a combined requirement of approximately 6.0 million to 6.5 million tons of coal in 2004. Most of the coal is expected to be supplied from Appalachian coal sources in the United States. Approximately two-thirds of the fuel is expected to be delivered by rail and the remainder by barge. All of this fuel is supplied by Progress Fuels, a subsidiary of Progress Energy, pursuant to contracts between PEF and Progress Fuels. For 2004, Progress Fuels has medium-term and long-term contracts with various sources for approximately 100% of the burn requirements of PEF's coal units. These contracts have price adjustment provisions and have expiration dates ranging from 2004 to 2006. Progress Fuels will continue to sign contracts of various lengths, terms and quality to meet PEF's expected burn requirements. All the coal to be purchased for PEF is considered to be low sulfur coal by industry standards. Oil and Gas Natural gas and oil supply for PEF's generation fleet is purchased under term and spot contracts from several suppliers. The majority of the cost of PEF's oil and gas is determined by market prices as reported in certain industry publications. PEF believes that it has access to an adequate supply of oil for the reasonably foreseeable future. PEF's natural gas transportation is purchased under term firm transportation contracts with interstate pipelines. PEF also purchases capacity on a seasonal basis from numerous shippers and interstate 21 pipelines to serve its peaking load requirements. PEF also uses interruptible transportation contracts on certain occasions when available. PEF believes that existing contracts for oil are sufficient to cover its requirements if natural gas is unavailable during certain time periods. 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 uranium oxide concentrate and the conversion of this 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. PEF has sufficient uranium, conversion, enrichment and fabrication contracts to meet its near-term nuclear fuel requirements needs. PEF typically contracts for all of its future long-term uranium, conversion and enrichment service needs with contract durations ranging from five to ten years. Recent shutdown of a major North American conversion facility and increased uncertainty of uranium supply has raised the risk of supply disruption. As a result, Progress Energy has adjusted its nuclear fuel inventory and procurement strategy accordingly to offset increased supply disruption risk by increasing planned delivery lead times and strategic inventory stockpiles. Purchased Power PEF, along with other Florida utilities, buys and sells power in the wholesale market on a short-term and long-term basis. At December 31, 2003, PEF had a variety of purchase power agreements for the purchase of approximately 1,313 MW of firm power. These agreements include (1) long-term contracts for the purchase of about 474 MW of purchased power with other investor-owned utilities, including a contract with The Southern Company for approximately 414 MWs, and (2) approximately 839 MWs of capacity under contract with certain QFs. The capacity currently available from QFs represents about 10% of PEF's total installed system capacity. COMPETITION Electric Industry Restructuring PEF continues to monitor developments 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 developments related to deregulation of the electric industry in other states. In response to a legislative directive, the FPSC and the FDEP submitted in February 2003 a joint report on renewable electric generating technologies for Florida. The report assessed the feasibility and potential magnitude of renewable electric capacity for Florida, and summarized the mechanisms other states have adopted to encourage renewable energy. The report did not contain any policy recommendations. The Company cannot anticipate when, or if, restructuring legislation will be enacted or if the Company would be able to support it in its final form. Regional Transmission Organizations As a result of Order 2000, PEF, along with Florida Power & Light Company and Tampa Electric Company (the Applicants) filed with the FERC in October 2000 an application for approval of a GridFlorida RTO. The GridFlorida proposal is pending before both the FERC and the FPSC. The FERC provisionally approved the structure and governance of GridFlorida. The Commission's most recent order in December 2003 ordered further state proceedings. It is unknown when the FERC or the FPSC will take final action with regard to the status of GridFlorida or what the impact of further proceedings will have on the Company's earnings, revenues or pricing. See PART II, ITEM 7, "Other Matters," for a discussion of current developments of GridFlorida RTO. Standard Market Design See PART I, ITEM 1, "General," under Competition for further discussion of standard market design developments. 22 Franchise Agreements PEF holds franchises with varying expiration dates in 107 of the municipalities in which it distributes electric energy. PEF also serves 14 other municipalities and in all its unincorporated areas without franchise agreements. The general effect of these franchises is to provide for the manner in which PEF occupies rights-of-way in incorporated areas of municipalities for the purpose of constructing, operating and maintaining an energy transmission and distribution system. Approximately 44% of PEF's total utility revenues for 2003 were from the incorporated areas of the 107 municipalities that had franchise ordinances during the year. Since 2000, PEF has renewed 32 expiring franchises and reached agreement on a franchise with a city that did not previously have a franchise. Franchises with five municipalities have expired without renewal. All but 26 of the existing franchises cover a 30-year period from the date enacted. The exceptions are 22 franchises, each with a term of 10 years and expiring between 2005 and 2012; two franchises each with a term of 15 years and expiring in 2017; 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 107 franchises, 36 expire between January 1, 2004 and December 31, 2012 and 71 expire between January 1, 2013 and December 31, 2034. Ongoing negotiations and, in some cases, litigation are taking place with certain municipalities to reach agreement on franchise terms and to enact new franchise ordinances. See PART II, ITEM 7, "Other Matters," for a discussion of PEF's franchise litigation. Stranded Costs The largest stranded cost exposure for PEF is its commitment to QFs. PEF has taken a proactive approach to this industry issue. PEF continues to seek ways to address the impact of escalating payments from contracts it was obligated to sign under provisions of PURPA. See PART I, ITEM 1, "General," under Competition for further discussion. Wholesale Competition See PART I, ITEM 1, "General," under Competition for a discussion of wholesale competition. REGULATORY MATTERS General PEF is subject to the jurisdiction of the FPSC with respect to, among other things, rates and service for electric energy sold at retail, retail service territory and issuances of securities. In addition, PEF is subject to regulation by the 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. Retail Rate Matters 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. In March 2002, the parties in PEF's rate case entered into a Stipulation and Settlement Agreement (the Agreement) related to retail rate matters. The Agreement was approved by the FPSC and is generally effective from May 1, 2002 through December 31, 2005. The Agreement eliminates the authorized Return on Equity (ROE) range normally used by the FPSC for the purpose of addressing earning levels; provided, however, that if PEF's base rate earnings fall below a 10% return on equity, PEF may petition the FPSC to amend its base rates. The Agreement is described in more detail in PART II, ITEM 8, Note 7D to the Progress Energy Consolidated Financial Statements. 23 Fuel and Other Cost Recovery PEF's operating costs not covered by the utility's base rates include fuel, purchased power, energy conservation expenses and specific environmental costs. 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. In addition, in December 2002, the FPSC approved an Environmental Cost Recovery Clause (ECRC) which permits the Company to recover the costs of specified environmental projects to the extent these expenses are found to be prudent in an annual hearing and not otherwise included in base rates. Costs are recovered through this recovery clause in the same manner as the other existing clause mechanisms. 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 In late 2002, CR3 received a license amendment authorizing a small power level increase. The power level increase of approximately four MW was implemented in February 2003. See PART I, ITEM 1, "Nuclear Matters," for further discussion of these and other nuclear matters. ENVIRONMENTAL MATTERS There are two former MGP sites and other sites associated with PEF that have required or are anticipated to require investigation and/or remediation costs. In addition, there are distribution substations and transformers which are also anticipated to incur investigation and remediation costs. Presently, PEF cannot determine the total costs that may be included in connection with the remediation of all sites. See PART II, ITEM 8, Note 21E to the Progress Energy Consolidated Financial Statements for further discussion of these environmental matters. FUELS The Fuels business segment owns an array of assets that produce, transport and deliver fuel and provide related services for the open market. The Fuels business segment has subsidiaries that produce natural gas and oil products, blend and transload coal, mine coal, and others that produce a solid coal-based synthetic fuel. This product has been classified as a synthetic fuel within the meaning of Section 29. Sales of synthetic fuel therefore qualify for tax credits. See PART II, ITEM 7, "Other Matters," for a discussion of the synthetic fuel tax credits. The current combined assets of Fuels which are involved in fuel extraction, manufacturing and delivery include: o Natural gas properties in Texas and Louisiana producing about 30 Bcf per year; o Five terminals on the Ohio River and its tributaries, part of the trucking, rail and barge network for coal delivery; o Three coal-mining complexes, expected to produce about 3 million tons per year: o Five wholly-owned synthetic fuel entities, and a 10% minority interest in one synthetic fuel entity, capable of producing up to 18 million tons per year; o Majority-ownership in a barge partnership that moves coal products from the mouth of the Mississippi River to the CR3 facility in Florida. During 2003, Progress Fuels acquired approximately 200 natural gas-producing wells with proven reserves of approximately 190 Bcf from Republic Energy, Inc. and three other privately-owned companies, all headquartered in Texas. The total cash purchase price for the transactions was approximately $168 million. See PART II, ITEM 8, Note 4B to the Progress Energy Consolidated Financial Statements. 24 COMPETITION Fuels' synthetic fuel operations and coal operations compete in the eastern United States industrial coal markets. Factors contributing to the success in these markets include a competitive cost structure and strategic locations. There are, however, numerous competitors in each of these markets, although no one competitor is dominant in any industry. Fuels' gas production operations compete in the East Texas, North Texas and North Louisiana region. Factors contributing to success include a competitive cost structure. Although there are numerous small, independent competitors in this market, the major oil and gas producers dominate this industry. ENVIRONMENTAL MATTERS See PART II, ITEM 8, Note 21E to the Progress Energy Consolidated Financial Statements for a discussion of Fuel's environmental matters. COMPETITIVE COMMERCIAL OPERATIONS (CCO) CCO sells capacity and energy on the wholesale market outside the realm of retail regulation. CCO currently owns six plants with approximately 3,100 MW of generation capacity. CCO has contracts representing 85% of planned production capacity for 2004 and 50% of planned production capacity for 2005 and 2006. In May 2003, PVI acquired from Williams Energy Marketing and Trading, a subsidiary of the Williams Companies, Inc., a long-term full-requirements power supply agreement at fixed prices with Jackson, for $188 million. CCO is responsible for marketing the energy produced by the nonregulated plants. The energy is sold under both term contracts and in the spot market. CCO markets the nonregulated plants not under contract into the nonregulated market and engages in limited financial trading activities primarily for hedging the fuel and economic value of its generation portfolio. CCO is also responsible for purchasing fuel for the merchant generation fleet, such as natural gas and oil. CCO 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 CCO does not operate in the same environment as regulated utilities. It operates specifically in the wholesale market, which means competition is its primary driver. CCO competes in the eastern United States utility markets. Factors contributing to the success in these markets include a competitive cost structure and strategic locations. RAIL SERVICES The Rail Services business segment, led by 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 two business units: Locomotive and Railcar Services (LRS) and Engineering and Trackwork (E&TW). The LRS unit is primarily focused on railroad rolling stock that includes freight cars, transit cars and locomotives, the repair and maintenance of these units, the manufacturing or reconditioning of major components for these units and scrap metal recycling. The E&TW unit focuses on rail and other track components, the infrastructure which supports the operation of rolling stock, and the equipment used in maintaining the railroad infrastructure and right-of-way. The Recycling division of the LRS unit supports both business units through its reclamation of reconditionable material and 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 short line railroads, North American transit systems, railcar and locomotive builders, and railcar lessors. The U.S. operations are located in 23 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. 25 In March 2003, the Company signed a letter of intent to sell the majority of Railcar Ltd. assets to the Andersons, Inc. A definitive purchase agreement was signed in November 2003 and the transaction closed in February 2004. See PART II, ITEM 8, Note 3B to the Progress Energy Consolidated Financial Statements for a discussion of this transaction. ENVIRONMENTAL MATTERS See PART II, ITEM 8, Note 21E to the Progress Energy Consolidated Financial Statements for a discussion of Rail's environmental matters. OTHER GENERAL The Other Businesses segment primarily includes the operations of PTC LLC and Strategic Resource Solutions Corp. (SRS). This segment also includes other nonregulated operations of PEC and FPC. PROGRESS TELECOM LLC In December 2003, PTC and Caronet, both wholly-owned subsidiaries of Progress Energy, and EPIK, a wholly-owned subsidiary of Odyssey, contributed substantially all of their assets and transferred certain liabilities to PTC LLC, a subsidiary of PTC. Subsequently, the stock of Caronet was sold to an affiliate of Odyssey for $2 million in cash and Caronet became a wholly-owned subsidiary of Odyssey. Following consummation of all the transactions described above, PTC holds a 55 percent ownership interest in, and is the parent, of PTC LLC; Odyssey holds a combined 45 percent ownership interest in PTC LLC through EPIK and Caronet. The accounts of PTC LLC are included in the Company's Consolidated Financial Statements since the transaction date. PTC LLC 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. PTC LLC markets wholesale fiber-optic-based capacity service in the Eastern United States to long-distance carriers, internet service providers and other telecommunications companies. PTC LLC also markets wireless structure attachments to wireless communication companies and governmental entities. At December 31, 2003, PTC LLC owned and managed more than 8,500 route miles and more than 420,000 fiber miles of fiber-optic cable. PTC LLC competes with other providers of fiber-optic telecommunications services, including local exchange carriers and competitive access providers, in the Eastern United States. Lease revenue for dedicated transport and data services is generally billed in advance on a fixed rate basis and recognized over the period the services are provided. Revenues relating to design and construction of wireless infrastructure are recognized upon completion of services for each completed phase of design and construction. For additional information regarding asset and investment impairments related to the Company's investments in the telecommunications industry, see PART II, ITEM 8, Note 9 to the Progress Energy Consolidated Financial Statements, and Note 6 to the PEC Consolidated Financial Statements. NCNG In October 2002, the Company approved the sale of NCNG. In September 2003, the Company completed the sale of NCNG and the Company's equity investment in ENCNG to Piedmont Natural Gas Company, Inc. See PART II, ITEM 8, Note 3A to the Progress Energy Consolidated Financial Statements for further discussion of this transaction. 26 ELECTRIC UTILITY OPERATING STATISTICS - PROGRESS ENERGY Years Ended December 31 2003 2002 2001 2000(d) 1999 ------------ ----------- ----------- ----------- ---------- Energy supply (millions of kilowatt-hours) Generated - Steam 51,501 49,734 48,732 31,132 28,260 Nuclear 30,576 30,126 27,301 23,857 22,451 Hydro 955 491 245 441 520 Combustion Turbines/Combined Cycle 7,819 8,522 6,644 1,337 435 Purchased 13,848 14,305 14,469 5,724 5,132 ------------ ----------- ----------- ----------- ---------- Total energy supply (Company share) 104,699 103,178 97,391 62,491 56,798 Jointly-owned share (a) 5,213 5,258 4,886 4,505 4,353 ------------ ----------- ----------- ----------- ---------- Total system energy supply 109,912 108,436 102,277 66,996 61,151 ============ =========== =========== =========== ========== Average fuel cost (per million Btu) Fossil $ 2.94 $ 2.62 $ 2.46 $ 1.96 $ 1.75 Nuclear fuel $ 0.44 $ 0.44 $ 0.45 $ 0.45 $ 0.46 All fuels $ 2.05 $ 1.84 $ 1.77 $ 1.30 $ 1.16 Energy sales (millions of kilowatt-hours) Retail Residential 34,712 33,993 31,976 15,365 13,348 Commercial 24,110 23,888 23,033 12,221 11,068 Industrial 16,749 16,924 17,204 14,762 14,568 Other Retail 4,382 4,287 4,149 1,626 1,359 Wholesale 19,841 19,204 17,715 15,012 14,526 Unbilled 189 275 (1,045) 1,098 (110) ------------ ----------- ----------- ----------- ---------- Total energy sales 99,983 98,571 93,032 60,084 54,759 Company uses and losses 3,753 3,604 3,478 2,286 2,039 ------------ ----------- ----------- ----------- ---------- Total energy requirements 103,736 102,175 96,510 62,370 56,798 ============ =========== =========== =========== ========== Electric revenues (in millions) Retail $ 5,620 $ 5,515 $ 5,462 $ 2,799 $ 2,531 Wholesale 915 881 923 665 556 Miscellaneous revenue 206 205 172 81 60 -------------- ----------- ----------- ----------- ---------- Total electric revenues $ 6,741 $ 6,601 $ 6,557 $ 3,545 $ 3,147 ============ =========== =========== =========== ========== Peak demand of firm load (thousands of kW) System (b) 19,876 20,365 19,166 18,874 10,948 Company 19,235 19,746 18,564 18,272 10,344 Total regulated capability at year-end (thousands of kW) Fossil plants 16,522 16,006 15,826 (e) 14,747 6,736 Nuclear plants 4,220 (g) 4,127 (f) 4,008 4,008 3,174 Hydro plants 218 218 218 218 218 Purchased 2,826 2,929 2,890 2,278 1,088 ------------ ----------- ----------- ---------- --------- Total system capability 23,786 23,280 22,942 21,251 11,216 Less jointly-owned portion (c) 698 682 668 662 593 ------------ ----------- ----------- ---------- --------- Total Company capability - regulated 23,088 22,598 22,274 20,589 10,623 ============ =========== =========== ========== =========
(a) Amounts represent co-owner's share of the energy supplied from the six generating facilities that are jointly owned. (b) For 2000 - 2003, this represents the combined summer non-coincident system net peaks for PEC and PEF. (c) For PEC, this represents Power Agency's retained share of jointly-owned facilities per the Power Coordination Agreement between PEC and Power Agency. (d) Amounts include information for PEF since November 30, 2000, the date of acquisition. (e) Amount includes 459 MW related to Rowan units that were transferred to PVI in February 2002. (f) Amount includes power uprates for Harris, Brunswick 1 and Robinson. The Maximum Dependable Capability (MDC) for Harris was restated January 2002; the MDCs for Brunswick 1 and Robinson were restated January 2003. (g) Amount includes power uprates for CR3 and Brunswick 2. The MDC's were restated January 2004. 27 OPERATING STATISTICS - PROGRESS ENERGY CAROLINAS Years Ended December 31 2003 2002 2001 2000 1999 ----------- ----------- ----------- ----------- --------- Energy supply (millions of kilowatt-hours) Generated - Steam 28,522 28,547 27,913 29,520 28,260 Nuclear 24,537 23,425 21,321 23,275 22,451 Hydro 955 491 245 441 520 Combustion Turbines/Combined Cycle 1,344 1,934 802 733 435 Purchased 4,467 5,213 5,296 4,878 5,132 ----------- ----------- ----------- ----------- --------- Total energy supply (Company share) 59,825 59,610 55,577 58,847 56,798 Power Agency share (a) 4,670 4,659 4,348 4,505 4,353 ----------- ----------- ----------- ----------- --------- Total system energy supply 64,495 64,269 59,925 63,352 61,151 =========== =========== =========== =========== ========= Average fuel cost (per million Btu) Fossil $ 2.29 $ 2.16 $ 1.91 $ 1.83 $ 1.75 Nuclear fuel $ 0.43 $ 0.43 $ 0.44 $ 0.45 $ 0.46 All fuels $ 1.43 $ 1.38 $ 1.26 $ 1.21 $ 1.16 Energy sales (millions of kilowatt-hours) Retail Residential 15,283 15,239 14,372 14,091 13,348 Commercial 12,557 12,468 11,972 11,432 11,068 Industrial 12,749 13,089 13,332 14,446 14,568 Other Retail 1,408 1,437 1,423 1,423 1,359 Wholesale 15,518 15,024 12,996 14,582 14,526 Unbilled (44) 270 (534) 679 (110) ----------- ----------- ----------- ----------- --------- Total energy sales 57,471 57,527 53,561 56,653 54,759 Company uses and losses 2,354 2,083 2,016 2,194 2,039 ----------- ----------- ----------- ----------- --------- Total energy requirements 59,825 59,610 55,577 58,847 56,798 =========== =========== =========== =========== ========= Electric revenues (in millions) Retail $ 2,825 $ 2,795 $ 2,666 $ 2,609 $ 2,531 Wholesale 687 652 634 577 556 Miscellaneous revenue 77 92 44 122 59 ----------- ----------- ----------- ----------- --------- Total electric revenues $ 3,589 $ 3,539 $ 3,344 $ 3,308 $ 3,146 =========== =========== =========== =========== ========= Peak demand of firm load (thousands of kW) System 11,771 11,977 11,376 11,157 10,948 Company 11,130 11,358 10,774 10,555 10,344 Total regulated capability at year-end (thousands of kW) Fossil plants 8,816 8,816 8,648 (c) 7,569 6,891 Nuclear plants 3,382 (e) 3,293 (d) 3,174 3,174 3,174 Hydro plants 218 218 218 218 218 Purchased 1,513 1,617 1,586 978 1,088 ----------- ----------- ---------- ---------- --------- Total system capability 13,929 13,944 13,626 11,939 11,371 Less Power Agency-owned portion (b) 629 613 599 593 593 ----------- ----------- ---------- ---------- --------- Total Company capability 13,300 13,331 13,027 11,346 10,778 =========== =========== ========== ========== =========
(a) Amounts represent Power Agency's share of the energy supplied from the four generating facilities that are jointly owned. (b) Amounts represent Power Agency's retained share of jointly-owned facilities per the Power Coordination Agreement between PEC and Power Agency. (c) Amount includes 459 MW related to Rowan units that were transferred to PVI in February 2002. (d) Amount includes power upgrades for Harris, Brunswick 1 and Robinson. The MDC for Harris was restated January 2002; the MDCs for Brunswick 1 and Robinson were restated January 2003. (e) Amount includes power uprate for Brunswick 2; the MDC was restated January 2004. 28 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 - PEC At December 31, 2003, PEC's eighteen generating plants represent a flexible mix of fossil, nuclear, hydroelectric, combustion turbines and combined cycle resources, with a total summer generating capacity of 12,416 MW. Of this total, Power Agency owns approximately 682 MW. On December 31, 2003, PEC had the following generating facilities: - -------------------------------------------------------------------------------------------------------------------- PEC Summer Net No. of In-Service Ownership Capability (a) Facility Location Units Date Fuel (in %) (in MW) - -------------------------------------------------------------------------------------------------------------------- STEAM TURBINES Asheville Skyland, NC 2 1964-1971 Coal 100 392 Cape Fear Moncure, NC 2 1956-1958 Coal 100 316 Lee Goldsboro, NC 3 1952-1962 Coal 100 407 Mayo Roxboro, NC 1 1983 Coal 83.83 745 (b) Robinson Hartsville, SC 1 1960 Coal 100 174 Roxboro Roxboro, NC 4 1966-1980 Coal 96.32 (c) 2,462 (b) Sutton Wilmington, NC 3 1954-1972 Coal 100 613 Weatherspoon Lumberton, NC 3 1949-1952 Coal 100 176 -------- --------------- Total 19 5,285 COMBINED CYCLE Cape Fear Moncure, NC 2 1969 Oil 100 84 Richmond Hamlet, NC 1 2002 Gas/Oil 100 472 -------- --------------- Total 3 556 COMBUSTION TURBINES Asheville Skyland, NC 2 1999-2000 Gas/Oil 100 330 Blewett Lilesville, NC 4 1971 Oil 100 52 Darlington Hartsville, SC 13 1974-1997 Gas/Oil 100 812 Lee Goldsboro, NC 4 1968-1971 Oil 100 91 Morehead City Morehead City, NC 1 1968 Oil 100 15 Richmond Hamlet, NC 5 2001-2002 Gas/Oil 100 775 Robinson Hartsville, SC 1 1968 Gas/Oil 100 15 Roxboro Roxboro, NC 1 1968 Oil 100 15 Sutton Wilmington, NC 3 1968-1969 Gas/Oil 100 64 Wayne County Goldsboro, NC 4 2000 Gas/Oil 100 668 Weatherspoon Lumberton, NC 4 1970-1971 Gas/Oil 100 138 -------- --------------- Total 42 2,975 NUCLEAR Brunswick Southport, NC 2 1975-1977 Uranium 81.67 1,772 (b)(d) Harris New Hill, NC 1 1987 Uranium 83.83 900 (b) Robinson Hartsville, SC 1 1971 Uranium 100 710 -------- --------------- Total 4 3,382 HYDRO Blewett Lilesville, NC 6 1912 Water 100 22 Marshall Marshall, NC 2 1910 Water 100 5 Tillery Mount Gilead, NC 4 1928-1960 Water 100 86 Walters Waterville, NC 3 1930 Water 100 105 -------- --------------- Total 15 218 TOTAL 83 12,416 - --------------------------------------------------------------------------------------------------------------------
(a) Amounts represent PEC's net summer peak rating, gross of co-ownership interest in plant capacity. (b) Facilities are jointly owned by PEC and Power Agency. The capacities shown include Power Agency's share. (c) PEC and Power Agency are co-owners of Unit 4 at the Roxboro Plant. PEC's ownership interest in this 700 MW turbine is 87.06%. (d) During 2003, a power uprate increased the net summer capability of Unit 2 to 900 MWs. The MDC was restated in January 2004. 29 At December 31, 2003, including both the total generating capacity of 12,416 MWs and the total firm contracts for purchased power of approximately 1,513 MWs, PEC had total capacity resources of approximately 13,929 MWs. 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, PEC 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. PEC also owns certain easements over private property on which transmission and distribution lines are located. At December 31, 2003, PEC had approximately 6,000 circuit miles of transmission lines including about 300 miles of 500 kilovolt (kV) lines and about 3,000 miles of 230 kV lines. PEC had distribution lines of approximately 45,000 circuit miles of overhead conductor and about 17,000 circuit miles of underground cable. Distribution and transmission substations in service had a transformer capacity of approximately 12,000,000 kilovolt-ampere (kVA) in 2,411 transformers. Distribution line transformers numbered approximately 502,700 with an aggregate capacity of about 21,000,000 kVA. ELECTRIC - PEF At December 31, 2003, PEF's fourteen generating plants represent a flexible mix of fossil, nuclear, combustion turbine and combined cycle resources with a total summer generating capacity (including jointly-owned capacity) of 8,544 MW. At December 31, 2003, PEF had the following generating facilities: - ------------------------------------------------------------------------------------------------------------------ PEF Summer Net No. of In-Service Ownership Capability (a) Facility Location Units Date Fuel (in %) (in MW) - ------------------------------------------------------------------------------------------------------------------ STEAM TURBINES Anclote Holiday, FL 2 1974-1978 Gas/Oil 100 993 Bartow St. Petersburg, FL 3 1958-1963 Gas/Oil 100 444 Crystal River Crystal River, FL 4 1966-1984 Coal 100 2,302 Suwannee River Live Oak, FL 3 1953-1956 Gas/Oil 100 143 ------- --------------- Total 12 3,882 COMBINED CYCLE Hines Bartow, FL 2 1999-2003 Gas/Oil 100 998 Tiger Bay Fort Meade, FL 1 1997 Gas 100 207 ------- --------------- Total 3 1,205 COMBUSTION TURBINES Avon Park Avon Park, FL 2 1968 Gas/Oil 100 52 Bartow St. Petersburg, FL 4 1958-1972 Gas/Oil 100 187 Bayboro St. Petersburg, FL 4 1973 Oil 100 184 DeBary DeBary, FL 10 1975-1992 Gas/Oil 100 667 Higgins Oldsmar, FL 4 1969-1970 Gas/Oil 100 122 Intercession City Intercession City, FL 14 1974-2000 Gas/Oil 100 (c) 1,041 (b) Rio Pinar Rio Pinar, FL 1 1970 Oil 100 13 Suwannee River Live Oak, FL 3 1980 Gas/Oil 100 164 Turner Enterprise, FL 4 1970-1974 Oil 100 154 University of Gainesville, FL 1 1994 Gas 100 35 Florida Cogeneration ------- --------------- Total 47 2,619 NUCLEAR Crystal River Crystal River, FL 1 1977 Uranium 91.8 838 (b) (d) ------- --------------- Total 1 838 TOTAL 63 8,544 - ------------------------------------------------------------------------------------------------------------------
(a) Amounts represent PEF's net summer peak rating, gross of co-ownership interest in plant capacity. (b) Facilities are jointly owned. The capacities shown include joint owners' share. (c) PEF and Georgia Power Company (Georgia Power) are co-owners of a 143 MW advanced combustion turbine located at PEF's Intercession City site (P11). Georgia Power has the exclusive right to the output of this unit during the months of June through September. PEF has that right for the remainder of the year. (d) During 2003, a power uprate increased the net summer capability of this unit to 838 MWs. The MDC was restated in January 2004. 30 At December 31, 2003, PEF had total capacity resources of approximately 9,857 MWs, including both the total generating capacity of 8,544 MWs and the total firm contracts for purchased power of 1,313 MWs. Several entities have acquired undivided ownership interests in CR3 in the aggregate amount of 8.2%. The joint ownership participants are: City of Alachua - - 0.08%, City of Bushnell - 0.04%, City of Gainesville - 1.41%, Kissimmee Utility Authority - 0.68%, City of Leesburg - 0.82%, Utilities Commission of the City of New Smyrna Beach - 0.56%, City of Ocala - 1.33%, Orlando Utilities Commission - 1.60% and Seminole Electric Cooperative, Inc. - 1.70%. PEF and Georgia Power are co-owners of a 143 MW advance combustion turbine located at PEF's Intercession City site (P11). Georgia Power has the exclusive right to the output of this unit during the months of June through September. PEF has that right for the remainder of the year. Otherwise, PEF 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. PEF also owns certain easements over private property on which transmission and distribution lines are located. At December 31, 2003, PEF had approximately 5,000 circuit miles of transmission lines including about 200 miles of 500 kV lines and about 1,500 miles of 230 kV lines. PEF had distribution lines of approximately 25,000 circuit miles of overhead conductor and about 15,000 circuit miles of underground cable. Distribution and transmission substations in service had a transformer capacity of approximately 45,000,000 kVA in 614 transformers. Distribution line transformers numbered 356,930 with an aggregate capacity of about 18,000,000 kVA. FUELS The Fuels business segment controls, either directly or through business units, coal reserves located in eastern Kentucky and southwestern Virginia. Fuels owns properties that contain estimated coal reserves of approximately 60 million tons and controls, through mineral leases, additional estimated coal reserves of approximately 18 million tons. The reserves controlled include substantial quantities of high quality, low sulfur coal that is appropriate for use at PEF's existing generating units. Fuels' total production of coal during 2003 was approximately 3.5 million tons. In connection with its coal operations, Fuels' business units 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, a river terminal facility in eastern Kentucky, a railcar-to-barge loading facility in West Virginia and two bulk commodity terminals on the Kanawha River near Charleston, West Virginia. Fuels employs both company and contract miners in their mining activities. The Fuels business segment, through its business units, owns all of the interests in five synthetic fuel entities and a minority interest in one synthetic fuel entity that owns facilities that produce synthetic fuel. These facilities are in six different locations in West Virginia, Virginia and Kentucky. Fuels' natural gas and oil production in 2003 was 25.4 Bcf equivalent. Fuels has oil and gas leases in East Texas, North Texas and Louisiana with total proven natural gas and oil reserves of approximately 360 Bcf equivalent. CCO At December 31, 2003, CCO had the following nonregulated generation plants in service. - ---------------------------------------------------------------------------------------------------------------- Construction Commercial Configuration/ Project Location Start Date Operation Date Number of Units MW (a) - ---------------------------------------------------------------------------------------------------------------- Monroe Units 1 and 2 Monroe, GA 4Q 1998/1Q 2000 4Q 1999/2Q 2001 Simple-Cycle, 2 315 Rowan Phase I (b) Salisbury, NC 1Q 2000 2Q 2001 Simple-Cycle, 3 459 Walton (c) Monroe, GA 2Q 2000 2Q 2001 Simple-Cycle, 3 460 DeSoto Units Arcadia, FL 2Q 2001 2Q 2002 Simple-Cycle, 2 320 Effingham Rincon, GA 1Q 2001 3Q 2003 Combined-Cycle, 1 480 Rowan Phase II (b) Salisbury, GA 4Q 2001 2Q 2003 Combined-Cycle, 1 466 Washington (c) Sandersville, GA 2Q 2002 2Q 2003 Simple-Cycle, 4 600 ----------- TOTAL 3,100 - ----------------------------------------------------------------------------------------------------------------
(a) Amounts represent CCO's summer rating. (b) This project was transferred from PEC to PVI in February 2002. (c) These projects were purchased from LG&E Energy Corp. in February 2002. 31 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 23 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. PTC PTC LLC provides wholesale telecommunications services throughout the Southeastern United States. PTC LLC incorporates more than 420,000 fiber miles of fiber-optic cable in its network including more than 185 Points-of-Presence, or physical locations where a presence for network access exists. 32 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. 1. Strategic Resource Solutions Corp. ("SRS") v. San Francisco Unified School District, et al., Sacramento Superior Court, Case No. 02AS033114 In November 2001, SRS filed a claim against the San Francisco Unified School District ("the District") and other defendants claiming that SRS is entitled to approximately $10 million in unpaid contract payments and delay and impact damages related to the District's $30 million contract with SRS. In March 2002, the District filed a counterclaim, seeking compensatory damages and liquidated damages in excess of $120 million, for various claims, including breach of contract and demand on a performance bond. SRS has asserted defenses to the District's claims. SRS has amended its claims and asserted new claims against the District and other parties, including a former SRS employee and a former District employee. On March 13, 2003, the City Attorney and the District filed new claims against SRS, Progress Energy, Inc., Progress Energy Solutions, Inc., and certain individuals, alleging fraud, false claims, violations of California statutes, and seeking compensatory damages, punitive damages, liquidated damages, treble damages, penalties, attorneys' fees and injunctive relief. The filing states that the City and the District seek "more than $300 million in damages and penalties." PEC was added as a cross-defendant. The Company, SRS, Progress Energy Solutions, Inc. and PEC all have denied the District's allegations and cross-claims. Discovery is in progress in the matter. The case has been assigned to a judge under the Sacramento County superior court's case management rules, and the judge and the parties have been conferring on scheduling and processes to narrow or resolve issues, if possible, and to prepare the case for trial. No trial date has been set. SRS and the Company are vigorously defending all of these claims. The Company cannot predict the outcome of this matter, but will vigorously defend against the allegations. 2. Collins v. Duke Energy Corporation et al, Civil Action No. 03CP404050 In August 2003, PEC was served as a co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation et al, Civil Action No. 03CP404050, in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. PEC is one of three electric utilities operating in South Carolina named in the suit. The plaintiffs are seeking damages for the alleged improper use of electric easements but have not asserted a dollar amount for their damage claims. The complaint alleges that the licensing of attachments on electric utility poles, towers and other structures to non-utility third parties or telecommunication companies for other than the electric utilities' internal use along the electric right-of-way constitutes a trespass. In September 2003, PEC filed a motion to dismiss all counts of the complaint on substantive and procedural grounds. In October 2003, the plaintiffs filed a motion to amend their complaint. PEC believes the amended complaint asserts the same factual allegations as are in the original complaint and also seeks money damages and injunctive relief. The court has not yet held any hearings or made any rulings in this case. In November 2003, PEC filed a motion to dismiss the plaintiffs' first amended complaint. PEC cannot predict the outcome of any future proceedings in this matter, but will vigorously defend against the allegations. 33 3. U.S. Global, LLC v. Progress Energy, Inc. et al, Case No. 03004028-03 and Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC, Case No. 03004028-03 A number of Progress Energy, Inc. subsidiaries and affiliates are parties to two lawsuits arising out of an Asset Purchase Agreement dated as of October 19, 1999, by and among U.S. Global LLC (Global), EARTHCO, certain affiliates of EARTHCO (collectively the EARTHCO Sellers), EFC Synfuel LLC (which is owned indirectly by Progress Energy, Inc.) and certain of its affiliates, including Solid Energy LLC, Solid Fuel LLC, Ceredo Synfuel LLC, Gulf Cost Synfuel LLC (currently named Sandy River Synfuel LLC) (Collectively the Progress Affiliates), as amended by an Amendment to Purchase Agreement as of August 23, 2000 (the Asset Purchase Agreement). Global has asserted that pursuant to the Asset Purchase Agreement it is entitled to (1) interest in two synthetic fuel facilities currently owned by the Progress Affiliates, and (2) an option to purchase additional interests in the two synthetic fuel facilities. The first suit, U.S. Global, LLC v. Progress Energy, Inc. et al, was filed in the Circuit Court for Broward County, Florida on March 4, 2003 (the Florida Global Case). The Florida Global Case asserts claims for breach of the Asset Purchase Agreement and other contract and tort claims related to the Progress Affiliates' alleged interference with Global's rights under the Asset Purchase Agreement. The Florida Global Case requests an unspecified amount of compensatory damages, as well as declaratory relief. On December 15, 2003, the Progress Affiliates filed a motion to dismiss the Third Amended Complaint in the Florida Global Case. The second suit, Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC, was filed by the Progress Affiliates in the Superior Court for Wake County, North Carolina seeking declaratory relief consistent with the Company's interpretation of the Asset Purchase Agreement (the North Carolina Global Case). Global was served with the North Carolina Global Case on April 17, 2003. On May 15, 2003, Global moved to dismiss the North Carolina Global Case for lack of personal jurisdiction over Global. In the alternative, Global requested that the court decline to exercise its discretion to hear the Progress Affiliates' declaratory judgment action. On August 7, 2003, the Wake County Superior Court denied Global's motion to dismiss and entered an order staying the North Carolina Global Case, pending the outcome of the Florida Global Case. The Progress Affiliates have appealed the Superior Court's order staying the case; Global has cross appealed the denial of its motion to dismiss for lack of personal jurisdiction. The North Carolina Court of Appeals has not set a hearing date for the Progress Affiliates' Appeal or Global's cross appeal. The Company cannot predict the outcome of these matters, but will vigorously defend against the allegations. 4. Gerber Asset Management LLC v. William Cavanaugh III and Progress Energy, Inc. et al, Case No. 04 CV 636 On February 3, 2004, Progress Energy, Inc. was served with a class action complaint alleging violations of federal security laws in connection with the Company's issuance of Contingent Value Obligations (CVOs). The action was filed in the United States District Court for the Southern District of New York and names Progress Energy, Inc. Chairman William Cavanaugh III and Progress Energy, Inc. as defendants. The Complaint alleges that Progress Energy failed to timely disclose the impact of the Alternative Minimum Tax required under Sections 55-59 of the Internal Revenue Code (Code) on the value of certain CVOs issued in connection with the Florida Progress Corporation merger. The suit seeks unspecified compensatory damages, as well as attorneys' fees and litigation costs. The Company is currently reviewing the complaint and cannot predict the outcome of this matter, but will vigorously defend against the allegations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS NONE 34 EXECUTIVE OFFICERS OF THE REGISTRANTS Name Age Recent Business Experience Robert B. McGehee 60 President and Chief Executive Officer, Progress Energy, October 2002 and March 1, 2004, respectively, to present. Mr. McGehee joined the Company (formerly CP&L) in 1997 as Senior Vice President and General Counsel. Since that time, he has held several senior management positions of increasing responsibility. Most recently, Mr. McGehee served as President and Chief Operating Officer of the Company, having responsibility for the day-to-day operations of the Company's regulated and nonregulated businesses. Prior to that, Mr. McGehee served as President and Chief Executive Officer of Progress Energy Service Company, LLC. Before joining Progress Energy, Mr. McGehee chaired the board of Wise Carter Child & Caraway, a law firm headquartered in Jackson, Miss. He primarily handled corporation, contract, nuclear regulatory and employment matters. During the 1990s, he also provided significant counsel to U.S. companies on reorganizations, business growth initiatives and preparing for deregulation and other industry changes. William S. Orser 59 Group President, Energy Supply, PEC and PEF, November 2000 to present. Mr. Orser is responsible for the operation of 38 utility and nonregulated power plants of Progress Energy. He also oversees the organizations that support those plants, as well as the Company's System Planning and Operations function. Mr. Orser joined Progress Energy (formerly CP&L) in 1993 as Executive Vice President and Chief Nuclear Officer. He later became Executive Vice President - Energy Supply, PEC, a position he held until the acquisition of Florida Progress in 2000. Before joining the Company in April 1993, Mr. Orser was an executive at the Detroit Edison Company, serving as Executive Vice President - Nuclear Generation. Previously, he worked with Portland General Electric Co. William D. Johnson 50 Group President, Energy Delivery, Progress Energy, January 2004 to present; Executive Vice President, Progress Energy Service Company, LLC, January 1, 2004 to present; PEC, FPC and PEF November 2000 to present. Mr. Johnson has been with Progress Energy (formerly CP&L) since 1992 and most recently served as President, CEO and Corporate Secretary, Progress Energy Service Company, LLC, October 2002 to December 2003. Prior to that, he was Executive Vice President - Corporate Relations & Administrative Services, General Counsel and Secretary of Progress Energy. Mr. Johnson served as Vice President - Legal Department and Corporate Secretary, CP&L from 1997 to 1999. Before joining Progress Energy, Johnson was a partner with the Raleigh office of Hunton & Williams, where he specialized in the representation of utilities. 35 Peter M. Scott III 54 President and Chief Executive Officer, Progress Energy Service Company, LLC, January 2004 to present; Executive Vice President, FPC, PEC, PEF, and Progress Energy Service Company, LLC, 2000 to present. Mr. Scott has been with the Company since May 2000 and most recently served as Executive Vice President and Chief Financial Officer of Progress Energy, Inc., May 2000 to December 2003. In that position, Mr. Scott oversaw the Company's strategic planning, financial and enterprise risk management functions. Before joining Progress Energy, Mr. Scott was the founding president of Scott, Madden & Associates, Inc., a general management consulting firm headquartered in Raleigh, N.C. The firm served clients in a number of industries, including energy and telecommunications. Particular practice area specialties for Mr. Scott included strategic planning and operations management. Geoffrey S. Chatas 41 Executive Vice President and Chief Financial Officer, Progress Energy, Inc., FPC, PEC and PEF, January 2004 to present. Mr. Chatas oversees the Company's accounting, strategic planning, tax, financial and regulatory services and enterprise risk management functions. He previously served as Senior Vice President, Progress Energy, Inc., October 2003 to December 2003. Before joining Progress Energy, Mr. Chatas served as Senior Vice President - Finance and Treasurer for American Electric Power, a multi-state energy holding company based in Columbus, Ohio. During his time at AEP, he managed investor relations and corporate finance. In addition, Mr. Chatas held executive financial positions at Banc One and Citibank. Robert H. Bazemore, Jr. 49 Chief Accounting Officer and Controller, Progress Energy, Inc., June 2000 to present; Controller, FPC and PEF, November 2000 to present; Vice President and Controller, Progress Energy Service Company, LLC, August 2000 to present; Chief Accounting Officer and Controller, PEC, May 2000 to present. Mr. Bazemore has been with Progress Energy (formerly CP&L) since 1986 and has served in a number of roles in corporate support and field positions, including Director, CP&L, Operations & Environmental Support Department, December 1998 to May 2000; Manager, CP&L Financial & Regulatory Accounting, September 1995 to December 1998. Prior to joining Progress Energy, Mr. Bazemore worked in managerial and accounting positions with companies in Roanoke, VA and Jacksonville, FL. Brenda F. Castonguay 51 Senior Vice President, Progress Energy Service Company, LLC, July 2002 to present. Ms. Castonguay directs the work of the Human Resources, Corporate Services, Real Estate, IT/Telecommunications and Corporate Security departments. She joined Progress Energy (formerly CP&L) in February 1994 as assistant to the Vice President - Human Resources. She has also served as Manager - Human Resources Administrative Services and Vice President - Human Resources. During her tenure with Progress Energy's Human Resources Department, Ms. Castonguay has managed human resources activities and initiatives affecting approximately 16,000 full-time employees. Before joining the Company, Ms. Castonguay held managerial positions with Maine Yankee Atomic Power Co., Central Maine Power Co. and General Telephone & Electronics (GTE) Corp. 36 Donald K. Davis 58 Executive Vice President, PEC, May 2000 to present. Mr. Davis is also President and Chief Executive Officer, SRS, June 2000 to present and was President and Chief Executive Officer, NCNG, July 2000 to September 2003. Mr. Davis joined the Company in May 2000 as Executive Vice President, Gas and Energy Services. Before joining the Company, Mr. Davis was Chairman, President and Chief Executive Officer of Yankee Atomic Electric Company, and served as Chairman, President and Chief Executive Officer of Connecticut Atomic Power Company from 1997 to May 2000 where he was responsible for two electric wholesale generating companies. Before joining Yankee Atomic Power Co., Davis served as a principal of PRISM Consulting Inc., a utility management consulting firm he founded in 1992. Fred N. Day IV 60 President and Chief Executive Officer, PEC, October 2003 to present; Executive Vice President, PEF, November 2000 to present. Mr. Day oversees all aspects of Carolinas Delivery operations, including distribution and customer service, transmission, and products and services. He previously served as Executive Vice President, PEC and PEF. During his more than 30 years with Progress Energy (formerly CP&L), Mr. Day has held several management positions of increasing responsibility. He was promoted to Vice President - Western Region in 1995. *H. William Habermeyer, Jr. 61 President and Chief Executive Officer, PEF, November 2000 to present. Mr. Habermeyer joined Progress Energy (formerly PEC) in 1993 after a career in the U.S. Navy. During his tenure with the Company, Mr. Habermeyer has served as Vice President - Nuclear Services and Environmental Support; Vice President - Nuclear Engineering; and Vice President - Western Region. While overseeing Western Region operations, Mr. Habermeyer was responsible for regional distribution management, customer support and community relations. *Bonnie V. Hancock 42 President, Progress Fuels Corporation, September 2002 to present. Ms. Hancock has served in several positions since joining Progress Energy (formerly CP&L) in 1993, including Director - Federal Tax, Vice President and Controller and Vice President - Strategic Planning. Before joining the Company, Ms. Hancock directed all tax planning and research activities at Potomac Electric Power Co. in Washington, D.C. She also worked in management positions with Finalco, Inc. and Aronson, Greene, Fisher and Co. CPAs. C.S. Hinnant 59 Senior Vice President and Chief Nuclear Officer, PEC, June 1998 to present. Mr. Hinnant joined Progress Energy (formerly CP&L) in 1972 at the Brunswick Nuclear Plant near Southport, N.C., where he held several positions in the startup testing and operating organizations. He left Progress Energy in 1976 to work for Babcock and Wilcox in the Commercial Nuclear Power Division, returning to Progress Energy in 1977. Since that time, he has served in various management positions at three of Progress Energy's nuclear plant sites. 37 Tom D. Kilgore 56 Group President, PEC (November 2000 to present); President and CEO, Progress Ventures, Inc., March 2000 to present. Progress Ventures, Inc. was created in 2000 to manage Progress Energy's assets and operations in fuel extraction, manufacturing and delivery, nonregulated generation and energy marketing and trading. Mr. Kilgore joined Progress Energy (formerly CP&L) in August 1998 as Senior Vice President - Power Operations. Before joining the Company, Mr. Kilgore was President and Chief Executive Officer - Oglethorpe Power Corp. He held other management positions at Oglethorpe including Senior Vice President - Power Supply. Before joining Oglethorpe Power, Mr. Kilgore was Director - Fossil and Hydro Operations for Arkansas Power and Light Co., where he held numerous other management positions. Jeffrey J. Lyash 42 Senior Vice President, PEF, November 2003 to present. Mr. Lyash oversees all aspects of energy delivery operations for PEF. Prior to coming to PEF, Mr. Lyash was Vice President - Transmission in Energy Delivery in the Carolinas since January 2002. Mr. Lyash joined Progress Energy in 1993 and spent his first eight years with the Company at the Brunswick Nuclear Plant in Southport, North Carolina. His last position at Brunswick was as Director of site operations. John R. McArthur 48 Senior Vice President, General Counsel and Secretary of Progress Energy, January 2004 to present. Mr. McArthur oversees the Audit Services, Corporate Communications, Corporate Relations and Administrative Services, Legal, Economic Development, Environment, Health & Safety and Public Affairs departments. Mr. McArthur is also Senior Vice President and Corporate Secretary, Florida Progress and PEC, and Senior Vice President, PEF, January 1 to present. Previously, he served the Company as Senior Vice President - Corporate Relations (December 2002 to December 2003) and as Vice President - Public Affairs (December 2001 to December 2002). Before joining Progress Energy in December 2001, Mr. McArthur was a member of North Carolina Governor Mike Easley's senior management team, handling major policy initiatives as well as media and legal affairs. He also directed Governor Easley's transition team after the election of 2000. Prior to joining Governor Easley, Mr. McArthur handled state government affairs in 10 southeastern states for General Electric Co. He also served as chief counsel in the North Carolina Attorney General's office, where he supervised utility, consumer, health care, and environmental protection issues. Before that, he was a partner at Hunton & Williams. E. Michael Williams 55 Senior Vice President, PEC and PEF, June 2000 and November 2000, respectively, to present. Before joining the Company in 2000, Mr. Williams was with Central and Southwest Corp., Inc. and subsidiaries for 28 years and served in various positions prior to becoming Vice President - Fossil Generation in Dallas. *Indicates individual is an executive officer of Progress Energy, Inc., but not Carolina Power & Light Company. 38 PART II ITEM 5. MARKET FOR THE REGISTRANTS' COMMON EQUITY AND RELATED SHAREHOLDER MATTERS Progress Energy's Common Stock is listed on the New York Stock Exchange. The high and low intra-day stock sales prices for Progress Energy for each quarter for the past two years, and the dividends declared per share are as follows: 2003 High Low Dividends Declared - ---- ---- --- ------------------ First Quarter $ 46.10 $ 37.45 $ 0.560 Second Quarter 48.00 38.99 0.560 Third Quarter 45.15 39.60 0.560 Fourth Quarter 46.00 41.60 0.575 2002 High Low Dividends Declared - ---- ---- --- ------------------ First Quarter $ 50.86 $ 43.01 $ 0.545 Second Quarter 52.70 47.91 0.545 Third Quarter 51.97 36.54 0.545 Fourth Quarter 44.82 32.84 0.560 The December 31 closing price of the Company's Common Stock was $45.26 for 2003 and $43.35 for 2002. As of January 30, 2004, the Company had 70,118 holders of record of Common Stock. Progress Energy holds all 159,608,055 shares outstanding of PEC common stock and, therefore, no public trading market exists for the common stock of PEC. Neither Progress Energy's Articles of Incorporation nor any of its debt obligations contain any restrictions on the payment of dividends. Certain documents restrict the payment of dividends by Progress Energy's subsidiaries. PROGRESS ENERGY Information on the equity compensation plans of Progress Energy is set forth under the heading "Equity Compensation Plant Information" in the Progress Energy 2003 definitive proxy statement dated March 31, 2004 and incorporated by reference herein. PEC PEC does not have any equity compensation plans under which its equity securities are issued. 39 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. Years Ended December 31 2003 (a) 2002 (a) 2001 (a) 2000 (a)(b) 1999 ---------- ---------- ---------- ------------- ----------- (dollars in millions, except per share data) Operating results Operating revenues $ 8,743 $ 8,091 $ 8,129 $ 3,769 $ 3,265 Income from continuing operations before cumulative $ 811 $ 552 $ 541 $ 478 $ 383 effect Net Income $ 782 $ 528 $ 542 $ 478 $ 379 Per share data Basic earnings Income from continuing operations $ 3.42 $ 2.54 $ 2.64 $ 3.04 $ 2.58 Net income $ 3.30 $ 2.43 $ 2.65 $ 3.04 $ 2.56 Diluted earnings Income from continuing operations $ 3.40 $ 2.53 $ 2.63 $ 3.03 $ 2.58 Net income $ 3.28 $ 2.42 $ 2.64 $ 3.03 $ 2.55 Dividends declared per common share $ 2.26 $ 2.20 $ 2.14 $ 2.08 $ 2.02 Assets (d) $ 26,202 $ 24,208 $ 23,647 $ 22,842 $ 10,655 Capitalization Common stock equity $ 7,444 $ 6,677 $ 6,004 $ 5,424 $ 3,413 Preferred stock - redemption not required 93 93 93 93 59 Long-term debt, net (c) 9,934 9,747 8,619 4,904 2,162 Current portion of long-term debt 868 275 688 184 197 Short-term obligations 4 695 942 4,959 1,035 ----------- ----------- ----------- ----------- ------------- Total capitalization and total debt $ 18,343 $ 17,487 $ 16,346 $ 15,564 $ 6,866 =========== =========== =========== =========== =============
(a) Operating results and balance sheet data have been restated for discontinued operations. (b) Operating results and balance sheet data includes information for FPC since November 30, 2000, the date of acquisition. (c) Includes long-term debt to affiliated trust of $309 million at December 31, 2003. (d) All periods have been restated for the reclassification of cost of removal, nuclear decommissioning and fossil dismantlement (See Note 5F). 40 PROGRESS ENERGY CAROLINAS, 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. Years Ended December 31 2003 2002 2001 2000(a)(b) 1999(b) ----------- ----------- ------------ ------------ ---------- (dollars in millions) Operating results Operating revenues $ 3,600 $ 3,554 $ 3,360 $ 3,528 $ 3,365 Net income $ 482 $ 431 $ 364 $ 461 $ 382 Earnings for common stock $ 479 $ 428 $ 361 $ 458 $ 379 Assets (d) $ 11,008 $ 10,405 $ 10,604 $ 10,525 $ 10,656 Capitalization Common stock equity $ 3,237 $ 3,089 $ 3,095 $ 2,852 $ 3,413 Preferred stock - redemption not required 59 59 59 59 59 Long-term debt, net 3,086 3,048 2,698 3,134 2,162 Current portion of long-term debt 300 - 600 - 197 Short-term obligations (c) 29 438 309 486 1,035 ----------- ----------- ----------- ----------- ----------- Total capitalization and total debt $ 6,711 $ 6,634 $ 6,761 $ 6,531 $ 6,866 =========== =========== =========== =========== ===========
(a) Operating results and balance sheet data do not include information for NCNG, SRS, Monroe Power Company or PVI subsequent to July 1, 2000, the date PEC distributed its ownership interest in the stock of these companies to Progress Energy. (b) Operating results include NCNG results for the period July 15, 1999 to July 1, 2000. Balance sheet data includes NCNG for December 31, 1999. (c) Includes notes payable to affiliated companies, related to the money pool program, of $25 million and $48 million at December 31, 2003 and 2001, respectively. (d) All periods have been restated for the reclassification of cost of removal and nuclear decommissioning (See Note 3F). 41 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following Management's Discussion and Analysis contains forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review the "Risk Factors" sections and "SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS" for a discussion of the factors that may impact any such forward-looking statements made herein. Management's Discussion and Analysis should be read in conjunction with the Progress Energy Consolidated Financial Statements. INTRODUCTION Progress Energy is an integrated energy company, with its primary focus on the end-use and wholesale electricity markets. The Company's reportable business segments and their primary operations include: o Progress Energy Carolinas Electric (PEC Electric) - primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina; o Progress Energy Florida (PEF) - primarily engaged in the generation, transmission, distribution and sale of electricity in portions of Florida; o Competitive Commercial Operations (CCO) - engaged in nonregulated electric generation operations and marketing activities primarily in the southeastern United States; o Fuels - primarily engaged in natural gas production in Texas and Louisiana, coal mining and related services, and the production of synthetic fuels and related services, both of which are located in Kentucky, West Virginia, and Virginia; o Rail Services (Rail) - engaged in various rail and railcar related services in 23 states, Mexico and Canada; and o Other Businesses (Other) - engaged in other nonregulated business areas, including telecommunications primarily in the eastern United States and energy services operations, which do not meet the requirements for separate segment reporting disclosure. In 2003, the Company realigned its business segments to reflect the current management structure and assigned new names to the segments to better reflect their operations. For comparative purposes, 2002 and 2001 segment information has been restated to align with the 2003 organizational and reporting structure. Strategy The Company's goals related to its regulated utilities and nonregulated businesses are to continue focusing on achieving their financial objectives, delivering excellent customer satisfaction and continually striving for operational excellence. The target is to maintain a business mix of approximately 80% regulated and 20% nonregulated business. A summary of the significant financial objectives or issues impacting Progress Energy, its regulated utilities and nonregulated operations are addressed more fully in the following discussion. o Progress Energy, Inc. Progress Energy has several key financial objectives, the first of which is to achieve operating cash flows sufficient to meet planned capital expenditures and support its current dividend policy. Any excess cash flow would be used for debt reduction, primarily at the holding company. In addition, the Company seeks to achieve earnings growth through its core regulated utility businesses and through improving returns at its nonregulated businesses. The Company also seeks to maintain ready access to credit markets. The ability to meet these objectives is largely dependent on the earnings and cash flows of its two regulated utilities. The regulated utilities contributed $787 million of net income and produced over 90% of consolidated cash flow from operations in 2003. In addition, synthetic fuel income of $200 million also contributed significantly to net income. Partially offsetting the net income contribution provided by the regulated utilities and synthetic fuels was a loss of $236 million recorded at Corporate, primarily related to interest expense. While the Company's synthetic fuel operations provide significant earnings, the significant amount of cash flow benefits from synthetic fuels will come in the future when deferred tax credits ultimately are utilized. Credits generated but not utilized are 42 carried forward indefinitely as alternative minimum tax credits and will provide positive cash flow when utilized. At December 31, 2003, deferred credits were $659 million. The Company does not anticipate any significant acquisitions in the near term. Progress Energy reduced its debt to total capitalization ratio to 58.9% at the end of 2003 as compared to 61.3% at the end of 2002. The Company expects to continue to improve this ratio as it plans to reduce total debt through growth in operating cash flow after dividends, ongoing equity issuances and with proceeds from asset sales. The Company expects capital expenditures to be approximately $1.3 billion in 2004 and in 2005. Progress Energy continues to maintain investment grade credit ratings, despite a ratings downgrade in 2003 by both Moody's and Standard & Poor's. Both these ratings agencies upgraded the Company's outlook from "negative" to "stable" in 2003. The downgrades have not materially affected Progress Energy's access to liquidity or the cost of its short-term borrowings. o Regulated Utilities The regulated utilities earnings and operating cash flows are heavily influenced by weather, the economy, demand for electricity related to customer growth, actions of regulatory agencies and cost controls. Both PEC Electric and PEF operate in retail service territories that are forecast to have income and population growth higher than the U.S. average. New housing starts in both these territories are also expected to exceed the U.S. average. In recent years, lower industrial sales, primarily at PEC Electric and mainly related to weakness in the textile sector, have negatively impacted earnings growth. The Company does not expect any significant improvement in industrial sales in the near term. These combined factors, and assuming normal weather, are expected to contribute to approximately 2%-3% annual KWh sales growth at the utilities through at least 2006. The Company does not anticipate any significant additional generation expansion to meet this growth other than the previously planned 500 MW combined-cycle unit at PEF in 2005. PEC Electric and PEF continue to monitor progress toward a more competitive environment. No retail electric restructuring legislation has been introduced in the jurisdictions in which PEC Electric and PEF operate and both operate under rate agreements. As part of the Clean Smokestacks bill in North Carolina and an agreement with the Public Service Commission of South Carolina (SCPSC), PEC Electric is operating under a rate freeze in North Carolina through 2007 and a rate cap in South Carolina through 2005. PEF is operating under a rate agreement in Florida through 2005. See Note 7 of the Progress Energy Consolidated Financial Statements for further discussion of the utilities' rates. The utilities will continue to exercise strong financial discipline as it relates to controlling operation and maintenance costs despite expected increases in benefit-related costs and insurance expense. Operating cash flows are expected to be more than sufficient to fund capital spending in 2004 and in 2005. o Nonregulated businesses The Company's primary nonregulated businesses are CCO, Fuels and Progress Rail. Cash flows and earnings of the nonregulated businesses are impacted largely by the ability to obtain additional term contracts or sell energy on the spot market at favorable terms, the volume of synthetic fuel produced and tax credits utilized, and volumes and prices of both coal and natural gas sales. Progress Energy expects an excess of supply in the wholesale electric energy market for the next several years. During 2003, CCO completed the build out of its nonregulated generation assets bringing CCO's total capacity to 3,100 MW. The Company has no current plans to expand its portfolio of nonregulated generating plants. The Company has contracts for planned production capacity of 85% in 2004 and 50% for both 2005 and 2006. CCO will continue to seek to secure term contracts with load-serving entities to utilize its excess capacity. Fuels will continue to develop its natural gas production asset base both as a long-term economic hedge for the Company's nonregulated generation fuel needs and to obtain a meaningful presence in natural gas markets that will allow it to provide attractive returns for the Company's shareholders. In 2004, Fuels anticipates that, with budgeted capital expenditures, it will have a 25% increase in gas production. 43 The Company's majority-owned synthetic fuel entities participate in the Internal Revenue Service (IRS) Prefiling Agreement (PFA) program. The PFA program is a program that allows taxpayers to voluntarily accelerate the IRS exam process in order to seek resolution of specific issues. The Company has resolved certain issues with the IRS and is continuing to work with the IRS to resolve any remaining issues. The Company cannot predict when the exam process will be completed or the final resolution of any outstanding matters. These facilities have private letter rulings (PLRs) from the IRS with respect to their synthetic fuel operations. The Company has no current plans to alter its synthetic fuel production schedule as a result of these matters. The Company plans to produce approximately 11 million to 12 million tons of synthetic fuel in 2004. Through December 31, 2003, the Company had generated $1,243 million of synthetic fuel tax credits to date (including FPC prior to the acquisition by the Company). See additional discussion at Synthetic Fuel Tax Credits in the OTHER MATTERS section below and at Note 14 to the Progress Energy Consolidated Financial Statements. Progress Energy continues to look for opportunities to divest of its Progress Rail subsidiary at an opportune time as it is not considered part of its core business strategy in the future. The Company expects to accomplish the divestiture within the next three years. Progress Energy and its consolidated subsidiaries are subject to various risks. For a complete discussion of these risks see the Risk Factors section. RESULTS OF OPERATIONS FOR 2003 AS COMPARED TO 2002 AND 2002 AS COMPARED TO 2001 In this section, earnings and the factors affecting earnings are discussed. The discussion begins with a summarized overview of the Company's consolidated earnings which is followed by a more detailed discussion and analysis by business segment. PROGRESS ENERGY In 2003, Progress Energy's net income was $782 million, a 48% increase from $528 million in 2002. Income from continuing operations before cumulative effect of changes in accounting principles and discontinued operations was $811 million in 2003, a 47% increase from $552 million in 2002. Net income for 2003 increased compared to 2002 primarily due to the inclusion in 2002 of an impairment of $265 million after-tax related to assets in the telecommunications and rail businesses. The Company recorded impairments of $23 million after-tax in 2003 on an investment portfolio and on long-lived assets. The increase in net income in 2003 of $12 million, excluding the impairments, is primarily due to: o An increase in retail customer growth at the utilities. o Growth in natural gas production and sales. o Higher synthetic fuel sales. o Absence of severe storm costs incurred in 2002. o Lower loss recorded in 2003 related to the sale of NCNG, with the majority of the loss on the sale being recorded in 2002. o Lower interest charges in 2003. Partially offsetting these items were the: o Net impact of the 2002 Florida Rate settlement. o Impact of the change in the fair value of the CVOs. o Milder weather in 2003 as compared to 2002. o Increased benefit-related costs. o Higher depreciation expense at both utilities and the Fuels and CCO segments. o The impact of changes in accounting principles in 2003. Each of these items is discussed further in the results of operations for the segments below. Basic earnings per share from net income increased from $2.43 per share in 2002 to $3.30 per share in 2003 in part due to the factors outlined above. Dilution related to a November 2002 equity issuance of 14.7 million shares and issuances under the Company's Investor Plus and employee benefit programs in 2002 and 2003 also reduced basic earnings per share by $0.33 in 2003. 44 Net income in 2002 decreased 2.6% from $542 million in 2001. The decrease in net income in 2002 is primarily due to impairments and other charges related to the telecommunications and rail business operations, the discontinued operations of NCNG, the rate case settlement of PEF, PEC severe storm costs and increased benefit costs. Partially offsetting these items were continued customer growth and usage at the utilities, lower depreciation at PEF, 2001 impairments in the telecommunications and SRS business units, the impact of the change in market value of CVOs and the elimination of goodwill amortization in 2002. The Company's segments contributed the following profit or loss from continuing operations for 2003, 2002 and 2001: - -------------------------------------------------------------------------------------------------------------------- (in millions) - -------------------------------------------------------------------------------------------------------------------- 2003 Change 2002 Change 2001 - -------------------------------------------------------------------------------------------------------------------- PEC Electric $ 515 $ 2 $ 513 $ 45 $ 468 PEF 295 (28) 323 14 309 Fuels 235 59 176 (23) 199 CCO 20 (7) 27 23 4 Rail Services (1) 41 (42) (30) (12) Other (17) 226 (243) (81) (162) ----------------------------------------------------------------- Total Segment Profit (Loss) $ 1,047 $ 293 $ 754 $ (52) $ 806 Corporate (236) (34) (202) 63 (265) ----------------------------------------------------------------- Total Income from Continuing Operations $ 811 $ 259 $ 552 $ 11 $ 541 Discontinued Operations, Net of Tax (8) 16 (24) (25) 1 Cumulative Effect of Changes in Accounting Principles (21) (21) - - - ----------------------------------------------------------------- Net Income $ 782 $ 254 $ 528 $ (14) $ 542 - --------------------------------------------------------------------------------------------------------------------
PROGRESS ENERGY CAROLINAS ELECTRIC PEC Electric contributed segment profits of $515 million, $513 million and $468 million in 2003, 2002 and 2001, respectively. The slight increase in profits in 2003, when compared to 2002, was primarily due to customer growth, strong wholesale sales during the first quarter of 2003, lower Service Company allocations and lower interest costs, which were offset by unfavorable weather in 2003, higher depreciation expense and increased benefit-related costs. The increase in profits in 2002, when compared to 2001, was attributable to customer growth, favorable weather in 2002, lower interest charges and the allocation of tax benefits from the holding company partially offset by severe storm costs in December 2002. Revenues PEC Electric's electric revenues for the years ended December 31, 2003, 2002 and 2001 and the percentage change by year and by customer class are as follows: - ------------------------------------------------------------------------------------------------- (in millions) - ------------------------------------------------------------------------------------------------- Customer Class 2003 % Change 2002 % Change 2001 - ------------------------------------------------------------------------------------------------- Residential $ 1,259 1.5% $ 1,241 7.7% $ 1,152 Commercial 850 2.2 832 6.0 785 Industrial 636 (1.4) 645 (1.4) 654 Governmental 79 1.3 78 4.0 75 ------------- ------------- ------------- Total Retail Revenues 2,824 1.0 2,796 4.9 2,666 Wholesale 687 5.5 651 2.7 634 Unbilled (6) - 15 - (32) Miscellaneous 84 9.1 77 1.3 76 ------------- ------------- ------------- Total Electric Revenues $ 3,589 1.4% $ 3,539 5.8% $ 3,344 - -------------------------------------------------------------------------------------------------
45 PEC Electric's electric energy sales for 2003, 2002 and 2001 and the percentage change by year and by customer class are as follows: - --------------------------------------------------------------------------------------------------- (in thousands of MWh) - --------------------------------------------------------------------------------------------------- Customer Class 2003 % Change 2002 % Change 2001 - --------------------------------------------------------------------------------------------------- Residential 15,283 0.3% 15,239 6.0% 14,372 Commercial 12,557 0.7 12,468 4.1 11,972 Industrial 12,749 (2.6) 13,089 (1.8) 13,332 Governmental 1,408 (2.0) 1,437 1.0 1,423 ------------- -------------- ------------- Total Retail Energy Sales 41,997 (0.6) 42,233 2.8 41,099 Wholesale 15,518 3.3 15,024 15.6 12,996 Unbilled (44) - 270 - (534) ------------- -------------- ------------- Total MWh Sales 57,471 (0.1%) 57,527 7.4% 53,561 - ---------------------------------------------------------------------------------------------------
PEC Electric's revenues, excluding recoverable fuel revenues of $901 million and $851 million in 2003 and 2002, respectively, were unchanged from 2002 to 2003. Milder weather in 2003, when compared to 2002 accounted for a $61 million retail revenue reduction. While heating degree days were 4.8% above prior year, cooling degree days were 25.2% below prior year. However, the more severe weather in the northeast region of the United States during the first quarter of 2003 drove a $19 million increase in wholesale revenues. Additionally, retail customer growth in 2003 generated an additional $42 million of revenues in 2003. PEC Electric's retail customer base increased as approximately 23,000 new customers were added in 2003. PEC's electric revenues, excluding recoverable fuel revenues of $851 million and $734 million in 2002 and 2001, respectively, increased $78 million. During 2002, residential and commercial sales reflected continued growth in the number of customers served by PEC Electric, with approximately 26,000 new customers in 2002. Sales of energy and revenue increased in 2002 compared to 2001 for all customer classes except industrial. Increases in retail sales and wholesale sales were also driven by favorable weather during 2002 when compared to 2001. Wholesale sales growth was partially offset by price declines in the wholesale market. Downturns in the economy during 2001, 2002 and 2003 impacted energy usage within the industrial customer class. Total industrial revenues, excluding fuel revenues, declined during 2003 when compared to 2002 and during 2002 when compared to 2001 by $13 million and $24 million, respectively, as the number of industrial customers decreased due to a slowdown in the textile industry, as well as a decrease in usage in the chemical industry. Expenses Fuel and Purchased Power Fuel expense increased $73 million in 2003, when compared to $752 million in 2002, primarily due to higher prices incurred for coal, oil and natural gas used during generation. Costs for fuel per Btu increased for all three commodities during the year. See movement in prices under Average Fuel Cost Summary in Part I, Item 1, PEC Electric - Fuel and Purchased Power. Fuel expense increased $114 million in 2002, when compared to $638 million in 2001, primarily due to an 8.2% increase in generation with a higher percentage of generation being produced by combustion turbines, which have higher fuel costs. Purchased power expense decreased $51 million in 2003, when compared to $347 million in 2002, mainly due to a decrease in the volume purchased as milder weather reduced system requirements and due to the renegotiation at more favorable terms of two contracts that expired during the year. For 2002, purchased power decreased $7 million, when compared to $354 million in 2001, mainly due to decreases in prices and volumes purchased. Fuel expenses are recovered primarily through cost recovery clauses and, as such, changes in expense have no material impact on operating results. Operations and Maintenance (O&M) O&M expense decreased $20 million in 2003 when compared to $802 million in 2002. O&M expense in 2002 included severe storm costs of $27 million. Those costs along with lower 2003 Service Company allocations of $16 million, due to the change in allocation methodology as required by the SEC in early 2003, are the primary reasons for decreased O&M expenses. This decrease was partially offset by higher benefit-related costs of $21 million. PEC Electric incurred O&M costs of $25 million related to three severe storms in 2003. The NCUC allowed deferral of $24 million of these storm costs. These costs are being amortized over a five-year period, beginning in the months the expenses were incurred. PEC Electric amortized $3 million of these costs in 2003 which is included in depreciation and amortization expense on the Consolidated Income Statement. 46 O&M expense increased $91 million in 2002 when compared to $711 million in 2001 primarily due to the 2002 storm costs of $27 million, which were not deferred. O&M expense in 2002, when compared to 2001, was also negatively impacted by a lower pension credit of $6 million, the establishment of an inventory reserve of $11 million for materials that have no future benefit, increased salaries and benefits and other increases in maintenance and outage support. Depreciation and Amortization Depreciation and amortization increased $38 million in 2003, when compared to $524 million in 2002. Depreciation and amortization increased $74 million related to the 2003 impact of the Clean Air legislation in North Carolina and decreased $53 million related to the 2002 impact of the accelerated nuclear amortization program. Both programs are approved by the state regulatory agencies and are discussed further at Notes 7 and 21E to the Progress Energy Consolidated Financial Statements. In addition, depreciation increased $19 million due to additional assets placed into service. Depreciation and amortization increased $2 million in 2002 when compared to $522 million in 2001. PEC Electric recorded $53 million of accelerated amortization expense in 2002 and $75 million in 2001 related to the nuclear amortization program. The year-over-year favorability was offset by additional depreciation recognized in 2002, as compared to 2001, on new assets that were placed in service during 2002. PEC filed a new depreciation study in 2004 that provides support for reducing depreciation expense on an annual basis by approximately $45 million. The reduction is primarily attributable to assumption changes for nuclear generation, offset by increases for distribution assets. The new rates are primarily effective January 1, 2004. Interest Expense Net interest expense was $194 million, $212 million and $241 million in 2003, 2002 and 2001, respectively. Declines in interest expense resulted from reduced short-term debt and refinancing certain long-term debt with lower interest rate debt. Income Tax Expense In 2003 and 2002, $24 million and $35 million, respectively, of the tax benefit that was previously held at the Company's holding company was allocated to PEC Electric. As required by an SEC order issued in 2002, holding company tax benefits are allocated to profitable subsidiaries. Other fluctuations in income taxes are primarily due to changes in pretax income. PROGRESS ENERGY FLORIDA PEF contributed segment profits of $295 million, $323 million and $309 million in 2003, 2002 and 2001, respectively. The decrease in profits in 2003, when compared to 2002, was primarily due to the impact of the 2002 rate case stipulation, higher benefit-related costs primarily related to higher pension expense, higher depreciation and the unfavorable impact of weather. These amounts were partially offset by continued customer growth and lower interest charges. The increase in profits in 2002, when compared to 2001, was attributed to the impact of milder weather in 2001 as compared to 2002, continued customer growth and the allocation of tax benefits from the holding company. These items were partially offset by the impact of the 2002 rate case stipulation, increased benefits costs and lower pension credit and higher system reliability and enhancement spending. PEF's profits in 2003 and 2002 were affected by the outcome of the rate case stipulation, which included a one-time retroactive revenue refund in 2002, a decrease in retail rates of 9.25% (effective May 1, 2002), provisions for revenue sharing with the retail customer base, lower depreciation and amortization and increased service revenue rates. See Note 7B to the Progress Energy Consolidated Financial Statements for further discussion of the rate case settlement. 47 Revenues PEF's electric revenues for the years ended December 31, 2003, 2002 and 2001 and the percentage change by year and by customer class, as well as the impact of the rate case settlement on revenue, are as follows: - ------------------------------------------------------------------------------------------------ (in millions) - ------------------------------------------------------------------------------------------------ Customer Class 2003 % Change 2002 % Change 2001 - ------------------------------------------------------------------------------------------------ Residential $ 1,691 2.8% $ 1,645 0.1% $ 1,643 Commercial 740 1.2 731 (3.1) 754 Industrial 219 3.8 211 (5.4) 223 Governmental 181 4.6 173 (1.7) 176 Revenue Sharing Refund (35) - (5) - - Retroactive Retail Rate Refund - - (35) - - ---------- ------------ ----------- Total Retail Revenues 2,796 2.8 2,720 (2.7) 2,796 Wholesale 227 (1.3) 230 (20.1) 288 Unbilled (2) - (3) - (22) Miscellaneous 131 13.9 115 (23.8) 151 ---------- ------------ ----------- Total Electric Revenues $ 3,152 2.9% $ 3,062 (4.7)% $ 3,213 - ------------------------------------------------------------------------------------------------
PEF's electric energy sales for the years ended December 31, 2003, 2002 and 2001 and the percentage change by year and by customer class are as follows: - -------------------------------------------------------------------------------------------- (in thousands of MWh) - -------------------------------------------------------------------------------------------- Customer Class 2003 % Change 2002 % Change 2001 - -------------------------------------------------------------------------------------------- Residential 19,429 3.6% 18,754 6.5% 17,604 Commercial 11,553 1.2 11,420 3.2 11,061 Industrial 4,000 4.3 3,835 (1.0) 3,872 Governmental 2,974 4.4 2,850 4.5 2,726 ---------- ----------- ----------- Total Retail Energy Sales 37,956 3.0 36,859 4.5 35,263 Wholesale 4,323 3.4 4,180 (11.4) 4,719 Unbilled 233 - 5 - (511) ---------- ----------- ----------- Total MWh Sales 42,512 3.6% 41,044 4.0% 39,471 - --------------------------------------------------------------------------------------------
PEF's revenues, excluding fuel revenues of $1,487 million and $1,402 million in 2003 and 2002, respectively, increased $5 million from 2002 to 2003. Revenues were favorably impacted by $49 million in 2003, primarily as a result of customer growth (approximately 36,000 additional customers). In addition, other operating revenues were favorable $16 million due primarily to higher wheeling and transmission revenues and higher service charge revenues (resulting from increased rates allowed under the 2002 rate settlement). These increases were partially offset by the negative impact of the rate settlement, which decreases revenues, lower wholesale sales and the impact of unfavorable weather. The provision for revenue sharing increased $12 million in 2003 compared to the $5 million provision recorded in 2002. Revenues in 2003 were also impacted by the final resolution of the 2002 revenue sharing provisions as the FPSC issued an order in July of 2003 that required PEF to refund an additional $18 million to customers related to 2002. The 9.25% rate reduction from the settlement accounted for an additional $46 million decline in revenues. The 2003 impact of the rate settlement was partially offset by the absence of the prior year interim rate refund of $35 million. Lower wholesale revenues (excluding fuel revenues) of $17 million and the $8 million impact of milder weather also reduced base revenues during 2003. PEF's revenues, excluding fuel revenues of $1,402 million and $1,453 million in 2002 and 2001, respectively, decreased $100 million from 2001 to 2002. The revenue declines were driven by the $119 million impact of the rate case, comprised of a $35 million one-time retroactive refund, a $79 million decrease due to the rate reduction, and an estimated revenue sharing refund of $5 million. Additionally, wholesale revenues (excluding fuel revenues) declined $12 million, driven primarily by a contract that was not renewed. Year-over-year comparisons were also unfavorably impacted by the recognition of $63 million of revenue deferred from 2000 to 2001. Partially offsetting the unfavorable revenue impacts was customer growth (approximately 33,000 additional customers), the impact of weather conditions, primarily a warmer than normal summer in 2002, and an increase in other operating revenue, resulting primarily from higher service charge revenues (resulting from increased rates allowed under the 2002 rate case settlement), along with higher transmission and wheeling revenues. 48 Expenses Fuel and Purchased Power Fuel used in generation and purchased power increased $87 million in 2003 when compared to $1,349 million in 2002. The increase is due to higher costs to generate electricity and higher purchased power costs as a result of an increase in volume due to system requirements and higher natural gas prices. Fuel used in generation and purchased power totaled $1,349 million for the year ended December 31, 2002, a decrease of $71 million from 2001. The decrease is primarily due to a lower recovery of fuel expense that resulted from a mid-course correction of PEF's fuel cost recovery clause, as part of the rate settlement, and lower purchased power costs, partially offset by an increase in coal prices and volume from high system requirements. Fuel and purchased power expenses are recovered primarily through cost recovery clauses and, as such, changes in expense have no material impact on operating results. Operations and Maintenance (O&M) O&M expense increased $49 million, when compared to $591 million in 2002. The increase is largely related to increases in certain benefit-related expenses of $36 million, which consisted primarily of higher pension expense of $27 million and higher operational costs related to the CR3 nuclear outage and plant maintenance. O&M expense increased $96 million in 2002 when compared to $495 million in 2001, due primarily to a reduced pension credit of $31 million, increased costs related to the Commitment to Excellence program of $11 million and an increase in other salary and benefit costs of $22 million related partially to increased medical costs. The Commitment to Excellence program was initiated in 2002 to improve service and reliability. Depreciation and Amortization Depreciation and amortization increased $12 million in 2003 when compared to $295 million in 2002. Depreciation increased primarily as a result of additional assets being placed into service that were partially offset by lower amortization of the Tiger Bay regulatory asset of $2 million, which was fully amortized in September 2003. Depreciation and amortization decreased $158 million in 2002 when compared to $453 million in 2001. In addition to the depreciation and amortization reduction of approximately $79 million related to the rate case, depreciation declined an additional $97 million related to accelerated amortization on the Tiger Bay regulatory asset, which was created as a result of the early termination of certain long-term cogeneration contracts. See Note 7D to the Progress Energy Consolidated Financial Statements for further details on the rate case. PEF amortized the regulatory asset according to a plan approved by the FPSC in 1997. Interest Expense Interest charges decreased $15 million in 2003 compared to $106 million in 2002 primarily due to the reversal of a regulatory liability for accrued interest related to previously resolved tax matters. Income Tax Expense In 2003 and 2002, $13 million and $20 million, respectively, of the tax benefit that was previously held at the Company's holding company was allocated to PEF. As required by an SEC order issued in 2002, holding company tax benefits are allocated to profitable subsidiaries. Other fluctuations in income taxes are primarily due to changes in pretax income. DIVERSIFIED BUSINESSES The Company's diversified businesses consist of the Fuels segment, the CCO segment, the Rail Services segment and the Other segment, which consists primarily of the energy services operations and telecommunications operations. 49 FUELS Fuels' segment profits increased $59 million in 2003 as compared to $176 million in 2002 primarily due to an increase in synthetic fuel earnings, higher natural gas earnings from increased natural gas prices, the addition of North Texas Gas operations in March 2003 and the addition of Westchester in April 2002. These results were partially offset by an asset impairment during the fourth quarter of $11 million after-tax at the Kentucky May Coal Company. Fuels' 2002 profits as compared to 2001 decreased $23 million primarily as a result of lower synthetic fuel production, which was partially offset by increased natural gas revenues as a result of the Westchester acquisition. Fuels contributed segment profits of $235 million, $176 million and $199 million in 2003, 2002 and 2001, respectively. The following summarizes Fuels' segment profits for the years ended December 31, 2003, 2002 and 2001: - --------------------------------------------------------------------- (in millions) 2003 2002 2001 - --------------------------------------------------------------------- Synthetic fuel operations $ 200 $ 156 $ 185 Natural gas operations 34 10 5 Coal fuel and other operations 1 10 9 ----------------------------------- Segment profits $ 235 $ 176 $ 199 - --------------------------------------------------------------------- Synthetic Fuel Operations Synthetic fuel operations generated profits of $200 million, $156 million and $185 million, respectively, for the years ended December 31, 2003, 2002 and 2001. The production and sale of the synthetic fuel generate operating losses, but qualify for tax credits under Section 29, which more than offset the effects of such losses. See "Synthetic Fuels Tax Credits" under OTHER MATTERS below for additional discussion of these tax credits. The operations resulted in the following losses (prior to tax credits) and tax credits for 2003, 2002 and 2001: - ---------------------------------------------------------------------- (in millions) 2003 2002 2001 - ---------------------------------------------------------------------- Tons sold 12.4 11.2 13.3 After-tax losses (excluding tax credits) $ (145) $ (135) $ (164) Tax credits 345 291 349 ---------------------------- Net Profit $ 200 $ 156 $ 185 - ---------------------------------------------------------------------- Synthetic fuels' net profits for 2003 increased as compared to 2002 due to higher sales, improved margins and a higher tax credit per ton. The 2003 tax credits also include a $12.7 million favorable true-up from 2002. Additionally, synthetic fuels' results in 2003 include 13 months of operations for some facilities. Prior to the fourth quarter of 2003, results of these synthetic fuels' operations had been recognized one month in arrears. The net impact of this action increased net income by $2 million for the year. Synthetic fuels' net profits decreased in 2002 compared to 2001 due to lower sales. Synthetic fuels' net profits decreased $29 million in 2002 when compared to 2001. The decrease in profits was primarily due to a decline in tons produced as severe storm costs incurred at one of the utilities reduced the Company's ability to use the tax credits generated from production. Natural Gas Operations Natural gas operations generated profits of $34 million, $10 million and $5 million for the years ended December 31, 2003, 2002 and 2001, respectively. The increase in production and price resulting from the acquisitions of Westchester in 2002 and North Texas Gas in the first quarter of 2003 drove increased revenue and earnings in 2003 as compared to 2002. In October of 2003, the Company completed the sale of certain gas-producing properties owned by Mesa Hydrocarbons, LLC. See Notes 4 and 3C to the Progress Energy Consolidated Financial Statements for discussions of the Westchester and the North Texas Gas acquisitions and the Mesa disposition. The increase in profits of $5 million from 2001 to 2002 is due to an increase in gas production of 49% as a result of the Westchester acquisition in April of 2002. The following summarizes the production and revenues of the natural gas operations for 2003, 2002 and 2001 by facility: 50 - ---------------------------------------------------------------- 2003 2002 2001 - ---------------------------------------------------------------- Production in Bcf equivalent Mesa 4.8 6.0 8.3 Westchester 13.5 5.8 - North Texas Gas 7.1 - - -------------------------- Total Production 25.4 11.8 8.3 -------------------------- Revenues in millions Mesa $ 13 $ 15 $ 18 Westchester 65 24 - North Texas Gas 38 - - -------------------------- Total Revenues $ 116 $ 39 $ 18 -------------------------- Gross Margin In millions of $ $ 91 $ 29 $ 15 As a % of revenues 78% 74% 83% - ---------------------------------------------------------------- Coal Fuel and Other Operations Coal fuel and other operations generated profits of $1 million, $10 million and $9 million, respectively, for the years ended December 31, 2003, 2002 and 2001. Coal fuel and other operations segment profits decreased $9 million from 2002 to 2003. The decrease is due primarily to the recording of an impairment of certain assets at the Kentucky May Coal Mine totaling $11 million after-tax. See discussion of impairment recorded in Note 9 to the Progress Energy Consolidated Financial Statements. COMPETITIVE COMMERCIAL OPERATIONS CCO generates and sells electricity to the wholesale market from nonregulated plants. These operations also include marketing activities. CCO's operations generated segment profits of $20 million, $27 million and $4 million in 2003, 2002 and 2001, respectively. CCO's operations were most significantly impacted by placing additional generating capability into service in 2002 and 2003. The following summarizes the annual revenues, gross margin and segment profits from the CCO plants: - -------------------------------------------------------- (in millions) 2003 2002 2001 - -------------------------------------------------------- Total revenues $ 170 $ 92 $ 16 Gross margin In millions of $ $ 141 $ 83 $ 14 As a % of revenues 83% 90% 87% Segment profits $ 20 $ 27 $ 4 - -------------------------------------------------------- The increase in revenue for 2003 when compared to 2002 is primarily due to increased contracted capacity on newly constructed plants, energy revenue from a new, full-requirements power supply contract and a tolling agreement termination payment received during the first quarter. Generating capacity increased from 1,554 megawatts at December 31, 2002 to 3,100 megawatts at December 31, 2003, with the Effingham, Rowan Phase 2 and Washington plants being placed in service in 2003. In the second quarter of 2003, PVI acquired from Williams Energy Marketing and Trading a full-requirements power supply agreement with Jackson in Georgia for $188 million, which resulted in additional revenues of $21 million when compared to the same periods in 2002. The revenue increases related to higher volumes were partially offset by higher depreciation costs of $22 million, increased interest charges of $16 million and other fixed charges. The increase in revenues from 2001 to 2002 is due to the increase in capacity during the year. In 2001 operations included one nonregulated plant with a 315-megawatt capacity and, at the end of 2002, plants with 1,554 megawatts of capacity were operational. The increase in capacity was due to the transfer of one plant from PEC Electric, the purchase of one operational plant from LG&E Energy Corp. (See Note 4D to the Progress Energy Consolidated Financial Statements) and one additional plant being placed in service. The increase in capacity drove the increase in net income. The earnings potential was offset by general softness in the energy market in 2002. 51 The Company has contracts representing 85%, 50%, and 50% of planned production capacity for 2004 through 2006, respectively. The Company is actively pursuing opportunities with current customers and other potential new customers to utilize its excess capacity. RAIL SERVICES Rail Services' (Rail) operations represent the activities of Progress Rail and include railcar and locomotive repair, trackwork, rail parts reconditioning and sales, scrap metal recycling, railcar leasing and other rail-related services. Rail's results for the year ended December 31, 2001, include Rail Services' cumulative revenues and net loss from the date of acquisition, November 30, 2000, because Rail Services had been held for sale from the date of acquisition through the second quarter of 2001. Rail contributed losses of $1 million, $42 million and $12 million for the years ended December 31, 2003, 2002 and 2001, respectively. The net loss in 2002 includes a $40 million after-tax estimated impairment of assets held for sale related to Railcar Ltd., a leasing subsidiary of Progress Rail. In March 2003, the Company signed a letter of intent to sell the majority of Railcar Ltd. assets to The Andersons, Inc. The asset purchase agreement was signed in November 2003 and the transaction closed on February 12, 2004. As such, assets of Railcar Ltd. have been reported as assets held for sale. See Note 3B to the Progress Energy Consolidated Financial Statements for discussion of this planned divestiture. Excluding the impairment recorded in 2002, profits for Rail were flat year over year 2003 compared to 2002. Earnings for Rail increased in 2002 compared to 2001, excluding the $40 million impairment booked in 2002 as discussed above. Rail Services' 2002 results were favorably impacted by aggressive cost cutting, new business opportunities and restructuring initiatives. Rail Services' results for both years were affected by a downturn in the overall economy and decreases in rail service procurement by major railroads. A downturn in the domestic scrap market also impacted Rail Services results for 2002. An SEC order approving the merger of FPC required the Company to divest of Progress Rail by November 30, 2003. However, the SEC has granted an extension until 2006. OTHER Progress Energy's Other segment includes the operations of SRS, the telecommunications operations of PTC and Caronet and the operation of nonutility subsidiaries of PEC. SRS is engaged in providing energy services to industrial, commercial and institutional customers to help manage energy costs and currently focuses its activities in the southeastern United States. Telecommunication operations provide broadband capacity services, dark fiber and wireless services in Florida and the eastern United States. In December 2003, PTC and Caronet, both wholly-owned subsidiaries of Progress Energy, and EPIK, a wholly-owned subsidiary of Odyssey, contributed substantially all of their assets and transferred certain liabilities to PTC LLC, a subsidiary of PTC. Subsequently, the stock of Caronet was sold to an affiliate of Odyssey for $2 million in cash, and Caronet became an indirect wholly-owned subsidiary of Odyssey. Following consummation of all the transactions described above, PTC holds a 55% ownership interest in, and is the parent of, PTC LLC. Odyssey holds a combined 45% ownership interest in PTC LLC through EPIK and Caronet. The accounts of PTC LLC are included in the Company's Consolidated Financial Statements since the transaction date. The Other segment contributed segment losses of $17 million, $243 million and $162 million, respectively, for the years ended December 31, 2003, 2002 and 2001. Included in the 2003 segment losses is an investment impairment of $6 million after-tax on the Affordable Housing portfolio held by the nonutility subsidiaries of PEC. The 2002 segment losses include an asset impairment and other charges in the telecommunications business of $225 million after-tax. Segment losses in 2001 include an asset and investment impairment recorded at SRS ($46 million after-tax) and investment impairments in Interpath Communications, Inc. (Interpath) of $102 million after-tax. See discussion of impairments at Note 9 of the Progress Energy Consolidated Financial Statements. 52 CORPORATE SERVICES Corporate Services (Corporate) includes the operations of the holding company, Progress Energy Service Company and other consolidating and nonoperating entities, as summarized below: - ------------------------------------------------------------------------------------------------ Income (Expense) (in millions) - ------------------------------------------------------------------------------------------------ 2003 Change 2002 Change 2001 - ------------------------------------------------------------------------------------------------ Other interest expense $ (285) $ (10) $ (275) $ (14) $ (261) Contingent value obligations (9) (37) 28 30 (2) Tax reallocation (38) 18 (56) (56) - Other income taxes 124 11 113 68 45 Other income (expense) (28) (16) (12) 35 (47) ------------- ------------ ------------ Segment loss $ (236) $ (34) $ (202) $ 63 $ (265) - ------------------------------------------------------------------------------------------------
Net pre-tax interest charges in Corporate were $285 million, $275 million and $261 million for the years ended December 31, 2003, 2002 and 2001, respectively. Interest expense increased $10 million in 2003 compared to 2002 due to a decrease of $9 million in the amount of interest capitalized related to construction at nonregulated generating plants, as construction was completed and plants were placed in service. The increase in 2002, when compared to 2001, was primarily related to increased debt associated with the purchase of nonregulated generating facilities. This was partially offset by lower interest rates and $19 million of interest capitalization in 2002 related to the building of the nonregulated generating plants. Progress Energy issued 98.6 million 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, 2003, 2002, and 2001, the CVOs had a fair market value of approximately $23 million, $14 million, and $42 million, respectively. Progress Energy recorded unrealized losses of $9 million and $2 million for the years ended December 31, 2003 and 2001, and an unrealized gain of $28 million for the year ended December 31, 2002 to record the changes in fair value of CVOs, which had average unit prices of $0.23, $0.14, and $0.43 at December 31, 2003, 2002 and 2001, respectively. As required by an SEC order issued in 2002, holding company tax benefits are allocated to profitable subsidiaries. Tax benefits reallocated from the Holding Company to the profitable subsidiaries increased Corporate's income tax expense by $38 million and $56 million in 2003 and 2002. Other fluctuations in income taxes are primarily due to changes in pretax income. As part of the acquisition of FPC, goodwill of approximately $3.6 billion was recorded, and amortization of $90 million was included in other income (expense) at the Corporate segment in 2001. In accordance with Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets," (SFAS No. 142) effective January 1, 2002, the Company no longer amortizes goodwill. See Note 8 to the Progress Energy Consolidated Financial Statements for more details on goodwill. DISCONTINUED OPERATIONS In 2002, the Company approved the sale of NCNG to Piedmont Natural Gas Company, Inc. As a result, the operating results of NCNG were reclassified to discontinued operations for all reportable periods. Progress Energy sold NCNG and ENCNG for net proceeds of approximately $450 million. Progress Energy incurred a loss from discontinued operations of $8 million for the year ended December 31, 2003 compared with a loss of $24 million for 2002. The loss for 2003 reflects the finalization of the sale of NCNG. See Note 3A to the Progress Energy Consolidated Financial Statements for more information on this divestiture. CUMULATIVE EFFECT OF ACCOUNTING CHANGES Progress Energy recorded adjustments for the cumulative effects of changes in accounting principles due to the adoption of several new accounting pronouncements. These adjustments totaled to a $21 million loss after-tax which was due primarily to new Financial Accounting Standards Board (FASB) guidance related to the accounting for certain contracts. This guidance discusses whether the pricing in a contract that contains broad market indices qualifies for certain exceptions that would not require the contract to be recorded at its fair value. PEC Electric had a purchase power contract with Broad River LLC that did not meet the criteria for an exception, and a negative fair value adjustment was recorded in the fourth quarter of 2003 for $23 million after-tax. See Note 17A to the Progress Energy Consolidated Financial Statements and Note 12A to the PEC Consolidated Financial Statements. 53 APPLICATION OF CRITICAL ACCOUNTING POLICIES AND ESTIMATES The Company prepared its consolidated financial statements in accordance with accounting principles generally accepted in the United States. In doing so, certain estimates were made that were critical in nature to the results of operations. The following discusses those significant estimates that may have a material impact on the financial results of the Company and are subject to the greatest amount of subjectivity. Senior management has discussed the development and selection of these critical accounting policies with the Audit Committee of the Company's Board of Directors. Utility Regulation The Company's regulated utilities segments are subject to regulation that sets the prices (rates) the Company is permitted to charge customers based on the costs that regulatory agencies determine the Company is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by a nonregulated company. This ratemaking process results in deferral of expense recognition and the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in each state in which the Company operates, a significant amount of regulatory assets has been recorded. The Company continually reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Additionally, the state regulatory agencies often provide flexibility in the manner and timing of the depreciation of property, nuclear decommissioning costs and amortization of the regulatory assets. Note 7 to the Progress Energy Consolidated Financial Statements provides additional information related to the impact of utility regulation on the Company. Asset Impairments The Company evaluates the carrying value of long-lived assets for impairment whenever indicators exist. Examples of these indicators include current period losses combined with a history of losses, or a projection of continuing losses, or a significant decrease in the market price of a long-lived asset group. If an indicator exists, the asset group held and used is tested for recoverability by comparing the carrying value to the sum of undiscounted expected future cash flows directly attributable to the asset group. If the asset group is not recoverable through undiscounted cash flows or if the asset group is to be disposed of, an impairment loss is recognized for the difference between the carrying value and the fair value of the asset group. A high degree of judgment is required in developing estimates related to these evaluations and various factors are considered, including projected revenues and cost and market conditions. Due to the reduction in coal production at the Kentucky May Coal Mine, the Company evaluated its long-lived assets in 2003 and recorded an impairment of $17 million before tax ($11 million after-tax). See Note 9A to the Progress Energy Consolidated Financial Statements for further information on this impairment and other charges. During 2002, the Company recorded pre-tax long-lived asset impairments of $305 million related to its telecommunications business. See Note 9A to the Progress Energy Consolidated Financial Statements for further information on this impairment and other charges. The fair value of these assets was determined using an external valuation study heavily weighted on a discounted cash flow methodology and using market approaches as supporting information. The Company also continually reviews its investments to determine whether a decline in fair value below the cost basis is other than temporary. In 2003, the Company's affordable housing investment (AHI) portfolio was reviewed and deemed to be impaired based on various factors including continued operating losses of the AHI portfolio and management performance issues arising at certain properties within the AHI portfolio. As a result, the Company recorded impairments of $18 million on a pre-tax basis during the fourth quarter of 2003. The Company also recorded an impairment of $3 million for a cost investment. During 2002 and 2001, the Company recorded pre-tax impairments to its cost method investment in Interpath of $25 million and $157 million, respectively. The fair value of this investment was determined using an external valuation study heavily weighted on a discounted cash flow methodology and using market approaches as supporting information. These cash flows included numerous assumptions including the pace at which the telecommunications market would rebound. In the fourth quarter of 2002, the Company sold its remaining interest in Interpath for a nominal amount. 54 Goodwill Effective January 1, 2002, the Company adopted SFAS No. 142, which requires that goodwill be tested for impairment at least annually and more frequently when indicators of impairment exist. See Note 8 to the Progress Energy Consolidated Financial Statements for further detail on goodwill. SFAS No. 142 requires a two-step goodwill impairment test. The Company performs the annual goodwill impairment test each year. The first step, used to identify potential impairment, compares the fair value of the reporting unit with its carrying amount, including goodwill. The second step, used to measure the amount of the impairment loss if step one indicates a potential impairment, compares the implied fair value of the reporting unit goodwill with the carrying amount of the goodwill. The Company completed the initial transitional goodwill impairment test, which indicated that the Company's goodwill was not impaired as of January 1, 2002. The carrying amounts of goodwill at December 31, 2003 and 2002, for reportable segments PEC Electric, PEF and CCO, are $1,922 million, $1,733 million and $64 million, respectively. During 2003, the Other segment acquired $7 million in goodwill as part of the PTC business combination with EPIK. The Company performed the annual goodwill impairment test for the CCO segment in the first quarter of 2003, and the annual goodwill impairment test for the PEC Electric and PEF segments in the second quarter of 2003, which indicated no impairment. If the fair values for the utility segments were lower by 10%, there still would be no impact on the reported value of their goodwill. During 2002, the Company completed the acquisition of two electric generating projects, Walton County Power, LLC and Washington County Power, LLC. The acquisitions resulted in goodwill of $64 million. Synthetic Fuels Tax Credits Progress Energy, through the Fuels business unit, produces coal-based synthetic fuel. The production and sale of the synthetic fuel qualifies for tax credits under Section 29 if certain requirements are satisfied, including a requirement that the synthetic fuel differs significantly in chemical composition from the feedstock used to produce such synthetic fuel and that the fuel was produced from a facility that was placed in service before July 1, 1998. Any synthetic fuel tax credit amounts not utilized are carried forward indefinitely and are included in deferred taxes on the accompanying Consolidated Balance Sheets. See Note 14 to the Progress Energy Consolidated Financial Statements for further information on the synthetic fuel tax credits. All of Progress Energy's synthetic fuel facilities have received PLRs from the IRS with respect to their operations. These tax credits are subject to review by the IRS, and if Progress Energy fails to prevail through the administrative 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. Pension Costs As discussed in Note 16A to the Progress Energy Consolidated Financial Statements, Progress Energy maintains qualified non-contributory defined benefit retirement (pension) plans. The Company's reported costs are dependent on numerous factors resulting from actual plan experience and assumptions of future experience. For example, such costs are impacted by employee demographics, changes made to plan provisions, actual plan asset returns and key actuarial assumptions such as expected long-term rates of return on plan assets and discount rates used in determining benefit obligations and annual costs. Due to a slight decline in the market interest rates for high-quality (AAA/AA) debt securities, which are used as the benchmark for setting the discount rate, the Company lowered the discount rate to 6.3% at December 31, 2003, which will increase the 2004 benefit costs recognized, all other factors remaining constant. However, after a few years of negative asset returns due to equity market declines, plan assets performed very well in 2003, with returns of approximately 30%. That positive asset performance will result in decreased pension cost in 2004. Evaluations of the effects of these factors have not been completed, but the Company estimates that the 2004 total cost recognized for pension will decrease by approximately $5 million from the amount recorded in 2003, due in large part to these factors. The Company has pension plan assets, with a fair value of approximately $1.6 billion at December 31, 2003. The Company's expected rate of return on pension plan assets is 9.25%. The Company reviews this rate on a regular basis. Under Statement of Financial Accounting Standards No. 87, "Employer's Accounting for Pensions" (SFAS No. 87), the expected rate of return used in pension cost recognition is a long-term rate of return; therefore, the Company would only 55 adjust that return if its fundamental assessment of the debt and equity markets changes or its investment policy changes significantly. The Company believes that its pension plans' asset investment mix and historical performance support the long-term rate of 9.25% being used. The Company did not adjust the rate in response to short-term market fluctuations such as the abnormally high market return levels of the latter 1990s, recent years' market declines and the market rebound in 2003. A 0.25% change in the expected rate of return for 2003 would have changed 2003 pension cost by approximately $4 million. Another factor affecting the Company's pension cost, and sensitivity of the cost to plan asset performance, is its selection of a method to determine the market-related value of assets, i.e., the asset value to which the 9.25% expected long-term rate of return is applied. SFAS No. 87 specifies that entities may use either fair value or an averaging method that recognizes changes in fair value over a period not to exceed five years, with the method selected applied on a consistent basis from year to year. The Company has historically used a five-year averaging method. When the Company acquired Florida Progress Corporation (Florida Progress) in 2000, it retained the Florida Progress historical use of fair value to determine market-related value for Florida Progress pension assets. Changes in plan asset performance are reflected in pension cost sooner under the fair value method than the five-year averaging method and, therefore, pension cost tends to be more volatile using the fair value method. For example, in 2003 the expected return for assets subject to the averaging method was 3% lower than in 2002, whereas the expected return for assets subject to the fair value method was 18% lower than in 2002. Approximately 50% of the Company's pension plan assets is subject to each of the two methods. LIQUIDITY AND CAPITAL RESOURCES OVERVIEW Progress Energy is a registered holding company and, as such, has no operations of its own. As a holding company, Progress Energy's primary cash obligations are its common dividend and interest expense associated with $4.8 billion of senior unsecured debt. The ability to meet its obligations is primarily dependent on the earnings and cash flows of its two electric utilities and nonregulated subsidiaries, and the ability of those subsidiaries to pay dividends or repay funds to Progress Energy. Other significant 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 the Fuels segment. Progress Energy relies upon its operating cash flow, generated primarily by its two regulated electric utility subsidiaries, 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. As a registered holding company under Public Utility Holding Company Act of 1935 (PUHCA), Progress Energy obtains approval from the SEC for the issuance and sale of securities as well as the establishment of intercompany extensions of credit (utility and nonutility money pools). PEC and PEF participate in the utility money pool, which allows the two utilities to lend and borrow between each other. Progress Energy can lend money into the utility money pool but cannot borrow funds. The nonutility money pool was established to allow Progress Energy's nonregulated operations to lend and borrow funds amongst each other. Progress Energy can also lend money to the nonutility money pool but cannot borrow funds. During 2003, the Company realized approximately $450 million of net cash proceeds from the sale of NCNG and ENCNG. The Company also received net proceeds of approximately $97 million in October 2003 for the sale of its Mesa gas properties located in Colorado. Progress Energy used the proceeds from these sales to reduce indebtedness, primarily commercial paper, then outstanding. On March 1, 2004, Progress Energy used available cash and proceeds from the issuance of commercial paper to retire $500 million 6.55% senior unsecured notes. Cash and commercial paper capacity were created primarily from the sale of the assets in 2003 as noted above. For the 12 months ended December 31, 2003, the Company received approximately $309 million of net proceeds through the sale of 7.6 million shares of common stock issued through the Progress Energy Direct Stock Purchase and Dividend Reinvestment Plan, and its 401(k) Savings and Stock Ownership Plan. The Company expects to reduce the issuance of common stock in 2004. Progress Energy's cash from operations and common stock issuances in 2004 is expected to fund its capital expenditures. To the extent necessary, incremental borrowings or commercial paper issuances may also be used as a source of liquidity. 56 Progress Energy believes its internal and external liquidity resources will be sufficient to fund its current business plans. Risk factors associated with commercial paper backup credit facilities and credit ratings are discussed below and in the "Risk Factors" section of this report. 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. Total cash from operations for 2003 was $1.8 billion, compared to $1.6 billion in 2002. The increase in cash from operating activities for 2003 when compared with 2002 is largely the result of improved operating results at PEC. Total cash from operations for 2002 was $1.6 billion, up $271 million from 2001. Progress Energy's two electric utilities produced over 90% of consolidated cash from operations in 2003. It is expected that the two electric utilities will continue to produce a majority of the consolidated cash flows from operations over the next several years as its nonregulated investments, primarily generation assets, improve asset utilization and begin generating operating cash flows. In addition, Fuels' 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 provided the funding for approximately 90% of the Company's capital expenditures, including property additions, nuclear fuel expenditures and diversified business property additions during 2003, excluding proceeds from asset sales of $579 million. Progress Energy expects its operating cash flow to exceed its projected capital expenditures and common dividends beginning in 2004 and current plans are to use the excess cash flow to reduce debt. INVESTING ACTIVITIES Excluding proceeds from sales of subsidiaries and investments, cash used in investing activities was $2.0 billion in 2003, down approximately $300 million when compared with 2002. The decrease is due primarily to lower utility property additions due to completion of Hines 2 construction at PEF and lower acquisitions of nonregulated assets. Cash used in investing was $2.2 billion in 2002, up $562 million when compared with 2001. The increase was due primarily to PVI purchasing two generating projects from LG&E Energy Corp. for approximately $350 million. Capital expenditures for Progress Energy's regulated electric operations were $1.0 billion or approximately 58% of consolidated capital expenditures in 2003, excluding proceeds from asset sales. As shown in the table below, the Company anticipates that the proportion of nonregulated capital spending to total capital expenditures will decrease substantially in 2004 when compared with 2003. The decrease reflects the completion of PVI's nonregulated generation portfolio in 2003. Progress Energy expects the majority of its capital expenditures to be incurred at its regulated operations. Forecasted nonregulated expenditures relate primarily to Progress Fuels and its gas operations, primarily for drilling new wells. (in millions) Actual Forecasted ----------- ------------------------------------------------ 2003 2004 2005 2006 ----------- ------------ -------------- ----------- Regulated capital expenditures $ 1,018 $ 980 $ 990 $ 1,020 Nuclear fuel expenditures 117 90 120 80 AFUDC - borrowed funds (7) (20) (20) (10) Nonregulated capital expenditures 607 200 160 120 ----------- ------------ -------------- ----------- Total $ 1,735 $ 1,250 $ 1,250 $ 1,210 =========== ============ ============== ===========
Regulated capital expenditures in the table above include total expenditures from 2004 through 2006 of approximately $105 million expected to be incurred at PEC fossil-fueled electric generating facilities to comply with Section 110 of the Clean Air Act, referred to as the NOx SIP Call. See Note 21E to the Progress Energy Consolidated Financial Statements. 57 In June 2002, legislation was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of nitrogen oxide (NOx) and sulfur dioxide (SO2) from coal-fired power plants. PEC expects its capital costs to meet these emission targets will be approximately $813 million by 2013. For the years 2004 through 2006, the Company expects to incur approximately $320 million of total capital costs associated with this legislation, which is included in the table above. See Note 21E to the Progress Energy Consolidated Financial Statements and "Current Regulatory Environment" under OTHER MATTERS below for more information on this legislation. In 2003, PEC determined that its external funding levels did not fully meet the nuclear decommissioning financial assurance levels required by the United States Nuclear Regulatory Commission (NRC). The funding levels had been adversely affected by the declines in the equity markets. The total shortfall was approximately $95 million (2010 dollars) for Robinson Unit No. 2, $82 million (2016 dollars) for Brunswick Unit No. 1 and $99 million (2014 dollars) for Brunswick Unit No. 2. PEC met the financial assurance requirements by obtaining a parent company guarantee. The funding status for these facilities would be positively affected by a continuing recovery in the equity markets and by the approval of license extension applications. PEC retains funds internally to meet decommissioning liability. The NCUC order issued February 2004 found that by January 1, 2008 PEC must begin transitioning these amounts to external funds. The transition of $131 million must be completed by December 31, 2017, and at least 10% must be transitioned each year. PEC has exclusively utilized external funding for its decommissioning liability since 1994. 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 operating activities and proceeds from asset sales exceeded property and fuel additions by approximately $625 million. The excess, when combined with $304 million of net cash generated from the sale of common stock, resulted in an increase of cash and cash equivalents of $212 million after paying common dividends. As of December 31, 2003, on a consolidated basis, the Company had $868 million of long-term debt maturing in 2004, $300 million of which was prefunded through issuances of long-term debt in 2003. On March 1, 2004, Progress Energy funded the maturity of its $500 million 6.55% senior unsecured notes with cash on hand and commercial paper. On January 15, 2004, PEC funded the maturity of $150 million 5.875% First Mortgage Bonds with commercial paper proceeds. PEC also has $150 million 7.875% First Mortgage Bonds maturing on April 15, 2004. It plans to use commercial paper proceeds to fund this maturity. During 2003, both PEC and PEF took advantage of historically low interest rates and refinanced several issues of debt. In February 2003, PEF issued $425 million of First Mortgage Bonds, 4.80% Series, Due March 1, 2013 and $225 million of First Mortgage Bonds, 5.90% Series, Due March 1, 2033. Proceeds from this issuance were used to repay the balance of its outstanding commercial paper, to refinance its secured and unsecured indebtedness, including $150 million of PEF's First Mortgage Bonds, 8% Series, Due December 1, 2022 at 103.75% of the principal amount of such bonds. On March 1, 2003, $70 million of PEF's First Mortgage Bonds, 6.125% Series, Due March 1, 2003, matured. PEF funded the maturity with commercial paper. On May 27, 2003, PEC redeemed $150 million of First Mortgage Bonds, 7.5% Series, Due March 1, 2023 at 103.22% of the principal amount of such bonds. PEC funded the redemption with commercial paper. On July 1, 2003, $110 million of PEF's First Mortgage Bonds, 6.0% Series, Due July 1, 2003 and $35 million of PEF's medium-term notes, 6.62% Series, matured. PEF funded the maturity with commercial paper. On August 15, 2003, PEC redeemed $100 million of First Mortgage Bonds, 6.875% Series, Due August 15, 2023 at 102.84%. PEC funded the redemption with commercial paper. 58 On September 11, 2003, PEC issued $400 million of First Mortgage Bonds, 5.125% Series, Due September 15, 2013 and $200 million of First Mortgage Bonds, 6.125% Series, Due September 15, 2033. Proceeds from this issuance were used to reduce the balance of PEC's outstanding commercial paper and short-term notes payable to affiliated companies, which notes represent PEC's borrowings under the internal money pool operated by Progress Energy. On November 21, 2003, PEF issued $300 million of First Mortgage Bonds, 5.10% Series Due December 1, 2015. Proceeds from this issuance were used to refinance $100 million of PEF's First Mortgage Bonds, 7% Series, Due 2023 at 103.19% of the principal amount of such bonds and to reduce the outstanding balance of its notes payable to affiliates. The amount of debt issued by PEC and PEF in September and November, respectively, took into consideration debt maturities and other financing needs for 2004. As such, neither PEC nor PEF anticipate the need to issue long-term debt in 2004. In March 2003, Progress Genco Ventures LLC (Genco), a wholly-owned subsidiary of PVI, terminated its $50 million working capital credit facility. Under a related construction facility, Genco has drawn $241 million at December 31, 2003. During 2003, Progress Energy obtained a new three-year financing order which will expire September 30, 2006. Under the new order, Progress Energy, the holding company, can issue up to $2.8 billion of long-term securities, $1.5 billion of short-term debt and $3 billion of parent guarantees. At December 31, 2003, the Company and its subsidiaries had committed lines of credit totaling $1.6 billion, for which there were no loans outstanding. All of the credit facilities supporting the $1.6 billion of credit were arranged through a syndication of commercial banks. There are no bilateral contracts associated with these facilities. These lines of credit support the Company's commercial paper borrowings. The following table summarizes the Company's credit facilities: (in millions) Company Description Total - ------------------------------------------------------------------------------ Progress Energy, Inc. 364-Day (expiring 11/10/04) $ 250 Progress Energy, Inc. 3-Year (expiring 11/13/04) 450 Progress Energy Carolinas, Inc. 364-Day (expiring 7/29/04) 165 Progress Energy Carolinas, Inc. 3-Year (expiring 7/31/05) 285 Progress Energy Florida, Inc. 364-Day (expiring 3/31/04) 200 Progress Energy Florida, Inc. 3-Year (expiring 4/01/06) 200 ----------- Total credit facilities $ 1,550 =========== The Company's financial policy precludes issuing commercial paper in excess of its supporting lines of credit. At December 31, 2003, the Company did not have any commercial paper outstanding, leaving $1.6 billion available for issuance. In addition, the Company had requirements to pay minimal annual commitment fees to maintain its credit facilities. At December 31, 2002, the total amount of commercial paper outstanding was $695 million. In addition, these credit agreements and Genco's $241 million bank facility 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, an interest coverage test, a material adverse change clause and cross-default provisions. All of the credit facilities and Genco's bank facility include a defined maximum total debt-to-total capital ratio (leverage) and coverage ratios. At December 31, 2003, the calculated ratios for these four companies, pursuant to the terms of the agreements, are as follows: 59 Maximum Actual Minimum Actual Leverage Leverage (a) Coverage Coverage Company Ratio Ratio Ratio Ratio - --------------------------------------------------------------------------------------------- Progress Energy, Inc. 68% 61.5% 2.5 : 1 3.74 : 1 Progress Energy Carolinas, Inc. 65% 51.4% n/a n/a Progress Energy Florida, Inc. 65% 51.5% 3.0 : 1 9.22 : 1 Progress Genco Ventures, LLC 40% 24.6% 1.25 : 1 6.35 : 1 - --------------------------------------------------------------------------------------------- (a) Indebtedness as defined by the bank agreements includes certain letters of credit and guarantees which are not recorded on the Consolidated Balance Sheets.
The credit facilities of Progress Energy, PEC, PEF and Genco 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. Each of these credit agreements contains cross-default provisions for defaults of indebtedness in excess of $10 million. Under these provisions, if the applicable borrower or certain subsidiaries of the borrower 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. Progress Energy's cross-default provision only applies to Progress Energy and its significant subsidiaries (i.e., PEC, Florida Progress, PEF, Progress Capital Holdings, Inc. (PCH), PVI and Progress Fuels). 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 only apply to other obligations of Progress Energy, primarily commercial paper issued by the holding company, not its subsidiaries. In the event that these indenture cross-default provisions are triggered, the debt holders could accelerate payment of approximately $4.3 billion in long-term debt, as of March 1, 2004. Certain agreements underlying the Company's indebtedness also limit its ability to incur additional liens or engage in certain types of sale and leaseback transactions. 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. At December 31, 2003, the Company had approximately $1 billion available under this shelf registration. Progress Energy and PEF each have an uncommitted bank bid facility authorizing each of them to borrow and re-borrow, and have loans outstanding at any time, up to $300 million and $100 million, respectively. At December 31, 2003, there were no outstanding loans against these facilities. PEC currently has on file with the SEC a shelf registration statement under which it can issue up to $900 million of various long-term securities. PEF currently has on file registration statements under which it can issue an aggregate of $750 million of various long-term debt securities. Both PEC and PEF can issue First Mortgage Bonds under their respective First Mortgage Bond indentures. At December 31, 2003, PEC and PEF could issue up to $2.8 billion and $3.4 billion based on property additions and $1.9 billion and $76 million based upon retirements. The following table shows Progress Energy's and Progress Energy Carolinas' capital structure at December 31, 2003 and 2002: Progress Energy PEC -------------------------- ------------------------ 2003 2002 2003 2002 - ------------------------------------------------------------------------- Common Stock 40.6% 38.2% 48.2% 46.6% Preferred Stock 0.5% 0.5% 0.9% 0.9% Total Debt 58.9% 61.3% 50.9% 52.5% 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. 60 CREDIT RATING MATTERS The major credit rating agencies have currently rated the Company's securities as follows: Moody's Investors Service Standard & Poor's Fitch Ratings - ---------------------------------------------------------------------------------------------------- Progress Energy, Inc. Corporate Credit Rating Not Applicable BBB Not Applicable Senior Unsecured Baa2 BBB- BBB- Commercial Paper P-2 A-2 Not Applicable Progress Energy Carolinas, Inc. Corporate Credit Rating Not Applicable BBB Not Applicable Commercial Paper P-2 A-2 F2 Senior Secured Debt A3 BBB A- Senior Unsecured Debt Baa1 BBB BBB+ Progress Energy Florida, Inc. Corporate Credit Rating Not Applicable BBB Not Applicable Commercial Paper P-1 A-2 F2 Senior Secured Debt A1 BBB A- Senior Unsecured Debt A2 BBB BBB+ FPC Capital I Preferred Stock* Baa1 BB+ Not Applicable Progress Capital Holdings, Inc. Senior Unsecured Debt* A3 BBB- Not Applicable - ---------------------------------------------------------------------------------------------------- *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 and its subsidiaries' debt indentures and credit agreements do not 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, certain Progress Energy guarantees 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. The power supply agreement with Jackson Electric Membership Corporation that PVI acquired from Williams Energy Marketing and Trading Company (See PART I, ITEM 1, General, Wholesale Energy Contract Acquisition) included a performance guarantee that Progress Energy assumed. In the event that Progress Energy's credit ratings fall below investment grade, Progress Energy will be required to provide additional security for its guarantee in form and amount acceptable to Jackson. See Progress Energy, Inc. Risk Factors for additional discussion. In February 2003, Moody's Investors Service announced that it was lowering Progress Energy, Inc.'s senior unsecured debt rating from Baa1 to Baa2, and changing the outlook of the rating from negative to stable. Moody's cited the slower-than-planned pace of the Company's efforts to pay down debt from its acquisition of Florida Progress as the primary reason for the ratings change. Moody's also changed the outlook of PEF (A1 senior secured) and PCH (A3 senior unsecured) from stable to negative and lowered the trust preferred rating of FPC Capital I from A3 to Baa1 with a negative outlook. Also in February 2003, Fitch Ratings Service assigned an initial rating to Progress Energy's senior unsecured debt of BBB-. No short-term rating was assigned. Fitch also downgraded the ratings of PEF and PEC. PEF's senior secured rating was changed to A- from AA- and its senior unsecured rating was changed to BBB+ from A+. PEF's short-term rating was changed to F-2 from F-1+. PEC's senior secured rating was changed to A- from A+ and its senior unsecured rating was changed to BBB+ from A. PEC's short-term rating was changed to F-2 from F-1. Fitch's outlook for all three rated entities is stable. 61 In August 2003, Standard & Poor's (S&P) credit rating agency announced that it had lowered its corporate credit rating on Progress Energy Inc., PEC, PEF, and Florida Progress to BBB from BBB+. The outlook of the ratings was changed from negative to stable. These changes have not had a material impact on the companies' access to capital or their financial results. Interest Rate Derivatives 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% variable rate debt, 70% fixed rate. At December 31, 2003, Progress Energy's variable rate and fixed rate debt comprised 16% and 84%, respectively, including the effects of interest rate derivatives. During 2003, cash proceeds from the sale of NCNG and gas reserves were used to pay down debt, primarily commercial paper. While this reduced the Company's floating rate portion well below its long-term target of 30%, on March 1, 2004, the Company issued commercial paper to fund a portion of the maturing $500 million 6.55% senior unsecured notes, increasing the amount of floating rate debt back to over 20%. Progress Fuels periodically enters into derivative instruments to hedge its exposure to price fluctuations on natural gas sales. At December 31, 2003, Progress Fuels had approximately 19 Bcf of cash flow hedges in place for its natural gas production. These positions extend through December 2005. Genco has a floating rate credit facility that requires, as part of the loan terms, a cash flow hedge against floating interest rate exposure. In order to satisfy this requirement, Genco entered into a series of interest rate collars during 2002 with notional amounts up to a maximum of $195 million and a final maturity date of March 20, 2007. Contractual Obligations The following table reflects Progress Energy's contractual cash obligations and other commercial commitments at December 31, 2003 in the respective periods in which they are due: (in millions) - --------------------------------------------------------------------------------------------------------- Less than 1 More than 5 Contractual Obligations Total year 1-3 years 3-5 years years - --------------------------------------------------------------------------------------------------------- Long-term debt $ 10,874 $ 868 $ 1,256 $ 1,742 $ 7,008 Capital lease obligations 50 4 8 7 31 Operating leases 307 38 60 41 168 Fuel and purchased power 10,683 1,672 1,976 1,312 5,723 Other purchase obligations 369 140 78 27 124 North Carolina clean air capital commitments 783 90 230 210 253 Funding obligations 182 51 - 13 118 Other commitments 111 26 52 33 - ------------------------------------------------------------------ Total $ 23,359 $ 2,889 $ 3,660 $ 3,385 $ 13,425 ==================================================================
Information on the Company's contractual obligations at December 31, 2003 is included in the notes to the Progress Energy Consolidated Financial Statements. Future debt maturities are included in Note 12 to the Progress Energy Consolidated Financial Statements. The Company's fuel and purchased power obligations have expiration dates ranging from 2004 to 2025 and are included in Note 21A to the Progress Energy Consolidated Financial Statements. The Company's other purchase obligations are included in Note 21A to the Progress Energy Consolidated Financial Statements. The Company's lease obligations are included in Note 21C to the Progress Energy Consolidated Financial Statements. PEC's North Carolina clean air legislation capital commitments are described in Note 21E to the Progress Energy Consolidated Financial Statements. In 2004, the Company expects to make $51 million of required contributions directly to retirement plan assets. Decommissioning cost provisions are included in Note 5D to the Progress Energy Consolidated Financial Statements. In 2008, PEC must begin transitioning amounts currently retained internally to its external decommissioning funds. The transition of $131 million must be complete by December 31, 2017, and at least 10% must be transitioned each year. The Company's other commitments are included in Note 21B to the Progress Energy Consolidated Financial Statements. 62 The Company takes into consideration the future commitments shown above when assessing its liquidity and future financing needs. The Company's maturing debt obligations are generally expected to be refinanced with new debt issuances in the capital markets. However, the Company does plan to annually reduce its leverage by one to two percentage points over the next few years through the sale of assets and excess operating cash flow. Fuel and purchased power commitments represent the majority of the Company's remaining future commitments after its debt obligations. Essentially all of the Company's fuel and purchased power costs are recovered through pass-through clauses in accordance with North Carolina, South Carolina and Florida regulations and therefore do not require separate liquidity support. OTHER MATTERS CURRENT REGULATORY ENVIRONMENT General The Company's electric utility operations in North Carolina, South Carolina and Florida are regulated by the NCUC, the Public Service Commission of South Carolina (SCPSC) and the FPSC, respectively. The electric businesses are also subject to regulation by the FERC, the NRC and other federal and state agencies common to the utility business. In addition, the Company is subject to SEC regulation 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 are permitted to earn, are subject to the approval of governmental agencies. Electric Industry Restructuring PEC and PEF continue to monitor any developments 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 other states. The Company expects the legislatures in all three states will continue to monitor the experiences of states that have implemented electric restructuring legislation. The Company cannot anticipate when, or if, any of these states will move to increase competition in the electric industry. Florida Retail Rate Proceeding In March 2002, the parties in PEF's rate case entered into a Stipulation and Settlement Agreement (the Agreement) related to retail rate matters. The Agreement was approved by the FPSC and is generally effective from May 1, 2002 through December 31, 2005; provided, however, that if PEF's base rate earnings fall below a 10% return on equity, PEF may petition the FPSC to amend its base rates. See Note 7D to the Progress Energy Consolidated Financial Statements for additional information on the Agreement. North Carolina Clean Air Legislation In June 2002, legislation was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of NOx and SO2 from coal-fired power plants. Progress Energy expects its capital costs to meet these emission targets to be approximately $813 million by 2013, of which approximately $30 million has been expended through December 31, 2003. PEC currently has approximately 5,100 MW of coal-fired generation in North Carolina that is affected by this legislation. The legislation requires the emissions reductions to be completed in phases by 2013, and applies to each utility's total system rather than setting requirements for individual power plants. The legislation also freezes the utilities' base rates for five years unless there are significant cost changes due to governmental action or other extraordinary events beyond the control of the utilities or unless the utilities persistently earn a return substantially in excess of the rate of return established and found reasonable by the NCUC in the utilities' last general rate case. Further, the legislation allows the utilities to recover from their retail customers the projected capital costs during the first seven years of the 10-year compliance period beginning on January 1, 2003. The utilities must recover at least 70% of their projected capital costs during the five-year rate freeze period. Pursuant to the law, PEC entered into an agreement with the state of North Carolina to transfer to the state all future emissions allowances it generates from over-complying with the federal emission limits when these units are completed. The law also requires the state to undertake a study of mercury and carbon dioxide emissions 63 in North Carolina. Operation and maintenance costs will increase due to the additional personnel, materials and general maintenance associated with the equipment. Operation and maintenance expenses are recoverable through base rates, rather than as part of this program. Progress Energy cannot predict the future regulatory interpretation, implementation or impact of this law. Florida Proposed Clean Air Legislation In 2004, a bill was introduced in the Florida legislature that would require significant reductions in SO2, NOx and particulate emissions from certain coal, natural gas and oil-fired generating units owned or operated by investor-owned electric utilities, including PEF. The SO2 and NOx reductions would be effective beginning with calendar year 2010 and the particulate reductions would be effective beginning with calendar year 2012. Under the proposed legislation, the FPSC would be authorized to allow the utilities to recover the costs of compliance with the emission reductions over a period not greater than seven years beginning in 2005, but the utilities' rates would be frozen at 2004 levels for at least five years of the maximum recovery period. The Company cannot predict the outcome of this matter. Other Retail Rate Matters See Note 7B to the Progress Energy Consolidated Financial Statements for additional information on the Company's other retail rate matters. Regional Transmission Organizations and Standard Market Design In 2000, the FERC issued Order 2000 regarding RTOs. This Order set minimum characteristics and functions that RTOs must meet, including independent transmission service. In July 2002, the FERC issued its Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). If adopted as proposed, the rules set forth in the SMD NOPR would materially alter the manner in which transmission and generation services are provided and paid for. PEC and PEF, as subsidiaries of Progress Energy, filed comments in November 2002 and supplemental comments in January 2003. In April 2003, the FERC released a White Paper on the Wholesale Market Platform. The White Paper provides an overview of what the FERC currently intends to include in a final rule in the SMD NOPR docket. The White Paper retains the fundamental and most-protested aspects of SMD NOPR, including mandatory RTOs and the FERC's assertion of jurisdiction over certain aspects of retail service. The FERC has not yet issued a final rule on SMD NOPR. The Company cannot predict the outcome of these matters or the effect that they may have on the GridFlorida and GridSouth proceedings currently ongoing before the FERC. It is unknown what impact the future proceedings will have on the Company's earnings, revenues or prices. See Note 7C to the Progress Energy Consolidated Financial Statements for additional information on GridFlorida and GridSouth. FRANCHISE LITIGATION Three cities, with a total of approximately 18,000 customers, have litigation pending against PEF in various circuit courts in Florida. Three other cities, with a total of approximately 30,000 customers, have subsequently settled their lawsuits with PEF and signed new, 30-year franchise agreements. The lawsuits principally seek 1) a declaratory judgment that the cities have the right to purchase PEF'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 PEF to continue to collect from PEF's customers and remit to the cities, franchise fees during the pending litigation, and as long as PEF continues to occupy the cities' rights-of-way to provide electric service, notwithstanding the expiration of the franchise ordinances under which PEF had agreed to collect such fees. Five circuit courts have entered orders requiring arbitration to establish the purchase price of PEF's electric distribution system within five cities. Two appellate courts have upheld those circuit court decisions and authorized cities to determine the value of PEF's electric distribution system within the cities through arbitration. Arbitration in one of the cases (the City of Casselberry) was held in August 2002. Following arbitration, the parties entered settlement discussions, and in July 2003, the City approved a settlement agreement and a new, 30-year franchise agreement with PEF. The settlement resolves all pending litigation with that city. A second arbitration (with the 13,000-customer City of Winter Park) was completed in February 2003. That arbitration panel issued an award in May 2003 setting the value of PEF's distribution system within the City of Winter Park at approximately $32 million, not including separation and reintegration costs and construction work in progress, which could add several million dollars to the award. The panel also awarded PEF approximately $11 million in stranded costs. In September 2003, Winter Park voters passed a referendum that would authorize the City to issue bonds of up to approximately $50 million to acquire PEF's electric distribution system. The City has not yet definitively decided whether it will acquire the system, but has indicated that it will seek wholesale power supply bids and bids to operate and maintain the distribution system. At this time, whether and when there will be further proceedings regarding the City of Winter Park cannot be determined. A third arbitration (with the 2,500-customer Town of Belleair) was completed in June 2003. In September 2003, the arbitration panel issued an award in that case setting the value of the electric distribution system within the Town at approximately $6 million. The panel further required the Town to pay to PEF its requested $1 million in separation and reintegration costs and approximately $2 million in stranded costs. The Town has not yet decided whether it will attempt to acquire the system. At this time, whether and when there will be further proceedings regarding the Town of Belleair cannot be determined. A fourth arbitration (with the 13,000-customer City of Apopka) had been scheduled for January 2004. In December 2003, the Apopka City Commission voted on first reading to approve a settlement agreement and a 30-year franchise with PEF. The settlement and franchise became effective upon approval by the Commission at a second reading of the franchise in January 2004. The settlement resolves all outstanding litigation between the parties. Arbitration in the remaining city's litigation (the 1,500-customer City of Edgewood) has not yet been scheduled. 64 As part of the above litigation, two appellate courts have also reached opposite conclusions regarding whether PEF must continue to collect from its customers and remit to the cities "franchise fees" under the expired franchise ordinances. PEF has filed an appeal with the Florida Supreme Court to resolve the conflict between the two appellate courts. The Florida Supreme Court held oral argument in one of the appeals in August 2003. Subsequently, the Court requested briefing from the parties in the other appeal, which was completed in November 2003. The Court has not yet issued a decision in these cases. The Company cannot predict the outcome of these matters at this time. 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 the FERC. See Note 5D to the Progress Energy Consolidated Financial Statements for a discussion of the Company's nuclear decommissioning costs. SYNTHETIC FUELS TAX CREDITS Progress Energy, through the Fuels business segment, produces coal-based solid synthetic fuel. The production and sale of the synthetic fuel qualifies for tax credits under Section 29 if certain requirements are satisfied, including a requirement that the synthetic fuel differs significantly in chemical composition from the feedstock used to produce such synthetic fuel and that the fuel was produced from a facility that was placed in service before July 1, 1998. Any synthetic fuel tax credit amounts not utilized are carried forward indefinitely and are included in deferred taxes on the accompanying Consolidated Balance Sheets. See Note 14 to the Progress Energy Consolidated Financial Statements. All entities have received PLRs from the IRS with respect to their synthetic fuel operations. These tax credits are subject to review by the IRS, and if Progress Energy fails to prevail through the administrative 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. Total Section 29 credits generated to date (including FPC prior to its acquisition by the Company) are approximately $1,243 million. The current Section 29 tax credit program expires at the end of 2007. One of the Company's synthetic fuel entities, Colona Synfuel Limited Partnership, L.L.L.P. (Colona), from which the Company (and FPC prior to its acquisition by the Company) has been allocated approximately $317 million in tax credits to date, is being audited by the IRS. The Company is audited regularly in the normal course of business, as are most similarly situated companies, and the audit of Colona was expected. In September 2002, all of Progress Energy's majority-owned synthetic fuel entities, including Colona, were accepted into the IRS Pre-Filing Agreement (PFA) program. The PFA program allows taxpayers to voluntarily accelerate the IRS exam process in order to seek resolution of specific issues. Either the Company or the IRS can withdraw from the program at any time, and issues not resolved through the program may proceed to the next level of the IRS exam process. 65 In June 2003, the Company was informed that IRS field auditors had raised questions regarding the chemical change associated with coal-based synthetic fuel manufactured at its Colona facility and the testing process by which the chemical change is verified. (The questions arose in connection with the Company's participation in the PFA program.) The chemical change and the associated testing process were described as part of the PLR request for Colona. Based on that application, the IRS ruled in Colona's PLR that the synthetic fuel produced at Colona undergoes a significant chemical change and thus qualifies for tax credits under Section 29. In October 2003, the National Office of the IRS informed the Company that it had rejected the IRS field auditors' challenges regarding whether the synthetic fuel produced at the company's Colona facility was the result of a significant chemical change. The National Office had concluded that the experts, engaged by Colona who test the synthetic fuel for chemical change, use reasonable scientific methods to reach their conclusions. Accordingly, the National Office will not take any adverse action on the PLR that has been issued for the Colona facility. Although this ruling applies only to the Colona facility, the Company believes that the National Office's reasoning would be equally applicable to the other Progress Energy facilities. The Company applies essentially the same chemical process and uses the same independent laboratories to confirm chemical change in the synthetic fuel manufactured at each of its other facilities. In February 2004, subsidiaries of the Company finalized execution of the Colona Closing Agreement with the IRS concerning their Colona synthetic fuel facilities. The Colona Closing Agreement provided that the Colona facilities were placed in service before July 1, 1998, which is one of the qualification requirements for tax credits under Section 29. The Colona Closing Agreement further provides that the fuel produced by the Colona facilities in 2001 is a "qualified fuel" for purposes of the Section 29 tax credits. This action concludes the IRS PFA program with respect to Colona. Although the execution of the Colona Closing Agreement is a significant event, the audits of the Company's facilities are not yet completed and the PFA process continues with respect to the four synthetic fuel facilities owned by other affiliates of Progress Energy and FPC. Currently, the focus of that process is to determine that the facilities were placed in service before July 1, 1998. In management's opinion, Progress Energy is complying with all the necessary requirements to be allowed such credits under Section 29, although it cannot provide certainty, that it will prevail if challenged by the IRS on credits taken. Accordingly, the Company has no current plans to alter its synthetic fuel production schedule as a result of these matters. In October 2003, the United States Senate Permanent Subcommittee on Investigations began a general investigation concerning synthetic fuel tax credits claimed under Section 29. The investigation is examining the utilization of the credits, the nature of the technologies and fuels created, the use of the synthetic fuel, and other aspects of Section 29 and is not specific to the Company's synthetic fuel operations. Progress Energy is providing information in connection with this investigation. The Company cannot predict the outcome of this matter. In addition, the Company has retained an advisor to assist in selling an interest in one or more synthetic fuel entities. The Company is pursuing the sale of a portion of its synthetic fuel production capacity that is underutilized due to limits on the amount of credits that can be generated and utilized by the Company. The Company would expect to retain an ownership interest and to operate any sold facility for a management fee. The final outcome and timing of these discussions is uncertain and the Company cannot predict the outcome of this matter. 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. These environmental matters are discussed in detail in Note 21E to the Progress Energy Consolidated Financial Statements and Note 16D to the Progress Energy Carolinas Consolidated Financial Statements. This discussion identifies specific environmental issues, the status of the issues, accruals associated with issue resolutions and the associated exposures to the Company. NEW ACCOUNTING STANDARDS See Note 2 to the Progress Energy Consolidated Financial Statements for a discussion of the impact of new accounting standards. 66 PEC 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 PEC: RESULTS OF OPERATIONS; LIQUIDITY AND CAPITAL RESOURCES; FUTURE OUTLOOK and OTHER MATTERS. The following Management's Discussion and Analysis and the information incorporated herein by reference contain forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review "Risk Factors" and "SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS" for a discussion of the factors that may impact any such forward-looking statements made herein. RESULTS OF OPERATIONS The results of operations for the PEC consolidated for the years ended December 31, 2003, 2002 and 2001, respectively, are summarized in the table below. The results of operations for the PEC Electric segment are identical between PEC and Progress Energy for all periods presented. The primary difference between the results of operations of the PEC Electric segment and the consolidated PEC results of operations for the 2001, 2002 and 2003 comparison periods relate to the non-electric operations, as summarized below: (in millions) 2003 2002 2001 ---------- --------- --------- PEC Electric income before cumulative effect $ 515 $ 513 $ 468 Caronet net income (loss) 5 (79) (99) Other non-electric net loss (18) (6) (8) Cumulative effect of accounting change (23) - - ---------- --------- --------- Earnings for common stock $ 479 $ 428 $ 361 ========== ========= =========
Caronet's results of operations for 2002 and 2001 include after-tax impairments of $87 million and $107 million, respectively, for other-than-temporary declines in the value of the assets of Caronet and Caronet's investment in Interpath. The Interpath investment was sold in December 2002 for a nominal amount. In December 2003, PTC and Caronet, both wholly-owned subsidiaries of Progress Energy, and EPIK, a wholly-owned subsidiary of Odyssey, contributed substantially all of their assets and transferred certain liabilities to PTC LLC, a subsidiary of PTC. Subsequently, the stock of Caronet was sold to an affiliate of Odyssey for $2 million in cash and Caronet become an indirect wholly-owned subsidiary of Odyssey. Following consummation of all the transactions described above, PTC holds a 55 percent ownership interest in, and is the parent, of PTC LLC. Odyssey holds a combined 45 percent ownership interest in PTC LLC through EPIK and Caronet. The accounts of PTC LLC are included in the Company's Consolidated Financial Statements since the transaction date. The Other non-electric segments contributed segment losses of $18 million. Included in the 2003 segment losses is an investment impairment of $6 million after-tax on the Affordable Housing portfolio held by the non-utility subsidiaries of PEC. PEC Electric recorded cumulative effects of changes in accounting principles due to the adoption of a new accounting pronouncement. This adjustment totaled to a $23 million loss which was due primarily to the new FASB guidance related to the accounting for certain contracts. This guidance discusses whether the pricing in a contract that contains broad market indices qualifies for certain exceptions that would not require the contract to be recorded at its fair value. PEC Electric had a purchase power contract with Broad River LLC, that did not meet the criteria for an exception, and a negative fair value adjustment was recorded in the fourth quarter of 2003 for $23 million. See Note 12A to the PEC Consolidated Financial Statements Note 1C to the PEC Consolidated Financial Statements discusses its significant accounting policies. The most critical accounting policies and estimates that impact PEC's financial statements are the economic impacts of utility regulation and asset impairment policies, which are described in more detail in the Progress Energy Management's Discussion and Analysis section. 67 LIQUIDITY AND CAPITAL RESOURCES PEC's estimated capital requirements for 2004, 2005 and 2006 are $625 million, $595 million and $610 million, respectively, and primarily reflect construction expenditures to support customer growth, add regulated generation and upgrade existing facilities. PEC expects to fund its capital requirements primarily through internally generated funds. In addition, PEC has a $450 million credit facility which supports the issuance of commercial paper. Access to the commercial paper market and the utility money pool provide additional liquidity to help meet PEC's working capital requirements. See Note 8 to the PEC Consolidated Financial Statements for information on PEC's available credit facilities at December 31, 2003, and the discussion above for Progress Energy under "Financing Activities" for information regarding PEC's financing activities. CONTRACTUAL OBLIGATIONS The following table reflects PEC's contractual obligations and other commercial commitments at December 31, 2003 in the respective periods in which they are due: (in millions) - ------------------------------------------------------------------------------------------------------- Less than 1 More than 5 Contractual Obligations Total year 1-3 years 3-5 years years - ------------------------------------------------------------------------------------------------------- Long-term debt $ 3,408 $ 300 $ 300 $ 500 $ 2,308 Capital lease obligations 35 2 4 4 25 Operating leases 135 6 15 12 102 Fuel and purchased power 2,062 543 659 313 547 Other purchase obligations 18 5 - - 13 North Carolina clean air capital commitments 783 90 230 210 253 Funding obligations 148 17 - 13 118 - ------------------------------------------------------------------------------------------------------- Total $ 6,589 $ 963 $ 1,208 $ 1,052 $ 3,366 =================================================================
Information on PEC's contractual obligations at December 31, 2002 is included in the notes to the PEC Consolidated Financial Statements. Future debt maturities are included in Note 8 to the PEC Consolidated Financial Statements. PEC's fuel and purchased power obligations and lease obligations are included in Notes 16A and 16B, respectively, to the PEC Consolidated Financial Statements. PEC's other purchase obligations are included in Note 16A to the PEC Consolidated Financial Statements. PEC's North Carolina clean air legislation commitments are described in Note 16E to PEC's Consolidated Financial Statements. In 2004, PEC expects to make required contributions of $17 million directly to pension plan assets. Decommissioning cost provisions are included in Note 3D to the PEC Consolidated Financial Statements. In 2008, PEC must begin transitioning amounts currently retained internally to its external decommissioning funds. The transition of $131 million must be complete by December 31, 2017, and at least 10% must be transitioned each year. 68 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 risks discussed below do not include the price risks associated with nonfinancial 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 at December 31, 2003 and 2002, 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 and FPC obligated mandatorily redeemable securities of trust. 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. See "Interest Rate Derivatives" under LIQUIDITY AND CAPITAL RESOURCES above for more information on interest rate derivatives. December 31, 2003 Fair Value December 31, (dollars in millions) 2004 2005 2006 2007 2008 Thereafter Total 2003 - ----------------------------------------------------------------------------------------------------------------------- Fixed rate long-term debt $ 868 $ 349 $ 909 $ 674 $ 827 $ 5,836 $ 9,463 $ 10,501 Average interest rate 6.67% 7.38% 6.78% 6.41% 6.27% 6.51% 6.55% Variable rate long-term debt - - - $ 241 - $ 861 $ 1,102 $ 1,103 Average interest rate - - - 3.04% - 1.08% 1.51% Debt to affiliated trust - - - - - $ 309 $ 309 $ 313(d) Interest rate - - - - - 7.10% 7.10% Interest rate derivatives: Pay variable/receive fixed(a) - - $ (300) $ (350) $ (200) - $ (850) $ (4) Payer swaptions(b) - - - - $ 400 - $ 400 $ 5 Interest rate collars(c) $ 65 - - $ 130 - - $ 195 $ (11) - -----------------------------------------------------------------------------------------------------------------------
(a) Receives floating rate based on three-month London Inter Bank Offering Rate (LIBOR). Designated as hedge of $850 million of fixed-rate debt. (b) PGN has the right to enter into a 3-year, pay-fixed swap beginning January 2005 at a fixed rate of 4.75%. (c) Interest rate collars on $195 million notional. Designated as hedge of variable rate interest. (d) Refer to Note 12F to the Progress Energy Consolidated Financial Statements. 69 December 31, 2002 Fair Value December 31, (dollars in millions) 2003 2004 2005 2006 2007 Thereafter Total 2002 - ----------------------------------------------------------------------------------------------------------------------- Fixed rate long-term debt $ 275 $ 869 $ 355 $ 909 $ 674 $ 5,614 $ 8,696 $ 9,584 Average interest rate 6.42% 6.66% 7.38% 6.78% 6.41% 6.90% 6.83% - Variable rate long-term debt - - - - $ 225 $ 861 $ 1,086 $ 1,087 Average interest rate - - - - 0.03% 1.24% 1.61% - FPC mandatorily redeemable securities of trust - - - - - $ 300 $ 300 $ 303 Interest rate - - - - - 7.10% 7.10% - Interest rate derivatives: Pay variable /receive fixed(a) - - - - $ 350 - $ 350 $ 5 Interest rate forward contracts(b) $ 35 - - - - - $ 35 $ (1) Interest rate collars(c) - $ 65 - - $ 130 - $ 195 $ (12) - -----------------------------------------------------------------------------------------------------------------------
(a) Receives fixed and pays floating rate based on three-month LIBOR. (b) Treasury Rate Lock agreement on $35 million designated as cash flow hedge of anticipated debt issuance. (c) Interest rate collars on $195 million notional. Designated as hedge of variable rate interest. 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 $938 million and $797 million at December 31, 2003 and 2002, respectively. The Company actively monitors its portfolio by benchmarking the performance of its investments against certain indices and by maintaining, and periodically reviewing, target allocation percentages for various asset classes. The accounting for nuclear decommissioning recognizes 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. Contingent Value Obligations Market Value Risk In connection with the acquisition of FPC, the Company issued 98.6 million Contingent Value Obligations (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, 2003 and 2002, the fair value of these CVOs was $23 million and $14 million, respectively. A hypothetical 10% decrease in the December 31, 2003 market price would result in a $2 million decrease in the fair value of the CVOs. Commodity Price Risk The Company is exposed to the effects of market fluctuations in the price of natural gas, electricity and other energy-related products marketed and purchased as a result of its ownership of energy-related assets. The Company's exposure to these fluctuations is significantly limited by the cost-based regulation of PEC and PEF. In addition, many of the Company's long-term power sales contracts shift substantially all fuel responsibility to the purchaser. The Company uses natural gas hedging instruments to manage a portion of the market risk associated with fluctuations in the future sales price of the Company's natural gas. In addition, the Company may engage in limited economic hedging and trading activity using natural gas and electricity financial instruments. Refer to Note 17 to the Progress Energy Consolidated Financial Statements for additional information with regard to the Company's commodity contracts and use of derivative financial instruments. 70 PEC 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 PEC. Interest Rate Risk The following tables provide information at December 31, 2003 and 2002, about PEC's interest rate risk sensitive instruments: December 31, 2003 Fair Value December 31, (dollars in millions) 2004 2005 2006 2007 2008 Thereafter Total 2003 - ----------------------------------------------------------------------------------------------------------------- Fixed rate long-term debt $ 300 $ 300 - $ 200 $ 300 $ 1,688 $ 2,788 $ 3,065 Average interest rate 6.9% 7.50% - 6.80% 6.65% 6.09% 6.44% Variable rate long-term debt - - - - - $ 620 $ 620 $ 621 Average interest rate - - - - - - 1.09% December 31, 2002 Fair Value December 31, (dollars in millions) 2003 2004 2005 2006 2007 Thereafter Total 2002 - ------------------------------------------------------------------------------------------------------------------- Fixed rate long-term debt - $ 300 $ 307 - $ 200 $ 1,638 $ 2,445 $ 2,708 Average interest rate - 6.9% 7.48% - 6.80% 6.61% 6.76% - Variable rate long-term debt - - - - - $ 620 $ 620 $ 620 Average interest rate - - - - - 1.29% 1.29% -
Commodity Price Risk PEC exposed to the effects of market fluctuations in the price of natural gas, electricity and other energy-related products marketed and purchased as a result of its ownership of energy-related assets. PEC's exposure to these fluctuations is significantly limited by cost-based regulation. PEC may engage in limited economic hedging and trading activity using natural gas and electricity financial instruments. Refer to Note 12 to the Progress Energy Carolinas Consolidated Financial Statements for additional information with regard to PEC's commodity contracts and use of derivative financial instruments. 71 ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The following consolidated financial statements, supplementary data and consolidated financial statement schedules are included herein: Page Progress Energy, Inc. Independent Auditors' Report 74 Consolidated Financial Statements - Progress Energy, Inc.: Consolidated Statements of Income for the Years Ended December 31, 2003, 2002 and 2001 75 Consolidated Balance Sheets at December 31, 2003 and 2002 76 Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001 77 Consolidated Statements of Changes in Common Stock Equity for the Years Ended December 31, 2003, 2002 and 2001 78 Consolidated Quarterly Financial Data (Unaudited) 79 Notes to Consolidated Financial Statements Note 1 - Organization and Summary of Significant Accounting Policies 80 Note 2 - New Accounting Standards 84 Note 3 - Divestitures 85 Note 4 - Acquisitions and Business Combinations 87 Note 5 - Property, Plant and Equipment 89 Note 6 - Inventory 93 Note 7 - Regulatory Matters 94 Note 8 - Goodwill and Other Intangible Assets 97 Note 9 - Impairments of Long-Lived Assets and Investments 98 Note 10 - Equity 99 Note 11 - Preferred Stock of Subsidiaries - Not Subject to Mandatory Redemption 102 Note 12 - Debt and Credit Facilities 103 Note 13 - Fair Value of Financial Instruments 106 Note 14 - Income Taxes 107 Note 15 - Contingent Value Obligations 109 Note 16 - Benefit Plans 109 Note 17 - Risk Management Activities and Derivatives Transactions 113 Note 18 - Related Party Transactions 115 Note 19 - Financial Information by Business Segment 115 Note 20 - Other Income and Other Expense 116 Note 21 - Commitments and Contingencies 117
72 Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. Independent Auditors' Report 128 Consolidated Financial Statements - Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.: Consolidated Statements of Income and Comprehensive Income for the Years Ended December 31, 2003, 2002, and 2001 129 Consolidated Balance Sheets at December 31, 2003 and 2002 130 Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001 131 Consolidated Statements of Retained Earnings for the Years Ended December 31, 2003, 2002 and 2001 132 Consolidated Quarterly Financial Data (Unaudited) 132 Notes to Consolidated Financial Statements Note 1 - Organization and Summary of Significant Accounting Policies 133 Note 2 - New Accounting Standards 136 Note 3 - Property, Plant and Equipment 138 Note 4 - Inventory 141 Note 5 - Regulatory Matters 141 Note 6 - Impairments of Long-Lived Assets and Investments 143 Note 7 - Equity 144 Note 8 - Debt and Credit Facilities 146 Note 9 - Fair Value of Financial Instruments 147 Note 10 - Income Taxes 147 Note 11 - Benefit Plans 149 Note 12 - Risk Management Activities and Derivatives Transactions 152 Note 13 - Related Party Transactions 153 Note 14 - Financial Information by Business Segment 153 Note 15 - Other Income and Other Expense 154 Note 16 - Commitments and Contingencies 155 Independent Auditors' Report on Consolidated Financial Statement Schedule - Progress Energy, Inc. 163 Independent Auditors' Report on Consolidated Financial Statement Schedule - Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. 164 Consolidated Financial Statement Schedules for the Years Ended December 31, 2003, 2002 and 2001: II-Valuation and Qualifying Accounts - Progress Energy, Inc. 165 II-Valuation and Qualifying Accounts - Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. 166
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. 73 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 at December 31, 2003 and 2002, 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, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements 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, such financial statements present fairly, in all material respects, the financial position of the Company and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. As discussed in Notes 5F and 17A to the consolidated financial statements, in 2003, the Company adopted Statement of Financial Accounting Standards No. 143 and Derivatives Implementation Group Issue C20. As discussed in Note 8 to the consolidated financial statements, in 2002, the Company changed its method of accounting for goodwill to conform to Statement of Financial Accounting Standards No. 142. /s/ DELOITTE & TOUCHE LLP Raleigh, North Carolina February 20, 2004 74 PROGRESS ENERGY, INC. CONSOLIDATED STATEMENTS of INCOME Years ended December 31 (In millions except per share data) 2003 2002 2001 - -------------------------------------------------------------------------------------------------------------- Operating Revenues Utility $ 6,741 $ 6,601 $ 6,557 Diversified business 2,002 1,490 1,572 - -------------------------------------------------------------------------------------------------------------- Total Operating Revenues 8,743 8,091 8,129 - -------------------------------------------------------------------------------------------------------------- Operating Expenses Utility Fuel used in electric generation 1,695 1,586 1,543 Purchased power 862 862 868 Operation and maintenance 1,419 1,390 1,228 Depreciation and amortization 883 820 1,067 Taxes other than on income 405 386 380 Diversified business Cost of sales 1,746 1,410 1,589 Depreciation and amortization 157 118 83 Impairment of long-lived assets 17 364 43 Other 197 145 92 - -------------------------------------------------------------------------------------------------------------- Total Operating Expenses 7,381 7,081 6,893 - -------------------------------------------------------------------------------------------------------------- Operating Income 1,362 1,010 1,236 - -------------------------------------------------------------------------------------------------------------- Other Income (Expense) Interest income 11 15 22 Impairment of investments (21) (25) (164) Other, net (25) 27 (34) - -------------------------------------------------------------------------------------------------------------- Total Other Income (Expense) (35) 17 (176) - -------------------------------------------------------------------------------------------------------------- Interest Charges Net interest charges 632 641 690 Allowance for borrowed funds used during construction (7) (8) (17) - -------------------------------------------------------------------------------------------------------------- Total Interest Charges, Net 625 633 673 - -------------------------------------------------------------------------------------------------------------- Income from Continuing Operations before Income Tax and Cumulative Effect of Changes in Accounting Principles 702 394 387 Income Tax Benefit (109) (158) (154) - -------------------------------------------------------------------------------------------------------------- Income from Continuing Operations before Cumulative Effect of Changes in Accounting Principles 811 552 541 Discontinued Operations, Net of Tax (8) (24) 1 - -------------------------------------------------------------------------------------------------------------- Income before Cumulative Effect of Changes in Accounting Principles 803 528 542 Cumulative Effect of Changes in Accounting Principles, Net of Tax (21) - - - -------------------------------------------------------------------------------------------------------------- Net Income $ 782 $ 528 $ 542 - -------------------------------------------------------------------------------------------------------------- Average Common Shares Outstanding 237 217 205 - -------------------------------------------------------------------------------------------------------------- Basic Earnings per Common Share Income from Continuing Operations before Cumulative Effect of Changes in Accounting Principles $ 3.42 $ 2.54 $ 2.64 Discontinued Operations, Net of Tax (.03) (.11) .01 Cumulative Effect of Changes in Accounting Principles, Net of Tax (.09) - - Net Income $ 3.30 $ 2.43 $ 2.65 - -------------------------------------------------------------------------------------------------------------- Diluted Earnings per Common Share Income from Continuing Operations before Cumulative Effect of Changes in Accounting Principles $ 3.40 $ 2.53 $ 2.63 Discontinued Operations, Net of Tax (.03) (.11) .01 Cumulative Effect of Changes in Accounting Principles, Net of Tax (.09) - - Net Income $ 3.28 $ 2.42 $ 2.64 - -------------------------------------------------------------------------------------------------------------- Dividends Declared per Common Share $ 2.26 $ 2.20 $ 2.14 - --------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements. 75 PROGRESS ENERGY, INC. CONSOLIDATED BALANCE SHEETS (In millions) December 31 ASSETS 2003 2002 - ------------------------------------------------------------------------------------------------------------ Utility Plant Utility plant in service $ 21,675 $ 20,157 Accumulated depreciation (8,116) (7,540) - ------------------------------------------------------------------------------------------------------------ Utility plant in service, net 13,559 12,617 Held for future use 13 15 Construction work in progress 634 752 Nuclear fuel, net of amortization 228 217 - ------------------------------------------------------------------------------------------------------------ Total Utility Plant, Net 14,434 13,601 - ------------------------------------------------------------------------------------------------------------ Current Assets Cash and cash equivalents 273 61 Accounts receivable 865 737 Unbilled accounts receivable 217 225 Inventory 808 875 Deferred fuel cost 317 184 Assets of discontinued operations - 490 Prepayments and other current assets 348 262 - ------------------------------------------------------------------------------------------------------------ Total Current Assets 2,828 2,834 - ------------------------------------------------------------------------------------------------------------ Deferred Debits and Other Assets Regulatory assets 612 347 Nuclear decommissioning trust funds 938 797 Diversified business property, net 2,158 1,884 Miscellaneous other property and investments 464 519 Goodwill 3,726 3,719 Prepaid pension costs 462 60 Intangibles, net 327 155 Other assets and deferred debits 253 292 - ------------------------------------------------------------------------------------------------------------ Total Deferred Debits and Other Assets 8,940 7,773 - ------------------------------------------------------------------------------------------------------------ Total Assets $ 26,202 $ 24,208 - ------------------------------------------------------------------------------------------------------------ CAPITALIZATION AND LIABILITIES - ------------------------------------------------------------------------------------------------------------ Common Stock Equity Common stock without par value, 500 million shares authorized, 246 and 238 million shares issued and outstanding, $ 5,270 $ 4,951 respectively Unearned restricted shares (1 and 1 million shares, respectively) (17) (21) Unearned ESOP shares (4 and 5 million shares, respectively) (89) (102) Accumulated other comprehensive loss (50) (238) Retained earnings 2,330 2,087 - ------------------------------------------------------------------------------------------------------------ Total Common Stock Equity 7,444 6,677 - ------------------------------------------------------------------------------------------------------------ Preferred Stock of Subsidiaries-Not Subject to Mandatory Redemption 93 93 Long-Term Debt Affiliate 309 - Long-Term Debt 9,625 9,747 - ------------------------------------------------------------------------------------------------------------ Total Capitalization 17,471 16,517 - ------------------------------------------------------------------------------------------------------------ Current Liabilities Current portion of long-term debt 868 275 Accounts payable 704 659 Interest accrued 209 220 Dividends declared 140 132 Short-term obligations 4 695 Customer deposits 167 158 Liabilities of discontinued operations - 125 Other current liabilities 572 430 - ------------------------------------------------------------------------------------------------------------ Total Current Liabilities 2,664 2,694 - ------------------------------------------------------------------------------------------------------------ Deferred Credits and Other Liabilities Accumulated deferred income taxes 737 858 Accumulated deferred investment tax credits 190 206 Regulatory liabilities 2,938 120 Cost of removal - 2,940 Asset retirement obligations 1,271 - Other liabilities and deferred credits 931 873 - ------------------------------------------------------------------------------------------------------------ Total Deferred Credits and Other Liabilities 6,067 4,997 - ------------------------------------------------------------------------------------------------------------ Commitments and Contingencies (Note 21) - ------------------------------------------------------------------------------------------------------------ Total Capitalization and Liabilities $ 26,202 $ 24,208 - ------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements. 76 PROGRESS ENERGY, INC. CONSOLIDATED STATEMENTS of CASH FLOWS - ------------------------------------------------------------------------------------------------------------------------ Years ended December 31 (In millions) 2003 2002 2001 - ------------------------------------------------------------------------------------------------------------------------ Operating Activities Net income $ 782 $ 528 $ 542 Adjustments to reconcile net income to net cash provided by operating activities: Loss (income) from discontinued operations 8 24 (1) Impairment of long-lived assets and investments 38 389 207 Cumulative effect of changes in accounting principles 21 - - Depreciation and amortization 1,146 1,099 1,266 Deferred income taxes (276) (402) (367) Investment tax credit (16) (18) (23) Deferred fuel cost (credit) (133) (37) 69 Cash provided (used) by changes in operating assets and liabilities: Accounts receivable (168) (35) 183 Inventories 78 (49) (299) Prepayments and other current assets 25 (39) (21) Accounts payable 41 100 (213) Other current liabilities 167 56 123 Other 75 28 (93) - ------------------------------------------------------------------------------------------------------------------------ Net Cash Provided by Operating Activities 1,788 1,644 1,373 - ------------------------------------------------------------------------------------------------------------------------ Investing Activities Gross utility property additions (1,018) (1,174) (1,177) Diversified business property additions (607) (570) (350) Nuclear fuel additions (117) (81) (116) Proceeds from sales of subsidiaries and investments 579 43 53 Acquisition of businesses, net of cash - (365) - Acquisition of intangibles (200) (10) - Other (17) (61) (66) - ------------------------------------------------------------------------------------------------------------------------ Net Cash Used in Investing Activities (1,380) (2,218) (1,656) - ------------------------------------------------------------------------------------------------------------------------ Financing Activities Issuance of common stock, net 304 687 488 Issuance of long-term debt, net 1,539 1,783 4,564 Net decrease in short-term indebtedness (696) (247) (4,018) Retirement of long-term debt (810) (1,157) (322) Dividends paid on common stock (541) (480) (432) Other 8 (5) (42) - ------------------------------------------------------------------------------------------------------------------------ Net Cash Provided by (Used in) Financing Activities (196) 581 238 - ------------------------------------------------------------------------------------------------------------------------ Cash Used in Discontinued Operations - - (1) - ------------------------------------------------------------------------------------------------------------------------ Net Increase (Decrease) in Cash and Cash Equivalents 212 7 (46) - ------------------------------------------------------------------------------------------------------------------------ Cash and Cash Equivalents at Beginning of Year 61 54 100 - ------------------------------------------------------------------------------------------------------------------------ Cash and Cash Equivalents at End of Year $ 273 $ 61 $ 54 - ------------------------------------------------------------------------------------------------------------------------ Supplemental Disclosures of Cash Flow Information Cash paid during the year - interest (net of amount capitalized) $ 612 $ 631 $ 588 income taxes (net of refunds $ 177 $ 219 $ 127
Noncash Activities o In April 2002, Progress Fuels Corporation, a subsidiary of the Company, acquired 100% of Westchester Gas Company. In conjunction with the purchase, the Company issued approximately $129 million in common stock (See Note 4E). o In December 2003, Progress Telecommunications Corporation (PTC) and Caronet, Inc., both indirectly wholly-owned subsidiaries of Progress Energy, and EPIK Communications, Inc., a wholly-owned subsidiary of Odyssey Telecorp, Inc., contributed substantially all of their assets and transferred certain liabilities to Progress Telecom, LLC, a subsidiary of PTC (See Note 4A). See Notes to Consolidated Financial Statements. 77 PROGRESS ENERGY, INC. CONSOLIDATED STATEMENTS of CHANGES in COMMON STOCK EQUITY Unearned Accumulated Total Common Stock Unearned ESOP Other Common (In millions except per share data) Outstanding Restricted Common Comprehensive Retained Stock Shares Amount Stock Stock Income (Loss) Earnings Equity - --------------------------------------------------------------------------------------------------------------------------- Balance, January 1, 2001 206 $ 3,621 $ (13) $ (127) - $ 1,943 $ 5,424 Net income 542 542 FAS 133 transition adjustment (net of tax of $15) (24) (24) Change in net unrealized losses on cash flow hedges (net of tax of $13) (21) (21) Reclassification adjustment for amounts included in net income (net of tax of $9) 14 14 Foreign currency translation and other (1) (1) ----------- Comprehensive income 510 ----------- Issuance of shares 13 489 489 Purchase of restricted stock (8) (8) Restricted stock expense recognition 6 6 Cancellation of restricted shares (1) 1 - Allocation of ESOP shares 12 13 25 Dividends ($2.14 per share) (442) (442) - --------------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2001 219 4,121 (14) (114) (32) 2,043 6,004 Net income 528 528 Change in net unrealized losses on cash flow hedges (net of tax of $18) (28) (28) Reclassification adjustment for amounts included in net income (net of tax of $10) 16 16 Foreign currency translation and other (2) (2) Minimum pension liability adjustment (net of tax of $121) (192) (192) ----------- Comprehensive income 322 ----------- Issuance of shares 19 815 815 Purchase of restricted stock (16) (16) Restricted stock expense recognition 8 8 Cancellation of restricted shares (1) 1 - Allocation of ESOP shares 16 12 28 Dividends ($2.20 per share) (484) (484) - --------------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2002 238 4,951 (21) (102) (238) 2,087 6,677 Net income 782 782 Change in net unrealized losses on cash flow hedges (net of tax of $7) (12) (12) Reclassification adjustment for amounts included in net income (net of tax of ($11)) 19 19 Foreign currency translation and other 4 4 Minimum pension liability adjustment (net of tax of ($112)) 177 177 ----------- Comprehensive income 970 ----------- Issuance of shares 8 309 309 Purchase of restricted stock (1) (7) (8) Restricted stock expense recognition 10 10 Cancellation of restricted shares (1) 1 - Allocation of ESOP shares 12 13 25 Dividends ($2.26 per share) (539) (539) - --------------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2003 246 $ 5,270 $ (17) $ (89) $ (50) $ 2,330 $ 7,444 ===========================================================================================================================
See Notes to Consolidated Financial Statements. 78 CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED) (In millions except per share data) First Second Third Fourth Quarter Quarter Quarter Quarter - ------------------------------------------------------------------------------------------------------------------ Year ended December 31, 2003 Operating revenues $ 2,187 $ 2,050 $ 2,458 $ 2,048 Operating income 357 274 478 253 Income from continuing operations 208 154 337 112 Income before cumulative effect of changes in accounting principles 218 157 318 110 Net income 219 157 318 88 Common stock data: Basic earnings per common share Income from continuing operations 0.89 0.65 1.41 0.47 Income before cumulative effect of changes in accounting principles 0.94 0.67 1.33 0.46 Net income 0.94 0.67 1.33 0.37 Diluted earnings per common share Income from continuing operations 0.89 0.65 1.40 0.47 Income before cumulative effect of changes in accounting principles 0.93 0.66 1.33 0.46 Net income 0.94 0.66 1.33 0.37 Dividends paid per common share 0.560 0.560 0.560 0.560 Market price per share - High 46.10 48.00 45.15 46.00 Low 37.45 38.99 39.60 41.60 - ------------------------------------------------------------------------------------------------------------ Year ended December 31, 2002 Operating revenues $ 1,813 $ 1,994 $ 2,316 $ 1,968 Operating income 244 306 201 259 Income from continuing operations 124 122 157 149 Net income 133 121 152 122 Common stock data: Basic earnings per common share Income from continuing operations 0.58 0.57 0.72 0.66 Net income 0.62 0.56 0.71 0.55 Diluted earnings per common share Income from continuing operations 0.58 0.56 0.71 0.66 Net income 0.62 0.56 0.70 0.55 Dividends paid per common share 0.545 0.545 0.545 0.545 Market price per share - High 50.86 52.70 51.97 44.82 Low 43.01 47.91 36.54 32.84
o 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. All amounts were restated for discontinued operations (See Note 3A) and 2003 amounts were restated for the cessation of reporting results for portions of the Fuels' segment operations one month in arrears (See Note 1B). o Fourth quarter 2003 includes impairments related to Kentucky May and Affordable Housing investment of $38 million ($24 million after-tax) (See Note 9). o Fourth quarter 2003 includes a cumulative effect for DIG Issue 20 of $38 million ($23 million after-tax) (See Note 17). o Third quarter 2002 includes impairment and other charges related to PTC, Caronet and Interpath Communications, Inc. of $355 million ($225 million after-tax) (See Note 9). o Fourth quarter 2002 includes estimated impairment of assets held for sale of Railcar Ltd. of $59 million ($40 million after-tax) (See Note 3B). See Notes to Consolidated Financial Statements. 79 PROGRESS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Organization and Summary of Significant Accounting Policies A. Organization Progress Energy, Inc. (Progress Energy or the Company) is a holding company headquartered in Raleigh, North Carolina. The Company is registered under the Public Utility Holding Company Act of 1935 (PUHCA), as amended and as such, the Company and its subsidiaries are subject to the regulatory provisions of PUHCA. Effective January 1, 2003, three of the Company's subsidiaries, Carolina Power & Light Company (CP&L), Florida Power Corporation and Progress Ventures, Inc., began doing business under the assumed names Progress Energy Carolinas, Inc. (PEC), Progress Energy Florida, Inc. (PEF) and Progress Energy Ventures, Inc. (PVI), respectively. The legal names of these entities have not changed. The current corporate and business unit structure remains unchanged. Through its wholly-owned subsidiaries, PEC and PEF, the Company's PEC Electric and PEF segments are primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina, South Carolina and Florida. The Progress Ventures business unit consists of the Fuels business segment (Fuels) and Competitive Commercial Operations (CCO) operating segments. The Fuels segment is involved in natural gas drilling and production, coal terminal services, coal mining, synthetic fuel production, fuel transportation and delivery. The CCO segment includes nonregulated generation and energy marketing activities. Through the Rail Services (Rail) segment, the Company is involved in nonregulated railcar repair, rail parts reconditioning and sales, railcar leasing and sales, and scrap metal recycling. Through its other business units, the Company engages in other nonregulated business areas, including telecommunications and energy management and related services. Progress Energy's legal structure is not currently aligned with the functional management and financial reporting of the Progress Ventures business unit. Whether, and when, the legal and functional structures will converge depends upon legislative and regulatory action, which cannot currently be anticipated. B. Basis of Presentation The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) 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 ratemaking process is probable. Unconsolidated investments in companies over which the Company 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. Certain investments in debt and equity securities that have readily determinable market values, and for which the Company does not have control, are accounted for at fair value in accordance with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." Other investments are stated principally at cost. These equity and cost investments, which total approximately $57 million and $109 million at December 31, 2003 and 2002, respectively, are included in miscellaneous other property and investments in the Consolidated Balance Sheets. The primary component of this balance is the Company's investments in affordable housing of $29 million and $72 million at December 31, 2003 and 2002, respectively. This decrease is primarily due to the sale of certain PEC investments in the third quarter of 2003. For a discussion of how new FASB interpretations will affect these affordable housing investments see Note 2. The results of operations of Rail are reported one month in arrears. During 2003, the Company ceased recording portions of the Fuels' segment operations one month in arrears. The net impact of this action increased net income by $2 million for the year. Certain amounts for 2002 and 2001 have been reclassified to conform to the 2003 presentation. 80 C. Significant Accounting Policies Use of Estimates and Assumptions In preparing consolidated financial statements that conform with GAAP, 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. Revenue Recognition 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." Gains and losses from energy trading activities and other derivatives are reported on a net basis. Revenues related to design and construction of wireless infrastructure are recognized upon completion of services for each completed phase of design and construction. Revenues from the sale of oil and gas production are recognized when title passes, net of royalties. Fuel Cost Deferrals 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. Excise Taxes PEC and PEF collect from customers certain excise taxes levied by the state or local government upon the customers. PEC and PEF account for excise taxes on a gross basis. For the years ended December 31, 2003, 2002 and 2001, gross receipts tax, franchise taxes and other excise taxes of approximately $217 million, $211 million and $210 million, respectively, are included in taxes other than on income in the accompanying Consolidated Statements of Income. These approximate amounts are also included in utility revenues. Stock-Based Compensation The Company measures compensation expense for stock options as the difference between the market price of its common stock and the exercise price of the option at the grant date. The exercise price at which options are granted by the Company equals the market price at the grant date, and accordingly, no compensation expense has been recognized for stock option grants. For purposes of the pro forma disclosures required by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - an Amendment of FASB Statement No. 123" (SFAS No. 148), the estimated fair value of the Company's stock options is amortized to expense over the options' vesting period. The following table illustrates the effect on net income and earnings per share if the fair value method had been applied to all outstanding and unvested awards in each period: (in millions except per share data) 2003 2002 2001 --------- --------- --------- Net income, as reported $ 782 $ 528 $ 542 Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects 11 8 2 --------- -------- --------- Pro forma net income $ 771 $ 520 $ 540 ========= ========= ========= Earnings per share Basic - as reported $ 3.30 $ 2.43 $ 2.65 Basic - pro forma $ 3.25 $ 2.40 $ 2.64 Diluted - as reported $ 3.28 $ 2.42 $ 2.64 Diluted - pro forma $ 3.24 $ 2.39 $ 2.63
81 Utility Plant Utility plant in service is stated at historical cost less accumulated depreciation. The Company capitalizes all construction-related direct labor and material costs of units of property as well as indirect construction costs. The cost of renewals and betterments is also capitalized. Maintenance and repairs of property, and replacements and renewals of items determined to be less than units of property, are charged to maintenance expense as incurred. The cost of units of property replaced or retired, less salvage, is charged to accumulated depreciation. Removal and decommissioning costs were charged to regulatory liabilities in 2003 and cost of removal in 2002. The Company follows the guidance in SFAS No. 143, "Accounting for Asset Retirement Obligations," to account for legal obligations associated with the retirement of certain tangible long-lived assets. Depreciation and Amortization - Utility Plant 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 salvage (See Note 5A). The North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (SCPSC) and the Florida Public Service Commission (FPSC) can also grant approval to accelerate or reduce depreciation and amortization of utility assets (See Note 7). 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 units-of-production method and charged to fuel used in electric generation in the accompanying Consolidated Statements of Income. 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 the Federal Energy Regulatory Commission (FERC). Cash and Cash Equivalents The Company considers cash and cash equivalents to include unrestricted cash on hand, cash in banks and temporary investments purchased with a maturity of three months or less. Allowance for Doubtful Accounts The Company maintains an allowance for doubtful accounts receivable, which totaled approximately $28 million and $40 million at December 31, 2003 and 2002, respectively, and is included in accounts receivable on the Consolidated Balance Sheets. Inventory The Company accounts for inventory using the average-cost method. Regulatory Assets and Liabilities The Company's regulated operations are subject to SFAS No. 71, which allows a regulated company to record costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a nonregulated enterprise. Accordingly, the Company records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the accompanying Consolidated Balance Sheets as regulatory assets and regulatory liabilities (See Note 7A). Diversified Business Property Diversified business property is stated at cost less accumulated depreciation. If an impairment is recognized on an asset, the fair value becomes its new cost basis. The costs of renewals and betterments are capitalized. The cost of repairs and maintenance is charged to expense as incurred. Depreciation is computed on a straight-line basis using the estimated useful lives disclosed in Note 5B. Depletion of mineral rights is provided on the units-of-production method based upon the estimates of recoverable amounts of clean mineral. The Company uses the full cost method to account for its natural gas and oil properties. Under the full cost method, substantially all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of natural gas and oil reserves are capitalized. These capitalized costs include the costs of all unproved properties, internal costs directly related to acquisition and exploration activities. The amortization base also includes the estimated future cost 82 to develop proved reserves. Except for costs of unproved properties and major development projects in progress, all costs are amortized using the units-of-production method over the life of the Company's proved reserves. Goodwill and Intangible Assets Effective January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142), and no longer amortizes goodwill. Instead, goodwill is subject to at least an annual assessment for impairment by applying a two-step fair-value-based test. This assessment could result in periodic impairment charges. Prior to the adoption of SFAS No. 142, the Company amortized goodwill on a straight-line basis over a period not exceeding 40 years. Intangible assets are being amortized based on the economic benefit of their respective lives. Unamortized Debt Premiums, Discounts and Expenses 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 applicable life using the straight-line method consistent with ratemaking treatment. Income Taxes The Company and its affiliates file a consolidated federal income tax return. Deferred income taxes have been provided for temporary differences. These occur when there are differences between the book and tax carrying amounts of assets and liabilities. Investment tax credits related to regulated operations have been deferred and are being amortized over the estimated service life of the related properties. Credits for the production and sale of synthetic fuel are deferred to the extent they cannot be or have not been utilized in the annual consolidated federal income tax returns. Derivatives Effective January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), as amended by SFAS No. 138 and SFAS No. 149. 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. During 2003, the FASB reconsidered an interpretation of SFAS No. 133. See Note 17 for the effect of the interpretation and additional information regarding risk management activities and derivative transactions. Environmental The Company accrues environmental remediation liabilities when the criteria for SFAS No. 5, "Accounting for Contingencies" (SFAS No. 5), have been met. Environmental expenditures are expensed as incurred or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as additional information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recognized when their receipt is deemed probable (See Note 21E). Impairment of Long-Lived Assets and Investments The Company reviews the recoverability of long-lived tangible and intangible assets whenever indicators exist. Examples of these indicators include current period losses, combined with a history of losses or a projection of continuing losses, or a significant decrease in the market price of a long-lived asset group. If an indicator exists for assets to be held and used, then the asset group is tested for recoverability by comparing the carrying value to the sum of undiscounted expected future cash flows directly attributable to the asset group. If the asset group is not recoverable through undiscounted cash flows or the asset group is to be disposed of, then an impairment loss is recognized for the difference between the carrying value and the fair value of the asset group. The accounting for impairment of assets is based on SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which was adopted by the Company effective January 1, 2002. Prior to the adoption of this standard, impairments were accounted for under SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (SFAS No. 121), which was superseded by SFAS No. 144. 83 The Company reviews its investments to evaluate whether or not a decline in fair value below the carrying value is an other-than-temporary decline. The Company considers various factors, such as the investee's cash position, earnings and revenue outlook, liquidity and management's ability to raise capital in determining whether the decline is other-than-temporary. If the Company determines that an other-than-temporary decline exists in the value of its investments, it is the Company's policy to write-down these investments to fair value. See Note 9 for a discussion of impairment evaluations performed and charges taken. Under the full cost method of accounting for natural gas and oil properties, total capitalized costs are limited to a ceiling based on the present value of discounted (at 10%) future net revenues using current prices, plus the lower of cost or fair market value of unproved properties. If the ceiling (discounted revenues) is not equal to or greater than total capitalized costs, the Company is required to write-down capitalized costs to this level. The Company performs this ceiling test calculation every quarter. No write-downs were required in 2003, 2002 or 2001. Subsidiary Stock Transactions Gains and losses realized as a result of common stock sales by the Company's subsidiaries are recorded in the Consolidated Statements of Income, except for any transactions that must be credited directly to equity in accordance with the provisions of SAB No. 51, "Accounting for Sales of Stock by a Subsidiary." 2. New Accounting Standards SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" In May 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" (SFAS No. 150). The adoption of SFAS No. 150 did not have an impact on the Company's financial position or results of operations as of and for the periods ended December 31, 2003. EITF Issue No. 03-04, "Accounting for `Cash Balance' Pension Plans" In May 2003, the Emerging Issues Task Force (EITF) reached consensus in EITF Issue No. 03-04, "Accounting for `Cash Balance' Pension Plans" (EITF 03-04), to specifically address the accounting for certain cash balance pension plans. The consensus reached in EITF 03-04 requires certain cash balance pension plans to be accounted for as defined benefit plans. For cash balance plans described in EITF 03-04, the consensus also requires the use of the traditional unit credit method for purposes of measuring the benefit obligation and annual cost of benefits earned as opposed to the projected unit credit method. The Company has historically accounted for its cash balance plan as a defined benefit plan; however, the Company was required to adopt the measurement provisions of EITF 03-04 at its cash balance plan's measurement date of December 31, 2003. Any differences in the measurement of the obligations as a result of applying EITF 03-04 were reported as a component of actuarial gain or loss. The ongoing effects of this standard are dependent on other factors that also affect the determination of actuarial gains and losses and the subsequent amortization of such gains and losses. However, the adoption of EITF 03-04 is not expected to have a material effect on the Company's results of operations or financial position. SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." The statement amends and clarifies SFAS No. 133 on accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. The new guidance incorporates decisions made as part of the Derivatives Implementation Group (DIG) process, as well as decisions regarding implementation issues raised in relation to the application of the definition of a derivative. SFAS No. 149 is generally effective for contracts entered into or modified after June 30, 2003. Interpretations and implementation issues with regard to SFAS No. 149 continue to evolve. The statement had no significant impact on the Company's accounting for contracts entered into subsequent to the statement's effective date (See Note 17). Future effects, if any, on the Company's results of operations and financial condition will be dependent on the specifics of future contracts entered into with regard to guidance provided by the statement. FIN No. 46, "Consolidation of Variable Interest Entities" In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities - an Interpretation of ARB No. 51" (FIN No. 46). This interpretation provides guidance related to identifying variable interest entities and determining whether such entities should be consolidated. FIN No. 46 requires an enterprise to consolidate a variable interest entity when the enterprise (a) absorbs a majority of the variable interest entity's expected losses, (b) receives a majority of the entity's expected residual returns, or both, as a result of ownership, contractual or other financial interests in the entity. Prior to the effective date of 84 FIN No. 46, entities were generally consolidated by an enterprise that had control through ownership of a majority voting interest in the entity. FIN No. 46 originally applied immediately to variable interest entities created or obtained after January 31, 2003. During 2003, the Company did not participate in the creation of, or obtain a new variable interest in, any variable interest entity. In December 2003, the FASB issued a revision to FIN No. 46 (FIN No. 46R), which modified certain requirements of FIN No. 46 and allowed for the optional deferral of the effective date of FIN No. 46R until March 31, 2004. However, entities subject to FIN No. 46R that are deemed to be special-purpose entities (as defined in FIN No. 46R) must implement either FIN No. 46 or FIN No. 46R at December 31, 2003. The Company elected to apply FIN No. 46 to special-purpose entities as of December 31, 2003. Because the Company expects additional transitional guidance to be issued, it has elected to apply FIN No. 46R to non-special-purpose entities as of March 31, 2004. Prior to the adoption of FIN No. 46, the Company consolidated the FPC Capital I trust (the Trust), which holds FPC-obligated mandatorily redeemable preferred securities. The Trust is a special-purpose entity as defined in FIN No. 46R, and therefore the Company applied FIN No. 46 to the Trust at December 31, 2003. The Trust is a variable interest entity, but the Company does not absorb a majority of the Trust's expected losses and therefore is not its primary beneficiary. Therefore, the Company deconsolidated the Trust at December 31, 2003. This deconsolidation resulted in recording an additional equity investment in the Trust of approximately $9 million, an increase in outstanding debt of approximately $8 million and a gain of approximately $1 million relating to the cumulative effect of a change in accounting principle. See Note 12F for a discussion of the Company's guarantees with the Trust. The Company also has investments in 14 limited partnerships accounted for under the equity method for which it may be the primary beneficiary. These partnerships invest in and operate low-income housing and historical renovation properties that qualify for federal and state tax credits. The Company has not concluded whether it is the primary beneficiary of these partnerships. These partnerships are partially funded with financing from third-party lenders, which is secured by the assets of the partnerships. The creditors of the partnerships do not have recourse to the Company. At December 31, 2003, the maximum exposure to loss as a result of the Company's investments in these limited partnerships was approximately $9 million. The Company expects to complete its evaluation of these partnerships under FIN No. 46R during the first quarter of 2004. If the Company had consolidated these 14 entities at December 31, 2003, it would have recorded an increase to both total assets and total liabilities of approximately $40 million. The Company also has interests in several other variable interest entities created before January 31, 2003, for which the Company is not the primary beneficiary. These arrangements include equity investments in approximately 20 limited partnerships, limited liability corporations and venture capital funds and two building leases with special-purpose entities. The aggregate maximum loss exposure at December 31, 2003 under these arrangements totals approximately $34 million. The creditors of these variable interest entities do not have recourse to the general credit of the Company in excess of the aggregate maximum loss exposure. In February 2004, the Company became aware that certain long-term purchase power and tolling contracts may be considered variable interests under FIN No. 46R. The Company has various long-term purchase power and tolling contracts with other utilities and certain qualifying facility plants. The Company believes the counterparties to these contracts are not special-purpose entities and, therefore, FIN No. 46R would not apply to these contracts until March 31, 2004. The Company has not yet completed its evaluation of these contracts to determine if the Company needs to consolidate these counterparties under FIN No. 46R and will continue to monitor developing practice in this area. 3. Divestitures A. NCNG Divestiture On September 30, 2003, the Company completed the sale of North Carolina Natural Gas Corporation (NCNG) and the Company's equity investment in Eastern North Carolina Natural Gas Company (ENCNG) to Piedmont Natural Gas Company, Inc. Net proceeds from the sale of NCNG of $443 million were used to reduce debt. Based on the net proceeds, the Company recorded an after-tax loss of $12 million during 2003. The accompanying consolidated financial statements have been restated for all periods presented for the discontinued operations of NCNG. The net income of these operations is reported as discontinued operations in the Consolidated Statements of Income. Interest expense of $10 million, $16 million and $15 million for the years ended December 31, 2003, 2002 and 2001, respectively, has been allocated to discontinued operations based on the net assets of NCNG, assuming a uniform debt-to-equity ratio across the Company's operations. The Company ceased recording depreciation effective 85 October 1, 2002, upon classification of the assets as discontinued operations. After-tax depreciation expense recorded by NCNG for each of the years ended December 31, 2002 and 2001 was $9 million and $10 million, respectively. Results of discontinued operations for years ended December 31 were as follows: (in millions) 2003 2002 2001 ----------------------------------- Revenues $ 284 $ 300 $ 321 =================================== Earnings before income taxes $ 6 $ 9 $ 4 Income tax expense 2 4 3 ----------------------------------- Net earnings from discontinued operations 4 5 1 Loss on disposal of discontinued operations, including applicable income tax expense of $1 and $3, respectively ( 12) (29) - ----------------------------------- Earnings (loss) from discontinued operations $ (8) $ (24) $ 1 ===================================
The major balance sheet classes included in assets and liabilities of discontinued operations in the Consolidated Balance Sheets at December 31, 2002 are as follows: (in millions) Utility plant, net $ 399 Current assets 73 Deferred debits and other assets 18 ---------- Assets of discontinued operations $ 490 ========== Current liabilities $ 76 Deferred credits and other liabilities 49 ---------- Liabilities of discontinued operations $ 125 ========== The sale of ENCNG resulted in net proceeds of $7 million and a pre-tax loss of $2 million, which is included in other, net on the accompanying Consolidated Statements of Income for the year ended December 31, 2003. The Company's equity investment in ENCNG of $8 million at December 31, 2002 is included in miscellaneous other property and investments in the accompanying Consolidated Balance Sheets. B. Railcar Ltd. Divestiture In December 2002, the Progress Energy Board of Directors adopted a resolution approving the sale of Railcar Ltd., a subsidiary included in the Rail Services segment. In accordance with SFAS No. 144, an estimated pre-tax impairment of $59 million on assets held for sale was recognized in December 2002 to write-down the assets to fair value less costs to sell. This impairment has been included in impairment of long-lived assets in the Consolidated Statements of Income (See Note 9A). The assets of Railcar Ltd. have been grouped as assets held for sale and are included in other current assets on the Consolidated Balance Sheets at December 31, 2003 and 2002. The assets were recorded at approximately $75 million and $24 million at December 31, 2003 and 2002, respectively, which reflects the Company's estimates of the fair value expected to be realized from the sale of these assets less costs to sell. The primary component of assets held for sale at December 31, 2003 was property and equipment of $74 million. The primary component of assets held for sale at December 31, 2002 was current assets of $22 million. The net increase in assets held for sale from December 31, 2002 to December 31, 2003 was primarily attributable to the purchase of railcars in 2003 that were subject to off-balance sheet obligations at December 31, 2002. In addition to the assets held for sale, the Company is subject to certain commitments under operating leases (See Note 21C). In March 2003, the Company signed a letter of intent to sell the majority of Railcar Ltd. assets to The Andersons, Inc. In November 2003, the asset purchase agreement was signed, and the transaction closed in February 2004. Proceeds from the sale were approximately $82 million. The Company was relieved of the majority of the operating lease commitments when the assets were sold. 86 C. Mesa Hydrocarbons, Inc. Divestiture In October 2003, the Company sold certain gas-producing properties owned by Mesa Hydrocarbons, LLC, a wholly-owned subsidiary of Progress Fuels Corporation (Progress Fuels), which is included in the Fuels segment. Net proceeds were approximately $97 million. Because the Company utilizes the full cost method of accounting for its oil and gas operations, the pre-tax gain of approximately $18 million was applied to reduce the basis of the Company's other U.S. oil and gas investments and will prospectively result in a reduction of the amortization rate applied to those investments as production occurs. D. Inland Marine Transportation Divestiture During 2001, the Company completed the sale of its Inland Marine Transportation business operated by MEMCO Barge Line, Inc., 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. In connection with the sale, the Company entered into environmental indemnification provisions covering both known and unknown sites (See Note 21E). The Company adjusted the FPC purchase price allocation to reflect a $15 million net realizable value of the Inland Marine Transportation business. E. Required Divestiture The U.S. Securities and Exchange Commission (SEC) original order approving the FPC merger required the Company to divest of Rail Services and certain immaterial, nonregulated investments of FPC by November 30, 2003. Although the Company has been actively marketing these investments, an acceptable divestiture opportunity was not found by that date. Therefore, the Company sought and in October 2003 was granted approval of a three-year extension from the SEC until 2006. 4. Acquisitions and Business Combinations A. Progress Telecommunications Corporation In December 2003, Progress Telecommunications Corporation (PTC) and Caronet, Inc. (Caronet), both wholly-owned subsidiaries of Progress Energy, and EPIK Communications, Inc. (EPIK), a wholly-owned subsidiary of Odyssey Telecorp, Inc. (Odyssey), contributed substantially all of their assets and transferred certain liabilities to Progress Telecom, LLC (PTC LLC), a subsidiary of PTC. Subsequently, the stock of Caronet was sold to an affiliate of Odyssey for $2 million in cash and Caronet became a wholly-owned subsidiary of Odyssey. Following consummation of all the transactions described above, PTC holds a 55% ownership interest in, and is the parent of PTC LLC. Odyssey holds a combined 45% ownership interest in PTC LLC through EPIK and Caronet. The accounts of PTC LLC are included in the Company's Consolidated Financial Statements since the transaction date. The minority interest is included in other liabilities and deferred credits in the Consolidated Balance Sheets. The transaction was accounted for as a partial acquisition of EPIK through the issuance of the stock of a consolidated subsidiary. The contributions of PTC's and Caronet's net assets were recorded at their carrying values of approximately $31 million. EPIK's contribution was recorded at its estimated fair value of $22 million using the purchase method, and was initially allocated as follows: property and equipment - $27 million; other current assets - $9 million; current liabilities - $21 million; and goodwill - $7 million. The goodwill was assigned to the Company's Other business segment and will not be deductible for tax purposes. The purchase price allocation is a preliminary estimate, based on available information, internal estimates and certain assumptions management believes are reasonable. Accordingly, the purchase price allocation is subject to finalization in 2004 pending the completion of internal and external appraisals of assets acquired. No gain or loss was recognized on the transaction. The pro forma results of operations reflecting the acquisition would not be materially different than the reported results of operations for the years ended December 31, 2002 or 2001. 87 B. Acquisition of Natural Gas Reserves During 2003, Progress Fuels entered into several independent transactions to acquire approximately 200 natural gas-producing wells with proven reserves of approximately 190 billion cubic feet (Bcf) from Republic Energy, Inc. and three other privately-owned companies, all headquartered in Texas. The total cash purchase price for the transactions was $168 million. C. Wholesale Energy Contract Acquisition In May 2003, PVI entered into a definitive agreement with Williams Energy Marketing and Trading, a subsidiary of The Williams Companies, Inc., to acquire a long-term full-requirements power supply agreement at fixed prices with Jackson Electric Membership Corporation (Jackson), located in Jefferson, Georgia. The agreement calls for a $188 million cash payment to Williams Energy Marketing and Trading in exchange for assignment of the Jackson supply agreement. The $188 million cash payment was recorded as an intangible asset and is being amortized based on the economic benefit of the contract (See Note 8). The power supply agreement terminates in 2015, with a first refusal right to extend for five years. The agreement includes the use of 640 megawatts (MW) of contracted Georgia System generation comprised of nuclear, coal, gas and pumped-storage hydro resources. PVI expects to supplement the acquired resources with its own intermediate and peaking assets in Georgia to serve Jackson's forecasted 1,100 MW peak demand in 2005 growing to a forecasted 1,700 MW demand by 2015. D. Generation Acquisition In February 2002, PVI acquired 100% of two electric generating projects located in Georgia from LG&E Energy Corp., a subsidiary of Powergen plc. The two projects consist of 1) Walton County Power, LLC in Monroe, Georgia, a 460 MW natural gas-fired plant placed in service in June 2001 and 2) Washington County Power, LLC in Washington County, Georgia, a 600 MW natural gas-fired plant placed in service in June 2003. The Walton and Washington projects have been accounted for using the purchase method of accounting and, accordingly, have been included in the consolidated financial statements since the acquisition date. In the final allocation, the aggregate cash purchase price of approximately $348 million was allocated to diversified business property, intangibles and goodwill for $250 million, $33 million and $64 million, respectively (See Note 8). Of the acquired intangible assets, $33 million was assigned to tolling and power sale agreements with LG&E Energy Marketing, Inc. for each project and is being amortized through December 31, 2004. Goodwill was assigned to the CCO segment and will be deductible for tax purposes. The pro forma results of operations reflecting the acquisition would not be materially different than the reported results of operations for the years ended December 31, 2002 or 2001. E. Westchester Acquisition In April 2002, Progress Fuels, a subsidiary of Progress Energy, acquired 100% of Westchester Gas Company (Westchester). The acquisition included approximately 215 natural gas-producing wells, 52 miles of intrastate gas pipeline and 170 miles of gas-gathering systems located within a 25-mile radius of Jonesville, Texas, on the Texas-Louisiana border. The aggregate purchase price of approximately $153 million consisted of cash consideration of approximately $22 million and the issuance of 2.5 million shares of Progress Energy common stock then valued at approximately $129 million. The purchase price included approximately $2 million of direct transaction costs. The final purchase price was allocated to oil and gas properties, intangible assets, diversified business property, net working capital and deferred tax liabilities for approximately $152 million, $9 million, $32 million, $5 million and $45 million, respectively. The $9 million intangible assets recorded relates to customer contracts acquired as part of the acquisition and are being amortized over their respective lives (See Note 8). The acquisition has been accounted for using the purchase method of accounting and, accordingly, the results of operations for Westchester have been included in Progress Energy's consolidated financial statements since the date of acquisition. The pro forma results of operations reflecting the acquisition would not be materially different than the reported results of operations for the years ended December 31, 2002 or 2001. 88 5. Property, Plant and Equipment A. Utility Plant The balances of electric utility plant in service at December 31 are listed below, with a range of depreciable lives for each: (in millions) 2003 2002 ------------- ----------- Production plant (7-33 years) $ 12,039 $ 11,063 Transmission plant (30-75 years) 2,167 2,104 Distribution plant (12-50 years) 6,432 6,073 General plant and other (8-75 years) 1,037 917 ------------- ----------- Utility plant in service $ 21,675 $ 20,157 ============= =========== Generally, electric utility plant at PEC and PEF, other than nuclear fuel, is pledged as collateral for the first mortgage bonds of PEC and PEF, respectively. Allowance for funds used during construction (AFUDC) represents the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated assets. As prescribed in the regulatory uniform systems of accounts, AFUDC is charged to the cost of the plant. The equity funds portion of AFUDC is credited to other income and the borrowed funds portion is credited to interest charges. 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 composite AFUDC rate for PEC's electric utility plant was 4.0% in 2003 and 6.2% in 2002 and 2001. The composite AFUDC rate for PEF's electric utility plant was 7.8% in 2003, 2002 and 2001. Depreciation provisions on utility plant, as a percent of average depreciable property other than nuclear fuel, were 2.5%, 2.6% and 2.8% in 2003, 2002 and 2001, respectively. The depreciation provisions related to utility plant were $517 million, $488 million and $530 million in 2003, 2002 and 2001, respectively. In addition to utility plant depreciation provisions, depreciation and amortization expense also includes decommissioning cost provisions, asset retirement obligation (ARO) accretion, cost of removal provisions (See Note 5D) and regulatory approved expenses (See Note 7). PEC filed a new depreciation study in 2004 that provides support for reducing depreciation expense on an annual basis by approximately $45 million. The reduction is primarily attributable to assumption changes for nuclear generation, offset by increases for distribution assets. The new rates are primarily effective January 1, 2004. Amortization of nuclear fuel costs, for the years ended December 31, 2003, 2002 and 2001 were $143 million, $141 million and $130 million, respectively. B. Diversified Business Property The balances of diversified business property at December 31 are listed below, with a range of depreciable lives for each: 89 (in millions) 2003 2002 --------------- ---------------- Equipment (3 - 25 years) $ 246 $ 299 Nonregulated generation plant and equipment (3 - 40 years) 1,299 549 Land and mineral rights 93 90 Buildings and plants (5 - 40 years) 153 153 Oil and gas properties (units-of-production) 412 265 Telecommunications equipment (5 - 20 years) 63 43 Rail equipment (3 - 20 years) 125 48 Marine equipment (3 - 35 years) 83 80 Computers, office equipment and software (3 - 10 years) 36 33 Construction work in progress 49 644 Accumulated depreciation (401) (320) --------------- ---------------- Diversified business property, net $ 2,158 $ 1,884 =============== ================
The Company's nonregulated businesses capitalize interest costs under SFAS No. 34, "Capitalizing Interest Costs." During the years ended December 31, 2003 and 2002, respectively, the Company capitalized $20 million and $38 million of its interest expense of $652 million and $679 million related to the expansion of its nonregulated generation portfolio at PVI. Capitalized interest is included in diversified business property, net on the Consolidated Balance Sheets. Diversified business depreciation expense was $120 million, $85 million and $61 million for December 31, 2003, 2002 and 2001, respectively. C. Joint Ownership of Generating Facilities PEC and PEF hold ownership interests in certain jointly owned generating facilities. Each is entitled to shares of the generating capability and output of each unit equal to their respective ownership interests. Each also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. PEC's and PEF's share of expenses for the jointly owned facilities is included in the appropriate expense category. The co-owner of Intercession City Unit P11 (P11) has exclusive rights to the output of the unit during the months of June through September. PEF has that right for the remainder of the year. PEC's and PEF's ownership interests in the jointly owned generating facilities are listed below with related information at December 31, ($ in millions): - ----------------------------------------------------------------------------------------------------------------- 2003 - ----------------------------------------------------------------------------------------------------------------- Company Construction Ownership Plant Accumulated Work in Subsidiary Facility Interest Investment Depreciation Progress - ----------------------------------------------------------------------------------------------------------------- PEC Mayo Plant 83.83% $ 464 $ 242 $ 50 PEC Harris Plant 83.83% 3,248 1,370 7 PEC Brunswick Plant 81.67% 1,611 884 21 PEC Roxboro Unit 4 87.06% 323 139 1 PEF Crystal River Unit 3 91.78% 1,069 432 49 PEF Intercession City Unit P11 66.67% 22 6 6 - ----------------------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------------------- 2002 - ----------------------------------------------------------------------------------------------------------------- Company Construction Ownership Plant Accumulated Work in Subsidiary Facility Interest Investment Depreciation Progress - ----------------------------------------------------------------------------------------------------------------- PEC Mayo Plant 83.83% $ 464 $ 232 $ 14 PEC Harris Plant 83.83% 3,160 1,331 6 PEC Brunswick Plant 81.67% 1,477 811 26 PEC Roxboro Unit 4 87.06% 316 134 8 PEF Crystal River Unit 3 91.78% 777 375 28 PEF Intercession City Unit P11 66.67% 22 5 4
In the tables above, plant investment and accumulated depreciation are not reduced by the regulatory disallowances related to the Shearon Harris Nuclear Plant (Harris Plant). 90 D. Decommissioning, Dismantlement and Cost of Removal Provisions Decommissioning cost provisions, which are included in depreciation and amortization expense, were $31 million, $31 million and $39 million in 2003, 2002 and 2001, respectively. The PEF rate case settlement required PEF to suspend accruals on its reserves for nuclear decommissioning and fossil dismantlement through December 31, 2005 (See Note 7D). Management believes that decommissioning costs that have been and will be recovered through rates by PEC and PEF will be sufficient to provide for the costs of decommissioning. PEF's provision for fossil plant dismantlement was previously suspended per a 1997 FPSC settlement agreement, but resumed mid-2001. The 2001 annual provision, approved by the FPSC, was $9 million. The accrual for fossil dismantlement reserves was suspended again in 2002 by the Florida rate case settlement (See Note 7D). Cost of removal provisions, which are included in depreciation and amortization expense, were $158 million, $149 million and $143 million in 2003, 2002 and 2001, respectively. These amounts represent the expense recognized for the disposal or removal of utility assets. The FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143), that changed the accounting for the decommissioning, dismantlement and cost of removal provisions (See Note 5F). E. Insurance PEC and PEF 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 Crystal River Unit No. 3 (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 PEC and PEF are insured thereunder, following a twelve-week deductible period, for 52 weeks in the amount of $3 million per week at the Brunswick and Harris Plants, $2.5 million per week at the Robinson Plant and $4.5 million per week at the CR3 Plant. An additional 110 weeks of coverage is provided at 80% of the above weekly amounts. For the current policy period, the companies are subject to retrospective premium assessments of up to approximately $27 million with respect to the primary coverage, $31 million with respect to the decontamination, decommissioning and excess property coverage, and $19 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 United States Nuclear Regulatory Commission (NRC), 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 decontaminate, 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 PEC and PEF are insured against public liability for a nuclear incident up to $10.9 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 $300 million (currently available through commercial insurers), each company would be subject to pro rata assessments of up to $101 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. Congress is expected to approve revisions to the Price Anderson Act during 2004 that could include increased limits and assessments per reactor owned. The final outcome of this matter cannot be predicted at this time. Under the NEIL policies, if there were multiple terrorism losses occurring within one year, 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 $300 million. The second 91 level of coverage obtained through the assessments discussed above would continue to apply to losses exceeding $300 million and would provide coverage in excess of any diminished primary limits due to the terrorist acts aggregate. PEC and PEF self-insure their transmission and distribution lines against loss due to storm damage and other natural disasters. PEF accrues $6 million annually to a storm damage reserve pursuant to a regulatory order and may defer losses in excess of the reserve (See Note 7A). F. Asset Retirement Obligations SFAS No. 143 provides accounting and disclosure requirements for retirement obligations associated with long-lived assets and was adopted by the Company 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 liability is then accreted over time by applying an interest method of allocation to the liability. Cumulative accretion and accumulated depreciation were recognized for the time period from the date the liability would have been recognized had the provisions of this statement been in effect, to the date of adoption of this statement. For assets acquired through acquisition, the cumulative effect was based on the acquisition date. Upon adoption of SFAS No. 143, the Company recorded AROs totaling $1,183 million for nuclear decommissioning of irradiated plants at PEC and PEF. The Company used an expected cash flow approach to measure these obligations. This amount includes accruals recorded prior to adoption totaling $775 million, which were previously recorded in cost of removal. The related asset retirement costs, net of accumulated depreciation, recorded upon adoption totaled $368 million for regulated operations. The adoption of this statement had no impact on the income of the regulated entities, as the effects were offset by the establishment of a regulatory asset and a regulatory liability pursuant to SFAS No. 71. A regulatory asset was recorded related to PEC in the amount of $271 million, representing the cumulative accretion and accumulated depreciation for the time period from the date the liability would have been recognized had the provisions of this statement been in effect to the date of adoption, less amounts previously recorded. A regulatory liability was recorded related to PEF in the amount of $231 million, representing the amount by which previously recorded accruals exceeded the cumulative accretion and accumulated depreciation for the time period from the date the liability would have been recognized had the provisions of this statement been in effect at the date of the acquisition of the assets by Progress Energy to the date of adoption. At December 31, 2003, the asset retirement costs related to nuclear decommissioning of irradiated plant, net of accumulated depreciation, totaled $354 million for regulated operations. The ongoing expense differences between SFAS No. 143 and regulatory cost recovery are being deferred to the regulatory asset and regulatory liability. Funds set aside in the Company's nuclear decommissioning trust funds for the nuclear decommissioning liability totaled $938 million at December 31, 2003 and $797 million at December 31, 2002. Net unrealized gains on the nuclear decommissioning trust funds were included in regulatory liabilities in 2003 and cost of removal in 2002. Upon adoption of SFAS No. 143, the Company also recorded AROs totaling $10 million for synthetic fuel operations of PVI and coal mine operations, synthetic fuel operations and gas production of Progress Fuels. The Company used an expected cash flow approach to measure these obligations. This amount includes accruals recorded prior to adoption totaling $5 million, which was previously recorded in other liabilities and deferred credits. The related asset retirement costs, net of accumulated depreciation, recorded upon adoption totaled $7 million for nonregulated operations. The cumulative effect of initial adoption of this statement related to nonregulated operations was $1 million of income, which is included in cumulative effect of change in accounting principles, net of tax on the Consolidated Statements of Income for the year ended December 31, 2003. The AROs for synthetic fuel operations of PVI and coal mine operations, synthetic fuel operations and gas production of Progress Fuels totaled $20 million at December 31, 2003. The related asset retirement costs, net of accumulated depreciation, totaled $7 million for nonregulated operations at December 31, 2003. The following table shows the changes to the asset retirement obligations during the year ended December 31, 2003. Additions relate primarily to additional reclamation obligations at coal mine operations of Progress Fuels. 92 (in millions) Regulated Nonregulated -------------- ------------ Asset retirement obligations as of January 1, 2003 $ 1,183 $ 10 Additions - 11 Accretion expense 68 1 Deductions - (2) -------------- ------------ Asset retirement obligations as of December 31, 2003 $ 1,251 $ 20 ============== ============
Pro forma net income has not been presented for prior years because the pro forma application of SFAS No. 143 to prior years would result in pro forma net income not materially different from the actual amounts reported. The Company has identified but not recognized AROs related to electric transmission and distribution and telecommunications assets as the result of easements over property not owned by the Company. These easements are generally perpetual and only require retirement action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements as the Company intends to utilize these properties indefinitely. In the event the Company decides to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time. The utilities previously recognized removal, decommissioning and dismantlement costs as a component of accumulated depreciation in accordance with regulatory treatment. At December 31, 2003, such costs totaling $2,169 million were included in regulatory liabilities on the Consolidated Balance Sheets and consist of removal costs of $1,897 million, removal costs for non-irradiated areas at nuclear facilities of $129 million and amounts previously collected for dismantlement of fossil generation plants of $143 million. At December 31, 2002, such costs totaling $2,940 million were included in cost of removal on the Consolidated Balance Sheets and consist of removal costs of $1,790 million, decommissioning costs for both the irradiated and non-irradiated areas at nuclear facilities of $1,008 million and amounts previously collected for dismantlement of fossil generation plants of $142 million. With the adoption of SFAS No. 143 in 2003, removal costs related to the irradiated areas at nuclear facilities are reported as asset retirement obligations on the 2003 Consolidated Balance Sheet. PEC filed a request with the NCUC requesting deferral of the difference between expense pursuant to SFAS No. 143 and expense as previously determined by the NCUC. The NCUC initially granted the deferral of the January 1, 2003 cumulative adjustment. During the third quarter of 2003, the NCUC issued an order allowing the deferral of the ongoing effects of SFAS No. 143. In April 2003, the SCPSC approved a joint request by PEC, Duke Energy Corporation and South Carolina Electric and Gas Company for an accounting order to authorize the deferral of all cumulative and prospective effects related to the adoption of SFAS No. 143. Therefore, SFAS No. 143 had no impact on the income of PEC for the year ended December 31, 2003. In January 2003, the Staff of the FPSC issued a notice of proposed rule development to adopt provisions relating to accounting for asset retirement obligations under SFAS No. 143. Accompanying the notice was a draft rule presented by the Staff which adopts the provisions of SFAS No. 143 along with the requirement to record the difference between amounts prescribed by the FPSC and those used in the application of SFAS No. 143 as regulatory assets or regulatory liabilities, which was accepted by all parties. A final order was issued in the third quarter of 2003. Therefore, the adoption of the statement had no impact on the income of PEF due to the establishment of a regulatory liability pursuant to SFAS No. 71. 6. Inventory At December 31, inventory was comprised of: (in millions) 2003 2002 -------------- ------------- Fuel $ 250 $ 313 Rail equipment and parts 132 155 Materials and supplies 386 363 Other 40 44 -------------- ------------- Total inventory $ 808 $ 875 ============== ============= 93 7. Regulatory Matters A. Regulatory Assets and Liabilities As regulated entities, the utilities are subject to the provisions of SFAS No. 71. Accordingly, the utilities record certain assets and liabilities resulting from the effects of the ratemaking process which would not be recorded under GAAP for nonregulated 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 was provided. Additionally, these factors could result in an impairment of utility plant assets as determined pursuant to SFAS No. 144. At December 31, the balances of regulatory assets (liabilities) were as follows: (in millions) 2003 2002 ----------------- --------------- Deferred fuel cost $ 317 $ 184 ----------------- --------------- Deferred impact of ARO (Note 5F) 291 - Income taxes recoverable through future rates (Note 14) 136 155 Deferred purchased power contract termination costs (Note 7B) - 47 Loss on reacquired debt (Note 1C) 55 33 Deferred DOE enrichment facilities-related costs (Note 1C) 24 31 Storm deferral (Note 7B) 21 - Other postretirement benefits (Note 16B) 9 11 Other 76 70 ----------------- --------------- Total long-term regulatory assets 612 347 ----------------- --------------- Non-ARO cost of removal (Note 5F) (2,169) - Deferred impact of ARO (Note 5F) (212) - Net nuclear decommissioning trust unrealized gains (Note 5F) (204) - Defined benefit retirement plan (Note 16B) (211) (51) Storm reserve (Note 5E) (41) (36) Clean air compliance (Note 7B) (74) - Other (27) (33) ----------------- --------------- Total long-term regulatory liabilities (2,938) (120) ----------------- --------------- Net regulatory assets(liabilities) $ (2,009) $ 411 ================= ===============
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. The Company expects to fully recover these assets and refund the liabilities through customer rates under current regulatory practice. B. Retail Rate Matters The NCUC and SCPSC have approved proposals to accelerate cost recovery of PEC's nuclear generating assets beginning January 1, 2000, and continuing through 2009. The aggregate minimum and maximum amounts of cost recovery are $530 million and $750 million, respectively. Accelerated cost recovery of these assets resulted in no additional expense in 2003 and additional depreciation expense of approximately $53 million and $75 million in 2002 and 2001, respectively. Total accelerated depreciation recorded through December 31, 2003 was $403 million. In compliance with a regulatory order, PEF accrues a reserve for maintenance and refueling expenses anticipated to be incurred during scheduled nuclear plant outages. In conjunction with the acquisition of NCNG in 1999, PEC 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. 94 The NC Clean Air Act of June 2002 (the Clean Air Act), requires state utilities to reduce emissions of nitrogen oxide (NOx) and sulfur dioxide (SO2) from coal-fired plants. The NCUC has allowed the utilities to amortize and recover the costs associated with meeting the new emission standards over a seven-year period beginning January 1, 2003. PEC recognized $74 million of clean air amortization during 2003. This legislation freezes PEC's base rates in North Carolina for five years, subject to certain conditions (See Note 21E). In conjunction with the FPC merger, PEC reached a settlement with the Public Staff of the NCUC in which it agreed to provide credits to its non-real time pricing customers in the amounts of $3 million in 2002, $5 million in 2003 and $6 million in both 2004 and 2005. At December 31, 2000, PEF, with the approval of the FPSC, had established a regulatory liability to defer $63 million of revenues. In 2001, PEF applied the deferred revenues, plus accrued interest, to reduce its regulatory asset related to deferred purchased power termination costs. In addition, PEF recorded accelerated amortization of $34 million to further offset this regulatory asset during 2001. During 2003, PEF fully amortized this regulatory asset. In February 2003, PEF petitioned the FPSC to increase its fuel factors due to continuing increases in oil and natural gas commodity prices. In March 2003, the FPSC approved PEF's petition. New rates also became effective in March 2003. In September 2003, PEF asked the FPSC to approve a cost adjustment in its annual fuel filing, primarily related to rising costs of fuel that will increase retail customer bills beginning January 1, 2004. The total amount of the fuel adjustment requested above current levels was approximately $322 million. In November 2003, the FPSC approved PEF's request and new rates became effective January 2004. PEC obtained SCPSC and NCUC approval of fuel factors in annual fuel-adjustment proceedings. The SCPSC approved PEC's petition to leave billing rates unchanged from the prior year by order issued in March 2003. The NCUC approved an increase of $20 million by order issued in September 2003. In October 2003, PEC made a filing with the NCUC to seek permission to defer expenses incurred from Hurricane Isabel and the February 2003 winter storms. As a result of rising storm costs and the frequency of major storm damage, PEC asked the NCUC to allow PEC to create a deferred account in which PEC would place expenses incurred as a result of named tropical storms, hurricanes and significant winter storms. In December 2003, the NCUC approved PEC's request to defer the costs and amortize them over a period of five years beginning in the month the storm occurs. PEC charged approximately $24 million in 2003 from Hurricane Isabel and from current year ice storms to the deferred account, of which $3 million was amortized during 2003. PEC retains funds internally to meet decommissioning liability. The NCUC order issued February 2004 found that by January 1, 2008 PEC must begin transitioning these amounts to external funds. The transition of $131 million must be completed by December 31, 2017, and at least 10% must be transitioned each year. PEC has exclusively utilized external funding for its decommissioning liability since 1994. C. Regional Transmission Organizations and Standard Market Design In 2000, the FERC issued Order 2000 regarding regional transmission organizations (RTOs). This Order set minimum characteristics and functions that RTOs must meet, including independent transmission service (ISOs). In July 2002, the FERC issued its Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). If adopted as proposed, the rules set forth in the SMD NOPR would materially alter the manner in which transmission and generation services are provided and paid for. PEC and PEF, as subsidiaries of Progress Energy, filed comments in November 2002 and supplemental comments in January 2003. In April 2003, the FERC released a White Paper on the Wholesale Market Platform. The White Paper provides an overview of what the FERC currently intends to include in a final rule in the SMD NOPR docket. The White Paper retains the fundamental and most protested aspects of SMD NOPR, including mandatory RTOs and the FERC's assertion of jurisdiction over certain aspects of retail service. The FERC has not yet issued a final rule on SMD NOPR. The Company cannot predict the outcome of these matters or the effect that they may have on the GridFlorida and GridSouth proceedings currently ongoing before the FERC. It is unknown what impact the future proceedings will have on the Company's earnings, revenues or prices. 95 The Company has $33 million and $4 million invested in GridSouth and GridFlorida, respectively, at December 31, 2003. Given the regulatory uncertainty of the ultimate timing, structure and operations of GridSouth, GridFlorida or an alternate combined transmission structure, the Company cannot predict the effect on future consolidated results of operations, cash flows or financial condition. Furthermore, the SMD NOPR presents several uncertainties, including what percentage of the investments in GridSouth and GridFlorida will be recovered, how the elimination of transmission charges, as proposed in the SMD NOPR, will impact the Company, and what amount of capital expenditures will be necessary to create a new wholesale market. D. PEF Rate Case Settlement The FPSC initiated a rate proceeding in 2001 regarding PEF's future base rates. In March 2002, the parties in PEF's rate case entered into a Stipulation and Settlement Agreement (the Agreement) related to retail rate matters. The Agreement was approved by the FPSC in April 2002. The Agreement is generally effective from May 2002 through December 2005; provided, however, that if PEF's base rate earnings fall below a 10% return on equity, PEF may petition the FPSC to amend its base rates. The Agreement provides that PEF will reduce its retail revenues from the sale of electricity by an annual amount of $125 million. The Agreement also provides that PEF will operate under a Revenue Sharing Incentive Plan (the Plan) through 2005, and thereafter until terminated by the FPSC, that establishes annual revenue caps and sharing thresholds. 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 PEF's shareholders, and a 2/3 share to be refunded to PEF's retail customers; provided, however, that for the year 2002 only, the refund to customers was limited to 67.1% of the 2/3 customer share. The retail base rate revenue sharing threshold amounts for 2003 and 2002 were $1,333 million and $1,296 million, respectively, and will increase $37 million each year thereafter. The Plan also provides that all retail base rate revenues above the retail base rate revenue caps established for each year will be refunded to retail customers on an annual basis. For 2002, the refund to customers was limited to 67.1% of the retail base rate revenues that exceeded the 2002 cap. The retail base revenue cap for 2003 and 2002 was $1,393 million and $1,356 million, respectively, and will increase $37 million each year thereafter. Any amounts above the retail base revenue caps will be refunded 100% to customers. At December 31, 2003, $17 million has been accrued and will be refunded to customers by March 2004. Approximately $5 million was originally returned in March 2003 related to 2002 revenue sharing. However, in February 2003, the parties to the Agreement filed a motion seeking an order from the FPSC to enforce the Agreement. In this motion, the parties disputed PEF's calculation of retail revenue subject to refund and contended that the refund should be approximately $23 million. In July 2003, the FPSC ruled that PEF must provide an additional $18 million to its retail customers related to the 2002 revenue sharing calculation. PEF recorded this refund in the second quarter of 2003 as a charge against electric operating revenue and refunded this amount by October 2003. The Agreement also provides that beginning with the in-service date of PEF's Hines Unit 2 and continuing through December 2005, PEF 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. Hines Unit 2 is a 516 MW combined-cycle unit that was placed in service in December 2003. PEF will suspend accruals on its reserves for nuclear decommissioning and fossil dismantlement through December 2005. Additionally, for each calendar year during the term of the Agreement, PEF will record a $63 million depreciation expense reduction, and may, at its option, record up to an equal annual amount as an offsetting accelerated depreciation expense. In addition, PEF is authorized, at its discretion, to accelerate the amortization of certain regulatory assets over the term of the Agreement. In 2003, PEF recorded $16 million of accelerated amortization of a regulatory liability related to a settled tax matter. There was no accelerated depreciation or amortization expense recorded for the year ended December 31, 2002. Under the terms of the Agreement, PEF 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, PEF 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. 96 The Agreement also provided that, PEF was required to refund to customers $35 million of revenues PEF collected during the interim period since March 2001. This one-time retroactive revenue refund was recorded in the first quarter of 2002 and was returned to retail customers during 2002. Any additional refunds under the Agreement are recorded when they become probable. 8. Goodwill and Other Intangible Assets Effective January 2002, the Company adopted SFAS No. 142. As required by SFAS No. 142, the results for the prior year periods have not been restated. A reconciliation of net income as if SFAS No. 142 had been adopted is presented below for the year ended December 31, 2001. The goodwill amortization used in the reconciliation includes $6 million related to NCNG, which is included in discontinued operations. Basic earnings per Diluted earnings per (in millions, except per share data) Net income common share common share ---------- ------------------ -------------------- Reported $ 542 $ 2.65 $2.64 Goodwill amortization 96 0.47 0.47 ---------- ------------------ -------------------- Adjusted $ 638 $ 3.12 $3.11 ========== ================== ====================
The changes in the carrying amount of goodwill for the years ended December 31, 2002 and 2003, by reportable segment, are as follows: (in millions) PEC Electric PEF CCO Other Total -------------------------------------------------- Balance as of January 1, 2002 $ 1,922 $ 1,733 $ - $ 35 $ 3,690 Acquisitions (Note 4D) - - 64 - 64 Divestitures - - - (2) (2) Discontinued operations (Note 3A) - - - (33) (33) -------------------------------------------------- Balance as of December 31, 2002 $ 1,922 $ 1,733 $ 64 $ - $ 3,719 Acquisitions (Note 4A) - - - 7 7 -------------------------------------------------- Balance as of December 31, 2003 $ 1,922 $ 1,733 $ 64 $ 7 $ 3,726 ==================================================
The Company performed the annual goodwill impairment test for the CCO segment in the first quarter of 2003, and the annual goodwill impairment test for the PEC Electric and PEF segments in the second quarter of 2003, which indicated no impairment. The first annual impairment test for the Other segment will be performed in 2004, since the goodwill was acquired in 2003. The gross carrying amount and accumulated amortization of the Company's intangible assets at December 31 are as follows: 2003 2002 ------------------------------- ------------------------------- (in millions) Gross Carrying Accumulated Gross Carrying Accumulated Amount Amortization Amount Amortization ------------------------------- ------------------------------- Synthetic fuel intangibles $ 140 $ (64) $ 140 $ (45) Power agreements acquired 221 (20) 33 (6) Other 62 (12) 41 (8) ------------------------------- ------------------------------- Total $ 423 $ (96) $ 214 $ (59) =============================== ===============================
All of the Company's intangibles are subject to amortization. Synthetic fuel intangibles represent intangibles for synthetic fuel technology. These intangibles are being amortized on a straight-line basis until the expiration of tax credits under Section 29 of the Internal Revenue Code (Section 29) in December 2007 (See Note 14). In May 2003, PVI acquired a long-term full-requirements power supply agreement at fixed prices for $188 million. The intangible related to this power agreement is being amortized based on the economic benefits of the contract (See Note 4C). As part of the acquisition of generating assets from LG&E Energy Corp. in February 2002, power agreements of $33 million were recorded and are amortized based on the economic benefits of the contracts through December 2004, which approximates straight-line (See Note 4D). Other intangibles are primarily acquired customer contracts and permits that are amortized over their respective lives. Of the increase in other intangible assets, $9 million relates to customer contracts acquired as part of the Westchester acquisition, which was identified as an intangible in the final purchase price allocation (See Note 4E). 97 Amortization expense recorded on intangible assets for the years ended December 31, 2003, 2002 and 2001 was, in millions, $37, $33 and $22, respectively. The estimated annual amortization expense for intangible assets for 2004 through 2008, in millions, is approximately $42, $35, $36, $36 and $17, respectively. 9. Impairments of Long-Lived Assets and Investments Effective January 1, 2002, the Company adopted SFAS No. 144, which 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." In 2003, 2002 and 2001, the Company recorded pre-tax long-lived asset and investment impairments and other charges of approximately $38 million, $414 million and $209 million, respectively. A. Long-Lived Assets Due to the reduction in coal production the Company evaluated Kentucky May Coal Mine's long-lived assets in 2003. Fair value was determined based on discounted cash flows. As a result of this review, the Company recorded asset impairments of $17 million on a pre-tax basis during the fourth quarter of 2003. An estimated impairment of assets held for sale of $59 million is included in the 2002 amount, which relates to Railcar Ltd. (See Note 3B). Due to the decline of the telecommunications industry and continued operating losses, the Company initiated an independent valuation study during 2002 to assess the recoverability of the long-lived assets of PTC and Caronet. Based on this assessment, the Company recorded asset impairments of $305 million on a pre-tax basis and other charges of $25 million on a pre-tax basis primarily related to inventory adjustments in the third quarter of 2002. This write-down constitutes a significant reduction in the book value of these long-lived assets. The long-lived asset impairments include an impairment of property, plant and equipment, construction work in process and intangible assets. The impairment charge represents the difference between the fair value and carrying amount of these long-lived assets. The fair value of these assets was determined using a valuation study heavily weighted on the discounted cash flow methodology, using market approaches as supporting information. Due to historical losses at Strategic Resource Solutions Corp. (SRS) and the decline in the market value for technology companies, the Company evaluated the long-lived assets of SRS in 2001. Fair value was determined based on discounted cash flows. As a result of this review, the Company recorded asset impairments of $43 million and other charges of $2 million on a pre-tax basis during the fourth quarter of 2001. B. Investments The Company continually reviews its investments to determine whether a decline in fair value below the cost basis is other than temporary. In 2003, PEC's affordable housing investment (AHI) portfolio was reviewed and deemed to be impaired based on various factors including continued operating losses of the AHI portfolio and management performance issues arising at certain properties within the AHI portfolio. As a result, PEC recorded an impairment of $18 million on a pre-tax basis during the fourth quarter of 2003. PEC also recorded an impairment of $3 million for a cost investment. In 2001, the Company obtained a valuation study to assess its investment in Interpath Communications Inc. (Interpath) based on current valuations in the technology sector. As a result, the Company recorded an impairment 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 million on a pre-tax basis for the year ended December 31, 2001. In May 2002, Interpath merged with a third party. As a result, the Company reviewed the Interpath investment for impairment and wrote off the remaining amount of its cost-basis investment in Interpath, recording a pre-tax impairment of $25 million in the third quarter of 2002. In the fourth quarter of 2002, the Company sold its remaining interest in Interpath for a nominal amount. 98 10. Equity A. Common Stock In November 2002, the Company issued 14.7 million shares of common stock for net cash proceeds of approximately $600 million, which were primarily used to retire commercial paper. In April 2002, the Company issued 2.5 million shares of common stock, valued at approximately $129 million, in conjunction with the purchase of Westchester (See Note 4E). In August 2001, the Company issued 12.6 million shares of common stock for net cash proceeds of $489 million, which were primarily used to retire commercial paper. At December 31, 2003, the Company had approximately 53 million 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. In 2002, the Board of Directors authorized meeting the requirements of the Progress Energy 401(k) Savings and Stock Ownership Plan and the Investor Plus Stock Purchase Plan with original issue shares. Prior to that authorization, the Company met the requirements of these stock plans with issued and outstanding shares held by the Trustee of the Progress Energy 401(k) Savings and Stock Ownership Plan (previously known as the Progress Energy, Inc. Stock Purchase-Savings Plan) or with open market purchases of common stock shares, as appropriate. During 2003 and 2002, respectively, the Company issued approximately 8 million and 2 million shares under these plans for net proceeds of approximately $309 million and $86 million. The Company continues to meet the requirements of the restricted stock plan with issued and outstanding shares. There are various provisions limiting the use of retained earnings for the payment of dividends under certain circumstances. At December 31, 2003, there were no significant restrictions on the use of retained earnings. B. Stock-Based Compensation 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, 2003 were PEC, PEF, PTC, Progress Fuels (Corporate) and Progress Energy Service Company. Effective December 19, 2003 (the PTC LLP/EPIK merger date), PTC no longer participates in the 401(k) plan. 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. Also, beginning in 2002, the dividends paid on ESOP shares which are either paid directly to participants or used to purchase additional shares which are then allocated to participants are fully deductible for income tax purposes. There were 4.0 million and 4.6 million ESOP suspense shares at December 31, 2003 and 2002, respectively, with a fair value of $183 million and $200 million, respectively. ESOP shares allocated to plan participants totaled 13.1 million and 13.6 million in December 31, 2003 and 2002, 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, with shares released from the ESOP suspense account and with newly issued shares. Costs for incentive goal compensation are accrued during the fiscal year and typically paid in shares in the following year; while costs for the matching component are typically met with shares in the same year incurred. Matching and incentive cost which were met and will be met with shares released from the suspense account totaled approximately $20 million, $20 million and $18 million for the years ended December 31, 2003, 2002 and 2001, respectively. Total 99 matching and incentive cost totaled approximately $35 million, $30 million and $29 million for the years ended December 31, 2003, 2002 and 2001, respectively, including 2001 amounts incurred under the previous Florida Progress Corporation (Florida Progress) Plan. 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. Stock Option Agreements Pursuant to the Company's 1997 Equity Incentive Plan and 2002 Equity Incentive Plan, amended and restated as of July 10, 2002, the Company may grant options to purchase shares of common stock to directors, officers and eligible employees for up to 5 million and 15 million shares, respectively. Generally, options granted to employees vest one-third per year with 100% vesting at the end of year three while options granted to directors vest 100% at the end of one year. The options expire ten 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. The Company measures compensation expense for stock options as the difference between the market price of its common stock and the exercise price of the option at the grant date. The exercise price at which options are granted by the Company equals the market price at grant date and accordingly, no compensation expense has been recognized for any options granted during 2003, 2002 and 2001. The pro forma information presented in Note 1 regarding net income and earnings per share is required by SFAS No. 148. 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 presented in Note 1 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: 2003 2002 2001 ------------------------------ Risk-free interest rate 4.25% 4.14% 4.83% Dividend yield 4.75% 5.20% 5.21% Volatility factor 22.28% 24.98% 26.47% Weighted-average expected life of the options (in years) 10 10 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 options outstanding at December 31, 2003, 2002 and 2001 had a weighted-average remaining contractual life of 8.70, 9.32 and 9.75 years, respectively, and had exercise prices that ranged from $40.41 to $51.85. At December 31, 2003, 92 thousand options have been exercised, while no options have expired. The tabular information for the option activity is as follows: 2003 2002 2001 ----------------------------------------------------------------------------- Weighted- Weighted- Weighted- Average Average Average Number of Exercise Number of Exercise Number of Exercise (option quantities in millions) Options Price Options Price Options Price - -------------------------------------------------------------------------------------------------------------------- Options outstanding, January 1 5.2 $ 42.84 2.3 $ 43.49 - Granted 3.0 $ 44.70 2.9 $ 42.34 2.4 $ 43.49 Forfeited (0.1) $ 43.64 - $ 43.71 (0.1) $ 43.49 Canceled (0.1) $ 43.62 - - - - Exercised - $ 43.00 - - - - Options outstanding, December 31 8.0 $ 43.54 5.2 $ 42.84 2.3 $ 43.49 Options exercisable, December 31 with a remaining contractual life of 8.75 years 2.4 $ 43.09 0.8 $ 43.49 - - Weighted-average grant date fair value of options granted during the year $ 7.16 $ 6.83 $ 8.05
100 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 and were continued under the Company's 2002 Equity Incentive Plan, as amended and restated as of July 10, 2002. 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 program allows the Company to grant shares of restricted common stock to officers and key employees of the Company. The restricted shares generally 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 $39.53, $44.27 and $41.86 in 2003, 2002 and 2001, 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: 2003 2002 2001 --------- --------- --------- Beginning balance 950,180 674,511 653,344 Granted 180,200 365,920 113,651 Vested (151,677) (75,200) (70,762) Forfeited (33,820) (15,051) (21,722) --------- --------- --------- Ending balance 944,883 950,180 674,511 ========= ========= ========= The total amount expensed for other stock-based compensation plans was $27 million, $17 million and $14 million in 2003, 2002 and 2001, respectively. C. Earnings Per Common Share Basic earnings per common share is based on the weighted-average number of common shares outstanding. Diluted earnings per share includes the effect of the non-vested portion of restricted stock awards and the effect of stock options outstanding. A reconciliation of the weighted-average number of common shares outstanding for basic and dilutive purposes is as follows: (in millions) 2003 2002 2001 -------- --------- -------- Weighted-average common shares - basic 237.2 217.2 204.7 Restricted stock awards 1.0 .8 .6 Stock options - .2 - -------- --------- -------- Weighted-average shares - fully diluted 238.2 218.2 205.3 ======== ========= ======== 101 There are no adjustments to net income or to income from continuing operations between the calculations of basic and fully diluted earnings per common share. 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 4.1 million, 4.8 million and 5.4 million for the years ended December 31, 2003, 2002 and 2001, respectively. There were 5.3 million and 92 thousand stock options outstanding at December 31, 2003 and 2002, respectively, which were not included in the weighted-average number of shares for computing the fully diluted earnings per share because they were antidilutive. D. Accumulated Other Comprehensive Loss Components of accumulated other comprehensive loss are as follows: (in millions) 2003 2002 ----------- ----------- Loss on cash flow hedges $ (35) $ (42) Minimum pension liability adjustments (15) (192) Foreign currency translation and other - (4) ----------- ----------- Total accumulated other comprehensive loss $ (50) $(238) =========== =========== 11. Preferred Stock of Subsidiaries - Not Subject to Mandatory Redemption All of the Company's preferred stock was issued by its subsidiaries and was not subject to mandatory redemption. Preferred stock outstanding at December 31, 2003 and 2002 consisted of the following: (in millions, except share data and par value) Progress Energy Carolinas, Inc. Authorized - 300,000 shares, cumulative, $100 par value Preferred Stock; 20,000,000 shares, cumulative, $100 par value Serial Preferred Stock: $5.00 Preferred - 236,997 shares outstanding (redemption price $110.00) $ 24 $4.20 Serial Preferred - 100,000 shares outstanding (redemption price $102.00) 10 $5.44 Serial Preferred - 249,850 shares outstanding (redemption price $101.00) 25 ------- $ 59 ------- Progress Energy Florida, Inc. Authorized - 4,000,000 shares, cumulative, $100 par value Preferred Stock; 5,000,000 shares, cumulative, no par value Preferred Stock; 1,000,000 shares, $100 par value Preference Stock $100 par value Preferred Stock: 4.00% - 39,980 shares outstanding (redemption price $104.25) $ 4 4.40% - 75,000 shares outstanding (redemption price $102.00) 8 4.58% - 99,990 shares outstanding (redemption price $101.00) 10 4.60% - 39,997 shares outstanding (redemption price $103.25) 4 4.75% - 80,000 shares outstanding (redemption price $102.00) 8 ------- $ 34 ------- Total Preferred Stock of Subsidiaries $ 93 =======
102 12. Debt and Credit Facilities A. Debt and Credit At December 31, the Company's long-term debt consisted of the following (maturities and weighted-average interest rates at December 31, 2003): (in millions) 2003 2002 --------------- -------------- Progress Energy, Inc. Senior unsecured notes, maturing 2004-2031 6.86% $ 4,800 $ 4,800 Unamortized fair value hedge gain, net 19 34 Unamortized premium and discount, net (27) (31) --------------- -------------- 4,792 4,803 --------------- -------------- Progress Energy Carolinas, Inc. First mortgage bonds, maturing 2004-2033 6.42% 1,900 1,550 Pollution control obligations, maturing 2010-2024 1.69% 708 708 Unsecured notes, maturing 2012 6.50% 500 500 Medium-term notes, maturing 2008 6.65% 300 300 Miscellaneous notes - 6 Unamortized premium and discount, net (22) (16) --------------- -------------- 3,386 3,048 --------------- -------------- Progress Energy Florida, Inc. First mortgage bonds, maturing 2004-2033 5.60% 1,330 810 Pollution control obligations, maturing 2018-2027 1.04% 241 241 Medium-term notes, maturing 2004-2028 6.75% 379 417 Unamortized premium and discount, net (3) (7) --------------- -------------- 1,947 1,461 --------------- -------------- Florida Progress Funding Corporation (See Note 12F) Debt to affiliated trust, maturing 2039 7.10% 309 - Mandatorily redeemable preferred securities, maturing 2039 - 300 Unamortized premium and discount, net (39) (39) --------------- -------------- 270 261 --------------- -------------- Progress Capital Holdings, Inc. Medium-term notes, maturing 2004-2008 6.78% 165 223 Miscellaneous notes 1 1 --------------- -------------- 166 224 --------------- -------------- Progress Genco Ventures, LLC Variable rate project financing, maturing 2007 3.04% 241 225 --------------- -------------- Current portion of long-term debt (868) (275) --------------- -------------- Total long-term debt $ 9,934 $ 9,747 =============== ==============
At December 31, 2003 and 2002, the Company had $4 million and $695 million, 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, 2003 and 2002 were 2.25% and 1.67%, respectively. At December 31, 2003, the Company had committed lines of credit which are used to support its commercial paper borrowings and had no outstanding loans. The Company is required to pay minimal annual commitment fees to maintain its credit facilities. The following table summarizes the Company's credit facilities: 103 (in millions) Company Description Total ---------------------------------------------------------------------------------- Progress Energy, Inc. 364-Day (expiring 11/10/04) $ 250 Progress Energy, Inc. 3-Year (expiring 11/13/04) 450 Progress Energy Carolinas, Inc. 364-Day (expiring 7/29/04) 165 Progress Energy Carolinas, Inc. 3-Year (expiring 7/31/05) 285 Progress Energy Florida, Inc. 364-Day (expiring 3/31/04) 200 Progress Energy Florida, Inc. 3-Year (expiring 4/1/06) 200 ------------ Total credit facilities $ 1,550 ============
Progress Energy and PEF each have an uncommitted bank bid facility authorizing them to borrow and reborrow, and have loans outstanding at any time, up to $300 million and $100 million, respectively. These bank bid facilities were not drawn at December 31, 2003. The combined aggregate maturities of long-term debt for 2004 through 2008 are approximately $868 million, $348 million, $908 million, $915 million and $827 million, respectively. B. Covenants and Default Provisions Financial Covenants Progress Energy's, PEC's and PEF's credit lines and the bank facility of Progress Genco Ventures, LLC (Genco), a PVI subsidiary, contain various terms and conditions that could affect the Company's ability to borrow under these facilities. These include maximum debt to total capital ratios, interest coverage tests, material adverse change clauses and cross-default provisions. All of the credit facilities and the Genco's bank facility include a defined maximum total debt to total capital ratio. At December 31, 2003, the maximum and calculated ratios for these four companies, pursuant to the terms of the agreements, are as follows: Company Maximum Ratio Actual Ratio (a) -------------------------------------------------------------------- Progress Energy, Inc. 68% 61.5% Progress Energy Carolinas, Inc. 65% 51.4% Progress Energy Florida, Inc. 65% 51.5% Progress Genco Ventures, LLC 40% 24.6% (a) Indebtedness as defined by the bank agreements includes certain letters of credit and guarantees which are not recorded on the Consolidated Balance Sheets. Progress Energy's 364-day credit facility and both PEF's 364-day and 3-year credit facilities have a financial covenant for interest coverage. The covenants require Progress Energy's and PEF's Earnings before interest, taxes, and depreciation and amortization to interest expense ratio to be at least 2.5 to 1 and 3 to 1, respectively. For the year ended December 31, 2003, the ratios were 3.74 to 1 and 9.22 to 1 for the Company and PEF, respectively. Genco's bank facility requires a minimum 1.25 to 1 debt service coverage ratio. For the year ended December 31, 2003, Genco's debt service coverage was 6.35 to 1. Material Adverse Change Clause The credit facilities of Progress Energy, PEC, PEF and Genco 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. Cross-Default Provisions Progress Energy's, PEC's and PEF's credit lines include cross-default provisions for defaults of indebtedness in excess of $10 million. Progress Energy's cross-default provisions only apply to defaults of indebtedness by Progress Energy and its significant subsidiaries (i.e., PEC, FPC, PEF, PVI, Progress Fuels and Progress Capital Holdings, Inc. (PCH)). PEC's and PEF's cross-default provisions only apply to defaults of indebtedness by PEC and PEF and their subsidiaries, respectively, not other affiliates of PEC or PEF. The Genco credit facility includes a similar provision for defaults by Progress Energy or PVI. 104 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 only apply to other obligations of Progress Energy, not its subsidiaries. In the event that these indenture cross-default provisions are triggered, the debt holders could accelerate payment of approximately $4,800 million in long-term debt. Certain agreements underlying the Company's indebtedness also limit its ability to incur additional liens or engage in certain types of sale and leaseback transactions. Other Restrictions Neither Progress Energy's Articles of Incorporation nor any of its debt obligations contain any restrictions on the payment of dividends. Certain documents restrict the payment of dividends by Progress Energy's subsidiaries as outlined below. PEC's mortgage indenture provides that, as long as any first mortgage bonds are outstanding, cash dividends and distributions on its common stock and purchases of its common stock are restricted to aggregate net income available for PEC since December 31, 1948, plus $3 million, less the amount of all preferred stock dividends and distributions, and all common stock purchases, since December 31, 1948. At December 31, 2003, none of PEC's retained earnings were restricted. In addition, PEC's Articles of Incorporation provide that cash dividends on common stock shall be limited to 75% of net income available for dividends if common stock equity falls below 25% of total capitalization, and to 50% if common stock equity falls below 20%. At December 31, 2003, PEC's common stock equity was approximately 50.7% of total capitalization. PEF's mortgage indenture provides that it will not pay any cash dividends upon its common stock, or make any other distribution to the stockholders, except a payment or distribution out of net income of PEF subsequent to December 31, 1943. At December 31, 2003, none of PEF's retained earnings were restricted. In addition, PEF's Articles of Incorporation provide that no cash dividends or distributions on common stock shall be paid, if the aggregate amount thereof since April 30, 1944, including the amount then proposed to be expended, plus all other charges to retained earnings since April 30, 1944, exceed (a) all credits to retained earnings since April 30, 1944, plus (b) all amounts credited to capital surplus after April 30, 1944, arising from the donation to PEF of cash or securities or transfers of amounts from retained earnings to capital surplus. PEF's Articles of Incorporation also provide that cash dividends on common stock shall be limited to 75% of net income available for dividends if common stock equity falls below 25% of total capitalization, and to 50% if common stock equity falls below 20%. On December 31, 2003, PEF's common stock equity was approximately 52.5% of total capitalization. Genco is required to hedge 75% of the amount outstanding under its bank facility through September 2005 and 50% thereafter, pursuant to the term of the agreement for expansion of its nonregulated generation portfolio. At December 31, 2003, Genco held interest rate cash flow hedges with a notional amount of $195 million and a total fair value of $11 million liability position related to this covenant. See additional discussion of interest rate cash flow hedges in Note 17. C. Secured Obligations PEC's and PEF's first mortgage bonds are secured by their respective mortgage indentures. Each mortgage constitutes a first lien on substantially all of the fixed properties of the respective company, subject to certain permitted encumbrances and exceptions. Each mortgage also constitutes a lien on subsequently acquired property. At December 31, 2003, PEC and PEF had a total of approximately $4,179 million of first mortgage bonds outstanding, including those related to pollution control obligations. Each mortgage allows the issuance of additional mortgage bonds upon the satisfaction of certain conditions. Genco obtained a bank facility to be used exclusively for expansion of its nonregulated generation portfolio. Borrowings under this facility are secured by the assets in the generation portfolio. The facility is for up to $260 million, of which $241 million had been drawn at December 31, 2003. Borrowings under the facility are restricted for the operations, construction, repayments and other related charges of the credit facility for the development projects. Cash held and restricted to operations was $24 million and $21 million at December 31, 2003 and 2002, respectively, and is included in other current assets. Cash held and restricted for long-term purposes was $9 million and $37 million at December 31, 2003 and 2002, respectively, and is included in other assets and deferred debits on the Consolidated Balance Sheets. 105 D. Guarantees of Subsidiary Debt FPC has guaranteed the outstanding debt obligations for PCH, a wholly-owned subsidiary of Florida Progress. At December 31, 2003 and 2002, PCH had $165 million and $223 million, respectively; in medium-term notes outstanding which are recorded on the Company's accompanying Consolidated Balance Sheets. E. Hedging Activities Progress Energy uses interest rate derivatives to adjust the fixed and variable rate components of its debt portfolio and to hedge cash flow risk related to commercial paper and to fixed rate debt to be issued in the future. See discussion of risk management activities and derivative transactions at Note 17. F. FPC-Obligated Mandatorily Redeemable Preferred Securities of an Unconsolidated 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 an annual distribution rate of 7.10%. Prior to the adoption of FIN No. 46, the Company consolidated the Trust, which holds the Preferred Securities. The Trust is a special-purpose entity, and therefore the Company applied FIN No. 46 to the Trust at December 31, 2003 (See Note 2). The adoption of FIN No. 46 required the Company to deconsolidate the Trust at December 31, 2003. 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 Florida Progress Funding Corporation (Funding Corp.) its 7.10% Junior Subordinated Deferrable Interest Notes (subordinated notes) due 2039, for a principal amount of $309 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 related to the $300 million Preferred Securities 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. Prior to December 2003, these Preferred Securities were classified as long-term debt on the Company's Consolidated Balance Sheets. After deconsolidation of the Trust at December 31, 2003, FPC's subordinated notes payable to the Trust are classified as affiliate long-term debt on the Company's December 31, 2003 Consolidated Balance Sheet. 13. 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, 2003 and 2002, investments in company-owned life insurance and other benefit plan assets, with carrying amounts of approximately $162 million and $150 million, respectively, are included in miscellaneous other property and investments and approximate fair value due to the short maturity of the instruments. Other instruments are presented at fair value in accordance with GAAP. The carrying amount of the Company's long-term debt, including current maturities, was $10,802 million and $10,022 million at December 31, 2003 and 2002, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $11,917 million and $10,974 million at December 31, 2003 and 2002, respectively. 106 External trust funds have been established to fund certain costs of nuclear decommissioning (See Note 5D). 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. 14. Income Taxes Deferred income taxes are provided for temporary differences between book and tax bases of assets and liabilities. Investment tax credits related to regulated operations are amortized over the service life of the related property. To the extent that the establishment of deferred income taxes under SFAS No. 109, "Accounting for Income Taxes" is different from the recovery of taxes by PEC and PEF through the ratemaking process, the differences are deferred pursuant to SFAS No. 71. 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 millions) 2003 2002 ----------- ------------ Accumulated depreciation and property cost differences $ 1,524 $ 1,624 Deferred costs, net (49) (73) Federal income tax credit carry forward (682) (472) Minimum pension liability adjustment (9) (117) Miscellaneous other temporary differences, net (153) (111) Valuation allowance 42 47 ----------- ------------ Net accumulated deferred income tax liability $ 673 $ 898 =========== ============
Total deferred income tax liabilities were $2,427 million and $2,430 million at December 31, 2003 and 2002, respectively. Total deferred income tax assets were $1,754 million and $1,532 million at December 31, 2003 and 2002, respectively. At December 31, 2003 and 2002, the Company had net noncurrent deferred tax liabilities of $737 million and $858 million. At December 31, 2003, the Company had a net current deferred tax asset of $64 million which is included on the Consolidated Balance Sheets under the caption prepayments and other current assets. At December 31, 2002, the Company had a net current deferred tax liability of $40 million which is included on the Consolidated Balance Sheets under the caption other current liabilities. The federal income tax credit carry forward at December 31, 2003 consists of $659 million of alternative minimum tax credit with an indefinite carry-forward period and $23 million of general business credit with a carry-forward period that will begin to expire in 2020. The Company established additional valuation allowances of $5 million, $12 million and $24 million during 2003, 2002 and 2001, respectively, due to the uncertainty of realizing certain future state tax benefits. The overall decrease in the 2003 valuation allowance balance is largely due to the Company's sale of its wholly-owned subsidiary Caronet. The Company believes it is more likely than not that the results of future operations will generate sufficient taxable income to allow for the utilization of the remaining deferred tax assets. 107 Reconciliations of the Company's effective income tax rate to the statutory federal income tax rate are: 2003 2002 2001 ------------ ------------- ------------- Effective income tax rate (15.5)% (40.0)% (40.0)% State income taxes, net of federal benefit (3.3) (8.2) (7.7) AFUDC amortization (2.0) (5.2) (5.0) Federal tax credits 50.3 78.0 94.5 Goodwill amortization and write-offs - - (11.4) Investment tax credit amortization 2.3 4.7 5.9 ESOP dividend deduction 2.1 3.8 1.9 Interpath investment impairment - - (2.1) Other differences, net 1.1 1.9 (1.1) ------------ ------------- ------------- Statutory federal income tax rate 35.0% 35.0% 35.0% ============ ============= =============
Income tax expense (benefit) applicable to continuing operations is comprised of: (in millions) 2003 2002 2001 ------------- ------------- ------------ Current - federal $ 129 $ 195 $ 184 state 54 67 52 Deferred - federal (255) (379) (357) state (21) (23) (10) Investment tax credit (16) (18) (23) ------------- ------------ ------------ Total income tax expense (benefit) $ (109) $ (158) $ (154) ============= ============ ============
The Company, through its subsidiaries, is a majority owner in five entities and a minority owner in one entity that owns facilities that produce synthetic fuel as defined under the Internal Revenue Code (Code). The production and sale of the synthetic fuel from these facilities qualifies for tax credits under 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 and that the fuel was produced from a facility that was placed in service before July 1, 1998. Total Section 29 credits generated to date (including FPC prior to its acquisition by the Company) are approximately $1,243 million. All entities have received private letter rulings (PLRs) from the Internal Revenue Service (IRS) with respect to their synthetic fuel operations. The PLRs 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. One of the Company's synthetic fuel entities, Colona Synfuel Limited Partnership, L.L.L.P. (Colona), is being audited by the IRS. The audit of Colona was expected. The Company is audited regularly in the normal course of business as are most similarly situated companies. The Company (including FPC prior to its acquisition by the Company) has been allocated approximately $317 million in tax credits to date from this synthetic fuel entity. In September 2002, all of Progress Energy's majority-owned synthetic fuel entities, including Colona, were accepted into the IRS's Pre-Filing Agreement (PFA) program. The PFA program allows taxpayers to voluntarily accelerate the IRS exam process in order to seek resolution of specific issues. Either the Company or the IRS can withdraw from the program at any time, and issues not resolved through the program may proceed to the next level of the IRS exam process. While the ultimate outcome is uncertain, the Company believes that participation in the PFA program will likely shorten the tax exam process. In June 2003, the Company was informed that IRS field auditors had raised questions regarding the chemical change associated with coal-based synthetic fuel manufactured at its Colona facility and the testing process by which the chemical change is verified. (The questions arose in connection with the Company's participation in the PFA program.) The chemical change and the associated testing process were described as part of the PLR request for Colona. Based on that application, the IRS ruled in Colona's PLR that the synthetic fuel produced at Colona undergoes a significant chemical change and thus qualifies for tax credits under Section 29. 108 In October 2003, the National Office of the IRS informed the Company that it had rejected the IRS field auditors' challenges regarding whether the synthetic fuel produced at the Company's Colona facility was the result of a significant chemical change. The National Office had concluded that the experts, engaged by Colona who test the synthetic fuel for chemical change, use reasonable scientific methods to reach their conclusions. Accordingly, the National Office will not take any adverse action on the PLR that has been issued for the Colona facility. Although this ruling applies only to the Colona facility, the Company believes that the National Office's reasoning would be equally applicable to the other Progress Energy facilities. The Company applies essentially the same chemical process and uses the same independent laboratories to confirm chemical change in the synthetic fuel manufactured at each of its other facilities. In February 2004, subsidiaries of the Company finalized execution of the Colona Closing Agreement with the Internal Revenue Service concerning their Colona synthetic fuel facilities. The Colona Closing Agreement provided that the Colona facilities were placed in service before July 1, 1998, which is one of the qualification requirements for tax credits under Section 29. The Colona Closing Agreement further provides that the fuel produced by the Colona facilities in 2001 is a "qualified fuel" for purposes of the Section 29 tax credits. This action concludes the IRS PFA program with respect to Colona. Although the execution of the Colona Closing Agreement is a significant event, the audits of the Company's facilities are not yet completed and the PFA process continues with respect to the four synthetic fuel facilities owned by other affiliates of Progress Energy and FPC. Currently, the focus of that process is to determine that the facilities were placed in service before July 1, 1998. In management's opinion, Progress Energy is complying with all the necessary requirements to be allowed such credits under Section 29, although it cannot provide certainty, that it will prevail if challenged by the IRS on credits taken. Accordingly, the Company has no current plans to alter its synthetic fuel production schedule as a result of these matters. In October 2003, the United States Senate Permanent Subcommittee on Investigations began a general investigation concerning synthetic fuel tax credits claimed under Section 29. The investigation is examining the utilization of the credits, the nature of the technologies and fuels created, the use of the synthetic fuel and other aspects of Section 29 and is not specific to the Company's synthetic fuel operations. Progress Energy is providing information in connection with this investigation. The Company cannot predict the outcome of this matter. 15. Contingent Value Obligations In connection with the acquisition of FPC during 2000, the Company issued 98.6 million contingent value obligations (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 CVO liability is adjusted to reflect market price fluctuations. The liability, included in other liabilities and deferred credits, at December 31, 2003 and 2002, was $23 million and $14 million, respectively. 16. Benefit Plans A. Postretirement Benefits 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. 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 Company uses a measurement date of December 31 for its pension and OPEB plans. 109 The components of net periodic benefit cost for the years ended December 31 are: Pension Benefits Other Postretirement Benefits --------------------------------- ----------------------------- (in millions) 2003 2002 2001 2003 2002 2001 --------------------------------- --------------------------- Service cost $ 52 $ 45 $ 31 $ 15 $ 13 $ 13 Interest cost 108 106 96 33 32 28 Expected return on plan assets (144) (161) (169) (4) (5) (5) Amortization of actuarial (gain) loss 25 2 (5) 5 1 - Other amortization, net - - (1) 4 4 5 --------------------------------- --------------------------- Net periodic cost/(benefit) $ 41 $ (8) $ (48) $ 53 $ 45 $ 41 Additional cost/(benefit) recognition (Note 16B) (18) (7) (16) 2 2 4 --------------------------------- --------------------------- Net periodic cost/(benefit) recognized $ 23 $ (15) $ (64) $ 55 $ 47 $ 45 ================================= ===========================
In addition to the net periodic cost and benefit reflected above, in 2003 the Company recorded curtailment and settlement effects related to the disposition of NCNG, which are reflected in income/(loss) from discontinued operations in the Consolidated Statements of Income. These effects included a pension-related loss of $13 million and an OPEB-related gain of $1 million. 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 projected benefit obligation or the market-related value of assets are amortized over the average remaining service period of active participants. To determine the market-related value of assets, the Company uses a 5-year averaging method for a portion of its pension assets and fair value for the remaining portion. The Company has historically used the 5-year averaging method. When the Company acquired Florida Progress in 2000, it retained the Florida Progress historical use of fair value to determine market-related value for Florida Progress pension assets. Reconciliations of the changes in the plans' benefit obligations and the plans' funded status are: Other Postretirement Pension Benefits Benefits ------------------------ ------------------------- (in millions) 2003 2002 2003 2002 ------------------------ ------------------------- Projected benefit obligation at January 1 $ 1,694 $ 1,391 $ 514 $ 401 Service cost 52 45 15 13 Interest cost 108 106 33 32 Disposition of NCNG (39) - (13) - Benefit payments (94) (91) (24) (24) Actuarial loss (gain) (66) 243 30 92 --------- ---------- --------- ---------- Obligation at December 31 1,655 1,694 555 514 Fair value of plan assets at December 31 1,631 1,364 65 52 --------- ---------- ---------- ---------- Funded status (24) (330) (490) (462) Unrecognized transition obligation - 1 25 30 Unrecognized prior service cost 4 5 7 7 Unrecognized net actuarial (gain) loss 388 742 123 108 Minimum pension liability adjustment (23) (497) - - ----------- ---------- ---------- ---------- Prepaid (accrued) cost at December 31, net $ 345 $ (79) $ (335) $ (317) (Note 16B) ======================== =======================
110 The net prepaid pension cost of $345 million at December 31, 2003 is recognized in the Consolidated Balance Sheets as prepaid pension cost of $462 million and accrued benefit cost of $117 million, which is included in other liabilities and deferred credits. The net accrued pension cost of $79 million at December 31, 2002 is recognized in the Consolidated Balance Sheets as prepaid pension cost of $60 million and accrued benefit cost of $139 million, of which $130 million is included in other liabilities and deferred credits and $9 million is included in liabilities of discontinued operations. The defined benefit pension plans with accumulated benefit obligations in excess of plan assets had projected benefit obligations totaling $125 million and $1.51 billion at December 31, 2003 and 2002, respectively. Those plans had accumulated benefit obligations totaling $117 million and $1.35 billion December 31, 2003 and 2002, respectively, no plan assets at December 31, 2003 and plan assets totaling $1.22 billion at December 31, 2002. The total accumulated benefit obligation for pension plans was $1.61 billion and $1.49 billion at December 31, 2003 and 2002, respectively. The accrued OPEB cost is included in other liabilities and deferred credits in the Consolidated Balance Sheets. A minimum pension liability adjustment of $23 million, related to the supplementary defined benefit pension plans, was recorded at December 31, 2003. This adjustment is offset by a corresponding pre-tax amount in accumulated other comprehensive loss, a component of common stock equity. Due to a combination of decreases in the fair value of plan assets and a decrease in the discount rate used to measure the pension obligation, a minimum pension liability adjustment of $497 million was recorded at December 31, 2002. This adjustment resulted in a charge of $5 million to intangible assets, included in other assets and deferred debits in the accompanying Consolidated Balance Sheets, a $178 million charge to a pension-related regulatory liability (See Note 16B) and a pre-tax charge of $313 million to accumulated other comprehensive loss, a component of common stock equity. Reconciliations of the fair value of plan assets are: Other Postretirement Pension Benefits Benefits ------------------------ ---------------------- (in millions) 2003 2002 2003 2002 ------------------------ ---------------------- Fair value of plan assets January 1 $ 1,364 $ 1,678 $ 52 $ 56 Actual return on plan assets 391 (228) 12 (5) Disposition of NCNG (35) - - - Benefit payments (94) (91) (24) (24) Employer contributions 5 5 25 25 ------------------------ ---------------------- Fair value of plan assets at December 31 $ 1,631 $ 1,364 $ 65 $ 52 ======================== ======================
In the table above, substantially all employer contributions represent benefit payments made directly from Company assets. The remaining benefits payments were made directly from plan assets. The OPEB benefit payments represent the net Company cost after participant contributions. Participant contributions represent approximately 20% of gross benefit payments. The asset allocation for the Company's plans at the end of 2003 and 2002 and the target allocation for the plans, by asset category, are as follows: Pension Benefits Other Postretirement Benefits ------------------------------------------ -------------------------------------------- Target Percentage of Plan Assets Target Percentage of Plan Assets at Allocations at Year End Allocations Year End ----------- ------------------------- ----------- ---------------------------- Asset Category 2004 2003 2002 2004 2003 2002 ----------- ---------- ---------- ----------- ----------- ------------ Equity - domestic 50% 49% 47% 35% 35% 32% Equity - international 15% 22% 20% 10% 16% 14% Debt - domestic 15% 11% 15% 45% 37% 41% Debt - international 10% 11% 10% 5% 7% 7% Other 10% 7% 8% 5% 5% 6% ----------- ---------- ---------- ----------- ----------- ------------ Total 100% 100% 100% 100% 100% 100% =========== ========== ========== =========== =========== ============
111 The Company sets target allocations among asset classes to provide broad diversification to protect against large investment losses and excessive volatility, while recognizing the importance of offsetting the impacts of benefit cost escalation. In addition, the Company employs external investment managers who have complementary investment philosophies and approaches. Tactical shifts (plus or minus 5%) in asset allocation from the target allocations are made based on the near-term view of the risk and return tradeoffs of the asset classes. In 2004, the Company expects to make $24 million of required contributions directly to pension plan assets and $1 million of discretionary contributions directly to the OPEB plan assets. The expected benefit payments for the pension benefit plan for 2004 through 2008 and in total for 2009-2013, in millions, are approximately $93, $96, $99, $104, $108 and $608, respectively. The expected benefit payments for the OPEB plan for 2004 through 2008 and in total for 2009-2013, in millions, are approximately $22, $24, $26, $28, $30 and $180, respectively. The expected benefit payments include benefit payments directly from plan assets and benefit payments directly from Company assets. The benefit payment amounts reflect the net cost to the Company after any participant contributions. The following weighted-average actuarial assumptions were used in the calculation of the year-end obligation: Pension Benefits Other Postretirement Benefits -------------------- ----------------------------- 2003 2002 2003 2002 ---------- --------- ----------------------------- Discount rate 6.30% 6.60% 6.30% 6.60% Rate of increase in future compensation Bargaining 3.50% 3.50% - - Non-bargaining - 4.00% - - Supplementary plans 5.00% 4.00% Initial medical cost trend rate for pre-Medicare benefits - - 7.25% 7.50% Initial medical cost trend rate for post-Medicare benefits - - 7.25% 7.50% Ultimate medical cost trend rate - - 5.25% 5.25% Year ultimate medical cost trend rate is achieved - - 2009 2009
The Company's primary defined benefit retirement plan for non-bargaining employees is a "cash balance" pension plan as defined in EITF Issue No. 03-4. Therefore, effective December 31, 2003, the Company began to use the traditional unit credit method for purposes of measuring the benefit obligation of this plan and will use that method to measure future benefit costs. Under the traditional unit credit method, no assumptions are included about future changes in compensation and the accumulated benefit obligation and projected benefit obligation are the same. The following weighted-average actuarial assumptions were used in the calculation of the net periodic cost: Pension Benefits Other Postretirement Benefits ---------------------------- ------------------------------- 2003 2002 2001 2003 2002 2001 ---------------------------- ------------------------------- Discount rate 6.60% 7.50% 7.50% 6.60% 7.50% 7.50% Rate of increase in future compensation Bargaining 3.50% 3.50% 3.50% - - - Non-bargaining and supplementary 4.00% 4.00% 4.00% - - - Expected long-term rate of return on plan assets 9.25% 9.25% 9.25% 8.45% 8.20% 8.70% Initial medical cost trend rate for pre-Medicare benefits - - - 7.50% 7.50% 7.2% - 7.5% Initial medical cost trend rate for post-Medicare benefits - - - 7.50% 7.50% 6.2% - 7.5% Ultimate medical cost trend rate - - - 5.25% 5.00% 5.0% - 5.3% Year ultimate medical cost trend rate is achieved - - - 2009 2008 2005-2009
The expected long-term rates of return on plan assets were determined by considering long-term historical returns for the plans and long-term projected returns based on the plans' target asset allocation. For all pension plan assets and a substantial portion of OPEB plans assets, those benchmarks support an expected long-term rate of return between 9.5% and 10.0%. The Company has chosen to use an expected long-term rate of 9.25% due to the uncertainties of future returns. 112 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 2003 would increase by $3 million, and the OPEB obligation at December 31, 2003, would increase by $38 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 2003 would decrease by $2 million and the OPEB obligation at December 31, 2003, would decrease by $33 million. In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed into law. In accordance with guidance issued by the FASB in FASB Staff Position FAS 106-1, the Company has elected to defer accounting for the effects of the Act due to uncertainties regarding the effects of the implementation of the Act and the accounting for certain provisions of the Act. Therefore, OPEB information presented above and in the financial statements does not reflect the effects of the Act. When specific authoritative accounting guidance is issued, it could require plan sponsors to change previously reported information. The Company is in the early stages of reviewing the Act and determining its potential effects on the Company. B. FPC Acquisition During 2000, the Company completed the acquisition of FPC. FPC's pension and OPEB liabilities, assets and net periodic costs are reflected in the above information as appropriate. Certain of FPC's non-bargaining unit benefit plans were merged with those of the Company effective January 1, 2002. PEF continues to recover qualified plan pension costs and OPEB costs in rates as if the acquisition had not occurred. Accordingly, a portion of the accrued OPEB cost reflected in the table above has a corresponding regulatory asset at December 31, 2003 and 2002 (See Note 7A). In addition, a portion of the prepaid pension cost reflected in the table above has a corresponding regulatory liability (See Note 7A). Pursuant to its rate treatment, PEF recognized additional periodic pension credits and additional periodic OPEB costs, as indicated in the net periodic cost information above. 17. Risk Management Activities and Derivatives Transactions Under its risk management policy, the Company may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk if the counterparty fails to perform under the contract. The Company minimizes such risk by performing credit reviews using, among other things, publicly available credit ratings of such counterparties. Potential nonperformance by counterparties is not expected to have a material effect on the consolidated financial position or consolidated results of operations of the Company. A. Commodity Contracts - General Most of the Company's commodity contracts 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. During 2003 the FASB reconsidered an interpretation of SFAS No. 133 related to the pricing of contracts that include broad market indices (e.g., CPI). In particular, that guidance discussed whether the pricing in a contract that contains broad market indices could qualify as a normal purchase or sale (the normal purchase or sale term is a defined accounting term, and may not, in all cases, indicate whether the contract would be "normal" from an operating entity viewpoint). The FASB issued final superseding guidance (DIG Issue C20) on this issue effective October 1, 2003 for the Company. DIG Issue C20 specifies new pricing-related criteria for qualifying as a normal purchase or sale, and it required a special transition adjustment as of October 1, 2003. PEC determined that it had one existing "normal" contract that was affected by DIG Issue C20. Pursuant to the provisions of DIG Issue C20, PEC recorded a pre-tax fair value loss transition adjustment of $38 million ($23 million after-tax) in the fourth quarter of 2003, which was reported as a cumulative effect of a change in accounting principle. The subject contract meets the DIG Issue C20 criteria for normal purchase or sale and, therefore, was designated as a normal purchase as of October 1, 2003. The liability of $38 million associated with the fair value loss is being amortized to earnings over the term of the related contract. 113 B. Commodity Derivatives - Cash Flow Hedges The Company held natural gas cash flow hedging instruments at December 31, 2003 and 2002. The objective for holding these instruments is to manage a portion of the market risk associated with fluctuations in the price of natural gas for the Company's forecasted sales. At December 31, 2003, the Company is hedging exposures to the price variability of natural gas through December 2005. The total fair value of these instruments at December 31, 2003 and 2002 was a $12 million and a $10 million liability position, respectively. The ineffective portion of commodity cash flow hedges was not material in 2003 and 2002. At December 31, 2003, $7 million of after-tax deferred losses in accumulated other comprehensive income (OCI) are expected to be reclassified to earnings during the next 12 months as the hedged transactions occur. Due to the volatility of the commodities markets, the value in OCI is subject to change prior to its reclassification into earnings. C. Commodity Derivatives - Economic Hedges and Trading Nonhedging derivatives, primarily electricity and natural gas contracts, are entered into for trading purposes and for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions. The Company manages open positions with strict policies that limit its exposure to market risk and require daily reporting to management of potential financial exposures. Gains and losses from such contracts were not material during 2003, 2002 or 2001, and the Company did not have material outstanding positions in such contracts at December 31, 2003 or 2002. D. Interest Rate Derivatives - Fair Value or Cash Flow Hedges The Company manages its interest rate exposure in part by maintaining its variable-rate and fixed-rate exposures within defined limits. In addition, the Company also enters into financial derivative instruments, including, but not limited to, interest rate swaps and lock agreements to manage and mitigate interest rate risk exposure. The Company uses cash flow hedging strategies to hedge variable interest rates on long-term and short-term debt and to hedge interest rates with regard to future fixed-rate debt issuances. At December 31, 2003 and 2002, the Company held interest rate cash flow hedges, with a varying notional amount and maximum of $195 million, related to variable rate long-term debt. At December 31, 2003, the Company also held interest rate cash flow hedges, with a total notional amount of $400 million, related to projected outstanding balances of commercial paper. At December 31, 2002, the Company also held an interest rate cash flow hedge, with a notional amount of $35 million, related to the issuance of fixed-rate debt in early 2003. The total fair value of these hedges at December 31, 2003 and 2002 was a $6 million and a $13 million liability position, respectively. At December 31, 2003, $7 million of after-tax deferred losses in OCI, including amounts in OCI related to terminated hedges, are expected to be reclassified to earnings during the next 12 months as the hedged interest payments occur. Due to the volatility of interest rates, the value in OCI is subject to change prior to its reclassification into earnings. The Company uses fair value hedging strategies to manage its exposure to fixed interest rates on long-term debt. At December 31, 2003, the Company had open interest rate fair value hedges with notional amounts totaling $850 million and a total fair value of $4 million liability position. At December 31, 2002, the Company had open interest rate fair value hedges with notional amounts totaling $350 million and a total fair value of $5 million asset position. In addition, at December 31, 2003, the Company had $23 million of net hedging gains related to terminated interest rate fair value hedges, which is reflected in long-term debt and is being amortized over periods ending in 2006 through 2008 coinciding with the maturities of the related debt instruments. The notional amounts of interest rate derivatives 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. 114 18. Related Party Transactions Progress Fuels sells coal to PEF for an insignificant profit. These intercompany revenues are eliminated in consolidation; however, in accordance with SFAS No. 71, 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 ratemaking process is probable. The profits for all the years presented were not significant. The Company sold NCNG to Piedmont Natural Gas Company, Inc. on September 30, 2003 (See Note 3A). Prior to disposition, NCNG sold natural gas to affiliates. During the years ended December 31, 2003, 2002 and 2001, sales of natural gas to affiliates amounted to $11 million, $20 million and $19 million, respectively. These revenues are included in discontinued operations on the Consolidated Statements of Income. The Company has an outstanding note due to a related trust. The principal outstanding on this note was $309 million at December 31, 2003 (See Note 12A and F). 19. Financial Information by Business Segment The Company currently provides services through the following business segments: PEC Electric, PEF, Fuels, CCO, Rail Services and Other. Prior to 2003, Fuels and CCO were reported together as the Progress Ventures business segment and corporate costs were included in the Other segment. These reportable segment changes reflect the current management structure. PEC Electric and PEF are primarily engaged in the generation, transmission, distribution and sale of electric energy in portions of North Carolina, South Carolina and Florida. These electric operations are subject to the rules and regulations of the FERC, the NCUC, the SCPSC and the FPSC. These electric operations also distribute and sell electricity to other utilities, primarily on the east coast of the United States. Fuels operations, which are located throughout the United States, are involved in natural gas drilling and production, coal terminal services, coal mining, synthetic fuel production, fuel transportation and delivery. CCO's operations, which are located in the southeastern United States, include nonregulated electric generation operations and marketing activities. Rail Services' operations include railcar repair, rail parts reconditioning and sales, railcar leasing and sales and scrap metal recycling. These activities include maintenance and reconditioning of salvageable scrap components of railcars, locomotive repair and right-of-way maintenance. Rail Services' operations are located in the United States, Canada and Mexico. The Other segment, whose operations are in the United States, is composed of other nonregulated business areas including telecommunications and energy service operations and other nonregulated subsidiaries that do not separately meet the disclosure requirements of SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." Included in this segment's 2002 losses are asset impairments and certain other after-tax charges related to the telecommunications operations of $225 million, the 2001 results include asset impairments and other after-tax charges of $153 million. In addition to these reportable operating segments, the Company has other corporate activities that include holding company operations, service company operations and eliminations. These corporate activities have been included in the Other segment in the past. Additionally, earnings from wholesale customers on the regulated plants have previously been reported in both the regulated utilities' results and the results of Progress Ventures (which referred to Fuels and CCO collectively). This activity is now included in the regulated utilities results only. The operations of NCNG, previously reported in the Other segment, were reclassified to discontinued operations and therefore are not included in the results from continuing operations during the periods reported. For comparative purposes, the results have been restated to align with the new business segment structure. The profit or loss of the identified segments plus the loss of Corporate represents the Company's total income from continuing operations. 115 - -------------------------------------------------------------------------------------------------------------- (in millions) PEC Rail Electric PEF Fuels CCO Services(a) Other Corporate Totals - -------------------------------------------------------------------------------------------------------------- Year ended December 31, 2003 Revenues Unaffiliated $ 3,589 $ 3,152 $ 928 $ 170 $ 846 $ 58 $ - $ 8,743 Intersegment - - 346 - 1 15 (362) - - -------------------------------------------------------------------------------------------------------------- Total revenues 3,589 3,152 1,274 170 847 73 (362) 8,743 - -------------------------------------------------------------------------------------------------------------- Depreciation and amortization 562 307 80 42 20 6 23 1,040 Total interest charges, 194 91 23 4 29 (1) 285 625 net Impairment of long-lived assets and investments 11 - 17 - - 10 - 38 Income tax (benefit) (b) 240 147 (415) 8 2 (4) (87) (109) Segment profit (loss) 515 295 235 20 (1) (17) (236) 811 Total assets 10,854 7,306 1,170 1,747 586 304 4,235 26,202 Capital and investment expenditures 470 548 310 360 103 12 22 1,825 - -------------------------------------------------------------------------------------------------------------- Year ended December 31, 2002 Revenues Unaffiliated $ 3,539 $ 3,062 $ 607 $ 92 $ 714 $ 77 $ - $ 8,091 Intersegment - - 329 - 5 14 (348) - - -------------------------------------------------------------------------------------------------------------- Total revenues 3,539 3,062 936 92 719 91 (348) 8,091 - -------------------------------------------------------------------------------------------------------------- Depreciation and amortization 524 295 47 20 20 15 17 938 Total interest charges, net 212 106 24 (12) 33 (5) 275 633 Impairment of long-lived assets and investments - - - - 59 330 - 389 Income tax (benefit) (b) 237 163 (373) 16 (16) (129) (56) (158) Segment profit (loss) 513 323 176 27 (42) (243) (202) 552 Total assets 10,139 6,678 934 1,452 529 318 3,668 23,718 Capital and investment expenditures 624 550 172 682 8 53 20 2,109 - -------------------------------------------------------------------------------------------------------------- - -------------------------------------------------------------------------------------------------------------- Year ended December 31, 2001 Revenues Unaffiliated $ 3,344 $ 3,213 $ 559 $ 16 $ 890 $ 107 $ - $ 8,129 Intersegment - - 299 - 1 13 (313) - - -------------------------------------------------------------------------------------------------------------- Total revenues 3,344 3,213 858 16 891 120 (313) 8,129 - -------------------------------------------------------------------------------------------------------------- Depreciation and amortization 522 453 34 4 36 18 83 1,150 Total interest charges, net 241 113 24 - 41 (7) 261 673 Impairment of long-lived assets and investments - - - - - 207 207 Income tax (benefit) 264 183 (424) 3 (6) (57) (117) (154) Segment profit (loss) 468 309 199 4 (12) (162) (265) 541 Capital and investment expenditures 824 353 70 195 13 72 - 1,527 - --------------------------------------------------------------------------------------------------------------
(a) Amounts for the year ended December 31, 2001 reflect cumulative operating results of Rail Services since the acquisition date of November 30, 2000. (b) Amounts for 2003 and 2002 include income tax benefit reallocation from holding company to profitable subsidiaries according to an SEC order. 20. Other Income and Other Expense Other income and expense includes interest income, gain on the sale of investments, impairment of investments and other income and expense items as discussed below. The components of other, net as shown on the Consolidated Statements of Income for the years ended December 31, are as follows: 116 (in millions) 2003 2002 2001 ---- ---- ---- Other income Net financial trading loss $ (2) $ (2) $ (1) Net energy brokered for resale 2 2 3 Nonregulated energy and delivery services income 22 29 29 Contingent value obligation unrealized gain (Note 15) - 28 - Investment gains 9 30 3 Income from equity investments 9 9 7 AFUDC equity 14 9 9 Other 26 16 5 ----------------------------- Total other income $ 80 $ 121 $ 55 ----------------------------- Other expense Nonregulated energy and delivery services expenses 20 29 35 Donations 15 21 23 Investment losses 27 18 4 Contingent value obligation unrealized loss (Note 15) 9 - 1 Loss from minority interest 3 - 3 Other 31 26 23 ----------------------------- Total other expense $ 105 $ 94 $ 89 ----------------------------- Other, net $ (25) $ 27 $ (34) =============================
Net financial trading loss represents nonasset-backed trades of electricity and gas. Nonregulated energy and delivery services include power protection services and mass market programs (surge protection, appliance services and area light sales) and delivery, transmission and substation work for other utilities. 21. Commitments and Contingencies A. Purchase Obligations The following table reflects Progress Energy's contractual cash obligations and other commercial commitments in the respective periods in which they are due: (in millions) Contractual Cash Obligations 2004 2005 2006 2007 2008 Thereafter ------------------------------------------------------------------------------------------- Fuel $ 1,245 $ 628 $ 459 $ 271 $ 151 $ 1,012 Purchased power 427 439 450 459 431 4,711 Construction obligations 112 49 - - - - Other purchase obligations 28 11 18 11 16 124 ----------------------------------------------------------- Total $ 1,812 $ 1,127 $ 927 $ 741 $ 598 $ 5,847 ===========================================================
Fuel and Purchased Power FPC, PEC and PVI have entered into various long-term contracts for coal, gas and oil. Payments under these commitments were $1,207 million, $1,359 million and $1,257 million for 2003, 2002 and 2001, respectively. Estimated annual payments for firm commitments of fuel purchases and transportation costs under these contracts are approximately $1,245 million, $628 million, $459 million, $271 million and $151 million for 2004 through 2008, respectively, with approximately $1,012 million payable thereafter. Pursuant to the terms of the 1981 Power Coordination Agreement, as amended, between PEC and the North Carolina Eastern Municipal Power Agency (Power Agency), PEC is obligated to purchase a percentage of Power Agency's ownership capacity of, and energy from, the Harris Plant. In 1993, PEC 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, PEC 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 $36 million. These contractual 117 purchases totaled $36 million, $36 million and $33 million for 2003, 2002 and 2001, respectively. In 1987, the NCUC ordered PEC 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, 2002, PEC had deferred purchased capacity costs, including carrying costs accrued on the deferred balances of $17 million. At December 31, 2003, all previously deferred costs have been expensed. PEC 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 MW of capacity through 2009 with minimum annual payments of approximately $42 million, representing capital-related capacity costs. Total purchases (including energy and transmission use charges) under the Rockport agreement amounted to $66 million, $59 million and $63 million for 2003, 2002 and 2001, respectively. Effective June 1, 2001, PEC 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 MW of capacity through 2021 with an original minimum annual payment of approximately $16 million, primarily representing capital-related capacity costs. A separate long-term agreement for additional power from Broad River commenced June 1, 2002. This agreement provided for the additional purchase of approximately 300 MW of capacity through 2022 with an original minimum annual payment of approximately $16 million representing capital-related capacity costs. Total purchases under the Broad River agreements amounted to $37 million, $38 million and $21 million in 2003, 2002 and 2001, respectively. PEF has long-term contracts for approximately 474 MW of purchased power with other utilities, including a contract with The Southern Company for approximately 414 MW of purchased power annually through 2010. PEF can lower these purchases to approximately 200 MW annually with a three-year notice. Total purchases, for both energy and capacity, under these agreements amounted to $141 million, $159 million and $112 million for 2003, 2002 and 2001, respectively. Total capacity payments were $57 million, $51 million and $54 million for 2003, 2002 and 2001, respectively. Minimum purchases under these contracts, representing capital-related capacity costs, are approximately $60 million annually through 2009 and $30 million annually for 2010. Both PEC and PEF have ongoing purchased power contracts with certain cogenerators (qualifying facilities) with expiration dates ranging from 2004 to 2025. These purchased power contracts generally provide for capacity and energy payments. Energy payments for the PEF contracts are based on actual power taken under these contracts. Capacity payments are subject to the qualifying facilities (QFs) meeting certain contract performance obligations. PEF's total capacity purchases under these contracts amounted to $241 million, $232 million and $226 million for 2003, 2002 and 2001, respectively. Minimum expected future capacity payments under these contracts at December 31, 2003 are $257 million, $269 million, $280 million, $289 million and $297 million for 2004 through 2008, respectively, and $4,147 million thereafter. PEC has various pay-for-performance contracts with QFs for approximately 400 MW of capacity expiring at various times through 2009. Payments for both capacity and energy are contingent upon the QFs' ability to generate. Payments made under these contracts were $118 million in 2003, $145 million in 2002 and 2001. Construction Obligations The Company has purchase obligations related to various capital construction projects. Total payments under these contracts were $202 million, $164 million and $24 million for 2003, 2002 and 2001, respectively. Future obligations under these contracts are $112 million and $49 million for 2004 and 2005, respectively. Other Purchase Obligations The Company has entered into various other contractual obligations primarily related to service contracts for operational services entered into by the PESC, a PVI parts and services contract, and a PEF service agreement related to the Hines Complex. Payments under these agreements were $17 million, $15 million and $15 million for 2003, 2002 and 2001, respectively. Future obligations under these contracts are $28 million, $11 million, $18 million, $11 million and $16 million for 2004 through 2008, respectively, and $124 million thereafter. 118 On December 31, 2002, PEC and PVI entered into a contractual commitment to purchase at least $13 million and $4 million, respectively, of capital parts by December 31, 2010. At December 31, 2003, no capital parts have been purchased under this contract. 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 million on synthetic fuel 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 $7 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 asset (included in other assets and deferred debits in the Consolidated Balance Sheets), each of approximately $94 million and $114 million at December 31, 2003 and 2002, respectively, representing the minimum amounts due through 2008, discounted at 6.05%. At December 31, 2003 and 2002, the portions of the asset and liability recorded that were classified as current were approximately $24 million. The deferred 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 paid under these agreements were approximately $2 million in 2003, $51 million in 2002 and $46 million in 2001. Future expected minimum royalty payments are approximately $26 million for 2004 through 2007 and $7 million for 2008. The large decline in amount paid from 2002 to 2003 is due to the Company's right in the related agreements and their amendments that allow the Company to escrow those payments if certain conditions in the agreements are met. The Company has exercised that right and retained 2003 royalty payments of approximately $48 million pending the establishment of the necessary escrow accounts. Once established, those funds will be placed into escrow. C. 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. These contingent rentals are not significant. Rent expense under operating leases totaled $55 million, $57 million and $63 million for 2003, 2002 and 2001, respectively. Assets recorded under capital leases at December 31 consist of: (in millions) 2003 2002 ----------- ----------- Buildings $ 30 $ 28 Equipment and other 3 3 Less: Accumulated amortization (10) (10) ----------- ----------- $ 23 $ 21 =========== =========== Equipment and other capital lease assets were written down in conjunction with the impairments of PTC and Caronet during the third quarter of 2002 (See Note 9A). Minimum annual rental payments, excluding executory costs such as property taxes, insurance and maintenance, under long-term noncancelable leases at December 31, 2003 are: (in millions) Capital Leases Operating Leases -------------- ---------------- 2004 $ 4 $ 38 2005 4 33 2006 4 27 2007 4 22 2008 3 19 Thereafter 31 168 -------------- ---------------- $ 50 $ 307 ================ Less amount representing imputed interest (20) -------------- Present value of net minimum lease payments under capital leases $ 30 ==============
119 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. In 2003, PEC entered into a new operating lease for a building, which minimum annual rental payments are included in the table above, and for 2004 through 2008 are approximately $1 million, $4 million, $4 million, $4 million and $4 million, respectively, with $96 million thereafter. Minimum rentals receivable under noncancelable leases for 2004 through 2008 are approximately $4 million, $4 million, $7 million, $8 million and $14 million, respectively, with $51 million receivable thereafter. These rental receivable totals exclude all leases attributable to Railcar Ltd. which was sold during the first quarter of 2004 (See Note 3B). PEC and PEF are lessors of electric poles, streetlights and other facilities. Rents received are contingent upon usage and totaled $87 million, $81 million and $78 million for 2003, 2002 and 2001, respectively. D. Guarantees As a part of normal business, Progress Energy and certain subsidiaries enter into various agreements providing financial or performance assurances to third parties. Such agreements include guarantees, standby letters of credit and surety bonds. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended commercial purposes. At December 31, 2003, management does not believe conditions are likely for significant performance under the guarantees of performance issued by or on behalf of affiliates discussed herein. Guarantees at December 31, 2003, are summarized in the table below and discussed more fully in the subsequent paragraphs. (in millions) Guarantees issued on behalf of affiliates Guarantees supporting nonregulated portfolio and energy marketing activities issued by Progress Energy $ 332 Guarantees supporting nuclear decommissioning 276 Guarantee supporting power supply agreements 307 Standby letters of credit 11 Surety bonds 117 Other guarantees 1 Guarantees issued on behalf of third parties Other guarantees 13 --------- Total $ 1,057 =========
Guarantees Supporting Nonregulated Portfolio and Energy Marketing Activities Progress Energy has issued approximately $332 million of guarantees on behalf of Progress Ventures (the business unit) and its subsidiaries for obligations under tolling agreements, transmission agreements, gas agreements, construction agreements, fuel procurement agreements and trading operations. Approximately $103 million of these guarantees were issued during the year to support energy marketing activities. The majority of the marketing contracts supported by the guarantees contain language regarding downgrade events, ratings triggers, monthly netting of exposure and/or payments and offset provisions in the event of a default. Based upon current business levels at December 31, 2003, if the Company's ratings were to decline below investment grade, the Company estimates that it may have to deposit cash or provide letters of credit or other cash collateral of approximately $56 million for the benefit of the Company's counterparties to support ongoing operations within a 90-day period. Guarantees Supporting Nuclear Decommissioning In 2003, PEC determined that its external funding levels did not fully meet the nuclear decommissioning financial assurance levels required by the NRC. Therefore, PEC met the financial assurance requirements by obtaining guarantees from Progress Energy in the amount of $276 million. 120 Guarantees Supporting Power Supply Agreements On March 20, 2003, PVI entered into a definitive agreement with Williams Energy Marketing and Trading, a subsidiary of The Williams Companies, Inc., to acquire a long-term full-requirements power supply agreement at fixed prices with Jackson. The power supply agreement included a performance guarantee by Progress Energy. The transaction closed during the second quarter of 2003. The Company issued a payment and performance guarantee to Jackson related to the power supply agreement of $280 million. In the event that Progress Energy's credit ratings fall below investment grade, Progress Energy may be required to provide additional security for this guarantee in form and amount (not to exceed $280 million) acceptable to Jackson. During the third quarter of 2003, PVI entered into an agreement with Morgan Stanley Capital Group Inc. to fulfill Morgan Stanley's obligations to schedule resources and supply energy to Oglethorpe Power Corporation of Georgia through March 31, 2005. The Company issued a payment and performance guarantee to Morgan Stanley related to the power supply agreement. In the event that Progress Energy's credit ratings fall below investment grade, Progress Energy estimates that it may have to deposit cash or provide letters of credit or other cash collateral of approximately $27 million for the benefit of Morgan Stanley at December 31, 2003. Standby Letters of Credit The Company has issued $11 million of standby letters of credit to financial institutions for the benefit of third parties that have extended credit to the Company and certain subsidiaries. These letters of credit have been issued primarily for the purpose of supporting payments of trade payables, securing performance under contracts and lease obligations and self-insurance for workers' compensation. If a subsidiary does not pay amounts when due under a covered contract, the counterparty may present its claim for payment to the financial institution, which will in turn request payment from the Company. Any amounts owed by the Company's subsidiaries are reflected in the accompanying Consolidated Balance Sheets. Surety Bonds At December 31, 2003, the Company had $117 million in surety bonds purchased primarily for purposes such as providing workers' compensation coverage, obtaining licenses, permits, rights-of-way and project performance. To the extent liabilities are incurred as a result of the activities covered by the surety bonds, such liabilities are included in the accompanying Consolidated Balance Sheets. Other Guarantees The Company has other guarantees outstanding of approximately $14 million. Included in the $14 million are $13 million of guarantees issued on behalf of third parties of which $3 million is related to obligations on leasing arrangements and $10 million is in support of synthetic fuel operations at a third-party plant. The Company estimates it will have to perform under the guarantees related to the leasing agreements and as such $3 million has been accrued and is reflected in the accompanying Consolidated Balance Sheets. The remaining $1 million in affiliate guarantees is related primarily to prompt performance payments, lease obligations and other payments subject to contingencies. E. Claims and uncertainties 1. The Company is subject to federal, state and local regulations addressing hazardous and solid waste management, air and water quality and other environmental matters. Hazardous and Solid Waste Management Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. The principal regulatory agency that is responsible for a specific former manufactured gas plant (MGP) site depends largely upon the state in which the site is located. There are several MGP sites to which both electric utilities have some connection. In this regard, both electric utilities and other potentially responsible parties (PRPs) are participating in, investigating and, if necessary, remediating former MGP 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). In addition, the Company and its subsidiaries are periodically notified by 121 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. A discussion of these sites by legal entity follows. PEC There are nine former MGP sites and other sites associated with PEC that have required or are anticipated to require investigation and/or remediation costs. PEC received insurance proceeds to address costs associated with environmental liabilities related to its involvement with some MGP sites. All eligible expenses related to these are charged against a specific fund containing these proceeds. At December 31, 2003, approximately $9 million remains in this centralized fund with a related accrual of $9 million recorded for the associated expenses of environmental issues. PEC does not believe that it can provide an estimate of the reasonably possible total remediation costs beyond what is currently accrued due to the fact that investigations have not been completed at all sites. This accrual has been recorded on an undiscounted basis. PEC measures its liability for these sites based on available evidence including its experience in investigating and remediating environmentally impaired sites. The process often involves assessing and developing cost-sharing arrangements with other PRPs. PEC will accrue costs for the sites to the extent its liability is probable and the costs can be reasonably estimated. Presently, PEC cannot determine the total costs that may be incurred in connection with the remediation of any of these MGP sites. In September 2003, the Company sold NCNG to Piedmont Natural Gas Company, Inc. As part of the sales agreement, the Company retained responsibility to remediate five former NCNG MGP sites, all of which also are associated with PEC, to state standards pursuant to an Administrative Order by consent. These sites are anticipated to have investigation or remediation costs associated with them. NCNG had previously accrued approximately $2 million for probable and reasonably estimable remediation costs at these sites. These accruals have been recorded on an undiscounted basis. At the time of the sale, the liability for these costs and the related accrual was transferred to PEC. PEC does not believe it can provide an estimate of the reasonably possible total remediation costs beyond the accrual because investigations have not been completed at all sites. Therefore, PEC cannot currently determine the total costs that may be incurred in connection with the investigation and/or remediation of all sites. PEF At December 31, 2003, PEF has accrued $18 million for probable and estimable costs related to various environmental sites. Of this accrual, $12 million is for costs associated with the remediation of distribution transformers which are more fully discussed below. The remaining $6 million is related to two former MGP sites and other sites associated with PEF that have required or are anticipated to require investigation and/or remediation costs. PEF does not believe that it can provide an estimate of the reasonably possible total remediation costs beyond what is currently accrued. In 2002, PEF accrued approximately $3 million for investigation and remediation associated with distribution transformers and received approval from the FPSC for annual recovery of these environmental costs through the Environmental Cost Recovery Clause (ECRC). In September 2003, PEF accrued an additional $15 million for similar environmental costs as a result of increased sites and estimated costs per site. PEF plans to seek approval from the FPSC to recover these costs through the ECRC. As more activity occurs at these sites, PEF will assess the need to adjust the accruals. These accruals have been recorded on an undiscounted basis. PEF measures its liability for these sites based on available evidence including its experience in investigating and remediating environmentally impaired sites. This process often includes assessing and developing cost-sharing arrangements with other PRPs. Presently, PEF cannot determine the total costs that may be incurred in connection with the remediation of all sites. Florida Progress Corporation In 2001, FPC sold its Inland Marine Transportation business operated by MEMCO Barge Line, Inc. to AEP Resources, Inc. FPC established an accrual to address indemnities and retained an environmental liability associated with the transaction. FPC estimates that its contractual liability to AEP Resources, Inc., associated with Inland Marine Transportation, is $4 million at December 31, 2003 and has accrued such amount. The previous accrual of $10 million was reduced in 2003 based on a change in estimate. This accrual has been determined on an undiscounted basis. FPC measures its liability for this site based on estimable and probable remediation scenarios. The Company believes that it is not reasonably probable that additional costs, which cannot be currently estimated, will be incurred related to the environmental indemnification provision beyond the amount accrued. The Company cannot predict the outcome of this matter. 122 PEC, PEF and Fuels 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 the Company 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. The Company is also currently in the process of assessing potential costs and exposures at other environmentally impaired sites. As the assessments are developed and analyzed, the Company will accrue costs for the sites to the extent the costs are probable and can be reasonably estimated. Certain historical sites exist that are being addressed voluntarily by PVI and FPC. An immaterial accrual has been established to address investigation expenses related to these sites. The Company cannot determine the total costs that may be incurred in connection with these sites. According to current information, these future costs are not expected to be material to the Company's financial condition or results of operations. Rail Services is voluntarily addressing certain historical waste sites. An immaterial accrual has been established to address estimable costs. The Company cannot determine the total costs that may be incurred in connection with these sites. According to current information, these future costs are not expected to be material to the Company's financial condition or results of operations. Air Quality There has been and may be further proposed federal legislation requiring reductions in air emissions for NOx, SO2, carbon dioxide and mercury. Some of these proposals establish nationwide caps and emission rates over an extended period of time. This national multi-pollutant approach to air pollution control could involve significant capital 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. Control equipment that will be installed on North Carolina fossil generating facilities as part of the North Carolina legislation discussed below may address some of the issues outlined above. However, the Company cannot predict the outcome of this matter. The EPA is 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 PEC and PEF were asked to provide information to the EPA as part of this initiative and cooperated in providing the requested information. The EPA initiated civil enforcement actions against other unaffiliated utilities as part of this initiative. Some of these actions resulted in settlement agreements calling for expenditures by these unaffiliated utilities, 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 at Section 110 of the Clean Air Act addressing the regional transport of ozone (NOx SIP Call). The EPA's rule requires 23 jurisdictions, including North Carolina, South Carolina and Georgia, but not Florida, to further reduce NOx emissions in order to attain preset state NOx emission levels by May 31, 2004. PEC is currently installing controls necessary to comply with the rule. Capital expenditures to meet these measures in North and South Carolina could reach approximately $370 million, which has not been adjusted for inflation. The Company has spent approximately $258 million to date 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. In July 1997, the EPA issued final regulations establishing a new 8-hour ozone standard. In October 1999, the District of Columbia Circuit Court of Appeals ruled against the EPA with regard to the federal 8-hour ozone standard. The U.S. Supreme Court has upheld, in part, the District of Columbia Circuit Court of Appeals' decision. Designation of areas that do not attain the standard is proceeding, and further litigation and rulemaking on this and other aspects of the standard are anticipated. North Carolina adopted the federal 8-hour ozone standard and is proceeding with the implementation process. North Carolina has promulgated final regulations, which will require PEC to install NOx controls under the state's 8-hour standard. The costs of those controls are included in the $370 million cost estimate above. However, further technical analysis and rulemaking may result in a requirement for additional controls at some units. The Company cannot predict the outcome of this matter. 123 The EPA published a final rule approving petitions under Section 126 of the Clean Air Act. This rule, as originally promulgated, required certain sources to make reductions in NOx emissions by May 1, 2003. The final rule also includes a set of regulations that affect NOx emissions from sources included in the petitions. The North Carolina coal-fired 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. In April 2002, the EPA published a final rule harmonizing the 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. The EPA has approved North Carolina's NOx SIP Call rule and has indicated it will rescind the Section 126 rule in a future rulemaking. The Company expects a favorable outcome of this matter. In June 2002, legislation was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of NOx and SO2 from coal-fired power plants. Progress Energy expects its capital costs to meet these emission targets will be approximately $813 million by 2013. PEC has expended approximately $30 million of these capital costs through December 31, 2003. PEC currently has approximately 5,100 MW of coal-fired generation capacity in North Carolina that is affected by this legislation. The legislation requires the emissions reductions to be completed in phases by 2013, and applies to each utility's total system rather than setting requirements for individual power plants. The legislation also freezes the utilities' base rates for five years unless there are extraordinary events beyond the control of the utilities or unless the utilities persistently earn a return substantially in excess of the rate of return established and found reasonable by the NCUC in the utilities' last general rate case. Further, the legislation allows the utilities to recover from their retail customers the projected capital costs during the first 7 years of the ten-year compliance period beginning on January 1, 2003. The utilities must recover at least 70% of their projected capital costs during the 5-year rate freeze period. PEC has recognized $74 million in 2003. Pursuant to the law, PEC entered into an agreement with the state of North Carolina to transfer to the state all future emissions allowances it generates from overcomplying with the federal emission limits when these units are completed. The law also requires the state to undertake a study of mercury and carbon dioxide emissions in North Carolina. Operation and maintenance costs will increase due to the additional personnel, materials and general maintenance associated with the equipment. Operation and maintenance expenses are recoverable through base rates, rather than as part of this program. Progress Energy cannot predict the future regulatory interpretation, implementation or impact of this law. In 2004, a bill was introduced in the Florida legislature that would require significant reductions in NOx, SO2 and particulate emissions from certain coal, natural gas and oil-fired generating units owned or operated by investor-owned electric utilities, including PEF. The NOx and SO2 reductions would be effective beginning with calendar year 2010 and the particulate reductions would be effective beginning with calendar year 2012. Under the proposed legislation, the FPSC would be authorized to allow the utilities to recover the costs of compliance with the emission reductions over a period not greater than seven years beginning in 2005, but the utilities' rates may be frozen at 2004 levels for at least five years of the maximum recovery period. The Company cannot predict the outcome of this matter. In 1997, the EPA's Mercury Study Report and Utility Report to Congress conveyed that mercury is not a risk to the average American and expressed uncertainty about whether reductions in mercury emissions from coal-fired power plants would reduce human exposure. Nevertheless, the EPA determined in 2000 that regulation of mercury emissions from coal-fired power plants was appropriate. In 2003, the EPA proposed two alternative control plans that would limit mercury emissions from coal-fired power plants. The first, a Maximum Achievable Control Technology (MACT) standard applicable to every coal-fired plant, would require compliance in 2008. The second, a national mercury cap and trade program, would require limits to be met in two phases, 2010 and 2018. The mercury rule is expected to become final in December 2004. Achieving compliance with either proposal could involve significant capital costs which could be material to the Company's consolidated financial position or results of operations. The Company cannot predict the outcome of this matter. In conjunction with the proposed mercury rule, the EPA proposed a MACT standard to regulate nickel emissions from residual oil-fired units. The agency estimates the proposal will reduce national nickel emissions to approximately 103 tons. The rule is expected to become final in December 2004. In December 2003, the EPA released its proposed Interstate Air Quality Rule (commonly known as the Fine Particulate Transport Rule and/or the Regional Transport Rule). The EPA's proposal requires 28 jurisdictions, including North Carolina, South Carolina, Georgia and Florida, to further reduce NOx and SO2 emissions in order to attain preset state NOx and SO2 emissions levels (which have not yet been determined). The rule is expected to become final in 2004. The installation of controls necessary to comply with the rule could involve significant capital costs. 124 Water Quality As a result of the operation of certain control equipment needed to address the air quality issues outlined above, new wastewater streams will be generated at the applicable facilities. Integration of these new wastewater streams into the existing wastewater treatment processes may result in permitting, construction and treatment challenges to PEC in the immediate and extended future. After many years of litigation and settlement negotiations the EPA published regulations in February 2004 for the implementation of Section 316(b) of the Clean Water Act. The purpose of these regulations is to minimize adverse environmental impacts caused by cooling water intake structures and intake systems. Over the next several years these regulations will impact the larger base load generation facilities and may require the facilities to mitigate the effects to aquatic organisms by constructing intake modifications or undertaking other restorative activities. Substantial costs could be incurred by the facilities in order to comply with the new regulation. The Company cannot predict the outcome and impacts to the facilities at this time. The EPA has published for comment a draft Environmental Impact Statement (EIS) for surface coal mining (sometimes referred to as "mountaintop mining") and valley fills in the Appalachian coal region, where Progress Fuels currently operates a surface mine and may operate others in the future. The final EIS, when published, may affect regulations for the permitting of mines and the cost of compliance with environmental regulations. Regulatory changes for mining may also affect the cost of fuel for the PEC and PEF coal-fueled electric-generating plants. The Company cannot predict the outcome of this matter. Other Environmental Matters The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of carbon dioxide and other greenhouse gases. The United States has not adopted the Kyoto Protocol; however, a number of carbon dioxide emissions control proposals have been advanced in Congress and by the Bush administration. The Bush administration favors voluntary programs. Reductions in carbon dioxide emissions to the levels specified by the Kyoto Protocol and some legislative proposals could be materially adverse to the Company's consolidated financial position or results of operations if associated costs cannot be recovered from customers. The Company favors the voluntary program approach recommended by the administration and is evaluating options for the reduction, avoidance and sequestration of greenhouse gases. However, the Company cannot predict the outcome of this matter. 2. As required under the Nuclear Waste Policy Act of 1982, PEC and PEF each 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 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. 125 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 Federal Court of Claims. 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 the DOE. On January 14, 2004, PEC and PEF filed a complaint with the United States Court of Federal Claims against the DOE claiming that the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel by failing to accept spent nuclear fuel from various Progress Energy facilities on or before January 31, 1998. Damages due to DOE's breach will likely exceed $100 million. Similar suits have been initiated by over two dozen other utilities. In July 2002, Congress passed an override resolution to Nevada's veto of DOE's proposal to locate a permanent underground nuclear waste storage facility at Yucca Mountain, Nevada. DOE plans to submit a license application for the Yucca Mountain facility by the end of 2004. On November 5, 2003, Congressional negotiators approved $580 million for fiscal year 2004 for the Yucca Mountain project, $123 million more than the previous year. PEC and PEF cannot predict the outcome of this matter. With certain modifications and additional approval by the NRC including the installation of onsite dry storage facilities at Robinson (2005) and Brunswick (2008), PEC's spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on PEC's system through the expiration of the current operating licenses for all of PEC's nuclear generating units. PEF currently is storing spent nuclear fuel onsite in spent fuel pools. PEF is seeking renewal of the current CR3 operating license. CR3 has sufficient storage capacity in place for fuel consumed through the end of the expiration of the current license in 2016. If PEF receives approval on its CR3 operating license renewal, additional dry storage may be necessary. 3. In November of 2001, Strategic Resource Solutions Corp. (SRS) filed a claim against the San Francisco Unified School District (the District) and other defendants claiming that SRS is entitled to approximately $10 million in unpaid contract payments and delay and impact damages related to the District's $30 million contract with SRS. On March 4, 2002, the District filed a counterclaim, seeking compensatory damages and liquidated damages in excess of $120 million, for various claims, including breach of contract and demand on a performance bond. SRS has asserted defenses to the District's claims. SRS has amended its claims and asserted new claims against the District and other parties, including a former SRS employee and a former District employee. On March 13, 2003, the City Attorney and the District filed new claims in the form of a cross-complaint against SRS, Progress Energy, Inc., Progress Energy Solutions, Inc., and certain individuals, alleging fraud, false claims, violations of California statutes, and seeking compensatory damages, punitive damages, liquidated damages, treble damages, penalties, attorneys' fees and injunctive relief. The filing states that the City and the District seek "more than $300 million in damages and penalties." PEC was added as a cross-defendant later in 2003. The Company, SRS, Progress Energy Solutions, Inc. and PEC all have denied the District's allegations and cross-claims. Discovery is in progress in the matter. The case has been assigned to a judge under the Sacramento County superior court's case management rules, and the judge and the parties have been conferring on scheduling and processes to narrow or resolve issues, if possible, and to get the case ready for trial. No trial date has been set. SRS and the Company are vigorously defending and litigating all of these claims. In November 2003, PEC filed a motion to dismiss the plaintiffs' first amended complaint. The Company cannot predict the outcome of this matter, but will vigorously defend against the allegations. 126 4. On August 21, 2003, PEC was served as a co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation et al, Civil Action No. 03CP404050, in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. PEC is one of three electric utilities operating in South Carolina named in the suit. The plaintiffs are seeking damages for the alleged improper use of electric easements but have not asserted a dollar amount for their damage claims. The complaint alleges that the licensing of attachments on electric utility poles, towers and other structures to nonutility third parties or telecommunication companies for other than the electric utilities' internal use along the electric right-of-way constitutes a trespass. On September 19, 2003, PEC filed a motion to dismiss all counts of the complaint on substantive and procedural grounds. On October 6, 2003, the plaintiffs filed a motion to amend their complaint. PEC believes the amended complaint asserts the same factual allegations as are in the original complaint and also seeks money damages and injunctive relief. The court has not yet held any hearings or made any rulings in this case. PEC cannot predict the outcome of this matter, but vigorously defend against the allegations. 5. 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" (SFAS No. 5), 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. 127 INDEPENDENT AUDITORS' REPORT TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.: We have audited the accompanying consolidated balance sheets of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. and its subsidiaries (PEC) at December 31, 2003 and 2002, 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, 2003. These financial statements are the responsibility of PEC's management. Our responsibility is to express an opinion on these financial statements 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, such consolidated financial statements present fairly, in all material respects, the financial position of PEC at December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. As discussed in Notes 3F and 12A to the consolidated financial statements, in 2003, the Company adopted Statement of Financial Accounting Standards No. 143 and Derivative Implementation Group Issue C20. /s/ DELOITTE & TOUCHE LLP Raleigh, North Carolina February 20, 2004 128 CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC. CONSOLIDATED STATEMENTS of INCOME and COMPREHENSIVE INCOME Years ended December 31 (In millions) 2003 2002 2001 - -------------------------------------------------------------------------------------------------- Operating Revenues Electric $ 3,589 $ 3,539 $ 3,344 Diversified business 11 15 16 - -------------------------------------------------------------------------------------------------- Total Operating Revenues 3,600 3,554 3,360 - -------------------------------------------------------------------------------------------------- Operating Expenses Fuel used in electric generation 825 752 638 Purchased power 296 347 354 Operation and maintenance 782 802 711 Depreciation and amortization 562 524 522 Taxes other than on income 162 158 150 Diversified business 4 15 10 Impairment of diversified business long-lived assets - 101 - - -------------------------------------------------------------------------------------------------- Total Operating Expenses 2,631 2,699 2,385 - -------------------------------------------------------------------------------------------------- Operating Income 969 855 975 - -------------------------------------------------------------------------------------------------- Other Income (Expense) Interest income 6 7 14 Impairment of investments (21) (25) (157) Other, net (11) 13 (4) - -------------------------------------------------------------------------------------------------- Total Other Expense (26) (5) (147) - -------------------------------------------------------------------------------------------------- Interest Charges Interest charges 196 217 257 Allowance for borrowed funds used during construction (2) (5) (16) - -------------------------------------------------------------------------------------------------- Total Interest Charges, Net 194 212 241 - -------------------------------------------------------------------------------------------------- Income before Income Tax and Cumulative Effect of Change in Accounting Principles 749 638 587 Income Tax Expense 244 207 223 - -------------------------------------------------------------------------------------------------- Income before Cumulative Effect of Change in Accounting 505 431 364 Principles Cumulative Effect of Change in Accounting Principles, Net of Tax (23) - - - -------------------------------------------------------------------------------------------------- Net Income 482 431 364 Preferred Stock Dividend Requirement 3 3 3 - -------------------------------------------------------------------------------------------------- Earnings for Common Stock $ 479 $ 428 $ 361 - -------------------------------------------------------------------------------------------------- Comprehensive Income, Net of Tax: Net Income $ 482 $ 431 $ 364 SFAS No. 133 transition adjustment (net of tax) - - (1) Change in net unrealized losses on cash flow hedges (net of tax of ($1), $9 and $8, respectively) 3 (14) (12) Reclassification adjustment for amounts included in net income (net of tax of $0, $8 and $4, respectively) 1 11 6 Minimum pension liability adjustment (net of tax of $(47) and $47, respectively) 72 (73) - - -------------------------------------------------------------------------------------------------- Comprehensive Income $ 558 $ 355 $ 357 - --------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements. 129 CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC. CONSOLIDATED BALANCE SHEETS (In millions) December 31 ASSETS 2003 2002 - -------------------------------------------------------------------------------------------------- Utility Plant Utility plant in service $ 13,331 $ 12,680 Accumulated depreciation (5,280) (4,869) - -------------------------------------------------------------------------------------------------- Utility plant in service, net 8,051 7,811 Held for future use 5 7 Construction work in progress 306 326 Nuclear fuel, net of amortization 159 177 - -------------------------------------------------------------------------------------------------- Total Utility Plant, Net 8,521 8,321 - -------------------------------------------------------------------------------------------------- Current Assets Cash and cash equivalents 238 18 Accounts receivable 265 301 Unbilled accounts receivable 145 151 Receivables from affiliated companies 27 37 Notes receivable from affiliated companies - 50 Taxes receivable 19 55 Inventory 348 343 Deferred fuel cost 113 146 Prepayments and other current assets 63 45 - -------------------------------------------------------------------------------------------------- Total Current Assets 1,218 1,146 - -------------------------------------------------------------------------------------------------- Deferred Debits and Other Assets Regulatory assets 477 206 Nuclear decommissioning trust funds 505 423 Miscellaneous other property and investments 169 219 Other assets and deferred debits 118 90 - -------------------------------------------------------------------------------------------------- Total Deferred Debits and Other Assets 1,269 938 - -------------------------------------------------------------------------------------------------- Total Assets $ 11,008 $ 10,405 - -------------------------------------------------------------------------------------------------- Capitalization and Liabilities - -------------------------------------------------------------------------------------------------- Common Stock Equity - -------------------------------------------------------------------------------------------------- Common stock without par value, authorized 200 million shares, 160 million shares issued and outstanding at December 31 $ 1,953 $ 1,930 Unearned ESOP common stock (89) (102) Accumulated other comprehensive loss (7) (83) Retained earnings 1,380 1,344 - -------------------------------------------------------------------------------------------------- Total Common Stock Equity 3,237 3,089 Preferred Stock - Not Subject to Mandatory Redemption 59 59 Long-Term Debt 3,086 3,048 - -------------------------------------------------------------------------------------------------- Total Capitalization 6,382 6,196 - -------------------------------------------------------------------------------------------------- Current Liabilities Current portion of long-term debt 300 - Accounts payable 188 258 Payables to affiliated companies 136 99 Notes payable to affiliated companies 25 - Interest accrued 64 59 Short-term obligations 4 438 Current portion of accumulated deferred income taxes - 66 Other current liabilities 166 92 - -------------------------------------------------------------------------------------------------- Total Current Liabilities 883 1,012 - -------------------------------------------------------------------------------------------------- Deferred Credits and Other Liabilities Accumulated deferred income taxes 1,125 1,105 Accumulated deferred investment tax credits 148 159 Regulatory liabilities 1,175 8 Cost of removal - 1,488 Asset retirement obligations 932 - Other liabilities and deferred credits 363 437 - -------------------------------------------------------------------------------------------------- Total Deferred Credits and Other Liabilities 3,743 3,197 - -------------------------------------------------------------------------------------------------- Commitments and Contingencies (Note 16) - -------------------------------------------------------------------------------------------------- Total Capitalization and Liabilities $ 11,008 $ 10,405 - --------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements. 130 CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC. CONSOLIDATED STATEMENTS of CASH FLOWS Years ended December 31 (In millions) 2003 2002 2001 - ------------------------------------------------------------------------------------------------------------------- Operating Activities Net income $ 482 $ 431 $ 364 Adjustments to reconcile net income to net cash provided by operating activities: Impairment of long-lived assets and investments 21 126 157 Depreciation and amortization 660 631 616 Cumulative effect of change in accounting principles 23 - - Deferred income taxes (68) (82) (150) Investment tax credit (10) (12) (15) Deferred fuel cost (credit) 33 (15) (12) Cash provided (used) by changes in operating assets and liabilities: Accounts receivable 41 (21) 304 Inventories 4 10 (140) Prepayments and other current assets 21 (15) 22 Accounts payable (32) 20 (261) Other current liabilities 56 (2) 53 Other 27 32 47 - ------------------------------------------------------------------------------------------------------------------- Net Cash Provided by Operating Activities 1,258 1,103 985 - ------------------------------------------------------------------------------------------------------------------- Investing Activities Gross property additions (470) (624) (824) Proceeds from sale of assets and investments 26 244 - Diversified business property additions and acquisitions (1) (12) (13) Nuclear fuel additions (66) (81) (73) Net contributions to nuclear decommissioning trust (31) (31) (31) Other investing activities 1 (17) (32) - ------------------------------------------------------------------------------------------------------------------- Net Cash Used in Investing Activities (541) (521) (973) - ------------------------------------------------------------------------------------------------------------------- Financing Activities Proceeds from issuance of long-term debt 588 542 296 Net increase (decrease) in short-term obligations (437) 177 (226) Net change in intercompany notes 74 (97) 188 Retirement of long-term debt (276) (807) (135) Equity contribution from parent - - 115 Dividends paid to parent (443) (397) (256) Dividends paid on preferred stock (3) (3) (3) - ------------------------------------------------------------------------------------------------------------------- Net Cash Used in Financing Activities (497) (585) (21) - ------------------------------------------------------------------------------------------------------------------- Net Increase (Decrease) in Cash and Cash Equivalents 220 (3) (9) - ------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at Beginning of Year 18 21 30 - ------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Year $ 238 $ 18 $ 21 - ------------------------------------------------------------------------------------------------------------------- Supplemental Disclosures of Cash Flow Information Cash paid during the year - interest (net of amount capitalized) $ 184 $ 208 $ 230 income taxes (net of refunds) $ 296 $ 319 $ 395
Noncash Investing and Financing Activities o In January 2001, PEC transferred certain assets, through a noncash dividend to Progress Energy in the amount of $18 million, to Progress Energy Service Company, LLC. See Notes to Consolidated Financial Statements. 131 CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC. CONSOLIDATED STATEMENTS of RETAINED EARNINGS Years ended December 31 (In millions) 2003 2002 2001 - ---------------------------------------------------------------------------------------------- Retained Earnings at Beginning of Year $ 1,344 $ 1,313 $ 1,226 Net income 482 431 364 Preferred stock dividends at stated rates (3) (3) (3) Common stock dividends (443) (397) (274) - ---------------------------------------------------------------------------------------------- Retained Earnings at End of Year $ 1,380 $ 1,344 $ 1,313 - ---------------------------------------------------------------------------------------------- CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED) (In millions) First Quarter Second Quarter Third Quarter Fourth Quarter - ----------------------------------------------------------------------------------------------------------------- Year ended December 31, 2003 Operating revenues $ 929 $ 819 $ 1,012 $840 Operating income 256 184 294 235 Income before cumulative effect of change in accounting principles 135 89 158 123 Net income 135 89 158 100 - ----------------------------------------------------------------------------------------------------------------- Year ended December 31, 2002 Operating revenues $ 815 $ 838 $ 1,049 $ 852 Operating income 193 210 240 212 Net income 85 131 94 121
o 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. o Fourth quarter 2003 includes impairment of investments of $21 million ($13 million after-tax) (See Note 6). o Fourth quarter 2003 includes a cumulative effect for DIG Issue C20 of $38 million ($23 million after-tax) (See Note 12). o Third quarter 2002 includes impairment and other charges related to Caronet and Interpath Communications, Inc. of $133 million ($87 million, after-tax) (See Note 6). See Notes to Consolidated Financial Statements. 132 CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC. 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. Effective January 1, 2003, CP&L began doing business under the assumed name Progress Energy Carolinas, Inc (PEC). The legal name has not changed and there is no restructuring of any kind related to the name change. Through its wholly-owned subsidiaries, PEC is involved in several nonregulated business activities, the most significant of which was its telecommunications operation. PEC is a wholly-owned subsidiary of Progress Energy, Inc. (the Company or Progress Energy). The Company is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both the Company and its subsidiaries are subject to the regulatory provisions of PUHCA. In December 2003, Progress Telecommunications Corporation (PTC) and Caronet, Inc. (Caronet), both indirectly wholly-owned subsidiaries of Progress Energy, and EPIK Communications, Inc. (EPIK), a wholly-owned subsidiary of Odyssey Telecorp, Inc. (Odyssey), contributed substantially all of their assets and transferred certain liabilities to Progress Telecom, LLC (PTC LLC), a subsidiary of PTC. Subsequently, the stock of Caronet was sold to an affiliate of Odyssey for $2 million in cash and Caronet became an indirect wholly-owned subsidiary of Odyssey. No gain or loss was recognized on this transaction. B. Basis of Presentation The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) and include the activities of PEC 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 ratemaking process is probable. Unconsolidated investments in companies over which PEC 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. Certain investments in debt and equity securities that have readily determinable market values, and for which PEC does not have control, are accounted for at fair value in accordance with SFAS No. 115 "Accounting for Certain Investments in Debt and Equity Securities." Other investments are stated principally at cost. These equity and cost investments, which total approximately $35 million and $95 million at December 31, 2003 and 2002, respectively, are included as miscellaneous property and investments in the Consolidated Balance Sheets. The primary component of this balance is PEC's investments in affordable housing of $21 million and $63 million at December 31, 2003 and 2002, respectively. This decrease is primarily due to the sale of certain PEC investments in the third quarter of 2003. For a discussion of how new FASB interpretations will affect these affordable housing investments see Note 2. Certain amounts for 2002 and 2001 have been reclassified to conform to the 2003 presentation. C. Significant Accounting Policies Use of Estimates and Assumptions In preparing consolidated financial statements that conform with GAAP, 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. 133 Revenue Recognition PEC recognizes electric utility revenue 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. Revenues related to Caronet for the design and construction of wireless infrastructure were recognized upon completion of services for each completed phase of design and construction. Fuel Cost Deferrals Fuel expense includes fuel costs or recoveries that are deferred through fuel clauses established by PEC's regulators. These clauses allow PEC to recover fuel costs and portions of purchased power costs through surcharges on customer rates. Excise Taxes PEC collects from customers certain excise taxes levied by the state or local government upon the customer. PEC accounts for excise taxes on a gross basis. For the years ended December 31, 2003, 2002 and 2001, gross receipts tax and other excise taxes of approximately $81 million, $79 million and $77 million, respectively, are included in taxes other than on income on the Consolidated Statements of Income and Comprehensive Income. These approximate amounts also are included in electric operating revenues. Income Taxes Progress Energy and its affiliates file a consolidated federal income tax return. The consolidated income tax of Progress Energy is allocated to PEC in accordance with the Inter-company Income Tax Allocation Agreement (Tax Agreement). The Tax Agreement provides an allocation that recognizes positive and negative corporate taxable income. The Tax Agreement provides for an equitable method of apportioning the carry over of uncompensated tax benefits. Progress Energy tax benefits not related to acquisition interest expense are allocated to profitable subsidiaries, beginning in 2002, in accordance with a PUHCA order. Income taxes are provided as if PEC filed a separate return. Deferred income taxes have been provided for temporary differences. These occur when there are differences between the book and tax carrying amounts of assets and liabilities. Investment tax credits related to regulated operations have been deferred and are being amortized over the estimated service life of the related properties (See Note 10). Stock-Based Compensation The Company measures compensation expense for stock options as the difference between the market price of its common stock and the exercise price of the option at the grant date. The exercise price at which options are granted by the Company equals the market price at the grant date, and accordingly no compensation expense has been recognized for stock option grants. For purposes of the pro forma disclosures required by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - an Amendment of FASB Statement No. 123" (SFAS No. 148), the estimated fair value of the Company's stock options is amortized to expense over the options' vesting period. The following table illustrates the effect on net income if the fair value method had been applied to all outstanding and unvested awards in each period. (in millions) 2003 2002 2001 -------- -------- --------- Net income, as reported $ 482 $ 431 $ 364 Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects 6 5 1 -------- -------- --------- Pro forma net income $ 476 $ 426 $ 363 ======== ======== =========
Utility Plant Utility plant in service is stated at historical cost less accumulated depreciation. PEC capitalizes all construction-related direct labor and material costs of units of property as well as indirect construction costs. The cost of renewals and betterments is also capitalized. Maintenance and repairs of property, and replacements and renewals of items determined to be less than units of property, are charged to maintenance expense as incurred. The cost of units of property replaced or retired, less salvage, is charged to accumulated depreciation. Removal or disposal costs were charged to regulatory liabilities in 2003 and cost of removal in 2002. PEC follows the guidance in SFAS No. 143, "Accounting for Asset Retirement Obligations," to account for legal obligations associated with the retirement of certain tangible long-lived assets. 134 Depreciation and Amortization - Utility Plant 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 salvage (See Note 3A). The North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (SCPSC) can also grant approval to accelerate or reduce depreciation and amortization of utility assets (See Note 5B). 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 units-of-production method and charged to fuel used in electric generation in the accompanying Consolidated Statements of Income and Comprehensive Income. In PEC'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 the Federal Energy Regulatory Commission (FERC). Cash and Cash Equivalents PEC considers cash and cash equivalents to include unrestricted cash on hand, cash in banks and temporary investments purchased with a maturity of three months or less. Allowance for Doubtful Accounts PEC maintains an allowance for doubtful accounts receivable, which totaled approximately $13 million and $11 million at December 31, 2003 and 2002, respectively, and is included in accounts receivable on the Consolidated Balance Sheets. Inventory PEC accounts for inventory using the average-cost method. Regulatory Assets and Liabilities PEC's regulated operations are subject to SFAS No. 71, which allows a regulated company to record costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a nonregulated enterprise. Accordingly, PEC records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the accompanying Consolidated Balance Sheets as regulatory assets and regulatory liabilities (See Note 5A). Diversified Business Property Diversified business property is stated at cost less accumulated depreciation. If an impairment loss is recognized on an asset, the fair value becomes its new cost basis. The costs of renewals and betterments are capitalized. The cost of repairs and maintenance is charged to expense as incurred. Depreciation is computed on a straight-line basis using the estimated useful lives disclosed in Note 3B. Unamortized Debt Premiums, Discounts and Expenses Long-term debt premiums, discounts and issuance expenses for the utility 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 utility are amortized over the remaining life of the original debt using the straight-line method consistent with ratemaking treatment. Derivatives Effective January 1, 2001, PEC adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), as amended by SFAS No. 138 and SFAS No. 149. 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. During 2003, the FASB reconsidered an interpretation of SFAS No. 133. See Note 12 for the effect of the interpretation and additional information regarding risk management activities and derivative transactions. 135 Environmental The Company accrues environmental remediation liabilities when the criteria for SFAS No. 5, "Accounting for Contingencies," has been met. Environmental expenditures are expensed as incurred or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as additional information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recognized when their receipt is deemed probable (See Note 16D). Impairment of Long-lived Assets and Investments The Company reviews the recoverability of long-lived tangible and intangible assets whenever indicators exist. Examples of these indicators include current period losses, combined with a history of losses or a projection of continuing losses, or a significant decrease in the market price of a long-lived asset group. If an indicator exists, then the asset group is tested for recoverability by comparing the carrying value to the sum of undiscounted expected future cash flows directly attributable to the asset group. If the asset group is not recoverable through undiscounted cash flows, then an impairment loss is recognized for the difference between the carrying value and the fair value of the asset group. The accounting for impairment of long-lived assets is based on SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which was adopted by the Company effective January 1, 2002. Prior to the adoption of this standard, impairments were accounted for under SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (SFAS No. 121), which was superceded by SFAS No. 144. PEC reviews its investments to evaluate whether or not a decline in fair value below the carrying value is an other-than-temporary decline. PEC considers various factors, such as the investee's cash position, earnings and revenue outlook, liquidity and management's ability to raise capital in determining whether the decline is other-than-temporary. If PEC determines that an other-than-temporary decline exists in the value of its investments, it is PEC's policy to write-down these investments to fair value. See Note 6 for a discussion of impairment evaluations performed and charges taken. Subsidiary Stock Transactions Gains and losses realized as a result of common stock sales by PEC's subsidiaries are recorded in the Consolidated Statements of Income and Comprehensive Income, except for any transactions that must be credited directly to equity in accordance with the provisions of SAB No. 51, "Accounting for Sales of Stock by a Subsidiary." 2. New Accounting Standards SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" In May 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." The adoption of SFAS No. 150 did not have an impact on PEC's financial position or results of operations. EITF Issue No. 03-04, "Accounting for `Cash Balance' Pension Plans" In May 2003, the Emerging Issues Task Force (EITF) reached consensus in EITF Issue No. 03-04, "Accounting for `Cash Balance' Pension Plans" (EITF 03-04), to specifically address the accounting for certain cash balance pension plans. The consensus reached in EITF 03-04 requires certain cash balance pension plans to be accounted for as defined benefit plans. For cash balance plans described in EITF 03-04, the consensus also requires the use of the traditional unit credit method for purposes of measuring the benefit obligation and annual cost of benefits earned as opposed to the projected unit credit method. PEC has historically accounted for its cash balance plan as a defined benefit plan; however, PEC was required to adopt the measurement provisions of EITF 03-04 at its cash balance plan's measurement date of December 31, 2003. Any differences in the measurement of the obligations as a result of applying EITF 03-04 were reported as a component of actuarial gain or loss. The on-going effects of this standard are dependent on other factors that also affect the determination of actuarial gains and losses and the subsequent amortization of such gains and losses. However, the adoption of EITF 03-04 is not expected to have a material effect on PEC's results of operations or financial position. 136 SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." The statement amends and clarifies SFAS No. 133 on accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. The new guidance incorporates decisions made as part of the Derivatives Implementation Group (DIG) process, as well as decisions regarding implementation issues raised in relation to the application of the definition of a derivative. SFAS No. 149 is generally effective for contracts entered into or modified after June 30, 2003. Interpretations and implementation issues with regard to SFAS No. 149 continue to evolve. The statement had no significant impact on PEC's accounting for contracts entered into subsequent to the statement's effective date (See Note 12). Future effects, if any, on PEC's results of operations and financial condition will be dependent on the specifics of future contracts entered into with regard to guidance provided by the statement. In connection with the January 2003 FASB EITF meeting, the FASB was requested to reconsider an interpretation of SFAS No. 133 (See Note 12). FIN No. 46, "Consolidation of Variable Interest Entities" In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities - an Interpretation of ARB No. 51" (FIN No. 46). This interpretation provides guidance related to identifying variable interest entities and determining whether such entities should be consolidated. FIN No. 46 requires an enterprise to consolidate a variable interest entity when the enterprise (a) absorbs a majority of the variable interest entity's expected losses, (b) receives a majority of the entity's expected residual returns, or both, as a result of ownership, contractual or other financial interests in the entity. Prior to the effective date of FIN No. 46, entities were generally consolidated by an enterprise that had control through ownership of a majority voting interest in the entity. FIN No. 46 originally applied immediately to variable interest entities created or obtained after January 31, 2003. During 2003, PEC did not participate in the creation of, or obtain a new variable interest in, any variable interest entity. In December 2003, the FASB issued a revision to FIN No. 46 (FIN No. 46R), which modified certain requirements of FIN No. 46 and allowed for the optional deferral of the effective date of FIN No. 46R until March 31, 2004. However, entities subject to FIN No. 46 or FIN No. 46R that are deemed to be special-purpose entities (as defined in FIN No. 46R) must implement either FIN No. 46 or FIN No. 46R at December 31, 2003. PEC elected to apply FIN No. 46 to special purpose entities as of December 31, 2003. Because PEC expects additional transitional guidance to be issued, it has elected to apply FIN No. 46R to non-special-purpose entities as of March 31, 2004. PEC has investments in 14 limited partnerships accounted for under the equity method for which it may be the primary beneficiary. These partnerships invest in and operate low-income housing and historical renovation properties that qualify for federal and state tax credits. PEC has not concluded whether it is the primary beneficiary of these partnerships. These partnerships are partially funded with financing from third party lenders, which is secured by the assets of the partnerships. The creditors of the partnerships do not have recourse to PEC. At December 31, 2003, the maximum exposure to loss as a result of PEC's investments in these limited partnerships is approximately $9 million. PEC expects to complete its evaluation of these partnerships under FIN No. 46R during the first quarter of 2004. If PEC had consolidated these 14 entities at December 31, 2003, it would have recorded an increase to both total assets and total liabilities of approximately $40 million. PEC also has interests in several other variable interest entities created before January 31, 2003, for which it is not the primary beneficiary. These arrangements include equity investments in approximately 14 limited partnerships, limited liability corporations and venture capital funds, and two building leases with special-purpose entities. The aggregate maximum loss exposure at December 31, 2003 under these arrangements totals approximately $23 million. The creditors of these variable interest entities do not have recourse to the general credit of PEC in excess of the aggregate maximum loss exposure. In February 2004, PEC became aware that certain long-term purchase power and tolling contracts may be considered variable interests under FIN No. 46R. PEC has various long-term purchase power and tolling contracts with other utilities and certain qualifying facility plants. PEC believes the counterparties to these contracts are not special-purpose entities and, therefore, FIN No. 46R would not apply to these contracts until March 31, 2004. PEC has not yet completed its evaluation of these contracts to determine if the Company needs to consolidate these counterparties under FIN No. 46R and will continue to monitor developing practice in this area. 137 3. Property, Plant and Equipment A. Utility Plant The balances of utility plant in service at December 31 are listed below, with a range of depreciable lives for each: (in millions) 2003 2002 --------------- ------------- Production plant (7-33 years) $ 8,024 $ 7,630 Transmission plant (30-75 years) 1,155 1,128 Distribution plant (12-50 years) 3,538 3,345 General plant and other (8-75 years) 614 577 --------------- ------------- Utility plant in service $ 13,331 $ 12,680 =============== ============= Generally, electric utility plant, other than nuclear fuel is pledged as collateral for the first mortgage bonds of PEC (See Note 8). Allowance for funds used during construction (AFUDC) represents the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated assets. As prescribed in the regulatory uniform systems of accounts, AFUDC is charged to the cost of the plant. The equity funds portion of AFUDC is credited to other income and the borrowed funds portion is credited to interest charges. 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 composite AFUDC rate for PEC's electric utility plant was 4.0% in 2003 and 6.2% in 2002 and 2001. Depreciation provisions on utility plant, as a percent of average depreciable property other than nuclear fuel, were 2.7% in 2003 and 2002 and 2.5% in 2001. The depreciation provisions related to utility plant were $345 million, $326 million and $305 million in 2003, 2002 and 2001, respectively. In addition to utility plant depreciation provisions, depreciation and amortization expense also includes decommissioning cost provisions, asset retirement obligations (ARO) accretion, cost of removal provisions (See Note 3D) and regulatory approved expenses (See Note 5). PEC filed a new depreciation study in 2004 that provides support for reducing depreciation expense on an annual basis by approximately $45 million. The reduction is primarily attributable to assumption changes for nuclear generation, offset by increases for distribution assets. The new rates are primarily effective January 1, 2004. The amortization of nuclear fuel costs for the years ended December 31, 2003, 2002 and 2001 were $112 million, $109 million and $101 million, respectively. B. Diversified Business Property Gross diversified business property was $8 million and $10 million at December 31, 2003 and 2002, respectively. These amounts consist primarily of equipment which is being depreciated over periods ranging from 3 to 10 years. Accumulated depreciation was $1 million at December 31, 2003 and 2002. Diversified business depreciation expense was $1 million, $4 million and $6 million in 2003, 2002 and 2001, respectively. Net diversified business property is included in miscellaneous other property and investments on the Consolidated Balance Sheets. C. Joint Ownership of Generating Facilities PEC holds ownership interests in certain jointly owned generating facilities. PEC is entitled to shares of the generating capability and output of each unit equal to their respective ownership interests. PEC also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. PEC's share of expenses for the jointly owned facilities is included in the appropriate expense category. PEC's ownership interest in the jointly-owned generating facilities is listed below with related information at December 31 ($ in millions): 138 - --------------------------------------------------------------------------------------------------------- Company Ownership Plant Investment Accumulated Construction Facility Interest Depreciation Work in Progress - --------------------------------------------------------------------------------------------------------- 2003 - --------------------------------------------------------------------------------------------------------- Mayo Plant 83.83% $ 464 $ 242 $ 50 Harris Plant 83.83% 3,248 1,370 7 Brunswick Plant 81.67% 1,611 884 21 Roxboro Unit No. 4 87.06% 323 139 1 - --------------------------------------------------------------------------------------------------------- 2002 - --------------------------------------------------------------------------------------------------------- Mayo Plant 83.83% $ 464 $ 232 $ 14 Harris Plant 83.83% 3,160 1,331 6 Brunswick Plant 81.67% 1,477 811 26 Roxboro Unit No. 4 87.06% 316 134 8
In the tables above, plant investment and accumulated depreciation are not reduced by the regulatory disallowances related to the Shearon Harris Nuclear Plant (Harris Plant). D. Decommissioning and Cost of Removal Provisions Decommissioning cost provisions, which are included in depreciation and amortization expense, were $31 million in 2003, 2002 and 2001. Management believes that the decommissioning costs that have been and will be recovered through rates will be sufficient to provide for the costs of decommissioning. PEC's cost of removal provisions, which are included in deprecation and amortization expense, were $86 million, $81 million and $77 million in 2003, 2002 and 2001, respectively. These amounts represent the expense recognized for the disposal or removal of utility assets. The FASB has issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143), that changed the accounting for decommissioning and cost of removal provisions (See Note 3F). E. Insurance PEC 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, PEC 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. PEC is insured thereunder, following a twelve-week deductible period, for 52 weeks in the amount of $3 million per week at the Brunswick and Harris Plants and $2.5 million per week at the Robinson Plant. An additional 110 weeks of coverage is provided at 80% of the above weekly amounts. For the current policy period, PEC is subject to retrospective premium assessments of up to approximately $21 million with respect to the primary coverage, $25 million with respect to the decontamination, decommissioning and excess property coverage, and $14 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 United States Nuclear Regulatory Commission (NRC), PEC'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 decontaminate, before any proceeds can be used for decommissioning, plant repair or restoration. PEC is responsible to the extent losses may exceed limits of the coverage described above. 139 PEC is insured against public liability for a nuclear incident up to $10.9 billion per occurrence. Under the current provisions of the Price Anderson Act, which limits liability for accidents at nuclear power plants, PEC, 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 $300 million (currently available through commercial insurers), PEC would be subject to pro rata assessments of up to $101 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. Congress is expected to approve revisions to the Price Anderson Act during 2004 that could include increased limits and assessments per reactor owned. The final outcome of this matter cannot be predicted at this time. Under the NEIL policies, if there were multiple terrorism losses occurring within one year, 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 $300 million. The second level of coverage obtained through the assessments discussed above would continue to apply to losses exceeding $300 million and would provide coverage in excess of any diminished primary limits due to the terrorist acts. PEC self-insures its transmission and distribution lines against loss due to storm damage and other natural disasters. F. Asset Retirement Obligations SFAS No. 143 provides accounting and disclosure requirements for retirement obligations associated with long-lived assets and was adopted by the Company effective January 1, 2003. This statement requires that the present value of retirement costs for which PEC has a legal obligation be recorded as a liability with an equivalent amount added to the asset cost and depreciated over an appropriate period. The liability is then accreted over time by applying an interest method of allocation to the liability. Cumulative accretion and accumulated depreciation were recognized for the time period from the date the liability would have been recognized had the provisions of this statement been in effect to the date of adoption of this statement. Upon adoption of SFAS No. 143, PEC recorded AROs for nuclear decommissioning of irradiated plant totaling $880 million. PEC used an expected cash flow approach to measure these obligations. This amount includes accruals recorded prior to adoption totaling $491 million, which were previously recorded in cost of removal. The related asset retirement costs, net of accumulated depreciation, recorded upon adoption totaled $117 million. The cumulative effect of adoption of this statement had no impact on the net income of PEC, as the effects were offset by the establishment of a regulatory asset in the amount of $271 million, pursuant to SFAS No. 71. The regulatory asset represents the cumulative accretion and accumulated depreciation for the time period from the date the liability would have been recognized had the provisions of this statement been in effect to the date of adoption, less the amount previously recorded. The asset retirement costs related to nuclear decommissioning of irradiated plant, net of accumulated depreciation, totaled $113 million at December 31, 2003. The ongoing expense differences between SFAS No. 143 and regulatory cost recovery are being deferred to the regulatory asset. Funds set aside in PEC's nuclear decommissioning trust fund for the nuclear decommissioning liability totaled $505 million at December 31, 2003 and $423 million at December 31, 2002. Net unrealized gains on the nuclear decommissioning trust fund were included in regulatory liabilities in 2003 and cost of removal in 2002. The following table shows the changes to the asset retirement obligations during the year ended December 31, 2003: (in millions) Asset retirement obligations as of January 1, 2003 $ 880 Accretion expense 52 --------- Asset retirement obligations as of December 31, 2003 $ 932 ========= 140 Pro forma net income has not been presented for prior years because the pro forma application of SFAS No. 143 to prior years would result in pro forma net income not materially different from the actual amounts reported. PEC has identified but not recognized AROs related to electric transmission and distribution and telecommunications assets as the result of easements over property not owned by PEC. These easements are generally perpetual and only require retirement action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements as PEC intends to utilize these properties indefinitely. In the event PEC decides to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time. PEC previously recognized removal and decommissioning costs as a component of accumulated depreciation in accordance with regulatory treatment. At December 31, 2003, such costs totaling $994 million were included in regulatory liabilities on the Consolidated Balance Sheet and consist of removal costs of $927 million and removal costs for non-irradiated areas at nuclear facilities of $67 million. At December 31, 2002, such costs totaling $1,488 million were included in cost of removal on the Consolidated Balance Sheet and consist of removal costs of $877 million and decommissioning costs for both the irradiated and non-irradiated areas at nuclear facilities of $611 million. With the adoption of SFAS No. 143 in 2003, removal costs related to the irradiated areas at nuclear facilities are reported as asset retirement obligations on the 2003 Consolidated Balance Sheet. PEC filed a request with the NCUC requesting deferral of the difference between expense pursuant to SFAS No. 143 and expense as previously determined by the NCUC. The NCUC initially granted the deferral of the January 1, 2003 cumulative adjustment. During the third quarter of 2003, the NCUC issued an order allowing the deferral of the ongoing effects. In April 2003, the SCPSC approved a joint request by PEC, Duke Energy Corporation and South Carolina Electric and Gas Company for an accounting order to authorize the deferral of all cumulative and prospective effects related to the adoption of SFAS No. 143. Therefore, the actions of the NCUC and SCPSC had no impact on the income of PEC for the year ended December 31, 2003. 4. Inventory At December 31, inventory was comprised of: (in millions) 2003 2002 ------------ ------------ Fuel $ 118 $ 118 Materials and supplies 230 225 ------------ ------------ Total inventory $ 348 $ 343 ============ ============ 5. Regulatory Matters A. Regulatory Assets and Liabilities As a regulated entity, PEC is subject to the provisions of SFAS No. 71. Accordingly, PEC records certain assets and liabilities resulting from the effects of the ratemaking process which would not be recorded under GAAP for nonregulated entities. PEC'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 PEC's operations, related regulatory assets and liabilities would be eliminated unless an appropriate regulatory recovery mechanism was provided. Additionally, these factors could result in an impairment of utility plant assets as determined pursuant to SFAS No. 144 (See Note 1C). 141 At December 31, the balances of PEC's regulatory assets (liabilities) were as follows: (in millions) 2003 2002 ---- ---- Deferred fuel cost $ 113 $ 146 ---------------- --------------- Deferred impact of ARO (Note 3F) 291 - Income taxes recoverable through future rates (Note 10) 94 122 Loss on reacquired debt (Note 1C) 22 13 Storm deferral (Note 5B) 21 - Deferred DOE enrichment facilities-related costs (Note 1C) 19 25 Other 30 46 ---------------- --------------- Total long-term regulatory assets 477 206 Non-ARO cost of removal (Note 3F) (994) - Emission allowance (8) (8) Net nuclear decommissioning trust unrealized gains (Note 3F) (99) - Clean air compliance (Note 5B) (74) - ---------------- --------------- Total long-term regulatory liabilities (1,175) (8) ---------------- --------------- Net regulatory assets/(liabilities) $ (585) $ 344 ================ ===============
Except for portions of deferred fuel, all 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. The utility expects to fully recover these assets and refund the liabilities through customer rates under current regulatory practice. B. Retail Rate Matters The NCUC and SCPSC approved proposals to accelerate cost recovery of PEC's nuclear generating assets beginning January 1, 2000, and continuing through 2009. The aggregate minimum and maximum amounts of accelerated cost recovery are $530 million and $750 million, respectively. Accelerated cost recovery of these assets resulted in no additional expense in 2003 and additional depreciation expense of approximately $53 million and $75 million in 2002 and 2001, respectively. Total accelerated depreciation recorded through December 31, 2003 was $403 million. In conjunction with the acquisition of NCNG in 1999, PEC 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. The NC Clean Air Act of June 2002 (the Clean Air Act), requires state utilities to reduce emissions of nitrogen oxide (NOx) and sulfur dioxide (SO2) from coal-fired plants. The NCUC has allowed the utilities to amortize and recover the costs associated with meeting the new emission standards over a seven-year period beginning January 1, 2003. PEC recognized $74 million of clean air amortization during 2003. This legislation freezes PEC's base rates in North Carolina for five years, subject to certain conditions (See Note 16D). In conjunction with the Company's merger with Florida Progress Corporation (Florida Progress), PEC 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, $5 million in 2003, and $6 million in both 2004 and 2005. PEC obtained SCPSC and NCUC approval of fuel factors in annual fuel-adjustment proceedings. The SCPSC approved PEC's petition to leave billing rates unchanged from the prior year by order issued March 28, 2003. The NCUC approved an increase of $20 million by order issued September 25, 2003. On October 16, 2003, PEC made a filing with the NCUC to seek permission to defer expenses incurred from Hurricane Isabel and the February 2003 winter storms. As a result of rising storm costs and the frequency of major storm damage, PEC asked the NCUC to allow PEC to create a deferred account in which PEC would place expenses incurred as a result of named tropical storms, hurricanes and significant winter storms. In December 2003, the NCUC approved PEC's request to defer the costs and amortize them over a period of 5 years beginning in the month the storm occurs. PEC charged approximately $24 million in 2003 from Hurricane Isabel and from current year ice storms to the deferred account, of which $3 million was amortized during 2003. 142 PEC retains funds internally to meet decommissioning liability. The NCUC order issued February 2004 found that by January 1, 2008 PEC must begin transitioning these amounts to external funds. The transition of $131 million must be completed by December 31, 2017, and at least 10% must be transitioned each year. PEC has exclusively utilized external funding for its decommissioning liability since 1994. C. Regional Transmission Organizations and Standard Market Design In 2000, the FERC issued Order No. 2000 on RTOs, which set minimum characteristics and eight functions for transmission entities, including independent system operators (ISOs) and transmission companies that are required to become FERC-approved RTOs. As a result of Order 2000, PEC, along with Duke Energy Corporation and South Carolina Electric & Gas Company, filed and received provisional approval from the FERC for a GridSouth RTO. However, in July 2001, the FERC issued orders recommending that companies in the Southeast engage in mediation to develop a plan for a single RTO for the Southeast. PEC participated in the mediation. The FERC has not issued an order specifically on this mediation. In July 2002, the FERC issued its Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). If adopted as proposed, the rules set forth in the SMD NOPR would materially alter the manner in which transmission and generation services are provided and paid for. PEC filed comments in November 2002 and supplement comments in January 2003. In April 2003, the FERC released a White Paper on the Wholesale Market Platform. The White Paper provides an overview of what the FERC currently intends to include in a final rule in the SMD NOPR docket. The White Paper retains the fundamental and most protested aspects of SMD NOPR, including mandatory RTOs and the FERC's assertion of jurisdiction over certain aspects of retail service. The FERC has not yet issued a final rule on SMD NOPR. PEC has $33 million invested in GridSouth at December 31, 2003. Given the regulatory uncertainty of the ultimate timing, structure and operations of GridSouth, or an alternate combined transmission structure, PEC cannot predict the effect on future consolidated results of operations, cash flows or financial condition. Furthermore, the SMD NOPR presents several uncertainties, including what percentage of the investment in GridSouth will be recovered, how the elimination of transmission charges, as proposed in the SMD NOPR, will impact PEC, and what amount of capital expenditures will be necessary to create a new wholesale market. 6. Impairments of Long-Lived Assets and Investments Effective January 1, 2002, PEC adopted SFAS No. 144, which provides guidance for the accounting and reporting of impairment or disposal of long-lived assets. The statement supersedes SFAS No. 121. In 2003, 2002 and 2001, PEC recorded pre-tax long-lived asset and investment impairments and other charges of approximately $21 million, $133 million and $157 million, respectively. A. Long-Lived Assets In 2002, PEC initiated an independent valuation study to assess the recoverability of Caronet's long-lived assets. Based on this assessment, PEC recorded asset impairments of $101 million on a pre-tax basis and other charges of $7 million on a pre-tax basis in the third quarter of 2002. This write-down constituted a significant reduction in the book value of these long-lived assets. The long-lived asset impairments included an impairment of property, plant and equipment, construction work in process and intangible assets. The impairment charge represents the difference between the fair value and carrying amount of these long-lived assets. The fair value of these assets was determined using a valuation study heavily weighted on the discounted cash flow methodology, while using market approaches as supporting information. 143 B. Investments PEC continually reviews its investments to determine whether a decline in fair value below the cost basis is other than temporary. In 2003, PEC's affordable housing investment (AHI) portfolio was reviewed and deemed to be impaired based on various factors including continued operating losses of the AHI portfolio and management performance issues arising at certain properties within the AHI portfolio. As a result, PEC recorded an impairment on the AHI portfolio of $18 million on a pre-tax basis during the fourth quarter of 2003. PEC also recorded an impairment of $3 million on a cost investment. PEC obtained a valuation study to assess its investment in Interpath Communications, Inc. (Interpath) based on current valuations in the technology sector during 2001. Interpath was an application service provider business in which PEC had a 35% ownership interest. As a result of the valuation study, PEC recorded investment impairments for other-than-temporary declines in the fair value of its investment in Interpath. The investment write-down was $157 million on a pre-tax basis for the year ended December 31, 2001. In May 2002, Interpath merged with a third party and PEC's ownership was diluted to approximately 19% of Interpath. As a result, PEC reviewed the Interpath investment for impairment and wrote off the remaining amount of its cost-basis investment in Interpath, recording a pre-tax impairment of $25 million in the third quarter of 2002. In the fourth quarter of 2002, PEC sold its remaining interest in Interpath for a nominal amount. 7. Equity A. Capitalization At December 31, 2003, PEC was authorized to issue up to 200 million shares of common stock. All shares issued and outstanding are held by the Company. Preferred stock outstanding at December 31, 2003 and 2002 consisted of the following (in millions except per share and par value): Authorized - 300,000 shares, cumulative, $100 par value Preferred Stock; 20,000,000 shares, cumulative, $100 par value Serial Preferred Stock $5.00 Preferred - 236,997 shares (redemption price $110.00) $24 $4.20 Serial Preferred - 100,000 shares outstanding redemption price $102.00) 10 $5.44 Serial Preferred -249,850 shares (redemption price $101.00) 25 ------- Total Preferred Stock $59 =======
There are various provisions limiting the use of retained earnings for the payment of dividends under certain circumstances. At December 31, 2003, there were no significant restrictions on the use of retained earnings. PEC's Articles of Incorporation provide that cash dividends on common stock shall be limited to 75% of net income available for dividends if common stock equity falls below 25% of total capitalization, and to 50% if common stock equity falls below 20%. On December 31, 2003, PEC's common stock equity was approximately 50.7% of total capitalization. Refer to Note 8 for additional dividend restrictions related to PEC's mortgage. B. Stock-Based Compensation Plans 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. PEC is a participating subsidiary of 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 144 Energy common stock to satisfy 401(k) common stock 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 4.0 million and 4.6 million ESOP suspense shares at December 31, 2003 and 2002, respectively, with a fair value of $183 million and $200 million, respectively. PEC'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, with shares released from the ESOP suspense account and with newly issued shares. Costs for incentive goal compensation are accrued during the fiscal year and typically paid with shares in the following year; costs for the matching component are typically met with shares in the same year incurred. PEC's matching and incentive cost which were and will be met with shares released from the suspense account totaled approximately $11 million, $13 million and $13 million for the years ended December 31, 2003, 2002 and 2001, respectively. Matching and incentive cost totaled approximately $16 million, $14 million and $14 million for the years ended December 31, 2003, 2002 and 2001, respectively. PEC has a long-term note receivable from the 401(k) Trustee related to the purchase of common stock from PEC 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. Stock Option Agreements Pursuant to Progress Energy's 1997 Equity Incentive Plan and 2002 Equity Incentive Plan, as amended and restated as of July 10, 2002, Progress Energy may grant options to purchase shares of common stock to directors, officers and eligible employees. For the years ended December 31, 2003, 2002 and 2001, respectively, approximately 3.0 million, 2.9 million and 2.4 million common stock options were granted. Of these amounts, approximately 1.9 million, 1.2 million and 1.0 million options were granted to officers and eligible employees of PEC in 2003, 2002 and 2001, respectively. Other Stock-Based Compensation Plans Progress Energy has additional compensation plans for officers and key employees that are stock-based in whole or in part. PEC 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 and were continued under the 2002 Equity Incentive Plan, as amended and restated as of July 10, 2002. 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 and is reduced by any forfeitures. The RSA program allows the Company to grant shares of restricted common stock to officers and key employees of the Company. The restricted shares generally 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 and is reduced by any forfeitures. The total amount expensed by PEC for other stock-based compensation plans was $15 million, $11 million and $10 million in 2003, 2002 and 2001, respectively. 145 C. Accumulated Other Comprehensive Loss Components of accumulated other comprehensive loss are as follows: (in millions) 2003 2002 ------------ ----------- Loss on cash flow hedges $ (6) $ (10) Minimum pension liability adjustments (1) (73) ------------ ----------- Total accumulated other comprehensive loss $ (7) $ (83) ============ =========== 8. Debt and Credit Facilities A. Debt and Credit At December 31, PEC's long-term debt consisted of the following (maturities and weighted-average interest rates at December 31, 2003): (in millions) 2003 2002 ------------ ----------- First mortgage bonds, maturing 2004-2033 6.42% $ 1,900 $ 1,550 Pollution control obligations, maturing 2010-2024 1.69% 708 708 Unsecured notes, maturing 2012 6.50% 500 500 Medium-term notes, maturing 2008 6.65% 300 300 Miscellaneous notes - 6 Unamortized premium and discount, net (22) (16) Current portion of long-term debt (300) - ------------ ----------- Total Long-Term Debt, Net $ 3,086 $ 3,048 ============ ===========
At December 31, 2003, PEC had committed lines of credit, which are used to support its commercial paper borrowings and had no outstanding loans. PEC is required to pay minimal annual commitment fees to maintain its credit facilities. The following table summarizes PEC's credit facilities (in millions): Description Total ---------------------------------------------------------------------- 364-Day (expiring 7/29/04) $ 165 3-Year (expiring 7/31/05) 285 ----------------- $ 450 ================= At December 31, 2003 and 2002, PEC had $4 million and $438 million, 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, 2003 and 2002 were 2.25% and 1.74%, respectively. The combined aggregate maturities of long-term debt for 2004 through 2008 are approximately, in millions, $300, $300, $0, $200 and $300, respectively. B. Covenants and Default Provisions Financial Covenants PEC's credit line contains various terms and conditions that could affect PEC'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. PEC's credit line requires a maximum total debt to total capital ratio of 65%. Indebtedness as defined by the bank agreement includes certain letters of credit and guarantees which are not recorded on the Consolidated Balance Sheets. At December 31, 2003, PEC's total debt to total capital ratio was 51.4%. Material Adverse Change Clause The credit facility of PEC includes a provision under which lenders could refuse to advance funds in the event of a material adverse change in the borrower's financial condition. 146 Default Provisions PEC's credit lines include cross-default provisions for defaults of indebtedness in excess of $10 million. PEC's cross-default provisions only apply to defaults of indebtedness by PEC and its subsidiaries, respectively, and not to other affiliates of PEC. In addition, the credit lines of Progress Energy include a similar provision. Progress Energy's cross-default provisions only apply to defaults of indebtedness by Progress Energy and its significant subsidiaries, which includes PEC. The lenders may accelerate payment of any outstanding debt if cross-default provisions are triggered. Any such acceleration would cause a material adverse change in the respective company's financial condition. Certain agreements underlying PEC's indebtedness also limit PEC's ability to incur additional liens or engage in certain types of sale and leaseback transactions. Other Restrictions PEC's mortgage indenture provides that, as long as any first mortgage bonds are outstanding, cash dividends and distributions on PEC's common stock and purchases of PEC's common stock are restricted to aggregate net income available for PEC, since December 31, 1948, plus $3 million, less the amount of all preferred stock dividends and distributions, and all common stock purchases, since December 31, 1948. At December 31, 2003, none of PEC's retained earnings were restricted. Refer to Note 7 for additional dividend restrictions related to PEC's Articles of Incorporation. C. Secured Obligations PEC's first mortgage bonds are secured by their respective mortgage indentures. PEC's mortgage constitutes a first lien on substantially all of its fixed properties, subject to certain permitted encumbrances and exceptions. The PEC mortgage also constitutes a lien on subsequently acquired property. At December 31, 2003, PEC had approximately $2,608 million in first mortgage bonds outstanding including those related to pollution control obligations. The PEC mortgage allows the issuance of additional mortgage bonds upon the satisfaction of certain conditions. D. Hedging Activities PEC uses interest rate derivatives to adjust the fixed and variable rate components of its debt portfolio and to hedge cash flow risk of fixed rate debt to be issued in the future. See discussion of risk management and derivative transactions at Note 12. 9. Fair Value of Financial Instruments At December 31, 2003 and 2002, there were miscellaneous investments consisting primarily of investments in company-owned life insurance and other benefit plan assets with carrying amounts totaling approximately $59 million and $54 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. Other instruments are presented at fair value in accordance with GAAP. The carrying amount of PEC's long-term debt, including current maturities, was $3,386 million at December 31, 2003 and $3,048 million at December 31, 2002. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $3,686 million and $3,328 million at December 31, 2003 and 2002, respectively. External trust funds have been established to fund certain costs of nuclear decommissioning. 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. 10. 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. To the extent that the establishment of deferred income taxes under SFAS No. 109 is different from the recovery of taxes by PEC through the ratemaking process, the differences are deferred pursuant to SFAS No. 71. 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. 147 Net accumulated deferred income tax liabilities/(assets) at December 31 are: (in millions) 2003 2002 -------------- ------------- Accumulated depreciation and property cost differences $ 1,207 $ 1,280 Minimum pension liability (1) (47) Deferred costs, net (26) (50) Income tax credit carry forward (22) (10) Valuation allowance 1 8 Miscellaneous other temporary differences, net (50) (10) -------------- ------------- Net accumulated deferred income tax liability $ 1,109 $ 1,171 ============== =============
Total deferred income tax liabilities were $1,880 million and $1,882 million at December 31, 2003 and 2002, respectively. Total deferred income tax assets were $771 million and $711 million at December 31, 2003 and 2002, respectively. At December 31, 2003 and 2002, PEC had net non-current deferred tax liabilities of $1,125 million and $1,105 million. At December 31, 2003 PEC had a net current deferred tax asset of $16 million which is included on the Consolidated Balance Sheets under the caption prepayments and other current assets. At December 31, 2002 PEC had a net current deferred tax liability of $66 million which is included on the Consolidated Balance Sheets under the caption other current liabilities. PEC established additional valuation allowances of $1 million, $4 million and $4 million during 2003, 2002 and 2001, respectively, due to the uncertainty of realizing certain future state tax benefits. PEC had a valuation allowance of $8 million at December 31, 2002, which decreased by $7 million in 2003. The overall decrease in the 2003 valuation allowance is largely due to PEC's sale of its wholly-owned subsidiary Caronet. Caronet's valuation allowance balance at December 31, 2002 and 2001 was $8 million and $4 million, respectively. PEC believes that it is more likely than not that the results of future operations will generate sufficient taxable income to allow for the utilization of the remaining deferred tax assets. Reconciliations of PEC's effective income tax rate to the statutory federal income tax rate are: 2003 2002 2001 ------------- ------------- ------------- Effective income tax rate 32.6% 32.5% 38.0% State income taxes, net of federal benefit (1.9) (3.1) (3.2) Investment tax credit amortization 1.4 1.9 2.5 Progress Energy tax benefit allocation 3.0 5.0 - Other differences, net (0.1) (1.3) (2.3) ------------- ------------- ------------- Statutory federal income tax rate 35.0% 35.0% 35.0% ============= ============= ============= The provisions for income tax expense are comprised of: (in millions) 2003 2002 2001 ------------- ------------- --------------- Income tax expense (credit): Current - federal $ 285 $ 265 $ 349 state 37 36 39 Deferred - federal (55) (76) (140) state (13) (6) (10) Investment tax credit (10) (12) (15) ------------- ------------- --------------- Total income tax expense $ 244 $ 207 $ 223 ============= ============= ===============
PEC and each of its wholly-owned subsidiaries have entered into a Tax Agreement with Progress Energy (See Note 1C). PEC's intercompany tax receivable was $16 million and $13 million at December 31, 2003 and 2002, respectively. 148 11. Benefit Plans PEC and some of its subsidiaries have a non-contributory defined benefit retirement (pension) plan for substantially all full-time employees. PEC also has supplementary defined benefit pension plans that provide benefits to higher-level employees. In addition to pension benefits, PEC 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. PEC uses a measurement date of December 31 for its pension and OPEB plans. The components of net periodic benefit cost for the years ended December 31 are: Pension Benefits Other Postretirement Benefits --------------------------------- ----------------------------- (in millions) 2003 2002 2001 2003 2002 2001 --------------------------------- --------------------------- Service cost $ 23 $ 19 $ 17 $ 7 $ 6 $ 7 Interest cost 51 51 47 15 14 14 Expected return on plan assets (70) (73) (72) (3) (3) (4) Amortization, net - 1 (6) 5 2 5 --------------------------------- --------------------------- Net periodic cost / (benefit) $ 4 $ (2) $ (14) $ 24 $ 19 $ 22 ================================= ===========================
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 obligation or the market-related value of assets are amortized over the average remaining service period of active participants. PEC uses a five-year averaging method to determine its market-related value of assets. Reconciliations of the changes in the plans' benefit obligations and the plans' funded status are: Pension Benefits Other Postretirement Benefits ------------------------ ------------------------------ (in millions) 2003 2002 2003 2002 ------------------------ ------------------------------ Obligation at January 1 $ 802 $ 682 $ 234 $ 192 Service cost 23 19 7 6 Interest cost 51 51 15 14 Benefit payments (46) (46) (8) (9) Actuarial loss (gain) (82) 96 12 31 ------------------------ ------------------------------ Obligation at December 31 748 802 260 234 Fair value of plan assets at December 31 694 574 43 33 ------------------------ ------------------------------ Funded status (54) (228) (217) (201) Unrecognized transition obligation - - 23 26 Unrecognized prior service cost 4 4 - - Unrecognized net actuarial (gain) loss 61 238 41 38 Minimum pension liability adjustment (2) (125) - - ------------------------ ------------------------------ Prepaid (accrued) cost at December 31, net $ 9 $ (111) $ (153) $ (137) ======================== ==============================
The net prepaid pension cost of $9 million at December 31, 2003 is recognized in the accompanying Consolidated Balance Sheets as prepaid pension cost of $28 million, which is included in other assets and deferred debits, and accrued benefit cost of $19 million, which is included in other liabilities and deferred credits. The accrued pension cost at December 31, 2002 is included in other liabilities and deferred credits in the accompanying Consolidated Balance Sheets. The defined benefit pension plans with accumulated benefit obligations in excess of plan assets had projected benefit obligations totaling $22 million and $802 million at December 31, 2003 and 2002, respectively. Those plans had accumulated benefit obligations totaling $19 million and $685 million, respectively, no plan assets at December 31, 2003, and plan assets totaling $574 million at December 31, 2002. The total accumulated benefit obligation for pension plans was $745 million and $685 million at December 31, 2003 and 2002, respectively. The accrued OPEB cost is included in other liabilities and deferred credits in the accompanying Consolidated Balance Sheets. 149 A minimum pension liability adjustment of $2 million, related to the supplementary defined benefit pension plan, was recorded at December 31, 2003. This adjustment is offset by a corresponding pre-tax amount in accumulated other comprehensive loss, a component of common stock equity. Due to a combination of decreases in the fair value of plan assets and a decrease in the discount rate used to measure the pension obligation, a minimum pension liability adjustment of $125 million was recorded at December 31, 2002. This adjustment resulted in a charge of $4 million to intangible assets, included in other assets and deferred debits in the accompanying Consolidated Balance Sheets, and a pre-tax charge of $121 million to accumulated other comprehensive loss, a component of common stock equity. Reconciliations of the fair value of plan assets are: Pension Benefits Other Postretirement Benefits ---------------------------- ----------------------------- (in millions) 2003 2002 2003 2002 ---------------------------- ------------------------ Fair value of plan assets January 1 $ 574 $ 717 $ 33 $ 38 Actual return on plan assets 164 (97) 10 (5) Benefit payments (46) (46) (8) (9) Employer contributions 1 1 8 9 Transfers - (1) - - ------------ ------------ ----------- ----------- Fair value of plan assets at December 31 $ 693 $ 574 $ 43 $ 33 ============ ============ =========== ===========
In the table above, substantially all employer contributions represent benefit payments made directly from Company assets. The remaining benefits payments were made directly from plan assets. The OPEB benefit payments represent the net PEC cost after participant contributions. Participant contributions represent approximately 35% of gross benefit payments. The asset allocation for PEC's plans at the end of 2003 and 2002 and the target allocation for the plans, by asset category, are as follows: Pension Benefits Other Postretirement Benefits ------------------------------------------ --------------------------------------------- Target Percentage of Plan Assets Target Percentage of Plan Assets Allocations at Year End Allocations at Year End ------------- ------------------------ ----------------- ------------------------ Asset Category 2004 2003 2002 2004 2003 2002 ------------- ---------------------- ----------------- ---------------------- Equity - domestic 50% 49% 47% 50% 49% 47% Equity - international 15% 22% 20% 15% 22% 20% Debt - domestic 15% 11% 15% 15% 11% 15% Debt - international 10% 11% 10% 10% 11% 10% Other 10% 7% 8% 10% 7% 8% ------------- ---------------------- ----------------- ---------------------- Total 100% 100% 100% 100% 100% 100% ============= ====================== ================= ======================
PEC sets target allocations among asset classes to provide broad diversification to protect against large investment losses and excessive volatility, while recognizing the importance of offsetting the impacts of benefit cost escalation. In addition, PEC employs external investment managers who have complementary investment philosophies and approaches. Tactical shifts (plus or minus five percent) in asset allocation from the target allocations are made based on the near-term view of the risk and return tradeoffs of the asset classes. In 2004, PEC expects to make required contributions of $17 million directly to pension plan assets. The expected benefit payments for the pension benefit plan for 2004 through 2008 and in total for 2009-2013, in millions, are approximately $48, $49, $50, $53, $55 and $301, respectively. The expected benefit payments for the OPEB plan for 2004 through 2008 and in total for 2009-2013, in millions, are approximately $7, $8, $9, $10, $10 and $62, respectively. The expected benefit payments include benefit payments directly from plan assets and benefit payments directly from Company assets. The benefit payment amounts reflect the net cost to PEC after any participant contributions. 150 The following weighted-average actuarial assumptions were used in the calculation of the year-end obligation: Pension Benefits Other Postretirement Benefits ------------------------- ----------------------------- 2003 2002 2003 2002 ------------------------- ---------------------------- Discount rate 6.30% 6.60% 6.30% 6.60% Rate of increase in future compensation - non-bargaining - 4.00% - - Rate of increase in future compensation - supplementary plan 5.00% 4.00% - - Initial medical cost trend rate for pre-Medicare benefits - - 7.25% 7.50% Initial medical cost trend rate for post-Medicare benefits - - 7.25% 7.50% Ultimate medical cost trend rate - - 5.25% 5.25% Year ultimate medical cost trend rate is achieved - - 2009 2009
PEC's primary defined benefit retirement plan for non-bargaining employees is a "cash balance" pension plan as defined in EITF Issue No. 03-4. Therefore, effective December 31, 2003, PEC began to use the traditional unit credit method for purposes of measuring the benefit obligation of this plan and will use that method to measure future benefit costs. Under the traditional unit credit method, no assumptions are included about future changes in compensation and the accumulated benefit obligation and projected benefit obligation are the same. The following weighted-average actuarial assumptions were used in the calculation of the net periodic cost: Pension Benefits Other Postretirement Benefits ---------------------------- ------------------------------- 2003 2002 2001 2003 2002 2001 ---------------------------- ------------------------------- Discount rate 6.60% 7.50% 7.50% 6.60% 7.50% 7.50% Rate of increase in future compensation 4.00% 4.00% 4.00% - - - Expected long-term rate of return on plan assets 9.25% 9.25% 9.25% 9.25% 9.25% 9.25% Initial medical cost trend rate for pre-Medicare benefits - - - 7.50% 7.50% 7.50% Initial medical cost trend rate for post-Medicare benefits - - - 7.50% 7.50% 7.50% Ultimate medical cost trend rate - - - 5.25% 5.00% 5.00% Year ultimate medical cost trend rate is achieved - - - 2009 2008 2007
The expected long-term rates of return on plan assets were determined by considering long-term historical returns for the plans and long-term projected returns based on the plans' target asset allocations. Those benchmarks support an expected long-term rate of return between 9.5% and 10.0%. PEC has chosen to use an expected long-term rate of 9.25% due to the uncertainties of future returns. 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 2003 would increase by $1 million, and the OPEB obligation at December 31, 2003, would increase by $18 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 2003 would decrease by $1 million and the OPEB obligation at December 31, 2003, would decrease by $15 million. In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed into law. In accordance with guidance issued by the FASB in FASB Staff Position FAS 106-1, PEC has elected to defer accounting for the effects of the Act due to uncertainties regarding the effects of the implementation of the Act and the accounting for certain provisions of the Act. Therefore, OPEB information presented above and in the financial statements does not reflect the effects of the Act. When specific authoritative accounting guidance is issued, it could require plan sponsors to change previously reported information. PEC is in the early stages of reviewing the Act and determining its potential effects on PEC. 151 12. Risk Management Activities and Derivatives Transactions Under its risk management policy, PEC may use 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. PEC 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 PEC. A. Commodity Contracts - General Most of PEC'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. In connection with the January 2003 EITF meeting, the FASB was requested to reconsider an interpretation of SFAS No. 133. The interpretation, which was contained in the Derivative Implementation Group's C11 guidance, related to the pricing of contracts that include broad market indices (e.g., CPI). In particular, that guidance discussed whether the pricing in a contract that contains broad market indices could qualify as a normal purchase or sale (the normal purchase or sale term is a defined accounting term, and may not, in all cases, indicate whether the contract would be "normal" from an operating entity viewpoint). In June 2003, the FASB issued final superseding guidance (DIG Issue C20) on this issue. The new guidance was effective October 1, 2003 for the Company. DIG Issue C20 specifies new pricing-related criteria for qualifying as a normal purchase or sale, and it required a special transition adjustment as of October 1, 2003. PEC determined that it had one existing "normal" contract that was affected by DIG Issue C20. Pursuant to the provisions of DIG Issue C20, PEC recorded a pre-tax fair value loss transition adjustment of $38 million ($23 million after-tax) in the fourth quarter of 2003, which was recorded as a cumulative effect of a change in accounting principle. The subject contract meets the DIG Issue C20 criteria for normal purchase or sale and, therefore, was designated as a normal purchase as of October 1, 2003. The liability associated with the fair value loss will be amortized to earnings over the term of the related contract. B. Commodity Derivatives - Economic Hedges and Trading Nonhedging derivatives, primarily electricity forward contracts, are entered into for trading purposes and for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions. PEC manages open positions with strict policies that limit its exposure to market risk and require daily reporting to management of potential financial exposures. Gains and losses from such contracts were not material during 2003, 2002 or 2001, and PEC did not have material outstanding positions in such contracts at December 31, 2003 or 2002. C. Interest Rate Derivatives - Fair Value or Cash Flow Hedges PEC manages its interest rate exposure in part by maintaining its variable-rate and fixed-rate exposures within defined limits. In addition, PEC also enters into financial derivative instruments including, but not limited to, interest rate swaps and lock agreements to manage and mitigate interest rate risk exposure. PEC uses cash flow hedging strategies to hedge variable interest rates on long-term debt and to hedge interest rates with regard to future fixed-rate debt issuances. PEC held no interest rate cash flow hedges at December 31, 2003 or 2002. At December 31, 2003, $1 million of net after-tax deferred losses in accumulated other comprehensive income, related to terminated hedges, will be reclassified to earnings during the next 12 months as the hedged interest payments occur. PEC uses fair value hedging strategies to manage its exposure to fixed interest rates on long-term debt. At December 31, 2003 and 2002, PEC had no open interest rate fair value hedges. The notional amounts of interest rate derivatives 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. 152 13. Related Party Transactions PEC participates in an internal money pool, operated by Progress Energy, to more effectively utilize cash resources and to reduce outside short-term borrowings. The money pool also is used to settle intercompany balances. The weighted-average interest rate for the money pool was 1.47%, 2.18% and 4.47% at December 31, 2003, 2002 and 2001, respectively. At December 31, 2003, PEC had $25 million of amounts payable to the money pool that are included in notes payable to affiliated companies on the Consolidated Balance Sheets. At December 31, 2002, PEC had $50 million of amounts receivable from the money pool that are included in notes receivable from affiliated companies on the Consolidated Balance Sheets. PEC recorded net interest expense of approximately $1 million related to the money pool for 2003 and 2002. Net interest expense for 2001 was not significant. 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 U.S. Securities and Exchange Commission (SEC). PEC has an agreement with PESC under which services, including purchasing, information technology, telecommunications, marketing, treasury, human resources, accounting, real estate, legal and tax are rendered at cost. Amounts billed to PEC by PESC for these services during 2003, 2002 and 2001 amounted to $184 million, $198 million and $156 million, respectively. At December 31, 2003 and 2002, PEC had net payables of $118 million and $63 million, respectively, to PESC. During 2002, the Office of Public Utility Regulation within the SEC completed an audit examination of the Company's books and records. This examination is a standard process for all PUHCA registrants. Based on the review, the method for allocating PESC costs to the Company and its affiliates changed for 2003 and retroactive reallocations of 2002 and 2001 charges were made during the first quarter. The net after-tax impact of the reallocation of costs was a reduction of expenses at PEC by $10 million. The Company sold North Carolina Natural Gas Corporation (NCNG) to Piedmont Natural Gas Company, Inc. on September 30, 2003. During the years ended December 31, 2003, 2002 and 2001, gas sales from NCNG to PEC amounted to $11 million, $18 million and $15 million, respectively. The gas sales for 2003 indicated above exclude any sales subsequent to September 2003. PEC entered into a Tax Agreement with Progress Energy (See Note 10). In February 2002, PEC transferred the Rowan Plant to Progress Ventures, Inc. The property and inventory transferred totaled approximately $244 million. In August 2002, PEC transferred reservation payments for the manufacture of two combustion turbines to PEF at PEC's original cost of $20 million. 14. Financial Information by Business Segment PEC's operations consist primarily of the PEC Electric segment which is engaged in the generation, transmission, distribution and sale of electric energy primarily in portions of North Carolina and South Carolina. These electric operations are subject to the rules and regulations of the FERC, the NCUC, the SCPSC and the NRC. The Other segment, whose operations are primarily in the United States, is made up of other nonregulated business areas including telecommunications and other nonregulated subsidiaries that do not separately meet the disclosure requirements of SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" and consolidation entities and eliminations. Included are the operations of Caronet, which recognized an $87 million after-tax asset and investment impairment in 2002 and an after-tax investment impairment of $107 million in 2001. 153 (In millions) PEC Electric Other Total - ------------------------------------------------------------------------------------------------ Year Ended December 31, 2003 Revenues $ 3,589 $ 11 $ 3,600 Depreciation and amortization 562 1 563 Total interest charges, net 194 - 194 Impairment of long-lived assets & investments 11 10 21 Income taxes 240 4 244 Income before cumulative effect 515 (13) 502 Total segment assets 10,854 154 11,008 Capital and investment expenditures 470 1 471 - ------------------------------------------------------------------------------------------------ Year Ended December 31, 2002 Revenues $ 3,539 $ 15 $ 3,554 Depreciation and amortization 524 4 528 Total interest charges, net 212 - 212 Impairment of long-lived assets & investments - 126 126 Income taxes 237 (30) 207 Income before cumulative effect 513 (85) 428 Total segment assets 10,139 266 10,405 Capital and investment expenditures 624 12 636 - ------------------------------------------------------------------------------------------------ Year Ended December 31, 2001 Revenues $ 3,344 $ 16 $ 3,360 Depreciation and amortization 522 7 529 Total interest charges, net 241 - 241 Impairment of long-lived assets & investments - 157 157 Income taxes 264 (41) 223 Income before cumulative effect 468 (107) 361 Capital and investment expenditures 824 13 837 - ------------------------------------------------------------------------------------------------
15. Other Income and Other Expense Other income and expense includes interest income, gain on the sale of investments, impairment of investments and other income and expense items as discussed below. The components of other, net as shown on the Consolidated Statements of Income and Comprehensive Income for years ended December 31, are as follows: 154 (in millions) 2003 2002 2001 ---- ---- ---- Other income Net financial trading gain (loss) $ (1) $ (2) $ 3 Net energy brokered for resale gain 2 1 3 Nonregulated energy and delivery services income 8 12 12 Investment gains 9 22 2 AFUDC equity 2 6 9 Other 12 21 13 --------------------------------------- Total other income $ 32 $ 60 $ 42 --------------------------------------- Other expense Nonregulated energy and delivery services expenses $ 9 $ 14 $ 21 Donations 6 8 11 Investment losses 12 14 4 Other 16 11 10 --------------------------------------- Total other expense $ 43 $ 47 $ 46 --------------------------------------- Other, net $ (11) $ 13 $ (4) =======================================
Net financial trading gain (loss) represents non-asset-backed trades of electricity and gas. Nonregulated energy and delivery services include power protection services and mass market programs (surge protection, appliance services and area light sales) and delivery, transmission and substation work for other utilities. 16. Commitments and Contingencies A. Purchase Obligations The following table reflects PEC's contractual cash obligations and other commercial commitments in the respective periods in which they are due. (in millions) Contractual Cash Obligations 2004 2005 2006 2007 2008 Thereafter - ------------------------------------------------------------------------------------------------------- Fuel $ 433 $ 244 $ 195 $ 96 $ 33 $ 73 Purchased power 110 110 110 110 74 474 Construction Obligations 5 - - - - - Other Purchase Obligations - - - - - 13 - ------------------------------------------------------------------------------------------------------- Total $ 548 $ 354 $ 305 $ 206 $ 107 $ 560
Fuel and Purchased Power PEC has entered into various long-term contracts for coal, gas and oil requirements of its generating plants. Total payments under these commitments were $498 million, $529 million and $496 million in 2003, 2002 and 2001, respectively. Estimated annual payments for firm commitments of fuel purchases and transportation costs under these contracts are approximately $433 million, $244 million, $195 million, $96 million and $33 million for 2004 through 2008, respectively, with $73 million payable thereafter. Pursuant to the terms of the 1981 Power Coordination Agreement, as amended, between PEC and the North Carolina Eastern Municipal Power Agency (Power Agency), PEC is obligated to purchase a percentage of Power Agency's ownership capacity of, and energy from, the Harris Plant. In 1993, PEC 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, PEC 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 $36 million. These contractual purchases totaled $36 million, $36 million and $33 million for 2003, 2002 and 2001, respectively. In 1987, the NCUC ordered PEC 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, 2002, PEC had deferred purchased capacity costs, including carrying costs accrued on the deferred balances of $17 million. At December 31, 2003 all previously deferred costs have been expensed. 155 PEC 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 MW of capacity through 2009 with estimated minimum annual payments of approximately $42 million, representing capital-related capacity costs. Estimated annual payments for energy and capacity costs are approximately $70 million through 2009. Total purchases (including energy and transmission use charges) under the Rockport agreement amounted to $66 million, $59 million and $63 million for 2003, 2002 and 2001, respectively. Effective June 1, 2001, PEC 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 MW of capacity through 2021 with an original minimum annual payment of approximately $16 million, primarily representing capital-related capacity costs. A separate long-term agreement for additional power from Broad River commenced June 1, 2002. This agreement provided for the additional purchase of approximately 300 MW of capacity through 2022 with an original minimum annual payment of approximately $16 million representing capital-related capacity costs. Total purchases under the Broad River agreements amounted to $37 million, $38 million, and $21 million in 2003, 2002 and 2001 respectively. PEC has various pay-for-performance purchased power contracts with certain cogenerators (qualifying facilities) for approximately 400 MW 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 QFs' ability to generate. Payments made under these contracts were $118 million in 2003 and $145 million in 2002 and 2001. Construction Obligations PEC has purchase obligations for various combustion turbines. Total purchases under these obligations were $21 million for 2003 and $13 million for 2002. Future purchase obligations are $5 million for 2004. Other Contractual Obligations On December 31, 2002, PEC entered into a contractual commitment to purchase at least $13 million of capital parts by December 31, 2010. At December 31, 2003 no capital parts have been purchased under this contract. B. Leases PEC leases office buildings, computer equipment, vehicles, and other property and equipment with various terms and expiration dates. Rent expense under operating leases totaled $11 million, $10 million and $22 million for 2003, 2002 and 2001, respectively. Assets recorded under capital leases consist of: (in millions) 2003 2002 ---- ---- Buildings $ 30 $ 28 Less: Accumulated amortization (10) (10) ----------- ---------- $ 20 $ 18 =========== ========== 156 Minimum annual rental payments, excluding executory costs such as property taxes, insurance and maintenance, under long-term noncancelable leases at December 31, 2003 are: (in millions) Capital Leases Operating Leases -------------- ---------------- 2004 $ 2 $ 6 2005 2 9 2006 2 6 2007 2 6 2008 2 6 Thereafter 25 102 -------------- ---------------- $ 35 $ 135 ================ Less amount representing imputed interest (15) -------------- Present value of net minimum lease payments $ 20 ==============
PEC is the lessor of electric poles, streetlights and other facilities. Rents received are contingent upon usage and totaled $31 million, $28 million and $31 million for 2003, 2002 and 2001, respectively. C. Guarantees As a part of normal business, PEC enters into various agreements providing financial or performance assessments to third parties. Such agreements include, for example, guarantees, standby letters of credit and surety bonds. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended commercial purposes. At December 31, 2003, management does not believe conditions are likely for performance under these agreements. At December 31, 2003, outstanding guarantees consisted of the following: (in millions) Standby letters of credit $ 3 Surety bonds 19 ------------ Total $ 22 ============ Standby Letters of Credit PEC has issued standby letters of credit to financial institutions for the benefit of third parties that have extended credit to PEC and certain subsidiaries. These letters of credit have been issued primarily for the purpose of supporting payments of trade payables, securing performance under contracts and on interest payments on outstanding debt obligations. If a subsidiary does not pay amounts when due under a covered contract, the counterparty may present its claim for payment to the financial institution, which will in turn request payment from PEC. Any amounts owed by its subsidiaries are reflected in the Consolidated Balance Sheets. Surety Bonds At December 31, 2003, PEC had $19 million in surety bonds purchased primarily for purposes such as providing workers' compensation coverage and obtaining licenses, permits and rights-of-way. To the extent liabilities are incurred as a result of the activities covered by the surety bonds, such liabilities are included in the Consolidated Balance Sheets. Guarantees Issued by the Parent In 2003, PEC determined that its external funding levels did not fully meet the nuclear decommissioning financial assurance levels required by the NRC. Therefore, PEC obtained parent company guarantees of $276 million to meet the required levels. D. Claims and Uncertainties 1. PEC is subject to federal, state and local regulations addressing hazardous and solid waste management, air and water quality and other environmental matters. 157 Hazardous and Solid Waste Management Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. The principal regulatory agency that is responsible for a specific former manufactured gas plant (MGP) site depends largely upon the state in which the site is located. There are several MGP sites to which PEC has some connection. In this regard, PEC and other potentially responsible parties (PRPs) are participating in, investigating and, if necessary, remediating former MGP 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). In addition, PEC is periodically notified by regulators such as the EPA and various state agencies of its involvement or potential involvement in sites, other than MGP sites, that may require investigation and/or remediation. There are nine former MGP sites and other sites associated with PEC that have required or are anticipated to require investigation and/or remediation costs. PEC received insurance proceeds to address costs associated with PEC environmental liabilities related to its involvement with some MGP sites. All eligible expenses related to these are charged against a specific fund containing these proceeds. At December 31, 2003, approximately $9 million remains in this centralized fund with a related accrual of $9 million recorded for the associated expenses of environmental issues. PEC does not believe that it can provide an estimate of the reasonably possible total remediation costs beyond what is currently accrued due to the fact that investigations have not been completed at all sites. PEC measures its liability for these sites based on available evidence including its experience in investigating and remediating environmentally impaired sites. The process often involves assessing and developing cost-sharing arrangements with other PRPs. PEC will accrue costs for the sites to the extent its liability is probable and the costs can be reasonably estimated. Presently, PEC cannot determine the total costs that may be incurred in connection with the remediation of any of these MGP sites. In September 2003, the Company sold NCNG to Piedmont Natural Gas Company, Inc. As part of the sales agreement, the Company retained responsibility to remediate five former NCNG MGP sites, all of which also are associated with PEC, to state standards pursuant to an Administrative Order by consent. These sites are anticipated to have investigation or remediation costs associated with them. NCNG had previously accrued approximately $2 million for probable and reasonably estimable remediation costs at these sites. These accruals have been recorded on an undiscounted basis. At the time of the sale, the liability for these costs and the related accrual was transferred to PEC. PEC does not believe it can provide an estimate of the reasonably possible total remediation costs beyond the accrual because investigations have not been completed at all sites. Therefore, PEC cannot currently determine the total costs that may be incurred in connection with the investigation and/or remediation of all sites. PEC has filed claims with its general liability insurance carriers to recover costs arising out of actual or potential environmental liabilities. All claims have settled other than with insolvent carriers. These settlements have not had a material effect on the consolidated financial position or results of operations. PEC is also currently in the process of assessing potential costs and exposures at other environmentally impaired sites. As the assessments are developed and analyzed, PEC will accrue costs for the sites to the extent the costs are probable and can be reasonably estimated. Air Quality There has been and may be further proposed federal legislation requiring reductions in air emissions for NOx, SO2, carbon dioxide and mercury. Some of these proposals establish nation-wide caps and emission rates over an extended period of time. This national multi-pollutant approach to air pollution control could involve significant capital costs which could be material to PEC's consolidated financial position or results of operations. Some companies may seek recovery of the related cost through rate adjustments or similar mechanisms. Control equipment that will be installed on North Carolina fossil generating facilities as part of the North Carolina legislation discussed below may address some of the issues outlined above. However, PEC cannot predict the outcome of this matter. 158 The EPA is 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. PEC was asked to provide information to the EPA as part of this initiative and cooperated in providing the requested information. The EPA initiated civil enforcement actions against other unaffiliated utilities as part of this initiative. Some of these actions resulted in settlement agreements calling for expenditures by these unaffiliated utilities, 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. PEC cannot predict the outcome of this matter. In 1998, the EPA published a final rule at Section 110 of the Clean Air Act addressing the regional transport of ozone (NOx SIP Call). The EPA's rule requires 23 jurisdictions, including North Carolina, South Carolina and Georgia, to further reduce NOx emissions in order to attain a pre-set state NOx (NOx) emission level by May 31, 2004. PEC is currently installing controls necessary to comply with the rule. Capital expenditures to meet these measures in North and South Carolina could reach approximately $370 million, which has not been adjusted for inflation. PEC has spent approximately $258 million to date related to these expenditures. Increased operation and maintenance costs relating to the NOx SIP Call are not expected to be material to PEC's results of operations. Further controls are anticipated as electricity demand increases. PEC cannot predict the outcome of this matter. In July 1997, the EPA issued final regulations establishing a new 8-hour ozone standard. In October 1999, the District of Columbia Circuit Court of Appeals ruled against the EPA with regard to the federal 8-hour ozone standard. The U.S. Supreme Court has upheld, in part, the District of Columbia Circuit Court of Appeals decision. Designation of areas that do not attain the standard is proceeding, and further litigation and rulemaking on this and other aspects of the standard are anticipated. North Carolina adopted the federal 8-hour ozone standard and is proceeding with the implementation process. North Carolina has promulgated final regulations, which will require PEC to install NOx controls under the State's 8-hour standard. The costs of those controls are included in the $370 million cost estimate above. However, further technical analysis and rulemaking may result in a requirement for additional controls at some units. PEC cannot predict the outcome of this matter. The EPA published a final rule approving petitions under Section 126 of the Clean Air Act. This rule as originally promulgated required certain sources to make reductions in NOx emissions by May 1, 2003. The final rule also includes a set of regulations that affect NOx emissions from sources included in the petitions. The North Carolina coal-fired 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. PEC, 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 NOx 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 PEC 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 April 30, 2002, the EPA published a final rule harmonizing the dates for the Section 126 Rule and the NOx SIP Call. In addition, the EPA determined in this rule that the future growth factor estimation methodology was appropriate. The new compliance date for all affected sources is now May 31, 2004, rather than May 1, 2003. The EPA has approved North Carolina's NOx SIP Call rule and has indicated it will rescind the Section 126 rule in a future rulemaking. PEC expects a favorable outcome of this matter. In June 2002, legislation was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of NOx and SO2 from coal-fired power plants. PEC expects its capital costs to meet these emission targets will be approximately $813 million by 2013. PEC has expended approximately $30 million of these capital costs through December 31, 2003. PEC currently has approximately 5,100 MW of coal-fired generation in North Carolina that is affected by this legislation. The legislation requires the emissions reductions to be completed in phases by 2013, and applies to each utility's total system rather than setting requirements for individual power plants. The legislation also freezes the utilities' base rates for five years unless there are extraordinary events beyond the control of the utilities or unless the utilities persistently earn a return substantially in excess of the rate of return established and found reasonable by the NCUC in the utilities' last general rate case. Further, the legislation allows the utilities to recover from their retail customers the projected capital costs during the first seven years of the 10-year compliance period beginning on January 1, 2003. The utilities must recover 159 at least 70% of their projected capital costs during the five-year rate freeze period. Pursuant to the law, PEC entered into an agreement with the state of North Carolina to transfer to the state all future emissions allowances it generates from over-complying with the federal emission limits when these units are completed. The law also requires the state to undertake a study of mercury and carbon dioxide emissions in North Carolina. Operation and maintenance costs will increase due to the additional personnel, materials and general maintenance associated with the equipment. Operation and maintenance expenses are recoverable through base rates, rather than as part of this program. PEC cannot predict the future regulatory interpretation, implementation or impact of this law. In 1997, the EPA's Mercury Study Report and Utility Report to Congress conveyed that mercury is not a risk to the average American and expressed uncertainty about whether reductions in mercury emissions from coal-fired power plants would reduce human exposure. Nevertheless, EPA determined in 2000 that regulation of mercury emissions from coal-fired power plants was appropriate. In 2003, the EPA proposed two alternative control plans that would limit mercury emissions from coal-fired power plants. The first, a Maximum Available Control Technology (MACT) standard applicable to every coal-fired plant, would require compliance in 2008. The second, a national mercury cap and trade program, would require limits to be met in two phases, 2010 and 2018. The mercury rule is expected to become final in December 2004. Achieving compliance with either proposal could involve significant capital costs which could be material to PEC's consolidated financial position or results of operations. PEC cannot predict the outcome of this matter. In conjunction with the proposed mercury rule, the EPA proposed to regulate nickel emissions from residual oil-fired units. The agency estimates the proposal will reduce national nickel emissions to approximately 103 tons. The rule is expected to become final in December 2004. In December 2003, the EPA released its proposed Interstate Air Quality Rule (commonly known as the Fine Particulate Transport Rule and/or the Regional Transport Rule). The EPA's proposal requires 28 jurisdictions, including North Carolina, South Carolina, Georgia and Florida, to further reduce NOx and SO2 emissions in order to attain pre-set NOx and SO2 emissions levels (which have not yet been determined). The rule is expected to become final in 2004. The installation of controls necessary to comply with the rule could involve significant capital costs. Water Quality As a result of the operation of certain control equipment needed to address the air quality issues outlined above, new wastewater streams will be generated at the applicable facilities. Integration of these new wastewater streams into the existing wastewater treatment processes may result in permitting, construction and treatment challenges to PEC in the immediate and extended future. After many years of litigation and settlement negotiations the EPA published regulations in February 2004 for the implementation of Section 316(b) of the Clean Water Act. The purpose of these regulations is to minimize adverse environmental impacts caused by cooling water intake structures and intake systems. Over the next several years these regulations will impact the larger base load generation facilities and may require the facilities to mitigate the effects to aquatic organisms by constructing intake modifications or undertaking other restorative activities. Substantial costs could be incurred by the facilities in order to comply with the new regulation. The Company cannot predict the outcome and impacts to the facilities at this time. Other Environmental Matters The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of carbon dioxide and other greenhouse gases. The United States has not adopted the Kyoto Protocol, however, a number of carbon dioxide emissions control proposals have been advanced in Congress and by the Bush administration. The Bush administration favors voluntary programs. Reductions in carbon dioxide emissions to the levels specified by the Kyoto Protocol and some legislative proposals could be materially adverse to PEC's consolidated financial position or results of operations if associated costs cannot be recovered from customers. PEC favors the voluntary program approach recommended by the administration and is evaluating options for the reduction, avoidance, and sequestration of greenhouse gases. However, PEC cannot predict the outcome of this matter. 2. As required under the Nuclear Waste Policy Act of 1982, PEC 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. 160 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 its 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 Federal Court of Claims. 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. On January 14, 2004, PEC filed a complaint with the United States Court of Federal Claims against the United States of America (Department of Energy) claiming that the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel by failing to accept spent nuclear fuel from various Progress Energy facilities on or before January 31, 1998. Damages due to DOE's breach will likely exceed $100 million. Similar suits have been initiated by over two dozen other utilities. In July 2002, Congress passed an override resolution to Nevada's veto of DOE's proposal to locate a permanent underground nuclear waste storage facility at Yucca Mountain, Nevada. DOE plans to submit a license application for the Yucca Mountain facility by the end of 2004. On November 5, 2003, Congressional negotiators approved $580 million for fiscal year 2004 for the Yucca Mountain project, $123 million more than the previous year. PEC cannot predict the outcome of this matter. With certain modifications and additional approval by the NRC, PEC'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. PEC obtained NRC approval in December 2000 to use additional storage space at the Harris Plant. 3. In August 2003, PEC was served as a co-defendant in a purported class action lawsuit styled as Collins v. Duke Energy Corporation et al, Civil action No. 03CP404050, in South Carolina's Circuit Court of Common Pleas for the Fifth Judicial Circuit. PEC is one of three electric utilities operating in South Carolina named in the suit. The plaintiffs are seeking damages for the alleged improper use of electric easements but have not asserted a dollar amount for their damage claims. The complaint alleges that the licensing of attachments on electric utility poles, towers and other structures to non-utility third parties or telecommunication companies for other than the electric utilities' internal use along the electric right-of-way constitutes a trespass. In September 2003, PEC filed a motion to dismiss all counts of the complaint on substantive and procedural grounds. In October 2003, the plaintiffs filed a motion to amend their complaint. PEC believes the amended complaint asserts the same factual allegations as are in the original complaint and also seeks money damages and injunctive relief. The court has not yet held any hearings or made any rulings in this case. In November 2003, PEC filed a motion to dismiss the plaintiffs' first amended complaint. PEC cannot predict the outcome of the outcome of this matter, but will vigorously defend against the allegations. 161 4. PEC 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 PEC's consolidated results of operations or financial position. 162 INDEPENDENT AUDITORS' REPORT TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.: We have audited the consolidated balance sheets of Progress Energy, Inc. and its subsidiaries at December 31, 2003 and 2002, 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, 2003 and have issued our report thereon dated February 20, 2004 (which expresses an unqualified opinion and includes an explanatory paragraph concerning the adoption of new accounting principles in 2003 and 2002); such consolidated financial statements and report are included herein. Our audits also included the consolidated financial statement schedule of the Company, listed in Item 8. This consolidated financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic 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 20, 2004 163 INDEPENDENT AUDITORS' REPORT TO THE BOARD OF DIRECTORS AND SHAREHOLDER OF CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.: We have audited the consolidated balance sheets of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. and its subsidiaries (PEC) at December 31, 2003 and 2002, 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, 2003 and have issued our report thereon dated February 20, 2004 (which express an unqualified opinion and includes an explanatory paragraph concerning the adoption of new accounting principles in 2003); such consolidated financial statements and report are included herein. Our audits also included the consolidated financial statement schedule of PEC listed in Item 8. This consolidated financial statement schedule is the responsibility of PEC's management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic 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 20, 2004 164 PROGRESS ENERGY, INC. Schedule II - Valuation and Qualifying Accounts For the Years Ended December 31, 2003, 2002 and 2001 Balance at Additions Balance at Beginning Charged to Other End of Description of Period Expenses Additions Deductions Period - ------------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 2003 Uncollectible accounts $ 40 $ 26 $ - $ (38) (a) $ 28 Fossil dismantlement reserve 142 1 - - 143 Nuclear refueling outage reserve 10 8 - (16) (b) 2 Year Ended December 31, 2002 Uncollectible accounts $ 39 $ 15 $ - $ (14) (a) $ 40 Fossil dismantlement reserve 141 1 - - 142 Nuclear refueling outage reserve - 10 - - 10 Year Ended December 31, 2001 Uncollectible accounts $ 26 $ 12 $ 20 (c) $ (19) (a) $ 39 Fossil dismantlement reserve 135 6 - - 141 Nuclear refueling outage reserve 11 17 - (28) (b) - (a) Represents write-off of uncollectible accounts, net of recoveries. (b) Represents payments of actual expenditures related to the outages. (c) Represents the reclassification of Rail Services' uncollectible accounts from Net Assets Held for Sale. - --------------------------------------------------------------------------------------------------------------------------
165 CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS Schedule II - Valuation and Qualifying Accounts For the Years Ended December 31, 2003, 2002 and 2001 Balance at Additions Balance at Beginning Charged to Other End of Description of Period Expense Additions Deductions Period - ---------------------------------------------------------------------------------------------------------------------- Year Ended December 31, 2003 Uncollectible accounts $ 11 $ 12 $ - $ (10) (a) $ 13 Year Ended December 31, 2002 Uncollectible accounts $ 12 $ 8 $ - $ (9) (a) $ 11 Year Ended December 31, 2001 Uncollectible accounts $ 17 $ 4 $ - $ (9) (a) $ 12 (a) Represents write-off of uncollectible accounts, net of recoveries. - --------------------------------------------------------------------------------------------------------------------------
166 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None ITEM 9A. CONTROLS AND PROCEDURES Progress Energy, Inc. Pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934, Progress Energy carried out an evaluation, with the participation of its management, including Progress Energy's Chairman and Chief Executive Officer and Chief Financial Officer, of the effectiveness of Progress Energy's disclosure controls and procedures (as defined under Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, Progress Energy's Chief Executive Officer and Chief Financial Officer concluded that its disclosure controls and procedures are effective in timely alerting them to material information relating to Progress Energy (including its consolidated subsidiaries) required to be included in its periodic SEC filings. There has been no change in Progress Energy's internal control over financial reporting during the quarter ended December 31, 2003 that has materially affected, or is reasonably likely to materially affect its internal control over financial reporting. Progress Energy Carolinas, Inc. Pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934, PEC carried out an evaluation, with the participation of its management, including PEC's Chairman and Chief Executive Officer and Chief Financial Officer, of the effectiveness of PEC's disclosure controls and procedures (as defined under Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, PEC's Chief Executive Officer and Chief Financial Officer concluded that its disclosure controls and procedures are effective in timely alerting them to material information relating to PEC (including its consolidated subsidiaries) required to be included in its periodic SEC filings. There has been no change in PEC's internal control over financial reporting during the quarter ended December 31, 2003 that has materially affected, or is reasonably likely to materially affect its internal control over financial reporting. 167 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT a) Information on Progress Energy, Inc.'s directors is set forth in the Progress Energy 2003 definitive proxy statement dated March 31, 2004, and incorporated by reference herein. Information on PEC's directors is set forth in the PEC 2003 definitive proxy statement dated March 31, 2004, and incorporated by reference herein. b) Information on both Progress Energy's and PEC's executive officers is set forth in PART I and incorporated by reference herein. c) The Company has adopted a Code of Ethics that applies to all of its employees, including its Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer and Controller (or persons performing similar functions). The Company's Board of Directors has adopted the Company's Code of Ethics as its own standard. Board members, Company officers and Company employees certify their compliance with the Code of Ethics on an annual basis. The Company's Code of Ethics is posted on its Internet website and can be accessed at www.progress-energy.com and is available in print to any shareholder upon request by writing to Progress Energy, Inc. The Company intends to satisfy the disclosure requirement under Item 10 of Form 8-K relating to amendments to or waivers from any provision of the Code of Ethics applicable to the Company's CEO, CFO, CAO and Controller by posting such information on its Internet website, www.progress-energy.com. d) The Board of Directors has determined that David L. Burner and Carlos A. Saladrigas are the "Audit Committee Financial Experts" as that term is defined in the rules promulgated by the Securities and Exchange Commission pursuant to the Sarbanes-Oxley Act of 2002, and have designated them as such. Both Mr. Burner and Mr. Saladrigas are "independent" as that term is defined in the general independence standards of the New York Stock Exchange listing standards. e) The following are available on the Company's website and in print: o Audit Committee Charter o Corporate Governance Committee Charter o Organization and Compensation Committee Charter o Corporate Governance Guidelines ITEM 11. EXECUTIVE COMPENSATION Information on Progress Energy's executive compensation is set forth in the Progress Energy 2003 definitive proxy statement dated March 31, 2004, and incorporated by reference herein. Information on PEC's executive compensation is set forth in the PEC 2003 definitive proxy statement dated March 31, 2004, and incorporated by reference herein. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT a) Information regarding any person Progress Energy knows to be the beneficial owner of more than five (5%) percent of any class of its voting securities is set forth in its 2003 definitive proxy statement, dated March 31, 2004, and incorporated herein by reference. Information regarding any person PEC knows to be the beneficial owner of more than five (5%) percent of any class of its voting securities is set forth in its 2003 definitive proxy statement, dated March 31, 2004, and incorporated herein by reference. b) Information on security ownership of the Progress Energy's and PEC's management is set forth in the Progress Energy and PEC 2003 definitive proxy statements dated March 31, 2004, and incorporated by reference herein. 168 c) Information on the equity compensation plans of Progress Energy is set forth under the heading "Equity Compensation Plan Information" in the Progress Energy 2003 definitive proxy statement dated March 31, 2004 and incorporated by reference herein. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Information on certain relationships and related transactions is set forth in the Progress Energy and PEC 2003 definitive proxy statements dated March 31, 2004, and incorporated by reference herein. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES Information regarding principal accountant fees and services is set forth in the Progress Energy and PEC 2003 definitive proxy statements dated March 31, 2004, and incorporated by reference herein. 169 PART IV ITEM 15. 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 or furnished during or with respect to the last quarter of 2003 and the portion of the first quarter of 2004 prior to the filing of this Form 10-K: Progress Energy, Inc. Financial Item Statements Reported Included Date of Event Date Filed -------- -------- ------------- ---------- 12 Yes February 26, 2004 February 26, 2004 5 No February 24, 2004 February 24, 2004 5 No January 23, 2004 January 23, 2004 9, 12 Yes January 21, 2004 January 21, 2004 7, 9 Yes December 1, 2003 December 1, 2003 9, 12 Yes October 22, 2003 October 22, 2003 Progress Energy Carolinas, Inc. Financial Item Statements Reported Included Date of Event Date Filed -------- -------- ------------- ---------- 12 Yes February 26, 2004 February 26, 2004 5 No January 23, 2004 January 23, 2004 9, 12 Yes January 21, 2004 January 21, 2004 9, 12 Yes October 22, 2003 October 22, 2003
170 PROGRESS ENERGY, INC. RISK FACTORS In this section, unless the context indicates otherwise, references to "our," "we," "us" or similar terms refer to Progress Energy, Inc. and its consolidated subsidiaries. Investing in our securities involves risks, including the risks described below, that could affect the energy industry, as well as us and our business. Although we have tried to discuss key factors, please be aware that other risks may prove to be important in the future. New risks may emerge at any time and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Before purchasing our securities, you should carefully consider the following risks and the other information in this Annual Report, as well as the documents we file with the SEC from time to time. Each of the risks described below could result in a decrease in the value of our securities and your investment therein. Risks Related to the Energy Industry We are subject to fluid and complex government regulations that may have a negative impact on our business and our results of operations. We are subject to comprehensive regulation by several federal, state and local regulatory agencies, which significantly influence our operating environment and may affect our ability to recover costs from utility customers. We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations. The 108th Congress spent much of 2003 working on a comprehensive energy bill. While that legislation passed the House, the Senate failed to pass the legislation in 2003. There will probably be an effort to resurrect the legislation in 2004. The legislation would have further clarified the Federal Energy Regulatory Commission's (FERC) role with respect to Standard Market Design and mandatory Regional Transmission Organizations (RTOs) and would have repealed PUHCA. The Company cannot predict the outcome of this matter. The Federal Energy Regulatory Commission ("FERC"), the U.S. Nuclear Regulatory Commission ("NRC"), the U.S. Environmental Protection Agency ("EPA"), the North Carolina Utilities Commission ("NCUC"), the Florida Public Service Commission ("FPSC"), and the Public Service Commission of South Carolina ("SCPSC") regulate many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers. Our system is also subject to the jurisdiction of the SEC under the Public Utility Holding Company Act of 1935 ("PUHCA"). The rules and regulations promulgated under PUHCA impose a number of restrictions on the operations of registered utility holding companies and their subsidiaries. These restrictions include a requirement that, subject to a number of exceptions, the SEC approve in advance securities issuances, acquisitions and dispositions of utility assets or of securities of utility companies, and acquisitions of other businesses. PUHCA also generally limits the operations of a registered holding company like ours to a single integrated public utility system, plus additional energy-related businesses. Furthermore, PUHCA rules require that transactions between affiliated companies in a registered holding company system be performed at cost, with limited exceptions. We are unable to predict the impact on our business and operating results from future regulatory activities of these federal, state and local agencies. Changes in regulations or the imposition of additional regulations could have a negative impact on our business and results of operations. We are subject to numerous environmental laws and regulations that may increase our cost of operations, impact or limit our business plans, or expose us to environmental liabilities. We are subject to numerous environmental regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations can result in increased capital, operating, and other costs, particularly with regard to enforcement efforts focused on power plant emissions obligations. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. We cannot predict the outcome (financial or operational) of any related litigation that may arise. 171 In addition, we may be a responsible party for environmental clean up at sites identified by a regulatory body. We cannot predict with certainty the amount or timing of all future expenditures related to environmental matters because of the difficulty of estimating clean up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all PRPs. We cannot assure you that existing environmental regulations will not be revised or that new regulations seeking to protect the environment will not be adopted or become applicable to us. Revised or additional regulations, which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our results of operations. The uncertain outcome regarding the timing, creation and structure of regional transmission organizations, or RTOs, may materially impact our results of operations, cash flows or financial condition. Congress, FERC, and the state utility regulators have paid significant attention in recent years to transmission issues, including the possibility of regional transmission organizations. While these deliberations have not yet resulted in significant changes to our utilities' transmission operations, they cast uncertainty over those operations, which constitute a material portion of our assets. For the last several years, the FERC has supported independent RTOs and has indicated a belief that it has the authority to order transmission-owning utilities to transfer operational control of their transmission assets to such RTOs. Many state regulators, including most regulators in the Southeast, have expressed skepticism over the potential benefits of RTOs and generally disagree with the FERC's interpretation of its authority to mandate RTOs. In addition, in July 2002, the FERC issued its Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design ("SMD NOPR"). The proposed rules set forth in the SMD NOPR would require, among other things, that 1) all transmission owning utilities transfer control of their transmission facilities to an independent third party; 2) transmission service to bundled retail customers be provided under the FERC-regulated transmission tariff, rather than state-mandated terms and conditions; 3) new terms and conditions for transmission service be adopted nationwide, including new provisions for pricing transmission in the event of transmission congestion; 4) new energy markets be established for the buying and selling of electric energy; and 5) load-serving entities (LSEs) be required to meet minimum criteria for generating reserves. If adopted as proposed, the rules set forth in the SMD NOPR would materially alter the manner in which transmission and generation services are provided and paid for. We filed comments in November 2002 and supplemental comments in January 2003. The FERC has not yet issued a final rule on SMD. Furthermore, the SMD NOPR presents several uncertainties, including what percentage of our investments in GridSouth and GridFlorida will be recovered, how the elimination of transmission charges, as proposed in the SMD NOPR, will impact us, and what amount of capital expenditures will be necessary to create a new wholesale market. To date, our electric utilities have responded as follows: o PEC and other investor-owned utilities filed applications with the FERC, the NCUC and the SCPSC for approval of an RTO, currently named GridSouth. However, PEC and the other GridSouth participants withdrew their RTO application before the NCUC and the SCPSC pending the review of the FERC's SMD NOPR. A determination about refiling will be made at a later date. o PEF and other investor-owned utilities filed applications with the FERC and the FPSC for approval of an RTO, currently named GridFlorida. The FERC provisionally approved the structure and governance of GridFlorida. The FPSC's most recent order in December 2003 ordered further state proceedings. The actual structure of GridSouth, GridFlorida or any alternative combined transmission structure, as well as the date it may become operational, depends upon the resolution of all regulatory approvals and technical issues. Given the regulatory uncertainty of the ultimate timing, structure and operations of GridSouth, GridFlorida or an alternate combined transmission structure, we cannot predict whether their creation will have any material adverse effect on our future consolidated results of operations, cash flows or financial condition. Since weather conditions directly influence the demand for and cost of providing electricity, our results of operations, financial condition, cash flows and ability to pay dividends on our common stock can fluctuate on a seasonal or quarterly basis and can be negatively affected by changes in weather conditions and severe weather. 172 Our results of operations, financial condition, cash flows and ability to pay dividends on our common stock may be affected by changing weather conditions. Weather conditions in our service territories, primarily North Carolina, South Carolina, and Florida, directly influence the demand for electricity affect the price of energy commodities necessary to provide electricity to our customers and energy commodities that our nonregulated businesses sell. Electric power demand is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. As a result, our overall operating results in the future may fluctuate substantially on a seasonal basis. The pattern of this fluctuation may change depending on the nature and location of facilities we acquire and the terms of power sale contracts into which we enter. In addition, we have historically sold less power, and consequently earned less income, when weather conditions are milder. While we believe that our North Carolina, South Carolina, and Florida markets complement each other during normal seasonal fluctuations, unusually mild weather could diminish our results of operations and harm our financial condition. Furthermore, severe weather in these states, such as hurricanes, tornadoes, severe thunderstorms and snow and ice storms, can be destructive, causing outages, downed power lines and property damage, requiring us to incur additional and unexpected expenses and causing us to lose generating revenues. Our revenues, operating results and financial condition may fluctuate with the economy and its corresponding impact on our commercial and industrial customers. Our business is impacted by fluctuations in the macroeconomy. For the year ended December 31, 2003, commercial and industrial customers represented approximately 37% of our electric revenues. As a result, changes in the macroeconomy can have negative impacts on our revenues. As our commercial and industrial customers experience economic hardships, our revenues can be negatively impacted. In North and South Carolina, sales to industrial customers have been affected by downturns in the textile and chemical industries. Deregulation or restructuring in the electric industry may result in increased competition and unrecovered costs that could adversely affect the financial condition, results of operations or cash flows of us and our utilities' businesses. Increased competition resulting from deregulation or restructuring efforts could have a significant adverse financial impact on us and our utility subsidiaries and consequently on our results of operations and cash flows. Increased competition could also result in increased pressure to lower costs, including the cost of electricity. Retail competition and the unbundling of regulated energy and gas service could have a significant adverse financial impact on us and our subsidiaries due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital. Because we have not previously operated in a competitive retail environment, we cannot predict the extent and timing of entry by additional competitors into the electric markets. Due to several factors, however, there currently is little discussion of any movement toward deregulation in North Carolina, South Carolina and Florida. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impact of these changes on our financial condition, results of operations or cash flows. Risks Related to Us and Our Business As a holding company, we are dependent on upstream cash flows from our subsidiaries. As a result, our ability to meet our ongoing and future financial obligations and to pay dividends on our common stock is primarily dependent on the earnings and cash flows of our operating subsidiaries and their ability to pay upstream dividends or to repay funds to us. We are a holding company. As such, we have no operations of our own. Our ability to meet our financial obligations and to pay dividends on our common stock at the current rate is primarily dependent on the earnings and cash flows of our operating subsidiaries and their ability to pay upstream dividends or to repay funds to us. Prior to funding us, our subsidiaries have financial obligations that must be satisfied, including among others, debt service, dividends and obligations to trade creditors. The rates that our utility subsidiaries may charge retail customers for electric power are subject to the authority of state regulators. Accordingly, our profit margins could be adversely affected if we or our utility subsidiaries do not control operating costs. 173 The NCUC, the SCPSC and the FPSC each exercises regulatory authority for review and approval of the retail electric power rates charged within its respective state. State regulators may not allow our utility subsidiaries to increase retail rates in the manner or to the extent requested by those subsidiaries. State regulators may also seek to reduce retail rates. For example, in March 2002, PEF entered into a Stipulation and Settlement Agreement that required PEF, among other things, to reduce its retail rates and to operate under a revenue sharing plan through 2005 which provides for possible rate refunds to its retail customers. The Agreement will also require increased capital expenditures for PEF's Commitment to Excellence program. However, if PEF's base rate earnings fall below a 10% return on equity, PEF may petition the FPSC to amend its base rates. Additionally, a North Carolina law passed in 2002 froze PEC's base retail rates for five years unless there are significant cost changes due to governmental action, significant expenditures due to force majeure or other extraordinary events beyond the control of PEC. The same legislation required a significant increase in capital expenditures over the next several years for clean air improvements. The cash costs incurred by our utility subsidiaries are generally not subject to being fixed or reduced by state regulators. Our utility subsidiaries will also require dedicated capital expenditures. Thus, our ability to maintain our profit margins depends upon stable demand for electricity and our efforts to manage our costs. There are inherent potential risks in the operation of nuclear facilities, including environmental, health, regulatory, terrorism, and financial risks that could result in fines or the shutdown of our nuclear units, which may present potential exposures in excess of our insurance coverage. We own and operate five nuclear units through our subsidiaries, PEC (four units) and PEF (one unit), that represent approximately 4,220 megawatts, or 18%, of our generation capacity. Our nuclear facilities are subject to environmental, health and financial risks such as the ability to dispose of spent nuclear fuel, the ability to maintain adequate capital reserves for decommissioning, potential liabilities arising out of the operation of these facilities, and the costs of securing the facilities against possible terrorist attacks. We maintain decommissioning trusts and external insurance coverage to minimize the financial exposure to these risks; however, it is possible that damages could exceed the amount of our insurance coverage. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or to shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could require us to make substantial capital expenditures at our nuclear plants. In addition, although we have no reason to anticipate a serious nuclear incident at our plants, if an incident did occur, it could materially and adversely affect our results of operations or financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit. Our facilities require licenses that need to be renewed or extended in order to continue operating. We do not anticipate any problems renewing these licenses. However, as a result of potential terrorist threats and increased public scrutiny of utilities, the licensing process could result in increased licensing or compliance costs that are difficult or impossible to predict. Our financial performance depends on the successful operation of electric generating facilities by our subsidiaries and our ability to deliver electricity to our customers. Operating electric generating facilities and delivery systems involves many risks, including: o operator error and breakdown or failure of equipment or processes; o operating limitations that may be imposed by environmental or other regulatory requirements; o labor disputes; o fuel supply interruptions; and o catastrophic events such as fires, earthquakes, explosions, floods, terrorist attacks or other similar occurrences. A decrease or elimination of revenues generated from our subsidiaries' electric generating facilities and electricity delivery systems or an increase in the cost of operating the facilities could have an adverse effect on our business and results of operations. Our business is dependent on our ability to successfully access capital markets. Our inability to access capital may limit our ability to execute our business plan, or pursue improvements and make acquisitions that we may otherwise rely on for future growth. 174 We rely on access to both short-term money markets and long-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flow from our operations. If we are not able to access capital at competitive rates, our ability to implement our strategy will be adversely affected. We believe that we will maintain sufficient access to these financial markets based upon current credit ratings. However, certain market disruptions or a downgrade of our credit rating may increase our cost of borrowing or adversely affect our ability to access one or more financial markets. Such disruptions could include: o an economic downturn; o the bankruptcy of an unrelated energy company; o capital market conditions generally; o market prices for electricity and gas; o terrorist attacks or threatened attacks on our facilities or unrelated energy companies; or o the overall health of the utility industry. Restrictions on our ability to access financial markets may affect our ability to execute our business plan as scheduled. An inability to access capital may limit our ability to pursue improvements or acquisitions that we may otherwise rely on for future growth. Increases in our leverage could adversely affect our competitive position, business planning and flexibility, financial condition, ability to service our debt obligations and to pay dividends on our common stock, and ability to access capital on favorable terms. Our cash requirements arise primarily from the capital-intensive nature of our electric utilities. In addition to operating cash flows, we rely heavily on our commercial paper and long-term debt. At December 31, 2003, commercial paper and bank borrowings and long-term debt balances for Progress Energy and its subsidiaries were as follows (in millions): Outstanding Commercial Paper Total Long-Term Company and Bank Borrowings Debt, Net - ------------------ ----------------------------- ------------------- Progress Energy, unconsolidated (a) $ - $ 4,292 PEC 4 3,086 PEF - 1,879 (b) Other Subsidiaries - 677 (c) ----------------------------- ------------------- Progress Energy, consolidated $ 4 $ 9,934 (b)(d)
(a) Represents solely the outstanding indebtedness of the holding company. (b) On February 21, 2003, PEF issued $650.0 million aggregate principal amount of its first mortgage bonds, the proceeds from which were or will be used to reduce, redeem, or retire our outstanding long-term and short-term, secured and unsecured, indebtedness. (c) Includes the following subsidiaries: Progress Genco Ventures, LLC ($241 million), Florida Progress Funding Corporation ($270 million) and Progress Capital Holdings, Inc. ($166 million). (d) Net of current portion, which at December 31, 2003, was $868 million on a consolidated basis. Progress Energy and its subsidiaries have an aggregate of six committed credit lines that support our commercial paper programs totaling $1.6 billion. While our financial policy precludes us from issuing commercial paper in excess of our credit lines, at December 31, 2003, we did not have any commercial paper outstanding, leaving $1.6 billion available for future borrowing under our credit lines. Our credit lines impose various limitations that could impact our liquidity. Our credit facilities include defined maximum total debt to total capital (leverage) ratios and minimum coverage ratios. Under the credit facilities, indebtedness includes certain letters of credit and guarantees which are not recorded on our consolidated Balance Sheets. At December 31, 2003, the maximum and actual ratios were as follows: Leverage Ratios Coverage Ratios Company Maximum Ratio Actual Ratio Maximum Ratio Actual Ratio ------- ------------- ------------ ------------- ------------ Progress Energy 68% 61.5% 2.5:1 3.74:1 PEC 65% 51.4% n/a n/a PEF 65% 51.5% 3.0:1 9.22:1 Genco 40% 24.6% 1.25:1 6.35:1
175 In the event our capital structure changes such that we approach the permitted ratios, our access to capital and additional liquidity could decrease. Furthermore, the credit lines of Progress Energy, PEC, PEF and Genco each include provisions under which lenders could refuse to advance funds to each company under their respective credit lines in the event of a material adverse change in the respective company's financial condition. A limitation in our liquidity could have a material adverse impact on our business strategy and our ongoing financing needs. Our indebtedness also includes several cross-default provisions which could significantly impact our financial condition. Progress Energy's, PEC's, PEF's and Genco's credit lines each include cross-default provisions 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 borrowings and terminate their commitments to the credit facility. Progress Energy's cross default provisions only apply to defaults of indebtedness by Progress Energy and its significant subsidiaries (i.e., PEC, Florida Progress, PEF, PCH, PVI and Progress Fuels). PEC's and PEF's cross-default provisions only apply to defaults of indebtedness by PEC and PEF and their subsidiaries, respectively, not other affiliates of PEC and PEF. 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 only apply to other obligations of Progress Energy, not its subsidiaries. In the event that either of these cross-default provisions are triggered, the debt holders could accelerate payment of approximately $4.8 billion in long-term debt. Any such acceleration would cause a material adverse change in the respective company's financial condition. Certain agreements underlying our indebtedness also limit our ability to incur additional liens or engage in certain types of sale and leaseback transactions. Changes in economic conditions could result in higher interest rates, which would increase our interest expense on our floating rate debt and reduce funds available to us for our current plans. Additionally, an increase in our leverage could adversely affect us by: o increasing the cost of future debt financing; o impacting our ability to pay dividends on our common stock at the current rate; o making it more difficult for us to satisfy our existing financial obligations; o limiting our ability to obtain additional financing, if we need it, for working capital, acquisitions, debt service requirements or other purposes; o increasing our vulnerability to adverse economic and industry conditions; o requiring us to dedicate a substantial portion of our cash flow from operations to payments on our debt, which would reduce funds available to us for operations, future business opportunities or other purposes; o limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we compete; o placing us at a competitive disadvantage compared to our competitors who have less debt; and o causing a downgrade in our credit ratings. Any reduction in our credit ratings could increase our borrowing costs, limit our access to additional capital and require posting of collateral, all of which could materially and adversely affect our business, results of operations and financial condition. In February 2003, Moody's announced that it was lowering Progress Energy's senior unsecured debt rating from "Baa1" to "Baa2," and changing the outlook of the rating from negative to stable. Moody's cited the slower than planned pace of the Company's efforts to pay down debt from its acquisition of Florida Progress as the primary reason for the ratings change. Moody's also changed the outlook of PEF's senior secured debt from stable to negative. PEC's senior unsecured debt has been assigned a rating by S&P of "BBB+" (negative outlook) and by Moody's of "Baa1" (stable outlook). PEF's senior unsecured debt has been assigned a rating by S&P of "BBB+" (negative outlook) and by Moody's of "A-2" (stable outlook). In August 2003, Standard & Poor's Ratings Group (S&P), a division of The McGraw-Hill Companies, Inc., announced that it had lowered its corporate credit rating on Progress Energy Inc., PEC, PEF, and Florida Progress to BBB from BBB+. The outlook of the ratings was changed from negative to stable. While our nonregulated operations, including those conducted through our Progress Ventures business unit, have a higher level of risk than our regulated utility operations, we will seek to maintain a solid investment grade rating through prudent capital management and financing structures. We cannot, however, assure you that any of Progress Energy's current ratings, or those of PEC and PEF, will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Any downgrade could increase our borrowing costs and adversely affect our access to capital, which could negatively impact our financial results. Further, we may be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources could decrease. Although we would have access to liquidity 176 under our committed and uncommitted credit lines, if our short-term rating were to fall below A-2 or P-2, the current ratings assigned by S&P and Moody's, respectively, it could significantly limit our access to the commercial paper market. We note that the ratings from credit agencies are not recommendations to buy, sell or hold our securities or those of PEC or PEF and that each rating should be evaluated independently of any other rating. Our energy marketing business relies on Progress Energy's investment grade ratings to stand behind transactions in that business. At December 31, 2003, Progress Energy has issued guarantees with a notional amount of approximately $332 million to support CCO's energy marketing businesses. Based upon the amount of trading positions outstanding at December 31, 2003, if Progress Energy's ratings were to decline below investment grade, we would have to deposit cash or provide letters of credit or other cash collateral for approximately $56 million for the benefit of our counterparties. Additionally, the power supply agreement with Jackson Electric Membership Corporation that PVI acquires from Williams Energy Marketing and Trading Company includes a performance guarantee that Progress Energy assumed. In the event that Progress Energy's credit ratings fall below investment grade, Progress Energy will be required to provide additional security for its guarantee in form and amount acceptable to Jackson, but not to exceed the coverage amount. The coverage amount at the inception of PVI's power sale to Jackson is $285 million and will decline over the life of the transaction. At December 31, 2003, the coverage amount is $280 million. These collateral requirements could adversely affect our profitability on energy trading and marketing transactions and limit our overall liquidity. The use of derivative contracts in the normal course of our business could result in financial losses that negatively impact our results of operations. We use derivatives, including futures, forwards and swaps, to manage our commodity and financial market risks. In the future, we could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the value of the reported fair value of these contracts. We could incur a significant tax liability, and our results of operations and cash flows may be materially and adversely affected if the Internal Revenue Service denies or otherwise makes unusable the Section 29 tax credits related to our coal and synthetic fuels businesses. Through our Fuels segment, we produce coal-based solid synthetic fuel. The production and sale of the synthetic fuel from these facilities qualifies for tax credits under 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 and that the fuel was produced from a facility that was placed in service before July 1, 1998. All of our synthetic fuel facilities have received favorable private letter rulings (PLRs) from the Internal Revenue Service (IRS) with respect to their synthetic fuel operations. These tax credits are subject to review by the IRS. In September 2002, all of our majority-owned synthetic fuel entities were accepted into the IRS' Pre-Filing Agreement (PFA) program. The PFA program allows taxpayers to voluntarily accelerate the IRS examination process in order to seek resolution of specific issues. Either we or the IRS can withdraw from the program at any time, and issues not resolved through the program may proceed to the next level of the IRS examination process. We believe that we operate in conformity with all the necessary requirements to be allowed such credits under Section 29. The current Section 29 tax credit program will expire at the end of 2007. With respect to any IRS review or audit of our synthetic fuel operations, if we fail to prevail through the administrative or legal process, there could be a significant tax liability owed for previously taken Section 29 credits or we could lose our ability to claim future tax credits that we might otherwise be able to benefit from both of which would significantly impact earnings and cash flows. In October 2003, the United States Senate Permanent Subcommittee on Investigations began a general investigation concerning synthetic fuel tax credits claimed under Section 29 of the Internal Revenue Code. The investigation generally relates to the utilization of the tax credits, the nature of the technologies and fuels created, the use of the synthetic fuel, and other aspects of Section 29 and is not specific to our synthetic fuel operations. We are providing information in connection with this investigation as requested. There are risks involved with the operation of our nonregulated plants, including dependence on third parties and related counter-party risks, and a lack of operating history, all of which may make our wholesale generation and overall operations less profitable and more unstable. 177 At December 31, 2003, we had approximately 3,100 megawatts of nonregulated generation in commercial operation. The operation of wholesale generation facilities is subject to many risks, including those listed below. During the execution of our wholesale generation strategy, these risks will intensify. These risks include: o We may enter into or otherwise acquire long-term contracts that take effect at a future date based upon our current expectations of our future wholesale generation capacity. If our expected future capacity does not meet our expectations, we may not be able to meet our obligations under any such long-term contracts and may have to purchase power in the spot market at then prevailing prices. Accordingly, we may lose current and future customers, impair our ability to implement our wholesale strategy, and suffer reputational harm. Additionally, if we are unable to secure favorable pricing in the spot market, our results of operations may be diminished. We may also become liable under any related performance guarantees then in existence. o Our wholesale facilities depend on third parties through power purchase agreements, fuel supply and transportation agreements, and transmission grid connection agreements. If such third parties breach their obligations to us, our revenues, financial condition, cash flow and ability to make payments of interest and principal on our outstanding debts may be impaired. Any material breach by any of these parties of their obligations under the project contracts could adversely affect our cash flows and could impair our ability to make payments of principal of and interest on our indebtedness. o We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity and natural gas that we sell to the wholesale market. If transmission is disrupted, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual obligations may be hindered. Although the FERC has issued regulations designed to encourage competition in wholesale market transactions for electricity, there is the potential that fair and equal access to transmission systems will not be available or that sufficient transmission capacity will not be available to transmit electric power as we desire. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets. o Agreements with our counter-parties frequently will include the right to terminate and/or withhold payments or performance under the contracts if specific events occur. If a project contract were to be terminated due to nonperformance by us or by the other party to the contract, our ability to enter into a substitute agreement having substantially equivalent terms and conditions is uncertain. o Because many of our facilities are newly constructed and have no significant operating history, various unexpected events may increase our expenses or reduce our revenues and impair our ability to service the related project debt. As with any new business venture of this size and nature, operation of our facility could be affected by many factors, including start-up problems, the breakdown or failure of equipment or processes, the performance of our facility below expected levels of output or efficiency, failure to operate at design specifications, labor disputes, changes in law, failure to obtain necessary permits or to meet permit conditions, government exercise of eminent domain power or similar events and catastrophic events including fires, explosions, earthquakes and droughts. o Our facilities seek to enter into long-term power purchase agreements to sell all or a portion of their generating capacity. Currently, the percentage of our anticipated nonregulated capacity that will be under contract is as follows: 2004--85%, 2005--50% and 2006--50%. Following the expiration or early termination of our power purchase agreements, or to the extent we cannot otherwise secure contracts for our current and future generation capacity, our facilities will generally become merchant facilities. Our merchant facilities may not be able to find adequate purchasers, attain favorable pricing, or otherwise compete effectively in the wholesale market. Additionally, numerous legal and regulatory limitations restrict our ability to operate a facility on a wholesale basis. Our energy marketing and trading operations are subject to risks that may reduce our revenues and adversely impact our results of operations and financial condition, many of which are beyond our control. Our fleet of nonregulated plants may sell energy into the spot market or other competitive power markets or on a contractual basis. We may also enter into contracts to purchase and sell electricity, natural gas and coal as part of our power marketing and energy trading operations. Our business may also include entering into long-term contracts that supply customers' full electric requirements. These contracts do not guarantee us any rate of return on our 178 capital investments through mandated rates, and our revenues and results of operations from these contracts are likely to depend, in large part, upon prevailing market prices for power in our regional markets and other competitive markets. These market prices can fluctuate substantially over relatively short periods of time. Trading margins may erode as markets mature, and should volatility decline, we may have diminished opportunities for gain. In particular, we believe that over the past few years, the Southeastern wholesale energy market has been overbuilt and accordingly believe that supply exceeds demand. Due to this overbuilding, we believe that spot prices as well as contractual pricing will provide us with a reduced rate of return on our capital investment and our revenues and results of operations from this market will be lower than originally expected unless and until demand catches up with supply. In addition, the Enron Corporation bankruptcy and enhanced regulatory scrutiny have contributed to more rigorous credit rating review of participants in the energy marketing and trading business. Credit downgrades of certain other market participants have significantly reduced such participants' participation in the wholesale power markets. These events are causing a decrease in the number of significant participants in the wholesale power markets, which could result in a decrease in the volume and liquidity in the wholesale power markets. We are unable to predict the impact of such developments on our power marketing and trading business. Furthermore, the FERC, which has jurisdiction over wholesale power rates, as well as ISOs that oversee some of these markets, may impose price limitations, bidding rules and other mechanisms to address some of the volatility in these markets. Fuel prices also may be volatile, and the price we can obtain for power sales may not change at the same rate as fuel costs changes. These factors could reduce our margins and therefore diminish our revenues and results of operations. Volatility in market prices for fuel and power may result from: o weather conditions; o seasonality; o power usage; o illiquid markets; o transmission or transportation constraints or inefficiencies; o availability of competitively priced alternative energy sources; o demand for energy commodities; o natural gas, crude oil and refined products, and coal production levels; o natural disasters, wars, embargoes and other catastrophic events; and o federal, state and foreign energy and environmental regulation and legislation. We actively manage the market risk inherent in our energy marketing operations. Nonetheless, adverse changes in energy and fuel prices may result in losses in our earnings or cash flows and adversely affect our balance sheet. Our marketing and risk management procedures may not work as planned. As a result, we cannot predict with precision the impact that our marketing, trading and risk management decisions may have on our business, operating results or financial position. In addition, to the extent that we do not cover the entire exposure of our assets or our positions to market price volatility, or our hedging procedures do not work as planned, fluctuating commodity prices could cause our sales and net income to be volatile. 179 PROGRESS ENERGY CAROLINAS, INC. RISK FACTORS In this section, references to "we," "our," "us" or similar terms are to Progress Energy Carolinas, Inc. and its consolidated subsidiaries. Investing in our securities involves risks, including the risks described below, that could affect the energy industry, as well as us and our business. Although we have tried to discuss key factors, please be aware that other risks may prove to be important in the future. New risks may emerge at any time and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Before purchasing our securities, you should carefully consider the following risks and the other information in this Annual Report, as well as documents we file with the SEC from time to time. Each of the risks described below could result in a decrease in the value of our securities and your investment therein. Risks Related to the Energy Industry We are subject to fluid and complex government regulations that may have a negative impact on our business and our results of operations. We are subject to comprehensive regulation by several federal and state regulatory agencies, which significantly influence our operating environment and may affect our ability to recover costs from utility customers. We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations. The Federal Energy Regulatory Commission ("FERC"), the U.S. Nuclear Regulatory Commission ("NRC"), the U.S. Environmental Protection Agency ("EPA"), the North Carolina Utilities Commission ("NCUC") and the Public Service Commission of South Carolina ("SCPSC") regulate many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers. Although we are not a registered holding company under the Public Utility Holding Company Act of 1935, as amended ("PUHCA"), we are subject to many of the regulatory provisions of PUHCA. We are a wholly-owned subsidiary of Progress Energy, Inc., a registered public utility holding company under PUHCA. Repeal of PUHCA has been proposed, but it is unclear whether or when such a repeal would occur. It is also unclear to what extent repeal of PUHCA would result in additional or new regulatory oversight or action at the federal or state levels, or what the impact of those developments might be on our business. We are unable to predict the impact on our business and operating results from future regulatory activities of these federal and state agencies. Changes in regulations or the imposition of additional regulations could have a negative impact on our business and results of operations. We are subject to numerous environmental laws and regulations that may increase our cost of operations, impact or limit our business plans, or expose us to environmental liabilities. We are subject to numerous environmental regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste, and hazardous waste. These laws and regulations can result in increased capital, operating and other costs, particularly with regard to enforcement efforts focused on power plant emissions obligations. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. We cannot predict the financial or operational outcome of any related litigation that may arise. In addition, we may be a responsible party for environmental clean up at sites identified by a regulatory body. We cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all PRPs. We cannot assure you that existing environmental regulations will not be revised or that new regulations seeking to protect the environment will not be adopted or become applicable to us. Revised or additional regulations, which result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our results of operations. 180 Deregulation or restructuring in the electric utility industry may result in increased competition and unrecovered costs that could adversely affect our financial condition, results of operations and cash flows. Increased competition resulting from deregulation or restructuring efforts could have a significant adverse financial impact on our results of operations and cash flows. Increased competition could also result in increased pressure to lower rates. Retail competition and the unbundling of regulated energy and gas service could have a significant adverse financial impact on us due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital. Because we have not previously operated in a competitive retail environment, we cannot predict the extent and timing of entry by additional competitors into the electric markets. Due to several factors, however, there currently is little discussion of any movement toward deregulation in North Carolina and South Carolina. We cannot predict when we will be subject to changes in legislation or regulation, nor can we predict the impact of these changes on our financial condition, results of operations or cash flows. The uncertain outcome regarding the timing, creation and structure of regional transmission organizations, or RTOs, may materially impact our results of operations, cash flows or financial condition. For the last several years, the FERC has supported independent RTOs and has indicated a belief that it has the authority to order transmission-owning utilities to transfer operational control of their transmission assets to participate in such RTOs. Many state regulators, including most regulators in the Southeast, have expressed skepticism over the potential benefits of RTOs and generally disagree with the FERC's interpretation of its authority to mandate RTOs. In addition, in July 2002, the FERC issued its Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design ("SMD NOPR"). The proposed rules set forth in the SMD NOPR would require, among other things, that 1) all transmission owning utilities transfer control of their transmission facilities to an independent third party; 2) transmission service to bundled retail customers be provided under the FERC- regulated transmission tariff, rather than state-mandated terms and conditions; 3) new terms and conditions for transmission service be adopted nationwide, including new provisions for pricing transmission in the event of transmission congestion; 4) new energy markets be established for the buying and selling of electric energy; and 5) LSEs be required to meet minimum criteria for generating reserves. If adopted as proposed, the rules set forth in the SMD NOPR would materially alter the manner in which transmission and generation services are provided and paid for. Progress Energy, Inc. filed comments on the SMD NOPR in November 2002 and supplemental comments in January 2003. The FERC has not yet issued a final rule on SMD. Furthermore, the SMD NOPR presents several uncertainties, including what percentage of our investments in GridSouth will be recovered, how the elimination of transmission charges, as proposed in the SMD NOPR, will impact us, and what amount of capital expenditures will be necessary to create a new wholesale market. In response, PEC and other investor-owned utilities filed applications with the FERC, the NCUC and the SCPSC for approval of an RTO, currently named GridSouth. However, PEC and the other GridSouth participants withdrew their RTO application before the NCUC and the SCPSC pending the review of the FERC's SMD NOPR. A determination about refilling will be made at a later date. The actual structure of GridSouth or any alternative combined transmission structure, as well as the date it may become operational, depends upon the resolution of all regulatory approvals and technical issues. Given the regulatory uncertainty of the ultimate timing, structure and operations of GridSouth, or an alternate combined transmission structure, we cannot predict whether their creation will have any material adverse effect on our future consolidated results of operations, cash flows or financial condition. Since weather conditions directly influence the demand for and cost of providing electricity, our results of operations, financial condition and cash flows can fluctuate on a seasonal or quarterly basis and can be negatively affected by changes in weather conditions and severe weather. Our results of operations, financial condition and cash flows may be affected by changing weather conditions. Weather conditions in our service territories directly influence the demand for electricity and affect the price of energy commodities necessary to provide electricity to our customers. Electric power demand is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. The pattern of this fluctuation may change depending on the nature and location 181 of facilities we acquire and the terms of power sale contracts into which we enter. In addition, we have historically sold less power, and consequently earned less income, when weather conditions are milder. As a result, our overall operating results in the future may fluctuate substantially on a seasonal basis. Furthermore, severe weather in North Carolina and South Carolina, such as hurricanes, tornadoes, severe thunderstorms and snow and ice storms, can be destructive, causing outages, downed power lines and property damage, requiring us to incur additional and unexpected expenses and causing us to lose generating revenues. Our revenues, operating results and financial condition may fluctuate with the economy and its corresponding impact on our commercial and industrial customers. Our business is impacted by fluctuations in the macroeconomy. For the year ended December 31, 2003, commercial and industrial customers represented approximately 24% and 18% of our electric revenues, respectively. As a result, changes in the macroeconomy can have negative impacts on our revenues. As our commercial and industrial customers experience economic hardships, our revenues can be negatively impacted. Risks Related to Us and Our Business Under a North Carolina law passed in 2002, our base rates are frozen for five years and we are required to increase capital expenditures for clean air improvements. Accordingly, our profit margin could be adversely affected if we do not control operating costs. The NCUC and the SCPSC each exercises regulatory authority for review and approval of the retail electric power rates charged within its respective state. State regulators may not allow us to increase retail rates in the manner or to the extent we request. State regulators may also seek to reduce retail rates. A North Carolina law passed in 2002 froze our base retail rates for five years unless there are significant cost changes due to governmental action, significant expenditures due to force majeure or other extraordinary events beyond our control. That same legislation required a significant increase in capital expenditures over the next several years for clean air improvements. The cash costs incurred by us are generally not subject to being fixed or reduced by state regulators. We will also require dedicated capital expenditures. Thus, our ability to maintain our profit margins depends upon stable demand for electricity and our efforts to manage our costs. There are inherent potential risks in the operation of nuclear facilities, including environmental, health, regulatory, terrorism, and financial risks that could result in fines or the shutdown of our nuclear units, which may present potential exposures in excess of our insurance coverage. We own and operate four nuclear units that represent approximately 3,382 megawatts, or approximately 27%, of our generation capacity. Our nuclear facilities are subject to environmental, health and financial risks such as the ability to dispose of spent nuclear fuel, the ability to maintain adequate capital reserves for decommissioning, potential liabilities arising out of the operation of these facilities, and the costs of securing the facilities against possible terrorist attacks. We maintain a decommissioning trust and external insurance coverage to minimize the financial exposure to these risks; however, it is possible that damages could exceed the amount of our insurance coverage. The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines or to shut down any of our units, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could require us to make substantial capital expenditures at our nuclear plants. In addition, although we have no reason to anticipate a serious nuclear incident at any of our plants, if an incident did occur, it could materially and adversely affect our results of operations or financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit. Our facilities require licenses that need to be renewed or extended in order to continue operating. We do not anticipate any problems renewing these licenses. However, as a result of potential terrorist threats and increased public scrutiny of utilities, the licensing process could result in increased licensing or compliance costs that are difficult or impossible to predict. Our financial performance depends on the successful operation of our electric generating facilities and our ability to deliver electricity to our customers. 182 Operating electric generating facilities and delivery systems involves many risks, including: o operator error and breakdown or failure of equipment or processes; o operating limitations that may be imposed by environmental or other regulatory requirements; o labor disputes; o fuel supply interruptions; and o catastrophic events such as fires, earthquakes, explosions, floods, terrorist attacks or other similar occurrences. A decrease or elimination of revenues generated from our electric generating facilities and electricity delivery systems or an increase in the cost of operating the facilities could have an adverse effect on our business and results of operations. Our business is dependent on our ability to successfully access capital markets. Our inability to access capital may limit our ability to execute our business plan, or pursue improvements and make acquisitions that we may otherwise rely on for future growth. We rely on access to both short-term money markets and long-term capital markets as a significant source of liquidity for capital requirements not satisfied by the cash flow from our operations. If we are not able to access capital at competitive rates, our ability to implement our business operations will be adversely affected. We believe that we will maintain sufficient access to these financial markets based upon current credit ratings. However, certain market disruptions or a downgrade of our credit rating may increase our cost of borrowing or adversely affect our ability to access one or more financial markets. Such disruptions could include: o an economic downturn; o a ratings downgrade of Progress Energy, Inc.; o the bankruptcy of an unrelated energy company; o capital market conditions generally; o market prices for electricity; o terrorist attacks or threatened attacks on our facilities or those of unrelated energy companies; or o the overall health of the utility industry. Restrictions on our ability to access financial markets may affect our ability to execute our business plan as scheduled. An inability to access capital may limit our ability to pursue improvements or acquisitions that we may otherwise rely on for future growth. Increases in our leverage could adversely affect our competitive position, business planning and flexibility, financial condition, ability to service our debt obligations and ability to access capital on favorable terms. Our cash requirements arise primarily from the capital-intensive nature of our business. In addition to operating cash flows, we rely heavily on our commercial paper and long-term debt. At December 31, 2003, our commercial paper balance was zero, we had $25 million notes payable to affiliated companies and our long-term debt balances were approximately $3.1 billion (with current portion of long-term debt of $300 million at December 31, 2003). We have a committed credit line that supports our commercial paper programs and matures in July 2005. At December 31, 2003, we had no outstanding borrowings under this line. Our credit lines impose various limitations that could impact our liquidity. Our credit facilities include defined maximum total debt to total capital (leverage) ratios. At December 31, 2003, the maximum and actual ratios, pursuant to the terms of the credit facilities, were 65% and 51.4%, respectively. Indebtedness, as defined under the credit facility agreements, includes certain letters of credit and guarantees that are not recorded on our balance sheets. In the event our capital structure changes such that we approach the permitted ratios, our access to capital and additional liquidity could decrease. Furthermore, our credit lines include provisions under which lenders could refuse to advance funds to us in the event of a material adverse change in our financial condition. A limitation in our liquidity could have a material adverse impact on our business strategy and our ongoing financing needs. 183 Our indebtedness also includes cross-default provisions which could significantly impact our financial condition. Our credit lines include cross-default provisions for defaults of indebtedness in excess of $10 million. Under these provisions, if the applicable borrower fails to pay various debt obligations in excess of $10 million, the lenders could accelerate payment of any outstanding borrowings and terminate their commitments to the credit facility. Our cross-default provisions only apply to defaults on our indebtedness, but not defaults by our affiliates. In the event that a cross-default provision was triggered, our lenders could accelerate payment of any outstanding debt. Any such acceleration would cause a material adverse change in our financial condition. Changes in economic conditions could result in higher interest rates, which would increase our interest expense on our floating rate debt and reduce funds available to us for our current plans. Additionally, an increase in our leverage could adversely affect us by: o increasing the cost of future debt financing; o making it more difficult for us to satisfy our existing financial obligations; o limiting our ability to obtain additional financing, if we need it, for working capital, acquisitions, debt service requirements or other purposes; o increasing our vulnerability to adverse economic and industry conditions; o requiring us to dedicate a substantial portion of our cash flow from operations to payments on our debt, which would reduce funds available to us for operations, future business opportunities or other purposes; o limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we compete; o placing us at a competitive disadvantage compared to our competitors who have less debt; and o causing a downgrade in our credit ratings. Any reduction in our credit ratings could increase our borrowing costs and limit our access to additional capital, which could materially and adversely affect our business, results of operations and financial condition. Our senior secured debt has been assigned a rating by Standard & Poor's Ratings Group, a division of The McGraw Hill Companies, Inc., of "BBB+" (negative outlook) and by Moody's Investors Service, Inc. of "A3" (stable outlook). Our senior unsecured debt rating has been assigned a rating by S&P of "BBB+" (negative outlook) and by Moody's of "Baa1" (stable outlook). In addition, S&P's rating philosophy links the ratings of a utility subsidiary to the credit rating of its parent corporation. Accordingly, if S&P were to downgrade Progress Energy, Inc.'s credit ratings, our credit rating would also likely be downgraded, regardless of whether or not we had experienced any change in our business operations or financial conditions. We will seek to maintain a solid investment grade rating through prudent capital management and financing structures. We cannot, however, assure you that our current ratings will remain in effect for any given period of time or that our ratings will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Any downgrade could increase our borrowing costs and adversely affect our access to capital, which could negatively impact our financial results. Further, we may be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources could decrease. Although we would have access to liquidity under our committed and uncommitted credit lines, if our short-term rating were to fall below "A-2" or "P-2," the current ratings assigned by S&P and Moody's, respectively, it could significantly limit our access to the commercial paper market. We note that the ratings from credit agencies are not recommendations to buy, sell or hold our securities and that each rating should be evaluated independently of any other rating. The use of derivative contracts in the normal course of our business could result in financial losses that negatively impact our results of operations. We use derivatives, including futures, forwards and swaps, to manage our commodity and financial market risks. In the future, we could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the value of the reported fair value of these contracts. 184 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized. PROGRESS ENERGY, INC. CAROLINA POWER & LIGHT COMPANY Date: March 12, 2004 (Registrants) By: /s/Robert B. McGehee ------------------------------------ Robert B. McGehee Chief Executive Officer Progress Energy, Inc. By: /s/Fred N. Day IV ------------------------------------ Fred N. Day IV President and Chief Executive Officer Carolina Power & Light Company By: /s/Geoffrey S. Chatas ------------------------------------ Geoffrey S. Chatas Executive Vice President and Chief Financial Officer Progress Energy, Inc. Carolina Power & Light Company By: /s/Robert H. Bazemore, Jr. ------------------------------------ Robert H. Bazemore, Jr. Vice President and Controller (Chief Accounting Officer) Progress Energy, Inc. Carolina Power & Light Company 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 Director March 12, 2004 - ------------------------- (William Cavanaugh III, Chairman) /s/ Edwin B. Borden Director March 12, 2004 - -------------------- (Edwin B. Borden) /s/ James E. Bostic, Jr. Director March 12, 2004 - ------------------------ (James E. Bostic, Jr.) /s/ David L. Burner Director March 12, 2004 - -------------------- (David L. Burner) 185 /s/ Charles W. Coker Director March 12, 2004 - --------------------- (Charles W. Coker) /s/ Richard L. Daugherty Director March 12, 2004 - ------------------------- (Richard L. Daugherty) /s/ W.D. Frederick, Jr. Director March 12, 2004 - ------------------------ (W.D. Frederick, Jr.) /s/ William O. McCoy Director March 12, 2004 - --------------------- (William O. McCoy) /s/ E. Marie McKee Director March 12, 2004 - ------------------- (E. Marie McKee) /s/ John H. Mullin, III Director March 12, 2004 - ------------------------ (John H. Mullin, III) /s/ Richard A. Nunis Director March 12, 2004 - --------------------- (Richard A. Nunis) /s/Peter S. Rummell Director March 12,2004 - ------------------- (Peter S. Rummell) /s/ Carlos A. Saladrigas Director March 12, 2004 - ------------------------- (Carlos A. Saladrigas) /s/ J. Tylee Wilson Director March 12, 2004 - -------------------- (J. Tylee Wilson) /s/ Jean Giles Wittner Director March 12, 2004 - ----------------------- (Jean Giles Wittner) EXHIBIT INDEX Progress Number Exhibit Energy, Inc. PEC *2(a) Agreement and Plan of Merger By and Among Carolina Power X & Light Company, North Carolina Natural Gas Corporation and Carolina Acquisition Corporation, dated as of November 10, 1998 (filed as Exhibit No. 2(b) to Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1998, File No. 1-3382.) *2(b) Agreement and Plan of Merger by and among Carolina Power X & Light Company, North Carolina Natural Gas Corporation and Carolina Acquisition Corporation, Dated as of November 10, 1998, as Amended and Restated as of April 22, 1999 (filed as Exhibit 2 to Quarterly Report on Form 10-Q for the quarterly period ended March 31, 1999, File No. 1-3382). *2(c) Agreement and Plan of Exchange, dated as of August 22, 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 Exchange, by X X 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 Company, as X 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 Company as X 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 Incorporation of CP&L X 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). 187 *3b(1) Amended and Restated Articles of Incorporation of CP&L X Energy, Inc., as amended and restated on December 4, 2000 (filed as Exhibit 3b(1) to Annual Report on Form 10-K dated March 28, 2002, File No. 1-3392 and 1-15929). *3b(2) By-Laws of Carolina Power & Light Company, as amended on X December 12, 2001 (filed as Exhibit 3b(2) to Annual Report on Form 10-K dated March 28, 2002, File No. 1-3382 and 1-15929). *3b(3) By-Laws of Progress Energy, Inc., as amended and restated X December 12, 2001 (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 December 8, 1954, X authorizing the issuance of, and establishing the series designation, dividend rate and redemption prices for Carolina Power & Light Company's Serial Preferred Stock, $4.20 Series (filed as Exhibit 3(c), File No. 33-25560). *4a(2) Resolution of Board of Directors, dated January 17, 1967, X authorizing the issuance of, and establishing the series designation, dividend rate and redemption prices for Carolina Power & Light Company's Serial Preferred Stock, $5.44 Series (filed as Exhibit 3(d), File No. 33-25560). *4a(3) Statement of Classification of Shares dated January 13, X 1971, relating to the authorization of, and establishing the series designation, dividend rate and redemption prices for Carolina Power & Light Company's Serial Preferred Stock, $7.95 Series (filed as Exhibit 3(f), File No. 33-25560). *4a(4) Statement of Classification of Shares dated September 7, X 1972, relating to the authorization of, and establishing the series designation, dividend rate and redemption prices for Carolina Power & Light Company'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, 1940 between X Carolina Power & Light Company and The Bank of New York formerly, Irving Trust Company) and Frederick G. Herbst (Douglas J. MacInnes, Successor), Trustees and the First through Fifth Supplemental Indentures thereto (Exhibit 2(b), File No. 2-64189); 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 188 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); and the Seventy-first Supplemental Indenture (Exhibit 4b(2) to Annual Report on Form 10-K dated March 28, 2002). *4b(2) Seventy-second Supplemental Indenture, dated as of X September 1, 2003, to PEC Mortgage and Deed of Trust dated May 1, 1940, between PEC and The Bank of New York and Douglas J. MacInnes, as Trustees (filed as Exhibit 4 to PEC Report on Form 8-K dated September 12, 2003, File No.1-03382). *4c(1) Indenture, dated as of February 15, 2001, between X Progress Energy, Inc. and Bank One Trust Company, N.A., as Trustee, with respect to Senior Notes (filed as Exhibit 4(a) to Form 8-K dated February 27, 2001, File No. 1-15929). *4c(2) Indenture, dated as of March 1, 1995, between Carolina X Power & Light Company 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(3) Resolutions adopted by the Executive Committee of the X Board of Directors at a meeting held on April 13, 1995, establishing the terms of the 8.55% Quarterly Income 189 Capital Securities (Series A Subordinated Deferrable Interest Debentures) (filed as Exhibit 4(b) to Current Report on Form 8-K dated April 13, 1995, File No. 1-3382). *4d Indenture (for Senior Notes), dated as of March 1, 1999 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 October 28, X 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 as of X 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 Agreement dated July X 30, 1981 between Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency, amending letter dated February 18, 1982, and amendment dated February 24, 1982 (filed as Exhibit 10(a), File No. 33-25560). *10a(2) Operating and Fuel Agreement dated July 30, 1981 between X Carolina Power & Light Company and North Carolina Municipal Power Agency Number 3 and Exhibits, together with resolution dated December 16, 1981 changing name to North Carolina Eastern Municipal Power Agency, amending letters dated August 21, 1981 and December 15, 1981, and amendment dated February 24, 1982 (filed as Exhibit 10(b), File No. 33-25560). *10a(3) Power Coordination Agreement dated July 30, 1981 between X 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). 190 *10a(4) Amendment dated December 16, 1982 to Purchase, X Construction and Ownership Agreement dated July 30, 1981 between Carolina Power & Light Company and North Carolina Eastern Municipal Power Agency (filed as Exhibit 10(d), File No. 33-25560). *10a(5) Agreement Regarding New Resources and Interim Capacity 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 North X 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) Progress Energy, Inc. $250,000,000 364-Day Amended and X Restated Credit Agreement dated as of November 10, 2003 (filed as Exhibit 10(i) to Quarterly Report on Form 10-Q for the period ended September 30, 2003, File No. 1-03382 and 1-15929). *10b(2) Amendment and Restatement, dated as of July 30, 2003, to the X 364-Day Revolving Credit Agreement among PEC and certain Lenders (filed as Exhibit 10(v) to Quarterly Report on Form 10-Q for the period ended June 30, 2003, File No. 1-3382 and 1-15929). *10b(3) Notice, dated March 25, 2003 to the Agent for the Lenders named X in the PEC 364-Day Revolving Credit Agreement dated July 31, 2002, of a commitment reduction in the amount of $120,000,000 (filed as Exhibit 10(ii) to Quarterly Report on Form 10-Q for the period ended March 31, 2003, File No. 1-03382 and 1-15929). *10b(4) Assumption Agreement from The Bank of New York dated August 5, X 2002 for a total commitment of $25 million, increasing the amount of the PEC 364-Day and 3-Year Revolving Credit Agreements, dated July 31, 2002, to $285,000,000 each (filed as Exhibit 10(v) to Quarterly Report on Form 10-Q for the period ended September 30, 2002, File No. 1-03382 and 1-15929). *10b(5) Carolina Power & Light Company $272,500,000 364-Day X Revolving Credit Agreement dated as of July 31, 2002 (filed as Exhibit 10(iv) to Quarterly Report on Form 10-Q for the period ended September 30, 2002, File No. 1-3382). *10b(6) Assumption Agreement from The Bank of New York dated X August 5, 2002 for a total commitment of $25 million, increasing the amount of the PEC 364-Day and 3-Year Revolving Credit Agreements dated as of July 31, 2002, to 191 $285,000,000 each (filed as exhibit 10(v) to Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002, File No. 1-3382 and 1-15929). *10b(7) Amendment and Restatement dated July 26, 2002 to Progress X Energy, Inc.'s $450,000,000 3-Year Revolving Credit Agreement dated November 13, 2001 as amended February 13, 2002 (filed as Exhibit 10(i) to Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002, File No. 1-3382 and 1-15929). *10b(8) Amendment, dated February 13, 2002, to Progress Energy, X Inc. $450,000,000 3-Year Revolving Credit Agreement dated November 13, 2001 (filed as Exhibit 10b(8) to Annual Report on Form 10-K dated March 28, 2002, File No. 1-3392 and 1-15929). *10b(9) Progress Energy, Inc. $450,000,000 3-Year Revolving Credit X Agreement dated as of November 13, 2001 (filed as Exhibit 10b(6) to Annual Report on Form 10-K dated March 28, 2002, File No. 1-3392 and 1-15929). *10b(10) PEF 364-Day $200,000,000 Credit Agreement dated as of April X 1, 2003 (filed as Exhibit 10(ii) to Florida Power Corporation Form 10-Q for the quarter ended March 31, 2003). *10b(11) PEF 3-Year $200,000,000 Credit Agreement, dated as of April X 1, 2003 (filed as Exhibit 10(iii) to the Florida Power Corporation Form 10-Q for the quarter ended March 31, 2003). - -+*10c(1) Directors Deferred Compensation Plan effective January 1, X 1982 as amended (filed as Exhibit 10(g), File No. 33-25560). - -+*10c(2) Retirement Plan for Outside Directors (filed as Exhibit X 10(i), File No. 33-25560). - -+*10c(3) Key Management Deferred Compensation Plan (filed as Exhibit X 10(k), File No. 33-25560). +*10c(4) Resolutions of the Board of Directors, dated 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 May 8, 1991, X X amending the PEC Directors Deferred Compensation Plan (filed as Exhibit 10(b), File No. 33-48607). +*10c(6) Resolutions of Board of Directors dated July 9, 1997, X amending the Deferred Compensation Plan for Key Management Employees of Carolina Power & Light Company. 192 +*10c(7) Progress Energy, Inc. Non-Employee Director Stock Unit X X Plan, amended and restated effective July 10, 2002 (filed as Exhibit 10(ii) to Quarterly Report on Form 10-Q for the period ended June 30, 2003, File No. 1-03382 and 1-15929). - -+*10c(8) Carolina Power & Light Company Restricted Stock X X 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) Progress Energy, Inc. Restoration Retirement Plan, as X X amended and restated July 10, 2002 (filed as Exhibit 10(i) to Quarterly Report on Form 10-Q for the period ended June 30, 2003, File No. 1-3382 and 1-15929). - -+*10c(10) Amended and Restated Supplemental Senior Executive X X Retirement Plan of Progress Energy, Inc., as last amended July 10, 2002 (filed as Exhibit 10b(iii) to Quarterly Report on Form 10-Q for the period ended June 30, 2003, File No. 1-3382 and 1-15929). - -+*10c(11) Performance Share Sub-Plan of the 2002 Progress Energy, X X Inc. Equity Incentive Plan, dated July 9, 2002 (filed as Exhibit 10(vii) to Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002, File No. 1-3382 and 1-15929). - -+*10c(12) Performance Share Sub-Plan of the 1997 Equity Incentive X X Plan, as amended January 1, 2001 (filed as Exhibit 10c(11) to Annual Report on Form 10-K dated March 28, 2002, File No. 1-3382 and 1-15929). +*10c(13) 2002 Progress Energy, Inc. Equity Incentive Plan, amended X X and restated July 10, 2002 (filed as Exhibit 10(vi) to Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002, File No. 1-3382 and 1-15929). +*10c(14) 1997 Equity Incentive Plan, Amended and 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(15) Progress Energy, Inc. Form of Stock Option Agreement X X (filed as Exhibit 4.4 to Form S-8 dated September 27, 2001, File No. 333-70332). +*10c(16) Progress Energy, Inc. Form of Stock Option Award (filed as X X Exhibit 4.5 to Form S-8 dated September 27, 2001, File No. 333-70332). 193 - -+*10c(17) Amended Management Incentive Compensation Plan of X X Progress Energy, Inc., as amended January 1, 2003 (filed as Exhibit 10(iv) to Quarterly Report on Form 10-Q for the period ended June 30, 2003, File No. 1-3382 and 1-15929). - -+*10c(18) Progress Energy, Inc. Management Deferred X X Compensation Plan, revised and restated as of January 1, 2003 (filed as Exhibit 4.3 to Progress Energy Form S-8 on May 2, 2003, File No. 333-104952). +*10c(19) Agreement dated April 27, 1999 between Carolina Power & X Light Company and Sherwood H. Smith, Jr. (filed as Exhibit 10b, File No. 1-3382). +*10c(20) Employment Agreement dated August 1, 2000 between CP&L X 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(21) Employment Agreement dated August 1, 2000 between X 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(22) Employment Agreement dated August 1, 2000 between Carolina X 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(23) Employment Agreement dated August 1, 2000 between CP&L X 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(24) Form of Employment Agreement dated August 1, 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(25) Form of Employment Agreement dated August 1, 2000 (i) X X 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 (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). 194 +*10c(26) Employment Agreement dated November 30, 2000 between X 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 Report on Form 10-K for the year ended December 31, 2000). +10c(27) Form of Employment Agreement between (i) Progress Energy X Service Company, LLC and Brenda F. Castonguay, effective September 2002; and (ii) Progress Energy Service Company and John R. McArthur, effective January 2003; dated December 15, 2003 (filed as Exhibit 10c(27) to Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-33382 and 1-5929). +10c(28) Employment Agreement dated October 1, 2003 between Progress X Energy Service Company, LLC and Geoffrey S. Chatas 12 Computation of Ratio of Earnings to Fixed Charges and X X 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 31(a) 302 Certification of Chief Executive Officer X X 31(b) 302 Certification of Chief Financial Officer X X 32(a) 906 Certification of Chief Executive Officer X X 32(b) 906 Certification of Chief Financial Officer X 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.
195 PROGRESS ENERGY, INC. EXHIBIT NO. 12 COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES Years Ended December 31, 2003 2002 2001 2000 1999 ---- ---- ---- ---- ---- (Millions of Dollars) Earnings, as defined: Income from continuing operations before cumulative effect of changes in accounting principles $ 811 $ 552 $ 541 $ 478 $ 383 Fixed charges, as below 657 667 719 275 193 Capitalized interest (20) (38) - - - Income taxes, as below (117) (166) (162) 188 250 - ----------------------------------------------------------------------------------------------------------------------------------- Total earnings, as defined $ 1,331 $ 1,015 $ 1,098 $ 941 $ 826 =================================================================================================================================== Fixed Charges, as defined: Interest on long-term debt $ 595 $ 600 $ 578 $ 224 $ 174 Other interest 37 41 112 37 7 Imputed interest factor in rentals-charged principally to operating expenses 18 19 21 9 7 Preferred dividend requirements of subsidiaries (a) 7 7 8 5 5 - ----------------------------------------------------------------------------------------------------------------------------------- Total fixed charges, as defined $ 657 $ 667 $ 719 $ 275 $ 193 =================================================================================================================================== Income Taxes: Income tax expense (benefit) $ (109) $ (158) $ (154) $ 196 $ 258 Included in AFUDC - deferred taxes in book depreciation (8) (8) (8) (8) (8) - ----------------------------------------------------------------------------------------------------------------------------------- Total income taxes $ (117) $ (166) $ (162) $ 188 $ 250 =================================================================================================================================== Ratio of Earnings to Fixed Charges 2.03 1.52 1.53 3.42 4.28
(a) Preferred dividends of subsidiaries not deductible times ratio of earnings before income taxes to net income 196 PROGRESS ENERGY CAROLINAS, INC. EXHIBIT NO. 12 COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED DIVIDENDS COMBINED AND RATIO OF EARNINGS TO FIXED CHARGES Years Ended December 31, 2003 2002 2001 2000 1999 ---- ---- ---- ---- ---- (Millions of Dollars) Earnings, as defined: Income before cumulative effect of change in accounting principles $ 505 $ 431 $ 364 $ 461 $ 382 Fixed charges, as below 200 220 264 246 196 Income taxes, as below 236 199 215 282 250 - ----------------------------------------------------------------------------------------------------------------------------------- Total earnings, as defined $ 941 $ 850 $ 843 $ 989 $ 828 =================================================================================================================================== Fixed Charges, as defined: Interest on long-term debt $ 185 $ 205 $ 246 $ 224 $ 181 Other interest 11 12 11 17 10 Imputed interest factor in rentals-charged principally to operating expenses 4 3 7 5 5 - ----------------------------------------------------------------------------------------------------------------------------------- Total fixed charges, as defined $ 200 $ 220 $ 264 $ 246 $ 196 =================================================================================================================================== Earnings Before Income Taxes $ 741 $ 630 $ 579 $ 743 $ 632 Ratio of Earnings Before Income Taxes to Income before 1.47 1.46 1.59 1.61 1.65 cumulative effect of change in accounting principles Income Taxes: Income tax expense $ 244 $ 207 $ 223 $ 290 $ 258 Included in AFUDC - deferred taxes in book depreciation (8) (8) (8) (8) (8) - ----------------------------------------------------------------------------------------------------------------------------------- Total income taxes $ 236 $ 199 $ 215 $ 282 $ 250 =================================================================================================================================== Fixed Charges and Preferred Dividends Combined: Preferred dividend requirements $ 3 $ 3 $ 3 $ 3 $ 3 Portion deductible for income tax purposes - - - - - Preferred dividend requirements not deductible $ 3 $ 3 $ 3 $ 3 $ 3 Preferred dividend factor: Preferred dividends not deductible times ratio of earnings before income taxes to net income $ 4 $ 4 $ 5 $ 5 $ 5 Preferred dividends deductible for income taxes - - - - - Fixed charges, as above 200 220 264 246 196 - ----------------------------------------------------------------------------------------------------------------------------------- Total fixed charges and preferred dividends combined $ 204 $ 224 $ 269 $ 251 $ 201 =================================================================================================================================== Ratio of Earnings to Fixed Charges 4.71 3.86 3.19 4.02 4.22 Ratio of Earnings to Fixed Charges and Preferred Dividends Combined 4.61 3.79 3.13 3.94 4.12
197 Exhibit 21 SUBSIDIARIES OF PROGRESS ENERGY, INC. AT DECEMBER 31, 2003 The following is a list of certain direct and indirect subsidiaries of Progress Energy, Inc. and their respective states of incorporation: Carolina Power & Light Company d/b/a PEC North Carolina Florida Progress Corporation Florida Florida Power Corporation d/b/a/ PEF Florida Progress Telecommunications Corporation Florida Progress Telecom, LLC Delaware Progress Capital Holdings, Inc. Florida Progress Fuels Corporation Florida Progress Rail Services Corporation Alabama Progress Ventures, Inc. North Carolina Strategic Resource Solutions Corp. North Carolina Progress Energy Service Company, LLC North Carolina
198 Exhibit 23(a) INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement No. 33-33520 on Form S-8, Post-Effective Amendment 1 to Registration Statement No. 33-38349 on Form S-3, Registration Statement No. 333-81278 on Form S-3, Registration Statement No. 333-81278-01 on Form S-3, Registration Statement No. 333-81278-02 on Form S-3, Registration Statement No. 333-81278-03 on Form S-3, Post-Effective Amendment 1 to Registration Statement No. 333-69738 on Form S-3, Registration Statement No. 333-70332 on Form S-8, Registration Statement No. 333-87274 on Form S-3, Post-Effective Amendment 1 to Registration Statement No. 333-47910 on Form S-3, Registration Statement No. 333-52328 on Form S-8, Post-Effective Amendment 1 to Registration Statement No. 333-89685 on Form S-8, and Registration Statement No. 333-48164 on Form S-8 of Progress Energy, Inc. of our reports dated February 20, 2004 (which express an unqualified opinion and include an explanatory paragraph concerning the adoption of new accounting principles in 2003 and 2002); appearing in this Annual Report on Form 10-K of Progress Energy, Inc. for the year ended December 31, 2003. We also consent to the incorporation by reference in Registration Statement No. 333-58800 on Form S-3 of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) of our reports dated February 20, 2004 (which express an unqualified opinion and includes an explanatory paragraph concerning the adoption of new accounting principles in 2003), appearing in this Annual Report on Form 10-K of (PEC) for the year ended December 31, 2003. /s/ Deloitte & Touche LLP Raleigh, North Carolina March 12, 2004 199 EX-10 3 pei_exhibit10c28-.txt EXHIBIT 10C(28) Exhibit 10c(28) EMPLOYMENT AGREEMENT BETWEEN PROGRESS ENERGY SERVICE COMPANY, LLC AND GEOFFREY S. CHATAS October 1, 2003 EMPLOYMENT AGREEMENT This EMPLOYMENT AGREEMENT ("Agreement"), dated as of the ____________ day of January 2004, is between Progress Energy Service Company, LLC, a limited liability company headquartered in Raleigh, North Carolina, and a wholly-owned subsidiary of Progress Energy, Inc., its successors or assigns and Geoffrey S. Chatas ("Chatas"). Progress Energy Service Company, LLC, shall be referred to as "PESC" or "the Company" throughout. Progress Energy, Inc. shall be referred to as "Progress Energy" throughout. Preamble The Company and Chatas agree to enter into an employment relationship in which Chatas will serve as Senior Vice President - Finance during the period from October 1, 2003 through December 31, 2003 and as Executive Vice President and Chief Financial Officer beginning January 1, 2004, for the term as set forth within the Agreement, and in consideration of this Agreement, the parties agree to the terms and provisions outlined herein: Provisions NOW, THEREFORE, in consideration of the mutual covenants and promises contained herein and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and accepted, the parties hereto hereby agree as follows: 1. RESPONSIBILITIES; OTHER ACTIVITIES. Chatas shall occupy the position of Senior Vice President - Finance at PESC during the period from October 1, 2003 through December 31, 2003 and the position of Executive Vice President and Chief Financial Officer beginning January 1, 2004 and shall undertake the general responsibilities and duties of such positions as directed by PESC senior management. During the Term of the Agreement as defined in Section 2, below, Chatas shall perform faithfully the duties of Chatas' position, devote all of Chatas' working time and energies to the business and affairs of PESC and shall use Chatas' best efforts, skills and abilities to promote PESC's general business interests. PESC reserves the right to reassign Chatas to other positions within the controlled group of Progress Energy companies. 2. TERM OF THE AGREEMENT: (a) The Agreement becomes effective on October 1, 2003 ("the Effective Date"), and shall remain in effect until December 31, 2005. (b) On January 1, 2004 and on January 1 of each year thereafter ("the Extension Date"), the Agreement will be extended such that each prospective term will always be three years forward ("Evergrow provisions"). 2 (c) The Company may elect to not extend the Agreement and must notify Chatas no later than 60 days prior to the Extension Date that it does not intend to renew the Agreement pursuant to paragraph 2(b), above. Should the Company elect not to renew the Agreement, the Agreement will continue in effect for the remainder of its term. (d) The Agreement cannot extend beyond Chatas' normal retirement date unless Chatas is requested to serve in his full-time position for a defined period as set forth by the Chief Executive Officer of Progress Energy. 3. BASE SALARY. As compensation for the services to be performed hereunder, Chatas will be paid an annual Base Salary ("Base Salary"). Chatas' Base Salary for 2003 will be Three Hundred Twenty-Five Thousand Dollars ($325,000.00). Chatas' Base Salary for 2004 will be Three Hundred Seventy-Five Thousand Dollars ($375,000.00). Base Salary for each subsequent year of employment under the Agreement shall be subject to adjustment by PESC during the normal annual salary review process for similarly situated executives as determined by PESC in its discretion. Annual Base Salary shall be deemed earned proportionally as Chatas performs services over the course of each year the Agreement is in effect. Payments of annual Base Salary shall be made, except as otherwise provided herein, in accordance with PESC's standard payroll policies and procedures. 4. SIGNING BONUS. In addition to his Base Salary, Chatas will receive a Seventy-Five Thousand Dollar ($75,000.00) out-of-base payment (less applicable withholdings) within thirty (30) days following his date of hire. He will receive a Seventy-Five Thousand Dollar ($75,000.00) out-of-base payment (less applicable withholdings) within thirty (30) days following the first anniversary of his date of hire; provided, however, that Chatas will not receive the second signing bonus payment if he voluntarily terminates his employment prior to the first anniversary of his date of hire. 5. RELOCATION. Chatas will be eligible to participate in the Progress Energy relocation program in accordance with its terms. 6. EMPLOYEE BENEFIT PLANS. During the Employment Term, Chatas shall be entitled to participate in all applicable Company and Progress Energy sponsored benefits plans as may be in effect upon terms and in accordance with policies and procedures equivalent to those then in effect and applicable generally to PESC employees. 7. EXECUTIVE INCENTIVES, BENEFITS AND PERQUISITES. Chatas will be eligible to participate in the following executive incentive and benefit plans and to receive the following executive perquisites: (a) Short Term Incentive Plan. Chatas is eligible to participate in the Progress Energy sponsored Management Incentive Compensation Plan (MICP), subject to its terms. 3 (b) Long Term Incentive Plans. Chatas is eligible to participate in the Progress Energy long term incentive program, subject to its terms, with the following components: (i) PSSP. An award of performance shares/units earned over a three-year period and adjusted based on Progress Energy performance. These annual awards are generally made in March. (ii) Stock Options. An award of stock options vesting 1/3, 1/3 and 1/3 on the 1st, 2nd and 3rd anniversaries, respectively, from the date of grant. These annual awards are generally granted in October. (iii) Restricted Stock. An award of restricted common stock vesting on the 3rd, 4th and 5th anniversaries, respectively, from the date of grant. These annual awards are generally made in March. Upon the Effective Date, Chatas shall receive 8,000 shares of restricted common stock in accordance with the terms of a Progress Energy restricted stock agreement. (c) Base Salary Deferral Plan. Chatas is eligible to participate in the Progress Energy sponsored Management Deferred Compensation Plan (MDCP), subject to its terms. (d) Restoration Pension Plan. Chatas is eligible to participate in the Progress Energy sponsored non-qualified pension plan ("the Restoration Retirement Plan"), subject to its terms. If Chatas becomes eligible for benefits under Progress Energy's Supplemental Senior Executive Retirement Plan, Chatas forfeits all benefits under the Restoration Retirement Plan. (e) Supplemental Senior Executive Retirement Plan. Upon meeting the Plan's eligibility requirements, Chatas shall be eligible for participation in Progress Energy's Supplemental Senior Executive Retirement Plan (SERP), subject to its terms. (f) Executive AD&D Life Insurance. Chatas shall be eligible to participate in Progress Energy's Executive AD&D Life Insurance Plan, subject to its terms. (g) Financial Planning. Consistent with PESC's practice with respect to other executives, Chatas will be reimbursed for financial planning and tax preparation. (h) Estate Planning. Chatas is eligible to receive reimbursement of up to $5,000 annually for the preparation and periodic update of Chatas' estate plan. (i) Automobile Allowance. Chatas is eligible to receive an automobile allowance of One Thousand Two Hundred Dollars ($1200) per month (less withholdings), subject to the terms of applicable PESC policies during the period from October 1, 2003 through December 31, 2003. Beginning January 1, 2004, the automobile allowance will increase to $1,350 per month. 4 (j) Annual Physical. Consistent with PESC's practice with respect to other executives, PESC will pay for an annual physical examination by a physician of Chatas' choice. (k) Luncheon Club. PESC will pay the monthly dues for a membership at the Capital City Club. Business related expenses will be reimbursed consistent with PESC's expense account guidelines. (l) Country Club Membership. PESC will pay an initiation fee and monthly dues for a membership for Chatas at a country club approved by PESC. Business related expenses will be reimbursed consistent with PESC expense account guidelines. (m) Health Club Membership. PESC will pay an initiation fee and monthly dues to a health club for Chatas' membership. (n) Home Security. PESC will install a home security system at Chatas' residence and reimburse Chatas for applicable monitoring fees. (o) Air Travel. (i) PESC will provide an airline club membership in accordance with PESC's policy. (ii) PESC will reimburse Chatas' spouse's travel expenses when she accompanies Chatas to business meetings where spousal attendance is customary. (iii) PESC will provide chartered aircraft for Chatas' business related travel as needed. (iv) PESC will allow Chatas to travel first class at his discretion for business related travel. (p) Personal Computer. PESC will provide a personal computer to Chatas to be used at his personal residence. 8. COMPANY PLAN AND PROGRAM MAINTENANCE. Chatas' entitlement to the benefits described in Sections 6 and 7 shall be governed exclusively by the terms of the plans and programs described in those provisions. Nothing in the Agreement shall require Progress Energy or the Company to continue or maintain any short term incentive, long term incentive, employee or executive benefit plan or program or any perquisite. Progress Energy and the Company shall have the right to modify, replace or eliminate any incentive or benefit plans or programs, including perquisites. 5 9. VACATION AND HOLIDAYS. Chatas will be entitled to four weeks of vacation leave per year, unless his combined years of service to Progress Energy subsidiaries entitle him to additional vacation leave pursuant to Company policy. Chatas will be granted paid holidays per Company policy. 10. TERMINATION OF EMPLOYMENT. (a) Involuntary Termination. (i) For purposes of this Agreement, PESC shall be deemed to have terminated Chatas' employment if Chatas is displaced from an assignment within the controlled group of Progress Energy subsidiaries and (1) is not simultaneously reassigned to another position within the controlled group of Progress Energy companies; or (2) in the event that Progress Energy sells more than 50% of its interest in a Progress Energy subsidiary to which Chatas is assigned to a third party during the term of Chatas' assignment, the third party purchaser does not offer Chatas a position with comparable authority, duties, wages and benefits. (ii) Termination Without Cause. During the term of this Agreement, if Chatas' employment from the controlled group of Progress Energy companies is terminated without Cause as Cause is defined in paragraph 10(a)(iii), then Chatas will be provided with his then-Base Salary at the rate at the time of termination for the remainder of the Term of the Agreement. Additionally, PESC will reimburse Chatas for the costs of continued coverage under certain health and welfare benefit plans pursuant to the Consolidated Omnibus Budget Reconciliation Act of 1985 ("COBRA") for up to eighteen (18) months after the termination of his employment; provided, however, that Chatas shall not be eligible for COBRA reimbursement if he is otherwise eligible for coverage under benefit plans offering substantially equivalent or greater benefits than the plans in which he is eligible to participate under COBRA. Receipt of the benefits in this paragraph is subject to the requirements of paragraphs 10(f), (g) and (h) of this Agreement. In addition, Chatas will be eligible to retain all benefits under existing benefit plans to the extent vested within the terms of those plans. (iii) Termination for Cause. During the Term of the Agreement, PESC may elect at any time to terminate Chatas' employment immediately hereunder and remove Chatas from employment for Cause. For purposes of this paragraph 10(a)(iii), Cause for the termination of employment shall be defined as: (1) any act of Chatas' including, but not limited to, misconduct, negligence, unlawfulness, dishonesty or inattention to the business, which is detrimental to PESC's interests; or (2) Chatas' unsatisfactory job performance or failure to comply with PESC policies, rules or regulations. If Chatas is terminated for Cause as defined herein, then he shall be eligible to retain all benefits under existing benefit plans that have vested pursuant to those plans, but he shall not be entitled to any form of salary continuation or severance benefits. Upon termination for Cause, Chatas shall be entitled to any earned but unpaid salary accrued to the date of termination. Any continued rights or benefits Chatas or his legal representatives may have under any PESC or Progress Energy sponsored employee benefit plan or program upon his termination for Cause shall be determined in accordance with the terms or provisions of the plan or program. 6 (b) Change in Control. In the event that Progress Energy experiences a Change in Control, as defined by the Progress Energy, Inc. Change in Control Plan ("the Change in Control Plan") and Chatas is (1) designated as covered by the Change in Control Plan, and (2) is Involuntarily Terminated or Constructively Terminated under the terms of the Change in Control Plan, then the greater of the benefits under the Change in Control Plan, if applicable, and the benefits available in the event of an involuntary termination without Cause as Cause is defined in paragraph 10(a)(iii), will be the legal authority regarding any severance compensation and benefits. (c) Voluntary Termination. If Chatas terminates his employment voluntarily for any reason at any time, then he shall be eligible to retain all benefits under existing benefit plans that have vested pursuant to the terms of those plans, but as of the last date of regular employment, he shall not be entitled to any form of salary continuation or other severance benefit. (d) Termination Due to Death. In the event of Chatas' death during the Term of the Agreement, Chatas' employment hereunder shall terminate and the Company shall have no further obligation to Chatas under this Agreement except as specifically provided in this Agreement. Chatas' estate shall be entitled to receive all earned but unpaid Base Salary accrued to the date of termination and any short term incentive for a prior fiscal year that has been earned but not paid. The short term incentive, if any, for the year in which Chatas' death occurs shall be calculated on a pro rata basis for the portion of the fiscal year prior to Chatas' death occurring and shall be paid at the regularly scheduled time for the payment of the short term incentive. Any rights and benefits Chatas, or Chatas' estate or other legal representatives, may have under employee benefit plans and programs of PESC or Progress Energy upon Chatas' death during the Term of the Agreement, if any, shall be determined in accordance with the terms and provisions of such plans and programs. (e) Termination Due to Medical Condition. (i) PESC may terminate Chatas' employment hereunder, subject to the Americans With Disabilities Act or other applicable law, due to medical condition if (1) for a period of 180 consecutive days during the Term of the Agreement, Chatas is totally and permanently disabled as determined in accordance with the Company's long term disability plan (LTD), if any, as in effect during such time; or (2) at any time during which no such plan is in effect, Chatas is substantially unable to perform his duties hereunder because of a medical condition for a period of 180 consecutive days during the Term of the Agreement. Provided, however, that if Chatas applies for and is deemed qualified for benefits under the Progress Energy sponsored Long Term Disability Plan (LTD Benefits), Chatas shall receive such benefits and his employment will not be terminated as long as he is receiving LTD Benefits. 7 (ii) Upon the termination of Chatas' employment due to medical condition or any period during which Chatas is qualified for LTD Benefits, PESC shall have no further obligation to Chatas under this Agreement except as specifically provided in this Agreement. Upon such termination or qualification for LTD Benefits, Chatas shall be entitled to all earned but unpaid Base Salary accrued to the date of termination or placement on LTD and any short term incentive for a prior fiscal year that has been earned but not paid. The short term incentive, if any, for the current fiscal year shall be calculated on a pro rata basis for the portion of the fiscal year Chatas was performing the duties of his position and shall be paid at the regularly scheduled time for the payment of the short term incentive. Any continued rights and benefits Chatas, or Chatas' legal representatives, may have under employee benefit plans and programs of PESC or Progress Energy upon Chatas' termination or placement on LTD due to medical condition, if any, shall be determined in accordance with the terms and provisions of such plans and programs. (f) Release of Claims. In order to receive continuation of salary under paragraph 10(a) or 10(b), Chatas agrees to execute a written release of all claims against PESC, and its employees, officers, directors, subsidiaries and affiliates, on a form acceptable to PESC. (g) Covenant Not to Compete. If PESC terminates Chatas' employment without Cause under paragraph 10(a), or if Chatas becomes eligible for the benefits available under paragraph 10(a) as the result of a Change in Control as set forth in paragraph 10(b), Chatas, for one year after the Termination Date, shall not compete directly or indirectly with the Company, or its affiliates within fifty (50) miles of any geographic area in which the Company or its affiliates has a material business interest with which Chatas was involved at the time of his separation. (h) Non Interference. If PESC terminates Chatas' employment without Cause under paragraph 10(a) or if Chatas becomes eligible for the benefits available under paragraph 10(a) as the result of a Change in Control as set forth in paragraph 10(b), Chatas, for one year after the Termination Date, shall not whether on his own account or on the account of another individual, partnership, firm, corporation, or other business organization (other than the Company and its affiliates), directly or indirectly, intentionally solicit, endeavor to entice away from the Company or any of its affiliates, or otherwise interfere with the relationship of the Company or its affiliates, any person who is employed by or otherwise engaged to perform services for the Company or its affiliates including but not limited to, any independent representatives or organizations, or any person or entity that is a customer of the Company or its affiliates. 8 11. ASSIGNABILITY. No rights or obligations of Chatas under this Agreement may be assigned or transferred by Chatas, except that (i) Chatas' rights to compensation and benefits hereunder may be transferred by will or laws of intestacy to the extent specified herein and (ii) Chatas' rights under employee benefit plans or programs described in Sections 6 and 7 may be assigned or transferred in accordance with the terms of such plans or programs, or regular practices thereunder. The Company may assign or transfer its rights and obligations under this Agreement. 12. CONFIDENTIALITY. Chatas will not disclose the terms of this Agreement except (i) to financial and legal advisors under an obligation to maintain confidentiality, or (ii) as required by a valid court order or subpoena (and in such event will use his best efforts to obtain a protective order requiring that all disclosures be kept under court seal) and will notify PESC promptly upon receipt of such order or subpoena. 13. MISCELLANEOUS. (a) Governing Law. This Agreement shall be governed by, and construed in accordance with, the laws of the State of North Carolina without reference to laws governing conflicts of law. (b) Entire Agreement. This Agreement contains all of the understandings and representations between the parties hereto pertaining to the subject matter hereof and supersedes all undertakings and agreements, whether oral or in writing, if any, previously entered into by them with respect thereto. (c) Amendment or Modification; Waiver. No provision in this Agreement may be amended or waived unless such amendment or waiver is agreed to in writing, signed by Chatas and by an officer of PESC thereunto duly authorized to do so. Except as otherwise specifically provided in the Agreement, no waiver by a party hereto of any breach by the other party hereto of any condition or provision of the Agreement to be performed by such other party shall be deemed a waiver of a similar or dissimilar provision or condition at the same or any prior or subsequent time. (d) Notice. Any notice (with the exception of notice of termination by PESC, which may be given by any means and need not be in writing except that if termination is for Cause, oral notice must be followed by written notice) or other document or communication required or permitted to be given or delivered hereunder shall be in writing and shall be deemed to have been duly given or delivered if (i) mailed by United States mail, certified, return receipt requested, with proper postage prepaid, or (ii) otherwise delivered by hand or by overnight delivery, against written receipt, by a common carrier or commercial courier or delivery service, to the party to whom it is to be given at the address of such party as set forth below (or to such other address as a party shall have designated by notice to the other parties given pursuant hereto): 9 If to Chatas: Geoffrey S. Chatas Progress Energy Service Company, LLC 410 S. Wilmington Street Raleigh, North Carolina 27601 If to PESC: Progress Energy Service Company, LLC 410 S. Wilmington Street Raleigh, North Carolina 27601 Attn.: Vice President of Human Resources Any such notice, request, demand, advice, schedule, report, certificate, direction, instruction or other document or communication so mailed or sent shall be deemed to have been duly given, if sent by mail, on the third business day following the date on which it was deposited at a United States post office, and if delivered by hand, at the time of delivery by such commercial courier or delivery service, and, if delivered by overnight delivery service, on the first business day following the date on which it was delivered to the custody of such common carrier or commercial courier or delivery service, as all such dates are evidenced by the applicable delivery receipt, airbill or other shipping or mailing document. (e) Severability. In the event that any provision or portion of this Agreement shall be determined to be invalid or unenforceable for any reason, the remaining provisions or portions of this Agreement shall be unaffected thereby and shall remain in full force and effect to the fullest extent permitted by law. (f) References. In the event of Chatas' death or a judicial determination of Chatas' incompetence, reference in this Agreement to Chatas shall be deemed, where appropriate, to refer to Chatas' legal representative, or, where appropriate, to Chatas' beneficiary or beneficiaries. (g) Headings. Headings contained herein are for convenient reference only and shall not in any way affect the meaning or interpretation of this Agreement. (h) Counterparts. This Agreement may be executed in several counterparts, each of which shall be deemed to be an original, but all of which together shall constitute one and the same instrument. (i) Rules of Construction. The following rules shall apply to the construction and interpretation of this Agreement: 10 (1) Singular words shall connote the plural number as well as the singular and vice versa, and the masculine shall include the feminine and the neuter. (2) All references herein to particular articles, paragraphs, sections, subsections, clauses, Schedules or Exhibits are references to articles, paragraphs, sections, subsections, clauses, Schedules or Exhibits of this Agreement. (3) Each party and its counsel have reviewed and revised (or requested revisions of) this Agreement, and therefore any rule of construction requiring that ambiguities are to be resolved against a particular party shall not be applicable in the construction and interpretation of this Agreement or any exhibits hereto or amendments hereof. (4) As used in this Agreement, "including" is illustrative, and means "including but not limited to." (j) Remedies. Remedies specified in this Agreement are in addition to any others available at law or in equity. (k) Withholding Taxes. All payments under this Agreement shall be subject to applicable income, excise and employment tax withholding requirements. IN WITNESS WHEREOF, the parties hereto have executed, or have caused this Agreement to be executed by their duly authorized officer, as the case may be, all as of the day and year written below. GEOFFREY S. CHATAS /s/ Geoffrey S. Chatas Date: - -------------------------------------------- ----------------------- PROGRESS ENERGY SERVICE COMPANY, LLC By: /s/ Peter M. Scott III Date: ----------------------------------- ----------------------- PETER M. SCOTT III PRESIDENT AND CHIEF EXECUTIVE OFFICER EX-31 4 pei_exhibit31-.txt EXHIBIT 31 CERTIFICATIONS Exhibit 31(a) CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Robert B. McGehee, certify that: 1. I have reviewed this annual report on Form 10-K of Progress Energy, Inc.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and c) disclosed in this annual report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors: a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: March 12, 2004 /s/ Robert B. McGehee --------------------- Robert B. McGehee President and Chief Executive Officer Exhibit 31(b) CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Geoffrey S. Chatas, certify that: 1. I have reviewed this annual report on Form 10-K of Progress Energy, Inc.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and c) disclosed in this annual report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors: a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: March 12, 2004 /s/ Geoffrey S. Chatas ---------------------- Geoffrey S. Chatas Executive Vice President and Chief Financial Officer Exhibit 31(a) CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Fred N. Day, IV, certify that: 1. I have reviewed this annual report on Form 10-K of Carolina Power & Light Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and c) disclosed in this annual report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors: a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. .. Date: March 12, 2004 /s/ Fred N. Day IV ------------------ Fred N. Day IV President and Chief Executive Officer Exhibit 31(b) CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Geoffrey S. Chatas, certify that: 1. I have reviewed this annual report on Form 10-K of Carolina Power & Light Company; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and c) disclosed in this annual report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting,, to the registrant's auditors and the audit committee of registrant's board of directors: a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. .. Date: March 12, 2004 /s/ Geoffrey S. Chatas ---------------------- Geoffrey S. Chatas Executive Vice President and Chief Financial Officer EX-32 5 pei_exhibit32-.txt EXHIBIT 32 CERTIFICATIONS Exhibit 32(a) CERTIFICATION FURNISHED PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report on Form 10-K of Progress Energy, Inc. (the "Company") for the period ending December 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Robert B. McGehee, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. /s/ Robert B. McGehee - ---------------------- Robert B. McGehee President and Chief Executive Officer March 12, 2004 A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. Exhibit 32(b) CERTIFICATION FURNISHED PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report on Form 10-K of Progress Energy, Inc. (the "Company") for the period ending December 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Geoffrey S. Chatas, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. /s/ Geoffrey S. Chatas - ----------------------- Geoffrey S. Chatas Executive Vice President and Chief Financial Officer March 12, 2004 A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. Exhibit 32(a) CERTIFICATION FURNISHED PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report on Form 10-K of Carolina Power & Light Company (the "Company") for the period ending December 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Fred N. Day, IV, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. /s/ Fred N. Day IV - ------------------- Fred N. Day IV President and Chief Executive Officer March 12, 2004 A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. Exhibit 32(b) CERTIFICATION FURNISHED PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report on Form 10-K of Carolina Power & Light Company (the "Company") for the period ending December 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Geoffrey S. Chatas, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company. /s/ Geoffrey S. Chatas - ------------------------ Geoffrey S. Chatas Executive Vice President and Chief Financial Officer March 12, 2004 A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. -----END PRIVACY-ENHANCED MESSAGE-----