-----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, BtJmHFkUMyxU1Ae19PscGrKelcjqsTXQXJnvEHQbNQ3bGHGE9C+BhgyoU/TK1JkB gXId0cJrLUIW9ghdzClthA== 0001094093-05-000056.txt : 20050316 0001094093-05-000056.hdr.sgml : 20050316 20050316121743 ACCESSION NUMBER: 0001094093-05-000056 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 13 CONFORMED PERIOD OF REPORT: 20041231 FILED AS OF DATE: 20050316 DATE AS OF CHANGE: 20050316 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: 05684137 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 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: 05684138 BUSINESS ADDRESS: STREET 1: 411 FAYETTEVILLE ST CITY: RALEIGH STATE: NC ZIP: 27601 BUSINESS PHONE: 9195466111 10-K 1 pei_2004form10k-.txt PGN_PEC 2004 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, 2004 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 required 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. [ X ] 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 . 1 As of June 30, 2004, the aggregate market value of the voting and non-voting common equity of Progress Energy, Inc. held by non-affiliates was $10,653,481,488. As of June 30, 2004, 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. As of March 4, 2005, each registrant had the following shares of common stock outstanding: Registrant Description Shares Progress Energy, Inc. Common Stock (Without Par Value) 248,533,367 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, 2005 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, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 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 DISCLOSURES 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 ITEM 9B. OTHER INFORMATION 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 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 Broad River LLC's Broad River Facility Btu British thermal unit CAIR Clean Air Interstate Rule 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, LLLP the Company Progress Energy, Inc. and subsidiaries CP&L Carolina Power & Light Company CP&L Energy CP&L Energy, Inc. CR3 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 ETS Engineering and Track-work ECRC Environmental Cost Recovery Clause EITF Emerging Issues Task Force EMCs Electric Membership Cooperatives ENCNG Eastern North Carolina Natural Gas Company, formerly referred to as EasternNC EPA of 1992 Energy Policy Act of 1992 EPIK EPIK Communications, Inc. ESOP Employee Stock Ownership Plan FASB Financial Accounting Standards Board FDEP Florida Department of Environment and Protection FERC Federal Energy Regulatory Commission FIN No. 45 Financial Accounting Standards Board (FASB) Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" FIN No. 46R FASB Interpretation No. 46R, "Consolidation of Variable Interest Entities - an Interpretation of ARB No. 51" Florida Progress or FPC Florida Progress Corporation FPSC Florida Public Service Commission Fuels Fuels business segment Funding Corp. Florida Progress Funding Corporation GAAP Accounting Principles Generally Accepted in the United States of America Genco Progress Genco Ventures LLC Georgia Power Georgia Power Company Global U.S. Global LLC Harris Plant Shearon Harris Nuclear Plant the holding company Progress Energy Corporate Interpath Interpath Communications, Inc. IBEW International Brotherhood of Electrical Workers IRS Internal Revenue Service ISO Independent System Operator 4 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 Medicare Act Medicare Prescription Drug, Improvement and Modernization Act of 2003 MGP Manufactured Gas Plant MW Megawatt MWh Megawatt-hour NC Clean Air North Carolina Clean Smokestacks Act enacted in June 2002 NCNG North Carolina Natural Gas Corporation NCUC North Carolina Utilities Commission NDE Nondestructive Examination 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 O&M Operations & Maintenance Expense Odyssey Odyssey Telecorp, Inc. OPEB Postretirement benefits other than pensions P11 Intercession Unit P11 PCH Progress Capital Holdings, Inc. PEC Progress Energy Carolinas, Inc. PEC Electric PEC Electric business segment made up of the utility operations and excludes operations of nonregulated subsidiaries PEF Progress Energy Florida 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 Preferred Securities FPC-obligated mandatorily redeemable preferred securities of FPC Capital I 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 PRP Potentially responsible party, as defined in CERCLA PSSP Performance Share Sub-Plan PTC Progress Telecommunications Corporation PT LLC Progress Telecom, LLC PUHCA Public Utility Holding Company Act of 1935, as amended PURPA Public Utilities Regulatory Policies Act of 1978 PVI Progress Energy Ventures, Inc. (formerly referred to as CPL Energy Ventures, Inc.) PWR Pressurized water reactor QF Qualifying facility Rail Services Rail Services business segment RCA Revolving credit agreement Rockport Indiana Michigan Power Company's Rockport Unit No. 2 Robinson PEC's Robinson Nuclear Plant ROE Return on Equity RSA Restricted Stock Awards program RTO Regional Transmission Organization 5 SCPSC Public Service Commission of South Carolina SEC U.S. Securities and Exchange Commission Section 29 Section 29 of the Internal Revenue Service Code (See Note/s "#") For all Sections, except the Carolina Power & Light Company Financial Statements in Part II, Item 8, this is a reference to the Notes in the Progress Energy Consolidated Financial Statements in Part II, Item 8 Service Company Progress Energy Service Company, LLC 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. 109 Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" 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. 123R Statement of Financial Accounting Standards No. 123R, "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" 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 Winchester Energy Winchester Energy Company, Ltd. (formerly Westchester Gas Company) Winchester Production Winchester Production Company, Ltd., an indirectly owned subsidiary of Progress Fuels Corporation
6 SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS Certain 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 1) 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: a) "Results of Operations" about trends and uncertainties; b) "Liquidity and Capital Resources" about operating cash flows, estimated capital requirements through the year 2007 and future financing plans; c) "Strategy" about Progress Energy, Inc.'s, strategy; and d) "Other Matters" about the effects of new environmental regulations, nuclear decommissioning costs and the effect of electric utility industry restructuring; and 2) statements made in the "Risk Factors" sections. Any forward-looking statement is based on information current as of the date of this report and speaks only as of the date on which such statement is made, and neither Progress Energy, Inc., (the Company) nor Progress Energy Carolinas (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; deregulation or restructuring in the electric industry that may result in increased competition and unrecovered (stranded) costs; the ability of the Company to implement its cost management initiatives as planned; the uncertainty regarding the timing, creation and structure of regional transmission organizations; weather conditions that directly influence the demand for electricity; the Company's ability to recover through the regulatory process, and the timing of such recovery of, the costs associated with the four hurricanes that impacted our service territory in 2004 or other future significant weather events; recurring seasonal fluctuations in demand for electricity; fluctuations in the price of energy commodities and purchased power; economic fluctuations and the corresponding impact on the Company and its subsidiaries' 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 on the Company's financial condition and ability to meet its cash and other financial obligations in the event its credit ratings are downgraded below investment grade; 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; the Company's ability to control costs, including pension and benefit expense, and achieve its cost management targets for 2007; 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 impact to the Company's financial condition and performance in the event it is determined the Company is not entitled to previously taken Section 29 tax credits; the impact of future accounting pronouncements regarding uncertain tax positions; the outcome of PEF's rate proceeding in 2005 regarding its future base rates; 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; the outcome of any ongoing or future litigation or similar disputes and the impact of any such outcome or related settlements; 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 and PEC's filings with the United States Securities and Exchange Commission (SEC). 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. The Company is 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., (PVI) began doing business under the 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 and there was no restructuring of any kind related to the name change. 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. The Progress Ventures business unit consists of the Fuels business segment (Fuels) and Competitive Commercial Operations (CCO) operating segments. 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. 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 and commodity economic hedging activities. Through its Rail Services business segment (Rail Services), Progress Energy engages in various rail and railcar-related services. In February 2005, Progress Energy signed a definitive agreement to sell its Progress Rail subsidiary for a sales price of $405 million (See Note 24). The Corporate and Other Businesses segment primarily includes Service Company activities, miscellaneous nonregulated activities and holding company operations. For information regarding the revenues, income and assets attributable to the Company's business segments, See Note 20 to the Progress Energy Consolidated Financial Statements in PART II, ITEM 8. The Company has approximately 24,000 megawatts (MW) of electric generation capacity and serves approximately 2.9 million retail electric customers in portions of North Carolina, South Carolina and Florida and also serves other load-serving entities. PEC's and PEF's customer base and demand cycles are complementary. Historically, PEC normally has a summer peaking demand, while PEF normally 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 Company's electric generation capacity and delivering reliable, competitively priced energy. Progress Energy revenues for the year ended December 31, 2004, were $9.8 billion and assets at year-end were $26.0 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 Web site 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. 8 SIGNIFICANT DEVELOPMENTS Sale of Natural Gas Assets In December 2004, the Company sold certain gas-producing properties and related assets owned by Winchester Production Company, Ltd. (Winchester Production), an indirectly owned subsidiary of Progress Fuels Corporation (Progress Fuels), which is included in the Fuels segment. Net proceeds of approximately $251 million were used to reduce debt (See Note 4A). 2004 Hurricanes Hurricanes Charley, Frances, Ivan and Jeanne struck significant portions of the Company's service territories during the third quarter of 2004, significantly impacting PEF's territory. As of December 31, 2004, restoration of the Company's systems from hurricane related damage was estimated at $398 million (See Note 3). Divestiture of Synthetic Fuel Partnership Interests In June 2004, the Company, through its subsidiary Progress Fuels, sold, in two transactions, a combined 49.8% partnership interest in Colona Synfuel Limited Partnership, LLLP, one of its synthetic fuel facilities. Substantially all proceeds from the sales will be received over time, which is typical of such sales in the industry (See Note 4B). Railcar Ltd., Divestiture 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 of approximately $75 million were used to reduce debt (See Note 4C). 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 (PT 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 PT LLC (See Note 5A). 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. Net proceeds of approximately $97 million were used to reduce debt (See Note 4D). NCNG Divestiture In September 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 $443 million were used to reduce debt (See Note 4E). 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 approximately $168 million (See Note 5B). 9 Wholesale Energy Contract Acquisition In May 2003, Progress Ventures, Inc. (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 Note 5C). Westchester Acquisition In April 2002, Progress Fuels acquired 100% of Westchester Gas Company (Westchester). During 2004, the name of the company was changed to Winchester Energy Co. Ltd., (Winchester Energy). 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 Note 5D). 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 Note 5E). Florida Progress Acquisition On November 30, 2000, the Company completed its acquisition of Florida Progress Corporation (FPC), a diversified, exempt electric utility holding company, for an aggregate purchase price of approximately $5.4 billion. The Company paid cash consideration of approximately $3.5 billion and issued 46.5 million shares of common stock valued at approximately $1.9 billion. In addition, the Company issued 98.6 million contingent value obligations (CVOs) valued at approximately $49 million. The FPC acquisition was accounted for using the purchase method of accounting and, accordingly, the results of operations for FPC have been included in the Company's Consolidated Financial Statements since the date of acquisition. 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 2004 working on a comprehensive energy bill. While that legislation passed the House, the Senate failed to pass the legislation in 2004. The Company expects that there will be an effort to resurrect the legislation in 2005. 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 nonutility 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. 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. 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. 10 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 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. These standards have been clarified and supplemented by subsequent FERC orders. The new standards of conduct govern the relationship between transmission providers and their energy affiliates in a manner that prevents excessive market power and preferential treatment. Each utility was required to submit a plan and schedule for compliance with the new rules by February 2004. PEC and PEF have complied in all material respects with all of the requirements associated with these standards and FERC orders. In April 2004, the FERC issued two orders concerning utilities' ability to sell wholesale electricity at market-based rates. In the first order, the FERC adopted two new interim screens for assessing potential generation market power of applicants for wholesale market-based rates, and described additional analyses and mitigation measures that could be presented if an applicant does not pass one of these interim screens. In July 2004, the FERC issued an order on rehearing affirming its conclusions in the April order. In the second order, the FERC initiated a rulemaking to consider whether the FERC's current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in any way. Management is unable to predict the outcome of these actions by the FERC or their effect on future results of operations and cash flows. PEF does not have market-based rate authority for wholesale sales in peninsular Florida. Given the difficulty PEC believes it would experience in passing one of the interim screens, on August 12, 2004, PEC notified the FERC that it would revise its Market-based Rate tariff to restrict it to sales outside PEC's control area and file a new cost-based tariff for sales within PEC's control area that incorporates the FERC's default cost-based rate methodologies for sales of one year or less. PEC anticipates making this filing the first quarter of 2005. On December 23, 2004, PEF advised the FERC that PEF only has market-based rate authority in Southern Company's control area in Georgia. PEF also advised the FERC that PEF filed market power studies in 2003 demonstrating that it does not have market power in that market and that because nothing has changed since that study was performed, PEF should not have to perform the new tests. Although the Company cannot predict the ultimate outcome of these changes, the Company does not anticipate that the current operations of PEC or PEF would be impacted materially if they were unable to sell power at market-based rates in their respective control areas. 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, acquisitions of securities and utility assets, and services performed by Progress Energy Service Company, LLC. While various proposals, including the 2004 energy bill, have been introduced in Congress regarding PUHCA, the prospects for legislative reform or repeal are uncertain at this time. 11 REGULATORY MATTERS GENERAL PEC is subject to regulation in North Carolina by the North Carolina Utilities Commission (NCUC), and in South Carolina by the Public Service Commission of South Carolina (SCPSC) and PEF is subject to regulation 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 cost recovery of unusual or unexpected expense, such as severe storm costs, and issuances of securities. PEC and PEF are also subject to regulation by the United States Nuclear Regulatory Commission (NRC). 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 generating units and PEF owns and operates one nuclear generating unit regulated by the 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. Nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, repairs and certain other modifications. 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. On April 19, 2004, the NRC announced that it has renewed the operating license for PEC's Robinson Nuclear Plant (Robinson) for an additional 20 years through July 2030. The original operating license of 40 years was set to expire in 2010. NRC operating licenses held by PEC currently expire in December 2014 and September 2016 for Brunswick Units 2 and 1, respectively. An application to extend these licenses 20 years was submitted in October 2004. The NRC operating license held by PEC for the Shearon Harris Nuclear Plant (Harris Plant) currently expires in October 2026. An application to extend this license 20 years is expected to be submitted in the fourth quarter of 2006. The NRC operating license held by PEF for Crystal River Unit No. 3 (CR3) currently expires in December 2016. An application to extend this license 20 years is expected to be submitted in the first quarter of 2009. A condition of the operating license for each unit requires an approved plan for decontamination and decommissioning. On February 27, 2004, PEC requested to have its license for the Independent Spent Fuel Storage Installation at the Robinson Plant extended by 20 years with an exemption request for an additional 20-year extension. Its current license is due to expire in August 2006. PEC expects to receive this extension including the exemption. 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. 12 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 Robinson reactor head was re-inspected during its 2004 outage, and no indication of control rod drive mechanism cracking or corrosion of the head was observed. The head is scheduled for replacement 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. The NRC also issued a bulletin requesting PWR licensees to address inspection plans for reactor pressure vessel lower head penetrations. The Company completed a bare metal visual inspection of the vessel bottom at Robinson during its 2004 outage and at Harris and CR3 during their 2003 outages and found no signs of corrosion or leakage at any 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 has reviewed the required inspection frequencies and has incorporated them into long-range plans. The Harris Plant will complete the required nonvisual nondestructive examination (NDE) inspection prior to February 2008. Both CR3 and Robinson will be required to inspect their new heads within seven years or four refueling outages after replacement. CR3 plans to inspect its new head prior to the end of 2009, and Robinson will need to inspect its new head prior to the end of 2012. 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 at nuclear facilities 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 completed the requirements as outlined in the orders by the committed dates. 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 (2010), 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. With certain modifications and additional approval by the NRC, including the installation of onsite dry storage facilities at PEF's nuclear unit, Crystal River Unit No. 3 (CR3), PEF's spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on PEF's system through the expiration of the operating license for CR3. See Note 23E and Note 18D to the PGN and PEC Consolidated Financial Statements, respectively, 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 Note 6D for a discussion of PEC and PEF's nuclear decommissioning costs. 13 ENVIRONMENTAL 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 2005 through 2007 are included in the "Capital Expenditures" discussion for Progress Energy under PART II, ITEM 7, "Liquidity and Capital Resources." The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liabilities. Some states, including North and South Carolina, have similar types of legislation. 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 that may require investigation and/or remediation. There are presently several sites, including manufactured gas plant (MGP) 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 a potentially responsible party (PRP). 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 determine the total costs that may be incurred in connection with all sites at this time. See Note 22 for a discussion of the Company's environmental matters. EMPLOYEES As of February 28, 2005, Progress Energy and its subsidiaries employed approximately 15,700 full-time employees. Of this total, approximately 2,400 employees at PEF are represented by the International Brotherhood of Electrical Workers (IBEW). The three-year labor contract with IBEW expires in December 2005. The Company and some of its subsidiaries have a noncontributory 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. On February 28, 2005, as part of a previously announced cost management initiative, the executive officers of the Company approved a workforce restructuring. The restructuring will result in a reduction of approximately 450 positions and is expected to be completed in September of 2005. In addition to the workforce restructuring, the cost management initiative includes a voluntary enhanced retirement program. See Note 24 for more information. As of February 28, 2005, PEC employed approximately 5,100 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, 2004, PEC had a total summer generating capacity (including jointly owned capacity) of approximately 12,482 MW. PEC distributes and sells electricity in 56 of the 100 counties in North Carolina and 14 counties in northeastern South Carolina. The service territory covers 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. At December 31, 2004, PEC was 14 providing electric services, retail and wholesale, to approximately 1.4 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, the SCPSC and the NRC. No single customer accounts for more than 10% of PEC's revenues. 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 2004 2003 2002 Residential 38% 36% 36% Commercial 25% 24% 24% Industrial 19% 18% 19% Wholesale 16% 20% 19% Other retail 2% 2% 2% Major industries in PEC's service area include textiles, chemicals, metals, paper, food, rubber and plastics, wood products and electronic machinery and equipment. FUEL AND PURCHASED POWER Sources of Generation PEC's consumption of various types of fuel depends on several factors, the most important of which are the demand for electricity by PEC's customers, the availability of various generating units, the availability and cost of fuel and the requirements of federal and state regulatory agencies. PEC's total system generation (including jointly owned capacity) by primary energy source, along with purchased power for the last three years is presented in the following table: ENERGY MIX PERCENTAGES 2004 2003 2002 Coal 47% 46% 46% Nuclear 43% 44% 42% Purchased power 6% 7% 8% Oil/Gas 3% 2% 3% Hydro 1% 1% 1% PEC is generally permitted to pass the cost of 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. See "Commodity Price Risk" under Item 7A, QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and "Risk Factors." 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) 2004 2003 2002 Coal $ 2.17 $ 2.00 $ 1.93 Nuclear 0.42 0.43 0.43 Oil 6.78 6.69 5.48 Gas 8.29 8.32 5.31 Hydro - - - Weighted-average 1.57 1.43 1.38 15 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 PEC anticipates a requirement of approximately 12.4 million to 13.0 million tons of coal in 2005. Almost all of the coal will be supplied from Appalachian coal sources in the United States and is primarily delivered by rail. For 2005, PEC has short-term, intermediate and long-term agreements from various sources for approximately 102% of its burn requirements of its coal units. All of these contracts are at fixed prices adjusted annually. The contracts have expiration dates ranging from 2005 to 2009. PEC will continue to sign contracts of various lengths, terms and quality to meet its expected burn requirements. All the coal to be purchased for PEC 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. PEC has sufficient uranium, conversion, enrichment and fabrication contracts to meet its near-term nuclear fuel requirement needs. PEC's nuclear fuel contracts typically have terms ranging from five to ten years. 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 all four 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 Oil and natural gas 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 and gas 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 4.0 million MWh, 4.5 million MWh and 5.2 million MWh of its system energy requirements during 2004, 2003 and 2002, respectively, and had available 1,498 MW, 1,810 MW and 1,737 MW of firm purchased capacity under contract at the time of peak load during 2004, 2003 and 2002, respectively. PEC may acquire additional purchased power capacity in the future to accommodate a portion of its system load needs. COMPETITION Electric Industry Restructuring PEC continues to monitor developments that may occur toward a more competitive environment and actively participates 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. 16 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. On December 22, 2004, the FERC, citing superseding events, voted to close a portion of the GridSouth docket. The GridSouth Companies asked the FERC for further clarification as to the portions of the GridSouth docket it intended to address. On March 2, 2005, the FERC affirmed that it only intended to close the mediation portion of the GridSouth docket. See Note 8D for additional discussion of current developments of GridSouth RTO. 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. The general effect of these franchises is to provide for the manner in which PEC occupies rights-of-way in incorporated areas of municipalities for the purpose of constructing, operating and maintaining an energy transmission and distribution system. 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 General PEC is subject to the jurisdiction of the NCUC and SCPSC with respect to, among other things, rates and service for electric energy sold at retail, retail service territory and issuances of securities. In addition, PEC 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 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. The Clean Smokestacks Act enacted in North Carolina in 2002 (NC Clean Air) 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 Note 22 and Note 8B to the PGN and PEC Consolidated Financial Statements, respectively, for further discussion of PEC's rate freeze. See Note 8B and Note 6B to the PGN and PEC Consolidated Financial Statements, respectively, for further discussion of PEC's retail rate developments during 2004. 17 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. See PART I, ITEM 1, "General," under Competition for further discussion of FERC screens for assessing generation market power. 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 a certain portion 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. NUCLEAR MATTERS PEC is 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. At the Brunswick Plant, Unit 1 increased its capacity by 52 MW in 2002 and by 66 MW in 2004. Brunswick Unit 2 increased its capacity by 89 MW in 2003, and an additional increase is planned for 2005. The total increased generation from all these projects is estimated to be approximately 300 MW. See PART I, ITEM 1, "Nuclear Matters," for further discussion of these and other nuclear matters. ENVIRONMENTAL MATTERS In the areas of air quality, water quality, control of toxic substances and hazardous and solid wastes and other environmental matters, PEC is subject to regulation by various federal, state and local authorities. PEC 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 PEC's existing fossil facilities that it expects to incur from 2005 through 2007 are included in the "Capital Expenditures" discussion under PART II, ITEM 7, "Liquidity and Capital Resources." The provisions of the Comprehensive Environmental Response, CERCLA, authorize the EPA to require the cleanup 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 nine former MGP sites and a number of other sites with respect to which PEC has been notified by the EPA or the State of North Carolina of its potential liability, as a PRP. Although PEC may incur costs at the sites about which it has been notified, based upon the current status of these sites, PEC cannot determine the total costs that may be incurred in connection with all sites at this time. See Notes 22 and 17 to the PGN and PEC Consolidated Financial Statements, respectively, for a discussion of PEC's environmental matters. 18 ELECTRIC - PEF GENERAL PEF, incorporated in Florida in 1899, is an operating public utility engaged in the generation, transmission, distribution and sale of electricity. At December 31, 2004, PEF had a total summer generating capacity (including jointly owned capacity) of approximately 8,544 MW. PEF provided electric service during 2004 to an average of 1.5 million customers in west central Florida. Its service territory 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 21 municipal and 9 rural electric cooperative systems. Major wholesale power sales customers include Seminole Electric Cooperative, Inc., Florida Power & Light Company, Tampa Electric Company and the City of Bartow. PEF is subject to the rules and regulations of the FERC, the FPSC and the NRC. No single customer accounts for more than 10% of PEF's revenues. 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 2004 2003 2002 Residential 53% 55% 55% Commercial 25% 24% 24% Industrial 8% 7% 7% Other retail 6% 6% 6% Wholesale 8% 8% 8% 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. FUEL AND PURCHASED POWER Sources of Generation 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 total system generation (including jointly owned capacity) by primary energy source, along with purchased power for the last three years is presented in the following table: ENERGY MIX PERCENTAGES Fuel Type 2004 2003 2002 Coal (a) 32% 36% 33% Oil 16% 16% 16% Nuclear 16% 14% 15% Gas 16% 13% 15% Purchased Power 20% 21% 21% (a) Amounts include synthetic fuel from unrelated third parties. PEF is generally permitted to pass the cost of 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 19 complete certainty. See "Commodity Price Risk" under Item 7A, QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and "Risk Factors." 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) 2004 2003 2002 Coal (a) $ 2.30 $ 2.42 $ 2.43 Oil 4.67 4.38 3.77 Nuclear 0.49 0.50 0.46 Gas 6.41 5.98 4.06 Weighted-average 3.21 3.07 2.60 (a) Amounts include synthetic fuel from unrelated third parties. 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 million tons of coal in 2005. Approximately 70% of the coal is expected to be supplied from Appalachian coal sources in the United States and 30% supplied from coal sources in South America. Approximately 67% 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 2005, Progress Fuels has medium-term and long-term contracts with various sources for approximately 115% of the burn requirements of PEF's coal units. Supply disruption caused by recent hurricanes has made it necessary to build inventories back to the traditional level of 45 days. These contracts have price adjustment provisions and have expiration dates ranging from 2005 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 Oil and natural gas 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 and gas for the reasonably foreseeable future. PEF's natural gas transportation is purchased under term firm transportation contracts with interstate pipelines. PEF purchases capacity on a seasonal basis from numerous shippers and interstate 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's nuclear fuel contracts typically have terms ranging from five to ten years. For a discussion of PEF's plans with respect to spent fuel storage, see PART I, ITEM I, "Nuclear Matters." 20 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, 2004, PEF had a variety of purchase power agreements for the purchase of approximately 1,498 MW of firm power. These agreements include (1) long-term contracts for the purchase of about 484 MW of purchased power with other investor-owned utilities, including a contract with The Southern Company for approximately 414 MW, and (2) approximately 821 MW of capacity under contract with certain QFs. The capacity currently available from QFs represents about 9% of PEF's total installed system capacity. COMPETITION Electric Industry Restructuring PEF continues to monitor developments toward a more competitive environment and actively participates 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 Florida Department of Environment and Protection (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, Florida Power & Light Company and Tampa Electric Company (collectively, 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. In December 2003, the FPSC ordered further state proceedings and established a collaborative workshop process to be conducted during 2004. In June 2004, the workshop process was abated pending completion of a cost-benefit study currently scheduled to be presented at a FPSC workshop on May 25, 2005, with subsequent action by the FPSC to be thereafter determined. 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 Note 8D for a discussion of current developments of GridFlorida RTO. Franchises PEF holds franchises with varying expiration dates in 108 of the municipalities in which it distributes electric energy. PEF also serves 13 other municipalities and in all its unincorporated areas without franchise agreements. The general purpose 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 39% of PEF's total utility revenues for 2004 were from the incorporated areas of the 108 municipalities that had franchise ordinances during the year. Since 2000, PEF has renewed 34 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 27 of the existing franchises cover a 30-year period from the date enacted. The exceptions are 23 franchises, each with a term of 10 years and expiring between 2005 and 2013; two franchises each with a term of 15 years and expiring in 2017; one 30-year franchise that was extended in 1999 for 5 years expiring in 2005; and one franchise with a term of 20 years expiring in 2020. Of the 108 franchises, 46 expire between January 1, 2005, and December 31, 2015, and 62 expire between January 1, 2016, 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. 21 Wholesale Competition See PART I, ITEM 1, "General," under Competition for a discussion of wholesale competition. 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. 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 Note 8C. In January 2005, in anticipation of the expiration of the Agreement, PEF notified the FPSC that it intends to request an increase in its base rates, effective January 1, 2006. In its notice, PEF requested the FPSC to approve calendar year 2006 as the projected test period for setting new base rates. The request for increased base rates is based on the fact that PEF has faced significant cost increases over the past decade and expects its operational costs to continue to increase. These costs include the costs associated with completion of the Hines 3 generation facility, extraordinary hurricane damage costs including capital costs which are not expected to be directly recoverable, the need to replenish the depleted storm reserve and the expected infrastructure investment necessary to meet high customer expectations, coupled with the demands placed on PEF as a result of strong customer growth. Related risks are described in more detail in the "Risk Factors" section. 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 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 FPSC's annual 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. 22 In accordance with a regulatory order, PEF accrues $6 million annually to a storm damage reserve and is allowed to defer losses in excess of the accumulated reserve for major storms. Under the order, the storm reserve is charged with operation and maintenance expenses related to storm restoration and with capital expenditures related to storm restoration that are in excess of expenditures assuming normal operating conditions. As of December 31, 2004, $291 million of hurricane restoration costs in excess of the previously recorded storm reserve of $47 million had been classified as a regulatory asset recognizing the probable recoverability of these costs. On November 2, 2004, PEF filed a petition with the FPSC to recover $252 million of storm costs plus interest from retail ratepayers over a two-year period. Hearings on PEF's petition for recovery of $252 million of storm costs filed with the FPSC are scheduled to begin on March 30, 2005 (See Note 3). PEF's January 2005 notice to the FPSC of its intent to file for an increase in its base rates effective January 1, 2006, anticipates the need to replenish the depleted storm reserve balance and adjust the annual $6 million accrual in light of recent storm history to restore the reserve to an adequate level over a reasonable time period. 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 that are also anticipated to incur investigation and remediation costs. At this time, PEF cannot determine the total costs that may be incurred in connection with the remediation of all sites. See Note 22 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 oil and gas products, blend and transload coal, mine coal and produce a solid coal-based synthetic fuel. This product has been classified as a synthetic fuel within the meaning of Section 29 of the Internal Revenue Service Code (Section 29). Sales of synthetic fuel therefore qualify for tax credits, as more fully described below. The current combined assets of Fuels that are involved in fuel extraction, manufacturing and delivery include: o Natural gas properties in Texas and Louisiana producing approximately 22 Bcf equivalent per year; o Five terminals on the Ohio River and its tributaries, part of the trucking, rail and barge network for coal delivery; o Two active coal-mining complexes, expected to produce approximately 3 to 5 million tons per year: o Four wholly owned synthetic fuel entities, a majority owned synthetic fuel entity and a minority interest in one synthetic fuel entity, capable of producing up to 16 million tons per year; o Majority-ownership in a barge partnership that transports coal products from the mouth of the Mississippi River to PEF's Crystal River 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 Note 5B). In December 2004, the Company sold certain gas-producing properties and related assets owned by Winchester Production, a wholly owned subsidiary of Progress Fuels Corporation (See Note 4A). 23 SYNTHETIC FUELS TAX CREDITS The Company has substantial operations associated with the production of coal-based synthetic fuels. The production and sale of these products qualifies for federal income tax credits so long as certain requirements are satisfied. These operations are subject to numerous risks. Although the Company believes that it operates its synthetic fuel facilities in compliance with applicable legal requirements for claiming the credits, its four Earthco facilities are under audit by the IRS. IRS field auditors have taken an adverse position with respect to the Company's compliance with one of these legal requirements, and if the Company fails to prevail with respect to this position it could incur significant liability and/or lose the ability to claim the benefit of tax credits carried forward or generated in the future. Similarly, the Financial Accounting Standards Board may issue new accounting rules that would require that uncertain tax benefits (such as those associated with the Earthco plants) be probable of being sustained in order to be recorded on the financial statements; if adopted, this provision could have an adverse financial impact on the Company. The Company's ability to utilize tax credits is dependent on having sufficient tax liability. Any conditions that negatively impact the Company's tax liability, such as weather, could also diminish the Company's ability to utilize credits, including those previously generated, and the synthetic fuel is generally not economical to produce absent the credits. Finally, the tax credits associated with synthetic fuels may be phased out if market prices for crude oil exceed certain prices. The Company's synthetic fuel operations and related risks are described in more detail in Note 23E and in the "Risk Factors" section. COMPETITION Fuels' synthetic fuel operations and coal operations compete in the eastern United States steam and 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 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 Note 22 for a discussion of Fuels' environmental matters. COMPETITIVE COMMERCIAL OPERATIONS (CCO) The CCO business segment is responsible for marketing energy in the wholesale market outside the realm of retail regulation. CCO currently owns six electricity generation facilities with approximately 3,100 MW of generation capacity, and it has contractual rights to an additional 2,500 MW of generation capacity from mixed fuel generation facilities through its agreements with 16 Georgia electric membership cooperatives (EMCs). CCO has contracts for its combined production capacity of approximately 77% for 2005, approximately 81% for 2006 and approximately 75% for 2007. The energy CCO markets is sold under both term contracts and in the spot market. CCO purchases fuel, such as oil and natural gas for use in the generation of electricity. The Company believes that there are adequate sources of fuel for CCO's expected fuel requirements. CCO also uses financial instruments to manage the risks associated with fluctuating commodity prices to hedge the economic value of its portfolio of assets. 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. In 2004, PVI executed wholesale power-supply agreements with 15 Georgia electric membership cooperatives (EMCs) to serve their electricity needs through 2010. 24 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 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 Track-work Services (ETS). 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 ETS unit focuses on rail and other track components, the infrastructure that 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. In February 2005, Progress Energy signed a definitive agreement to sell its Progress Rail subsidiary to subsidiaries of One Equity Partners LLC for a sales price of $405 million. Proceeds from the sale are expected to be used to reduce debt. See Note 24 for more information. 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 Note 4C). ENVIRONMENTAL MATTERS See Note 22 for a discussion of Rail's environmental matters. CORPORATE AND OTHER BUSINESS SEGMENT GENERAL The Corporate and Other Businesses segment includes the operations of PT LLC and Strategic Resource Solutions Corp. (SRS) and holding company operations. 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 PT 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, PT LLC; Odyssey holds a combined 45% ownership interest in PT LLC through EPIK and Caronet. The accounts of PT LLC have been included in the Company's Consolidated Financial Statements since the transaction date. 25 PT 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. PT LLC markets wholesale fiber-optic-based capacity service in the Eastern United States to long-distance carriers, Internet service providers and other telecommunications companies. PT LLC also markets wireless structure attachments to wireless communication companies and governmental entities. At December 31, 2004, PT LLC owned and managed more than 8,500 route miles and more than 420,000 fiber miles of fiber-optic cable. PT 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 Notes 7 and 10 to the PEC Consolidated Financial Statements. 26 ELECTRIC UTILITY REGULATED OPERATING STATISTICS - PROGRESS ENERGY - ---------------------------------------------------------------------------------------------------------------------------- Years Ended December 31 2004 2003 2002 2001 2000(d) - ---------------------------------------------------------------------------------------------------------------------------- Energy supply (millions of kilowatt-hours) Generated - Steam 50,782 51,501 49,734 48,732 31,132 Nuclear 30,445 30,576 30,126 27,301 23,857 Combustion Turbines/Combined Cycle 9,695 7,819 8,522 6,644 1,337 Hydro 802 955 491 245 441 Purchased 13,466 13,848 14,305 14,469 5,724 - ---------------------------------------------------------------------------------------------------------------------------- Total energy supply (Company share) 105,190 104,699 103,178 97,391 62,491 Jointly owned share (a) 5,395 5,213 5,258 4,886 4,505 - ---------------------------------------------------------------------------------------------------------------------------- Total system energy supply 110,585 109,912 108,436 102,277 66,996 - ---------------------------------------------------------------------------------------------------------------------------- Average fuel cost (per million Btu) Fossil $ 3.17 $ 2.94 $ 2.62 $ 2.46 $ 1.96 Nuclear fuel $ 0.44 $ 0.44 $ 0.44 $ 0.45 $ 0.45 All fuels $ 2.21 $ 2.05 $ 1.84 $ 1.77 $ 1.30 Energy sales (millions of kilowatt-hours) Retail Residential 35,350 34,712 33,993 31,976 15,365 Commercial 24,753 24,110 23,888 23,033 12,221 Industrial 17,105 16,749 16,924 17,204 14,762 Other Retail 4,475 4,382 4,287 4,149 1,626 Wholesale 18,323 19,841 19,204 17,715 15,012 Unbilled 449 189 275 (1,045) 1,098 - ---------------------------------------------------------------------------------------------------------------------------- Total energy sales 100,455 99,983 98,571 93,032 60,084 Company uses and losses 3,936 3,753 3,604 3,478 2,286 - ---------------------------------------------------------------------------------------------------------------------------- Total energy requirements 104,391 103,736 102,175 96,510 62,370 - ---------------------------------------------------------------------------------------------------------------------------- Electric revenues (in millions) Retail $ 6,066 $ 5,620 $ 5,515 $ 5,462 $ 2,799 Wholesale 843 915 881 923 665 Miscellaneous revenue 244 206 205 172 81 - ---------------------------------------------------------------------------------------------------------------------------- Total electric revenues $ 7,153 $ 6,741 $ 6,601 $ 6,557 $ 3,545 - ---------------------------------------------------------------------------------------------------------------------------- Peak demand of firm load (thousands of kW) System (b) 19,711 19,876 20,365 19,166 18,874 Company 19,126 19,235 19,746 18,564 18,272 Total regulated capability at year-end (thousands of kW) Fossil plants 16,522 16,522 16,006 15,826 (e) 14,747 Nuclear plants 4,286 (h) 4,220 (g) 4,127 (f) 4,008 4,008 Hydro plants 218 218 218 218 218 Purchased 2,852 2,826 2,929 2,890 2,278 - ---------------------------------------------------------------------------------------------------------------------------- Total system capability 23,878 23,786 23,280 22,942 21,251 Less jointly owned portion (c) 714 698 682 668 662 - ---------------------------------------------------------------------------------------------------------------------------- Total Company capability - regulated 23,164 23,088 22,598 22,274 20,589 - ----------------------------------------------------------------------------------------------------------------------------
(a) Amounts represent co-owner's share of the energy supplied from the six generating facilities that are jointly owned. (b) Amounts represent the combined summer noncoincident 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 MDCs were restated January 2004. (h) Amount includes power uprate for Brunswick 1; the MDC was restated January 2005. 27 REGULATED OPERATING STATISTICS - PROGRESS ENERGY CAROLINAS - ---------------------------------------------------------------------------------------------------------------------------- Years Ended December 31 2004 2003 2002 2001 2000 - ---------------------------------------------------------------------------------------------------------------------------- Energy supply (millions of kilowatt-hours) Generated - Steam 28,632 28,522 28,547 27,913 29,520 Nuclear 23,742 24,537 23,425 21,321 23,275 Combustion Turbines/Combined Cycle 1,926 1,344 1,934 802 733 Hydro 802 955 491 245 441 Purchased 4,023 4,467 5,213 5,296 4,878 - ---------------------------------------------------------------------------------------------------------------------------- Total energy supply (Company share) 59,125 59,825 59,610 55,577 58,847 Power Agency share (a) 4,794 4,670 4,659 4,348 4,505 - ---------------------------------------------------------------------------------------------------------------------------- Total system energy supply 63,919 64,495 64,269 59,925 63,352 - ---------------------------------------------------------------------------------------------------------------------------- Average fuel cost (per million Btu) Fossil $ 2.52 $ 2.29 $ 2,16 $ 1.91 $ 1.83 Nuclear fuel $ 0.42 $ 0.43 $ 0.43 $ 0.44 $ 0.45 All fuels $ 1.57 $ 1.43 $ 1.38 $ 1.26 $ 1.21 Energy sales (millions of kilowatt-hours) Retail Residential 16,003 15,283 15,239 14,372 14,091 Commercial 13,019 12,557 12,468 11,972 11,432 Industrial 13,036 12,749 13,089 13,332 14,446 Other Retail 1,432 1,408 1,437 1,423 1,423 Wholesale 13,221 15,518 15,024 12,996 14,582 Unbilled 91 (44) 270 (534) 679 - ---------------------------------------------------------------------------------------------------------------------------- Total energy sales 56,802 57,471 57,527 53,561 56,653 Company uses and losses 2,323 2,354 2,083 2,016 2,194 - ---------------------------------------------------------------------------------------------------------------------------- Total energy requirements 59,125 59,825 59,610 55,577 58,847 - ---------------------------------------------------------------------------------------------------------------------------- Electric revenues (in millions) Retail $ 2,953 $ 2,824 $ 2,796 $ 2,666 $ 2,609 Wholesale 575 687 651 634 577 Miscellaneous revenue 100 78 92 44 122 - ---------------------------------------------------------------------------------------------------------------------------- Total electric revenues $ 3,628 $ 3,589 $ 3,539 $ 3,344 $ 3,308 - ---------------------------------------------------------------------------------------------------------------------------- Peak demand of firm load (thousands of kW) (g) System 11,192 11,771 11,977 11,376 11,157 Company 10,607 11,130 11,358 10,774 10,555 Total regulated capability at year-end (thousands of kW) Fossil plants 8,816 8,816 8,816 8,648 (c) 7,569 Nuclear plants 3,448 (f) 3,382 (e) 3,293 (d) 3,174 3,174 Hydro plants 218 218 218 218 218 Purchased 1,545 1,513 1,617 1,586 978 - ---------------------------------------------------------------------------------------------------------------------------- Total system capability 14,027 13,929 13,944 13,626 11,939 Less Power Agency-owned portion (b) 645 629 613 599 593 - ---------------------------------------------------------------------------------------------------------------------------- Total Company capability 13,382 13,300 13,331 13,027 11,346 - ----------------------------------------------------------------------------------------------------------------------------
(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. (f) Amount includes power uprate for Brunswick 1; the MDC was restated January 2005. (g) Amount is the summer peak demand. 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, 2004, PEC's 18 generating plants represent a flexible mix of fossil, nuclear, hydroelectric, combustion turbines and combined cycle resources, with a total summer generating capacity of 12,482 MW. Of this total, Power Agency owns approximately 694 MW. On December 31, 2004, 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, N.C. 2 1964-1971 Coal 100 392 Cape Fear Moncure, N.C. 2 1956-1958 Coal 100 316 Lee Goldsboro, N.C. 3 1952-1962 Coal 100 407 Mayo Roxboro, N.C. 1 1983 Coal 83.83 745 (b) Robinson Hartsville, S.C. 1 1960 Coal 100 174 Roxboro Roxboro, N.C. 4 1966-1980 Coal 96.32 (c) 2,462 (b) Sutton Wilmington, N.C. 3 1954-1972 Coal 100 613 Weatherspoon Lumberton, N.C. 3 1949-1952 Coal 100 176 -------- --------------- Total 19 5,285 COMBINED CYCLE Cape Fear Moncure, N.C. 2 1969 Oil 100 84 Richmond Hamlet, N.C. 1 2002 Gas/Oil 100 472 -------- --------------- Total 3 556 COMBUSTION TURBINES Asheville Skyland, N.C. 2 1999-2000 Gas/Oil 100 330 Blewett Lilesville, N.C. 4 1971 Oil 100 52 Darlington Hartsville, S.C. 13 1974-1997 Gas/Oil 100 812 Lee Goldsboro, N.C. 4 1968-1971 Oil 100 91 Morehead City Morehead City, N.C. 1 1968 Oil 100 15 Richmond Hamlet, N.C. 5 2001-2002 Gas/Oil 100 775 Robinson Hartsville, S.C. 1 1968 Gas/Oil 100 15 Roxboro Roxboro, N.C. 1 1968 Oil 100 15 Sutton Wilmington, N.C. 3 1968-1969 Gas/Oil 100 64 Wayne County Goldsboro, N.C. 4 2000 Gas/Oil 100 668 Weatherspoon Lumberton, N.C. 4 1970-1971 Gas/Oil 100 138 -------- --------------- Total 42 2,975 NUCLEAR Brunswick Southport, N.C. 2 1975-1977 Uranium 81.67 1,838 (b)(d) Harris New Hill, N.C. 1 1987 Uranium 83.83 900 (b) Robinson Hartsville, S.C. 1 1971 Uranium 100 710 -------- --------------- Total 4 3,448 HYDRO Blewett Lilesville, N.C. 6 1912 Water 100 22 Marshall Marshall, N.C. 2 1910 Water 100 5 Tillery Mount Gilead, N.C. 4 1928-1960 Water 100 86 Walters Waterville, N.C. 3 1930 Water 100 105 -------- --------------- Total 15 218 TOTAL 83 12,482 - -----------------------------------------------------------------------------------------------------------
(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 2004, a power uprate increased the net summer capability of Unit 1 to 938 MW. The MDC was restated in January 2005. 29 At December 31, 2004, including both the total generating capacity of 12,482 MW and the total firm contracts for purchased power of approximately 1,545 MW, PEC had total capacity resources of approximately 14,027 MW. The Power Agency has 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, 2004, PEC had approximately 6,000 circuit miles of transmission lines including 300 miles of 500 kilovolt (kV) lines and 3,000 miles of 230 kV lines. PEC also had approximately 45,000 circuit miles of overhead distribution conductor and 18,000 circuit miles of underground distribution cable. Distribution and transmission substations in service had a transformer capacity of approximately 12,000,000 kilovolt-ampere (kVA) in 2,405 transformers. Distribution line transformers numbered approximately 509,700 with an aggregate capacity of approximately 21,000,000 kVA. ELECTRIC - PEF At December 31, 2004, PEF's 14 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, 2004, 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, Fla. 2 1974-1978 Gas/Oil 100 993 Bartow St. Petersburg, Fla. 3 1958-1963 Gas/Oil 100 444 Crystal River Crystal River, Fla. 4 1966-1984 Coal 100 2,302 Suwannee River Live Oak, Fla. 3 1953-1956 Gas/Oil 100 143 -------- ----------------- Total 12 3,882 COMBINED CYCLE Hines Bartow, Fla. 2 1999-2003 Gas/Oil 100 998 Tiger Bay Fort Meade, Fla. 1 1997 Gas 100 207 -------- ----------------- Total 3 1,205 COMBUSTION TURBINES Avon Park Avon Park, Fla. 2 1968 Gas/Oil 100 52 Bartow St. Petersburg, Fla. 4 1958-1972 Gas/Oil 100 187 Bayboro St. Petersburg, Fla. 4 1973 Oil 100 184 DeBary DeBary, Fla. 10 1975-1992 Gas/Oil 100 667 Higgins Oldsmar, Fla. 4 1969-1970 Gas/Oil 100 122 Intercession City Intercession City, 14 1974-2000 Gas/Oil 100 (c) 1,041 (b) Fla. Rio Pinar Rio Pinar, Fla. 1 1970 Oil 100 13 Suwannee River Live Oak, Fla. 3 1980 Gas/Oil 100 164 Turner Enterprise, Fla. 4 1970-1974 Oil 100 154 University of Gainesville, Fla. 1 1994 Gas 100 35 Florida Cogeneration -------- ----------------- Total 47 2,619 NUCLEAR Crystal River Crystal River, Fla. 1 1977 Uranium 91.78 838 (b) -------- ----------------- 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. At December 31, 2004, PEF had total capacity resources of approximately 10,042 MW, including both the total generating capacity of 8,544 MW and the total firm contracts for purchased power of 1,498 MW. 30 Several entities have acquired undivided ownership interests in CR3 in the aggregate amount of 8.22%. 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, 2004, PEF had approximately 5,000 circuit miles of transmission lines including 200 miles of 500 kV lines and about 1,500 miles of 230 kV lines. PEF also had approximately, 22,000 circuit miles of overhead distribution conductor and 13,000 circuit miles of underground distribution cable. Distribution and transmission substations in service had a transformer capacity of approximately 45,000,000 kVA in 616 transformers. Distribution line transformers numbered approximately 365,000 with an aggregate capacity of approximately 18,000,000 kVA. FUELS Progress Fuels controls, either directly or through subsidiaries, coal reserves located in eastern Kentucky and southwestern Virginia of approximately 46 million tons and controls, through mineral leases, additional estimated coal reserves of approximately 48 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. Progress Fuels' total production of coal during 2004 was approximately 3.4 million tons. In connection with its coal operations, Progress Fuels' business units own and operate surface and underground mines, coal processing and loadout facilities in southeastern Kentucky and southwestern Virginia. Other subsidiaries own and operate a river terminal facility in eastern Kentucky, a railcar-to-barge loading facility in West Virginia, two bulk commodity terminals on the Kanawha River near Charleston, West Virginia, and a bulk commodity terminal on the Ohio River near Huntington, West Virginia. Progress Fuels and its subsidiaries employ both Company and contract miners in their mining activities. The Fuels business segment, through its business units, has an interest in six synthetic fuel entities. Four of the entities are wholly owned, one is majority owned and one is minority owned. These facilities are in six different locations in West Virginia, Virginia and Kentucky. Fuels' oil and gas production in 2004 was 30.4 Bcf equivalent. Fuels has oil and gas leases in East Texas and Louisiana with total proven oil and gas reserves of approximately 247 Bcf equivalent. CCO At December 31, 2004, 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, N.C. 1Q 2000 2Q 2001 Simple-Cycle, 3 459 Walton (c) Monroe, Ga. 2Q 2000 2Q 2001 Simple-Cycle, 3 460 DeSoto Units Arcadia, Fla. 2Q 2001 2Q 2002 Simple-Cycle, 2 320 Effingham Rincon, Ga. 1Q 2001 3Q 2003 Combined-Cycle, 1 480 Rowan Phase II (b) Salisbury, N.C. 4Q 2001 2Q 2003 Combined-Cycle, 1 466 Washington (c) Sandersville, 2Q 2002 2Q 2003 Simple-Cycle, 4 600 Ga. - -------------------------------------------------------------------------------------------------------------- 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 2,000 railcars and 50 locomotives that are used for the transportation and shipping of coal, steel and other bulk products. In February 2005, Progress Energy signed a definitive agreement to sell its Progress Rail subsidiary to subsidiaries of One Equity Partners LLC for a sales price of $405 million. Proceeds from the sale are expected to be used to reduce debt. See Note 24 for more information. PT LLC PT LLC provides wholesale telecommunications services throughout the Southeastern United States. PT LLC incorporates more than 420,000 fiber miles of fiber-optic cable in its network, including more than 189 Points-of-Presence, or physical locations where a presence for network access exists. 32 ITEM 3. LEGAL PROCEEDINGS Legal proceedings are included in the discussion of the Company's business in PART I, ITEM 1 under "Environmental Matters," and are incorporated by reference herein. 1. 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 Coast 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) an 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, in March 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. Following briefing and argument on a number of dispositive motions on successive versions of Global's complaint, on August 16, 2004, the Progress Affiliates answered the Fourth Amended Complaint by generally denying all of Global's substantive allegations and asserting numerous affirmative defenses. The parties are currently engaged in discovery 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 appealed the Superior court's order staying the case. By order dated September 7, 2004, the North Carolina Court of Appeals dismissed the Progress Affiliates' appeal. The Company cannot predict the outcome of these matters, but will vigorously defend against the allegations. 2. In re Progress Energy, Inc. Securities Litigation, Master File No. 04-CV-636 (JES) 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 by Gerber Asset Management LLC in the United States District Court for the Southern District of New York and names Progress Energy, Inc.'s former 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. On March 31, 2004, a second class action complaint was filed by Stanley Fried, Raymond X. Talamantes and Jacquelin Talamantes against William Cavanaugh III and Progress Energy, Inc. in the United States District Court for the Southern District of New York alleging violations of federal securities laws arising out of the Company's issuance of CVOs nearly identical to those alleged in the February 3, 2004, Gerber Asset Management complaint. On April 29, 2004, the Honorable John E. Sprizzo ordered among other things that (1) the two class action cases be consolidated, (2) Peak6 Capital Management LLC shall serve as the lead plaintiff in the consolidated action, and (3) the lead plaintiff shall file a consolidated amended complaint on or before June 15, 2004. 33 The lead plaintiff filed a consolidated amended complaint on June 15, 2004. In addition to the allegations asserted in the Gerber Asset Management and Fried complaints, the consolidated amended complaint alleges that the Company failed to disclose that excess fuel credits could not be carried over from one tax year into later years. On July 30, 2004, the Company filed a motion to dismiss the complaint; plaintiff submitted its opposition brief on September 14, 2004. The Court heard oral argument on the Company's motion to dismiss on November 15, 2004; it has not, to date, rendered a decision on this motion. The Company cannot predict the outcome of this matter, but will vigorously defend against the allegations. For a discussion of certain other legal matters, see Note 23E to the Progress Energy Consolidated Financial Statements. 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 61 Chairman and Chief Executive Officer, Progress Energy, May 2004 and March 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 60 Group President, Energy Supply, PEC and PEF, November 2000 to present. (separating from the Company, effective April 1, 2005.) Mr. Orser is responsible for the operation of 38 utility and nonregulated power plants of Progress Energy. He also oversees plant construction and the organizations that support those plants, including 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 FPC 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 51 President and Chief Operating Officer, Progress Energy, January 2005 to present; Group President, PEC, January 2005 to present; Executive Vice President, PEC and PEF, November 2000 to present. Mr. Johnson has been with Progress Energy (formerly CP&L) since 1992 and most recently served as Group President, Energy Delivery, Progress Energy, January 2004 to December 2004. Prior to that, he was President, CEO and Corporate Secretary, Progress Energy Service Company, LLC, October 2002 to December 2003. He also served as 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 55 President and Chief Executive Officer, Progress Energy Service Company, LLC, January 2004 to present; Executive Vice President, PEC and PEF, 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 president of Scott, Madden & Associates, Inc., a general management consulting firm headquartered in Raleigh, N.C. that he founded in 1983. 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 42 Executive Vice President and Chief Financial Officer, Progress Energy, Inc., Progress Energy Service Company, LLC, 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, October 2003 to December 2003. Mr. Chatas served in various positions with American Electric Power (AEP), a multi-state energy holding company based in Columbus, Ohio from 1997 until he joined Progress Energy. Mr. Chatas' last position at AEP was Senior Vice President - Finance and Treasurer for AEP. 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. 50 Chief Accounting Officer and Controller, Progress Energy, Inc., June 2000 to present; Controller, FPC and PEF, November 2000 to present; Chief Accounting Officer, FPC, 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, Fla. Donald K. Davis 59 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 36 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 61 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. 62 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. C. S. Hinnant 60 Senior Vice President and Chief Nuclear Officer, PEC, June 1998 to present. Mr. Hinnant is also Senior Vice President, PEF, November 2000 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. *Jeffrey J. Lyash 43 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, N.C. His last position at Brunswick was as Director of site operations. John R. McArthur 49 Senior Vice President, General Counsel and Secretary of Progress Energy, January 2004 to present. Mr. McArthur oversees the Audit Services, Corporate Communications, Legal, Regulatory and Corporate Relations - Florida, and State Public Affairs departments, and the Environmental and Health and Safety sections. Mr. McArthur is also Senior Vice President and Corporate Secretary, FPC 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, 37 handling major policy initiatives as well as media and legal affairs. He also directed Governor Easley's transition team after the election of 2000. From November of 1997 until November of 2000, Mr. McArthur handled state government affairs in 10 southeastern states for General Electric Co. Prior to joining General Electric Co., Mr. McArthur 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 56 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. Lloyd M. Yates 44 Senior Vice President, PEC, January 2005 to present. Mr. Yates is responsible for managing the four regional vice presidents in the PEC organization. He served PEC as Vice President - Transmission from November 2003 to December 2004. Mr. Yates served as Vice President - Fossil Generation for PEC from 1998 to 2003. Before joining the Company in 1998, Mr. Yates was with PECO Energy, where he had served in a number of engineering and management roles over 16 years. His last position with PECO was as general manager -Operations in the Company's power operations group.
*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, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Progress Energy Progress Energy's Common Stock is listed on the New York Stock Exchange. The high and low intra-day stock sales prices for each quarter for the past two years, and the dividends declared per share are as follows: - -------------------------------------------------------------------------------- 2004 High Low Dividends Declared - -------------------------------------------------------------------------------- First Quarter $ 47.95 $ 43.02 $0.575 Second Quarter 47.50 40.09 0.575 Third Quarter 44.32 40.76 0.575 Fourth Quarter 46.10 40.47 0.590 - -------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------- The December 31 closing price of the Company's Common Stock was $45.24 for 2004 and $45.26 for 2003. As of March 4, 2005, the Company had 67,160 holders of record of Common Stock. Neither Progress Energy's Articles of Incorporation nor any of its debt obligations contain any restrictions on the payment of dividends. Progress Energy's subsidiaries have provisions restricting dividends in certain limited circumstances (See Note 13B). Issuer purchases of equity securities for fourth quarter of 2004 are as follows: - ---------------------------------------------------------------------------------------------------------------- (a) (b) (c) (d) Maximum Number (or Total Number of Shares Approximate Dollar Total Number of Average (or Units) Purchased as Value) of Shares (or Shares Price Paid Part of Publicly Units) that May Yet Be (or Units) Per Share Announced Plans or Purchased Under the Period Purchased(1) (or Unit) Programs(1) Plans or Programs(1) - ---------------------------------------------------------------------------------------------------------------- October 1 - October 31(2) 191,436 $ 41.90 N/A N/A - ---------------------------------------------------------------------------------------------------------------- November 1 - November 30 N/A N/A N/A N/A - ---------------------------------------------------------------------------------------------------------------- December 1 - December 31 N/A N/A N/A N/A - ---------------------------------------------------------------------------------------------------------------- Total: 191,436 $ 41.90 N/A N/A - ----------------------------------------------------------------------------------------------------------------
(1) As of December 31, 2004, Progress Energy does not have any publicly announced plans or programs to purchase shares of its common stock. (2) All shares were purchased in open-market transactions by the plan administrator to satisfy share delivery requirements under the Progress Energy 401(k) Savings and Stock Ownership Plan (See Note 11A). PEC Since 2000, Progress Energy has owned all of PEC's common stock, and as a result there is no established public trading market for the stock. PEC has not issued or repurchased any equity securities since becoming a wholly owned subsidiary of Progress Energy. For the past three years, PEC has paid quarterly dividends to Progress Energy totaling the amounts shown in the Statements of Common Equity in the PEC Consolidated Financial Statements. PEC has provisions restricting dividends in certain limited circumstances (See Note 8 and 13 to the PEC Consolidated Financial Statements). 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. (in millions, except per share data) - ---------------------------------------------------------------------------------------------------------------------- Years Ended December 31 2004 2003 2002 2001 2000(a) - ---------------------------------------------------------------------------------------------------------------------- Operating results Operating revenues $ 9,772 $ 8,741 $ 8,091 $ 8,129 $ 3,769 Income from continuing operations before cumulative $ 753 $ 811 $ 552 $ 541 $ 478 effect Net Income $ 759 $ 782 $ 528 $ 542 $ 478 Per share data Basic earnings Income from continuing operations $ 3.11 $ 3.42 $ 2.54 $ 2.64 $ 3.04 Net income $ 3.13 $ 3.30 $ 2.43 $ 2.65 $ 3.04 Diluted earnings Income from continuing operations $ 3.10 $ 3.40 $ 2.53 $ 2.63 $ 3.03 Net income $ 3.12 $ 3.28 $ 2.42 $ 2.64 $ 3.03 Assets (c) $ 25,993 $ 26,093 $ 24,272 $ 23,701 $ 22,875 Capitalization Common stock equity $ 7,633 $ 7,444 $ 6,677 $ 6,004 $ 5,424 Preferred stock of subsidiaries - not subject to mandatory redemption 93 93 93 93 93 Minority interest 36 30 18 12 - Long-term debt, net (b) 9,521 9,934 9,747 8,619 4,904 Current portion of long-term debt 349 868 275 688 184 Short-term obligations 684 4 695 942 4,959 - --------------------------------------------------------------------------------------------------------------------- Total capitalization and total debt $ 18,316 $ 18,373 $ 17,505 $ 16,358 $ 15,564 - --------------------------------------------------------------------------------------------------------------------- Dividends declared per common share $ 2.32 $ 2.26 $ 2.20 $ 2.14 $ 2.08 - ---------------------------------------------------------------------------------------------------------------------
(a) Operating results and balance sheet data include information for FPC since November 30, 2000, the date of acquisition. (b) Includes long-term debt to affiliated trust of $270 million at December 31, 2004, and 2003 (See Note 19). (c) All periods have been restated for the reclassification of certain cost of removal amounts. 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. - ------------------------------------------------------------------------------------------------------------------ (in millions) Years Ended December 31 2004 2003 2002 2001 2000(a) - ------------------------------------------------------------------------------------------------------------------ Operating results Operating revenues $ 3,629 $ 3,600 $ 3,554 $ 3,360 $ 3,528 Net income $ 461 $ 482 $ 431 $ 364 $ 461 Earnings for common stock $ 458 $ 479 $ 428 $ 361 $ 458 Assets (c) $ 10,787 $ 10,938 $ 10,442 $ 10,640 $ 10,552 Capitalization Common stock equity $ 3,072 $ 3,237 $ 3,089 $ 3,095 $ 2,852 Preferred stock - not subject to mandatory redemption 59 59 59 59 59 Long-term debt, net 2,750 3,086 3,048 2,698 3,134 Current portion of long-term debt 300 300 - 600 - Short-term obligations (b) 337 29 438 309 486 - ------------------------------------------------------------------------------------------------------------------ Total capitalization and total debt $ 6,518 $ 6,711 $ 6,634 $ 6,761 $ 6,531 - ------------------------------------------------------------------------------------------------------------------
(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) Includes notes payable to affiliated companies, related to the money pool program, of $116 million, $25 million and $48 million at December 31, 2004, 2003 and 2001, respectively. (c) All periods have been restated for the reclassification of certain cost of removal amounts. 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 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, which are located in Kentucky, West Virginia and Virginia; and o Rail Services (Rail) - engaged in various rail and railcar-related services in 23 states, Mexico and Canada. The Progress Ventures business unit consists of the Fuels and CCO operating segments. The Corporate and Other category includes other businesses engaged in other nonregulated business areas, including telecommunications, primarily in the eastern United States, and energy services operations and holding company results, which do not meet the requirements for separate segment reporting disclosure. In 2004, the Company realigned its business segments to no longer report the other nonregulated businesses as a reportable business segment. For comparative purposes, 2003 and 2002 segment information has been restated to align with the 2004 reporting structure. Strategy Progress Energy is an integrated energy company, with its primary focus on the end-use and wholesale electricity markets. The Company operates in retail utility markets in the southeastern United States and competitive markets in the eastern United States. The target is to develop a business mix of approximately 80% regulated and 20% nonregulated business. The Company is focused on achieving the following key goals: restoring balance sheet strength and flexibility, disciplined capital and operations and maintenance (O&M) management to support earnings and current dividend policy and achieving constructive regulatory frameworks in all three regulated jurisdictions. A summary of the significant financial objectives or issues impacting Progress Energy, its regulated utilities and nonregulated operations is addressed more fully in the following discussion. PROGRESS ENERGY, INC. Progress Energy has several key financial objectives, the first of which is to achieve sustainable earnings growth in its three core energy businesses, which include PEC Electric, PEF and Progress Ventures (excluding synthetic fuels). In addition, the Company seeks to continue its track record of dividend growth, as the Company has increased its dividend for 17 consecutive years, and 29 of the last 30. The Company also seeks to restore balance sheet strength and flexibility by reducing its debt to total capitalization ratio through selected asset sales, free cash flow (defined as cash from operations less capital expenditures and common dividends) and increased equity from retained earnings and ongoing equity issuances. 42 In the short-term, the Company's ability to achieve its objectives will be impacted by, among other things, its ability to recover storm costs incurred during 2004, cash flow available to reduce debt after funding capital expenditures and common dividends, obtaining a reasonable rate agreement in Florida at the expiration of the current agreement in December 2005 and the outcome of the ongoing Internal Revenue Service (IRS) audit of the Company's synthetic fuel facilities. The Company's long-term challenges include escalating nonfuel operating costs, the need for sufficient earnings growth to sustain the track record of dividend growth, and the scheduled expiration of the Section 29 tax credit program for its synthetic fuels business at the end of 2007. The Company's ability to meet its financial objectives is largely dependent on the earnings and cash flows of its two regulated utilities. The regulated utilities contributed $797 million of net income and produced 100% of consolidated cash flow from operations in 2004. In addition, Fuels contributed $180 million of net income, of which $91 million represented synthetic fuel net income. Partially offsetting the net income contribution provided by the regulated utilities and Fuels was a loss of $236 million recorded at Corporate and Other, primarily related to interest expense on holding company debt. While the Company's synthetic fuel operations currently provide significant earnings that are scheduled to expire at the end of 2007, the associated cash flow benefits from synthetic fuels are expected to come in the future when deferred tax credits are ultimately utilized. Credits that have been generated but not yet utilized are carried forward indefinitely as alternative minimum tax credits and will provide positive cash flow when utilized. At December 31, 2004, deferred credits were $745 million. See Note 23E and the "Risk Factors" section for additional information on the Company's synthetic fuel operations and its ability to utilize its current and future tax credits. Progress Energy reduced its debt to total capitalization ratio to 57.6% at the end of 2004 as compared to 58.8% at the end of 2003. The Company seeks to continue to improve this ratio as it plans to reduce total debt with proceeds from asset sales, free cash flow (defined as cash from operations less capital expenditures and common dividends) and growth in equity from retained earnings and ongoing equity issuances. The Company expects total capital expenditures to be approximately $1.3 billion in both 2005 and 2006. Progress Energy's ratings outlook was changed to "negative" from "stable" in 2004 by both Moody's and Standard & Poor's (S&P). Both ratings agencies cited the uncertainty around the timing of storm cost recovery, potential delays in the Company's de-leveraging plan, uncertainty about the upcoming rate case in Florida and uncertainty about the IRS audit of the Company's synthetic fuel partnerships in their ratings actions. The change in outlook has not materially affected Progress Energy's access to liquidity or the cost of its short-term borrowings. If Standard & Poor's lowers Progress Energy's senior unsecured rating one ratings category to BB+ from its current rating, it would be a noninvestment grade rating. The effect of a noninvestment grade rating would primarily be to increase borrowing costs. The Company's liquidity would essentially remain unchanged as the Company believes it could borrow under its revolving credit facilities instead of issuing commercial paper for its short-term borrowing needs. However, there would be additional funding requirements of approximately $450 million due to ratings triggers embedded in various contracts. See "Guarantees" Section under FUTURE LIQUIDITY AND CAPITAL RESOURCES below and "Risk Factors" for more information regarding the potential impact on the Company's financial condition and results of operations resulting from a ratings downgrade. REGULATED UTILITIES The regulated utilities earnings and operating cash flows are heavily influenced by weather, including related storm damage, 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 forecasted to have income and population growth higher than the U.S. average. In recent years, lower industrial sales mainly related to weakness in the textile sector at PEC Electric have negatively impacted earnings growth. The Company does not expect any significant improvement in industrial sales in the near term. These combined factors under normal weather conditions are expected to contribute approximately 2% annual retail kilowatt-hour (KWh) sales growth at PEC Electric and approximately 3% annual retail kilowatt-hour (KWh) sales growth at PEF through at least 2007. The utilities must continue to invest significant capital in new generation, transmission and distribution facilities to support this load growth. Subject to regulatory approval, these investments are expected to increase the utilities' rate base, upon which additional return can be realized that creates the basis for long-term financial growth in the utilities. The Company will meet this load growth through the two previously planned approximately 500 MW combined-cycle units at PEF's Hines Energy Complex in 2005 and 2007. The contribution from the utilities' regulated wholesale business is expected to increase slightly in 2005 and be relatively flat over the following few years. 43 While the two utilities expect retail sales growth in the future, they are facing rising costs. The Company began a cost-management initiative in late 2004 to permanently reduce by $75-$100 million the projected growth in the Company's annual nonfuel O&M costs by the end of 2007. See "Cost Management Initiative" under RESULTS OF OPERATIONS for more information. The utilities expect capital expenditures to be approximately $1.1 billion in both 2005 and 2006. The Company will continue an approximate $900 million program of installing new emission-control equipment at PEC's coal-fired power plants in North Carolina. Operating cash flows are expected to be sufficient to fund capital spending in 2005 and in 2006. The costs associated with the unprecedented series of major hurricanes that impacted the Company's service territories significantly impacted the utility operations in 2004. Restoration of the Company's systems from hurricane-related damage cost almost $400 million. Although PEF has filed for recovery of approximately $252 million of these storm costs, the timing of recovery is not certain at this time. See OTHER MATTERS below for more information on storm costs incurred during 2004. 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. 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 an agreement not to seek a base retail electric rate increase in South Carolina through 2005. PEF is operating under a retail rate agreement in Florida through 2005. PEF has initiated a rate proceeding in 2005 regarding its future base rates. See Note 8 for further discussion of the utilities' retail rates. 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 2004, CCO entered into additional wholesale power contracts with cooperatives in Georgia and will serve approximately one-third of the Georgia cooperative market starting in 2005. CCO completed the build out of its nonregulated generation assets in 2003 and currently has total capacity of 3,100 MW. The Company has no current plans to expand its portfolio of nonregulated generating plants. CCO short-term challenges include absorbing the fixed costs associated with these plants and the general weakness in wholesale power markets. Three above-market tolling agreements for approximately 1,200 MW of capacity expired at the end of 2004. CCO has replaced the expired agreements with the increased cooperative load in Georgia. The increased cooperative load in Georgia will significantly increase CCO's revenue and cost of sales from 2004 to 2005 with lower margins expected. Currently CCO has contracts for its planned production capacity, which includes callable resources from the cooperatives, of approximately 77% for 2005, 81% for 2006 and 75% for 2007. CCO will continue its optimization strategy for the nonregulated generation portfolio. 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 continue its presence in natural gas markets that will allow it to provide attractive returns for the Company's shareholders. The Company has begun exploring strategic alternatives regarding the Fuels' coal mining business, which could include divesting assets. As of December 31, 2004, the carrying value of long-lived assets of the coal mining business was $66 million. 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. The production and sale of the synthetic fuel from these facilities qualifies for tax credits under Section 29 if certain requirements are satisfied. These facilities have private letter rulings (PLRs) from the IRS with respect to their synthetic fuel operations. However, these PLRs do not address placed-in-service date requirements. The Company has resolved certain synthetic fuel tax credit issues with the IRS and 44 is continuing to work with the IRS to resolve any remaining issues. The Company cannot predict the final resolution of any outstanding matters. 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 8 to 12 million tons of synthetic fuel in 2005. Through December 31, 2004, the Company had generated approximately $1.5 billion of synthetic fuel tax credits to date (including FPC prior to the acquisition by the Company). See additional discussion of synthetic fuel tax credits in Note 23E and in the "Risk Factors" section. In February 2005, Progress Energy signed a definitive agreement to sell its Progress Rail subsidiary to subsidiaries of One Equity Partners LLC for a sales price of $405 million. Proceeds from the sale are expected to be used to reduce debt. See Note 24 for more information. 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 2004 AS COMPARED TO 2003 AND 2003 AS COMPARED TO 2002 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. Overview For the year ended December 31, 2004, Progress Energy's net income was $759 million or $3.13 per share compared to $782 million or $3.30 per share for the same period in 2003. The decrease in net income as compared to prior year was due primarily to: o Reduction in synthetic fuel earnings due to lower synthetic fuel sales due to the impact of hurricanes during the year. o Lower off-system wholesale sales, primarily at PEC Electric. o Higher O&M expenses at PEC Electric. o Recording of litigation settlement reached in the civil suit by Strategic Resource Solutions (SRS). o Decreased nonregulated generation earnings due to receipt of a contract termination payment on a tolling agreement in 2003, loss recognized on early extinguishment of debt in 2004 and higher fixed costs and interest charges in 2004. o Reduction in revenues due to customer outages in Florida associated with the hurricanes. o Increased interest charges due to the reversal of interest expense for resolved tax matters in 2003. Partially offsetting these items were: o Favorable weather in the Carolinas. o Reduction in revenue sharing provisions in Florida. o Favorable customer growth in both the Carolinas and Florida. o Increased margins as a result of the allowed return on the Hines 2 Plant in Florida. o Increased earnings for natural gas operations, which include the gain recorded on the disposition of certain Winchester Production Company assets. o Increased earnings for Rail operations. o Unrealized gains recorded on contingent value obligations (CVOs). o Reduction in impairments recorded for an investment portfolio and long-lived assets. o Reduction in losses recorded for discontinued operations. o Reduction in losses recorded for changes in accounting principles. For the year ended December 31, 2003, Progress Energy's net income was $782 million, or $3.30 per share, compared to $528 million, or $2.43 per share, for the same period in 2002. Income from continuing operations before the 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: 45 o 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 in the Carolinas. o Lower loss recorded in 2003 related to the sale of North Carolina Natural Gas Company (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. Basic earnings per share decreased in 2004 and increased in 2003 due in part to the factors outlined above. Dilution related to issuances under the Company's Investor Plus and employee benefit programs in 2004 also reduced basic earnings per share by $0.06 in 2004. 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. Beginning in the fourth quarter of 2003, the Company ceased recording portions of the Fuels segment's operations, primarily synthetic fuel facilities, one month in arrears. As a result, earnings for the year ended December 31, 2003, included 13 months of operations, resulting in a net income increase of $2 million for the year. The Company's segments contributed the following profit or loss from continuing operations: - --------------------------------------------------------------------------------------------------------------- (in millions) - --------------------------------------------------------------------------------------------------------------- 2004 Change 2003 Change 2002 - --------------------------------------------------------------------------------------------------------------- PEC Electric $ 464 $ (51) $ 515 $ 2 $ 513 PEF 333 38 295 (28) 323 Fuels 180 (55) 235 59 176 CCO (4) (24) 20 (7) 27 Rail services 16 17 (1) 41 (42) - --------------------------------------------------------------------------------------------------------------- Total segment profit (loss) 989 (75) 1,064 67 997 Corporate and other (236) 17 (253) 192 (445) - --------------------------------------------------------------------------------------------------------------- Total income from continuing operations 753 (58) 811 259 552 Discontinued operations, net of tax 6 14 (8) 16 (24) Cumulative effect of changes in accounting principles - 21 (21) (21) - - --------------------------------------------------------------------------------------------------------------- Net income $ 759 $ (23) $ 782 $ 254 $ 528 - ---------------------------------------------------------------------------------------------------------------
In March 2003, the SEC completed an audit of Progress Energy Service Company, LLC (Service Company), and recommended that the Company change its cost allocation methodology for allocating Service Company costs. As part of the audit process, the Company was required to change the cost allocation methodology for 2003 and record retroactive reallocations between its affiliates in the first quarter of 2003 for allocations originally made in 2001 and 2002. This change in allocation methodology and the related retroactive adjustments have no impact on consolidated expense or earnings. The new allocation methodology, as compared to the previous allocation methodology, generally decreases expenses in the regulated utilities and increases expenses in the nonregulated businesses. The regulated utilities' reallocations are within O&M expense, while the diversified businesses' reallocations are generally within diversified business expenses. The impact on the individual lines of business is included in the following discussions. 46 Cost Management Initiative On February 28, 2005, as part of a previously announced cost management initiative, the executive officers of the Company approved a workforce restructuring. The restructuring will result in a reduction of approximately 450 positions and is expected to be completed in September of 2005. The cost management initiative is designed to permanently reduce by $75-100 million the projected growth in the Company's annual operation and maintenance expenses by the end of 2007. In addition to the workforce restructuring, the cost management initiative includes a voluntary enhanced retirement program. In connection with the cost management initiative, the Company expects to incur one-time pre-tax charges of approximately $130 million. Approximately $30 million of that amount relates to payments for severance benefits, and will be recognized in the first quarter of 2005 and paid over time. The remaining approximately $100 million will be recognized in the second quarter of 2005 and relates primarily to postretirement benefits that will be paid over time to those eligible employees who elect to participate in the voluntary enhanced retirement program. Approximately 3,500 of the Company's 15,700 employees are eligible to participate in the voluntary enhanced retirement program. The total cost management initiative charges could change significantly depending upon how many eligible employees elect early retirement under the voluntary enhanced retirement program and the salary, service years and age of such employees (See Note 24). Energy Delivery Capitalization Practice The Company has reviewed its capitalization policies for its Energy Delivery business units in PEC and PEF. That review indicated that in the areas of outage and emergency work not associated with major storms and allocation of indirect costs, both PEC and PEF should revise the way that they estimate the amount of capital costs associated with such work. The Company has implemented such changes effective January 1, 2005, which include more detailed classification of outage and emergency work and result in more precise estimation and a process of retesting accounting estimates on an annual basis. As a result of the changes in accounting estimates for the outage and emergency work and indirect costs, a lesser proportion of PEC's and PEF's costs will be capitalized on a prospective basis. The Company estimates that the combined impact for both utilities in 2005 will be that approximately $55 million of costs that would have been capitalized under the previous policies will be expensed. Pursuant to SFAS No. 71, PEC and PEF have informed the state regulators having jurisdiction over them of this change and that the new estimation process will be implemented effective January 1, 2005. The Company has also requested a method change from the IRS. Progress Energy Carolinas Electric PEC Electric contributed segment profits of $464 million, $515 million and $513 million in 2004, 2003 and 2002, respectively. The decrease in profits for 2004 as compared to 2003 is primarily due to higher O&M charges and lower wholesale revenues partially offset by the favorable impact of weather, increased revenues from customer growth and a reduction in investment losses and impairment charges compared to the prior year. 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. REVENUES PEC Electric's electric revenues and the percentage change by year and by customer class are as follows: - ------------------------------------------------------------------------------------------------- (in millions) - ------------------------------------------------------------------------------------------------- Customer Class 2004 % Change 2003 % Change 2002 - ------------------------------------------------------------------------------------------------- Residential $ 1,324 5.2 $ 1,259 1.5 $ 1,241 Commercial 888 4.5 850 2.2 832 Industrial 659 3.6 636 (1.4) 645 Governmental 82 3.8 79 1.3 78 - ------------------------------------------------------------------------------------------------- Total retail revenues 2,953 4.6 2,824 1.0 2,796 Wholesale 575 (16.3) 687 5.5 651 Unbilled 10 - (6) - 15 Miscellaneous 90 7.1 84 9.1 77 - ------------------------------------------------------------------------------------------------- Total electric revenues $ 3,628 1.1 $ 3,589 1.4 $ 3,539 - -------------------------------------------------------------------------------------------------
47 PEC Electric's electric energy sales and the percentage change by year and by customer class are as follows: - ------------------------------------------------------------------------------------------------- (in thousands of MWh) - ------------------------------------------------------------------------------------------------- Customer Class 2004 % Change 2003 % Change 2002 - ------------------------------------------------------------------------------------------------- Residential 16,003 4.7 15,283 0.3 15,239 Commercial 13,019 3.7 12,557 0.7 12,468 Industrial 13,036 2.3 12,749 (2.6) 13,089 Governmental 1,431 1.6 1,408 (2.0) 1,437 - ------------------------------------------------------------------------------------------------- Total retail energy sales 43,489 3.6 41,997 (0.6) 42,233 Wholesale 13,222 (14.8) 15,518 3.3 15,024 Unbilled 91 - (44) - 270 - ------------------------------------------------------------------------------------------------- Total MWh sales 56,802 1.2 57,471 (0.1) 57,527 - -------------------------------------------------------------------------------------------------
PEC Electric's revenues, excluding recoverable fuel revenues of $933 million and $901 million for 2004 and 2003, respectively, increased $7 million. The increase in revenues was due primarily to increased retail revenues of $35 million as a result of favorable weather, with cooling degree days 16% above prior year. Retail customer growth contributed an additional $55 million in revenues in 2004. PEC Electric's retail customer base increased as approximately 26,000 new customers were added in 2004. The increase in retail revenues was offset partially by lower wholesale revenues. Wholesale revenues decreased $86 million when compared to $393 million in 2003. The decrease in PEC Electric's wholesale revenues in 2004 from 2003 is primarily the result of reduced excess generation sales. Revenues for 2003 included strong sales to the northeastern United States as a result of favorable market conditions. In addition, lower contracted capacity compared to 2003 further reduced wholesale revenues. The remaining reduction in wholesale revenues is attributable to an inelastic power market. While the cost of fuel continues to rise, the power market prices have not responded as quickly to the fuel increases. The differential between fuel cost and market price limited opportunities to enter the market. PEC monitors its wholesale contract portfolio on a regular basis. During 2003 and 2004, several contracts expired or were renegotiated at lower prices. Due to the slightly depressed wholesale market and increased competition, this trend could continue as contracts are renewed in the upcoming years. The expiration and renegotiation of wholesale contracts is a normal business activity. PEC actively manages its portfolio by seeking to sign new contracts to replace expiring arrangements. 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 in 2003 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. Downturns in the economy during 2002 and 2003 impacted energy usage within the industrial customer class. Total industrial revenues, excluding fuel revenues, declined during 2003 when compared to 2002 by $13 million, as sales to industrial customers decreased due to a general industrial slowdown. Decreases in the textile industry and the chemical industry were among the largest. This declining trend leveled out in 2004 as industrial sales increased in the primary and fabricated metal, chemicals, lumber and food industries. Industrial sales growth is expected to be flat or very low as expired textile quotas are expected to lower textile sales and balance gains in other industries. EXPENSES Fuel and Purchased Power Fuel and purchased power costs represent the costs of generation, which include fuel purchases for generation, as well as energy purchased in the market to meet customer load. Fuel and purchased power expenses are recovered primarily through cost recovery clauses, and, as such, changes in these expenses do not have a material impact on earnings. The difference between fuel and purchased power costs incurred and associated fuel revenues that are subject to recovery is deferred for future collection or refund to customers. Fuel and purchased power expenses were $1.137 billion for 2004, which represents a $16 million increase compared to the same period in the prior year. Fuel used in electric generation increased $11 million to $836 million compared to the prior year. This increase is due to an increase in fuel used in generation of $78 million due to higher fuel costs and a change in generation mix. Higher fuel costs are being driven primarily by an increase in coal prices. Outages at 48 several nuclear facilities during the year resulted in increased combustion turbine generation, which has a higher average fuel cost. See Part I, Item I, "Fuel and Purchased Power" of Electric - PEC for a summary of average fuel costs. The increase in fuel used in generation is offset by a reduction in deferred fuel expense as a result of the under-recovery of current period fuel costs. Purchased power expenses increased $5 million to $301 million compared to prior year. The increase in purchased power is due primarily to an increase in price. Fuel and purchased power expenses were $1.121 billion for 2003, which represents a $22 million increase compared to the same period in the prior year. Fuel used in electric generation increased $73 million in 2003, compared to prior year, 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 Part I, Item I, "Fuel and Purchased Power" of Electric - PEC for a summary of average fuel costs. Purchased power expense decreased $51 million in 2003, 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. Operations and Maintenance (O&M) O&M expenses were $871 million for 2004, which represents an $89 million increase compared to 2003. This increase is driven primarily by higher outage costs and storm costs in 2004 than in the prior year. Outages increased O&M costs by $29 million primarily due to an increase in the number and scope of nuclear plant outages in 2004. In addition, costs associated with restoration efforts after severe storms increased O&M expense $18 million. Storm costs for 2004 included costs related to an ice storm and Hurricanes Charley and Ivan in the North Carolina service territory. PEC Electric also incurred storm costs in 2003; however, the Company requested and the NCUC approved deferral of these costs. The Company did not seek to defer costs associated with the ice storm, which hit the North Carolina service territory, and Hurricanes Charley and Ivan. O&M expenses also increased $9 million due to higher salary- and benefit-related expenditures. In addition, O&M charges in the prior year were favorably impacted by $16 million related to the retroactive reallocation of Service Company costs. O&M expenses were $782 million in 2003, which represents a $20 million decrease compared to 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. Depreciation and Amortization Depreciation and amortization expense was $570 million for 2004, which represents an $8 million increase compared to 2003. This increase is attributable primarily to the impact of the NC Clean Air legislation. PEC Electric recorded the maximum amortization allowed under the legislation in 2004. NC Clean Air amortization increased $100 million to $174 million in 2004 compared to $74 million in 2003. Depreciation expense also increased $9 million for assets placed in service. These increases were partially offset by a reduction in depreciation expense related to depreciation studies filed during the year. During 2004, PEC met the requirements of both the NCUC and the SCPSC for the implementation of depreciation studies that allowed the utility to reduce the rates used to calculate depreciation expense. The annual reduction in depreciation expense is approximately $82 million compared to 2003. The reduction is due primarily to extended lives at each of PEC's nuclear units. The new rates became effective January 2004. Depreciation and amortization increased $38 million in 2003, compared to $524 million in 2002. Depreciation and amortization increased $74 million related to the 2003 impact of the NC Clean Air legislation 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 8B and 22. In addition, depreciation increased $19 million due to additional assets placed into service. 49 Taxes Other than on Income Taxes other than on income were $173 million for 2004, which represents an $11 million increase compared to the prior year. This increase is due primarily to an increase in gross receipts taxes of $8 million related to an increase in revenues and a 2004 adjustment related to the prior year. The remaining variance in other taxes is due to an increase in property taxes of $7 million due to higher property appraisals partially offset by a reduction in payroll taxes of $4 million. Taxes other than on income were $162 million in 2003, which represents a $4 million increase compared to prior year. This increase is due to an increase in property taxes and payroll taxes of $2 million each. Interest Expense Net interest expense was $192 million, $197 million and $212 million in 2004, 2003 and 2002, respectively. Declines in interest expense in 2003 resulted from reduced short-term debt and refinancing certain long-term debt with lower interest rate debt. Income Tax Expense Income tax expense was $237 million, $238 million and $237 million in 2004, 2003 and 2002, respectively. In 2004, 2003 and 2002, $22 million, $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, certain holding company tax benefits are allocated to profitable subsidiaries. Other fluctuations in income taxes are primarily due to changes in pre-tax income. Progress Energy Florida PEF contributed segment profits of $333 million, $295 million and $323 million in 2004, 2003 and 2002, respectively. Profits for 2004 increased due to favorable customer growth, a reduction in the provision for revenue sharing, favorable wholesale revenues, the additional return on investment on the Hines 2 plant and reduced O&M expenses. These items were partially offset by unfavorable weather, a reduction in revenues related to the hurricanes, increased interest expense and increased depreciation expense from assets placed in service. 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. In 2002, PEF's profits were affected by the outcome of the rate case stipulation, which included a one-time retroactive revenue refund, 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 8C). REVENUES PEF's electric revenues 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 2004 % Change 2003 % Change 2002 - ----------------------------------------------------------------------------------------------- Residential $ 1,806 6.8 $ 1,691 2.8 $ 1,645 Commercial 853 15.3 740 1.2 731 Industrial 254 16.0 219 3.8 211 Governmental 211 16.6 181 4.6 173 Revenue sharing refund (11) - (35) - (5) Retroactive retail rate refund - - - - (35) - ------------------------------------------------ ----------------- ------------- Total retail revenues 3,113 11.3 2,796 2.8 2,720 Wholesale 268 18.1 227 (1.3) 230 Unbilled 7 - (2) - (3) Miscellaneous 137 4.6 131 13.9 115 - ------------------------------------------------ ----------------- ------------- Total electric revenues $ 3,525 11.8 $ 3,152 2.9 $ 3,062 - -----------------------------------------------------------------------------------------------
50 PEF's electric energy sales and the percentage change by year and by customer class are as follows: - --------------------------------------------------------------------------------------------- (in thousands of MWh) - --------------------------------------------------------------------------------------------- Customer Class 2004 % Change 2003 % Change 2002 - --------------------------------------------------------------------------------------------- Residential 19,347 (0.4) 19,429 3.6 18,754 Commercial 11,734 1.6 11,553 1.2 11,420 Industrial 4,069 1.7 4,000 4.3 3,835 Governmental 3,044 2.4 2,974 4.4 2,850 - ----------------------------------------------- ---------------- ------------- Total retail energy sales 38,194 0.6 37,956 3.0 36,859 Wholesale 5,101 18.0 4,323 3.4 4,180 Unbilled 358 - 233 - 5 - ----------------------------------------------- ---------------- ------------- Total MWh sales 43,653 2.6 42,512 3.6 41,044 - ---------------------------------------------------------------------------------------------
PEF's revenues, excluding recoverable fuel and other pass-through revenues of $2.007 billion and $1.692 billion for 2004 and 2003, respectively, increased $58 million. This increase was due primarily to favorable customer growth, which increased revenues $34 million. PEF has 37,000 additional retail customers compared to prior year. Revenues were also favorably impacted by a reduction in the provision for revenue sharing of $24 million. Results for 2003 included an additional refund of $18 million related to the 2002 revenue sharing provision as ordered by the FPSC in July 2003. In addition, improved wholesale sales increased revenues by $11 million. Included in fuel revenues is the recovery of depreciation and capital costs associated with the Hines Unit 2, which was placed into service in December 2003 and contributed $36 million in additional revenues in 2004. The recovery of the Hines Unit 2 costs through the fuel clause is in accordance with the 2002 rate stipulation (See Note 8C). These increases were partially offset by the reduction in revenues related to customer outages for Hurricanes Charley, Frances and Jeanne of approximately $12 million and the impact of milder weather in the current year of $10 million. PEF's revenues, excluding recoverable fuel and other pass-through revenues of $1.692 billion and $1.602 billion in 2003 and 2002, respectively, were unchanged 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 by $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 offset by the negative impact of the rate settlement, which decreased 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 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. EXPENSES Fuel and Purchased Power Fuel and purchased power costs represent the costs of generation, which include fuel purchases for generation, as well as energy purchased in the market to meet customer load. Fuel and purchased power expenses are recovered primarily through cost recovery clauses, and, as such, changes in these expenses do not have a material impact on earnings. The difference between fuel and purchased power costs incurred and associated fuel revenues that are subject to recovery is deferred for future collection or refund to customers. Fuel and purchased power expenses were $1.742 billion in 2004, which represents a $306 million increase compared to 2003. This increase is due to increases in fuel used in electric generation and purchased power expenses of $305 million and $1 million, respectively. Higher system requirements and increased fuel costs in the current year account for $87 million of the increase in fuel used in electric generation. The remaining increase is due to the recovery of fuel expenses that were deferred in the prior year, partially offset by the deferral of current year under-recovered fuel expenses. In November 2003, the FPSC approved PEF's request for a cost adjustment in its annual fuel filing due to the rising costs of fuel. The new rates became effective January 2004. 51 Fuel used in generation and purchased power expenses were $1.436 billion in 2003, which represents an $87 million increase compared to the prior year. 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 resulted in a $229 million increase partially offset by the deferral of 2003 under-recovered fuel and purchased power expense of $142 million. Operations and Maintenance (O&M) O&M expenses were $630 million in 2004, which represents a $10 million decrease when compared to the prior year. This decrease is primarily related to favorable benefit-related costs of $16 million, primarily due to lower pension costs which resulted from improved pension asset performance. O&M expenses were $640 million in 2003, which represents a $49 million increase when compared to the prior year. 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. Depreciation and Amortization Depreciation and amortization expense was $281 million for 2004, which represents a decrease of $26 million when compared to the prior year, primarily due to the amortization of the Tiger Bay regulatory asset in the prior year. The Tiger Bay regulatory asset, for contract termination costs, was recovered pursuant to an agreement between PEF and the FPSC that was approved in 1997. The amortization of the regulatory asset was calculated using revenues collected under the fuel adjustment clause; as such, fluctuations in this expense did not have an impact on earnings. During 2003, Tiger Bay amortization was $47 million. The Tiger Bay asset was fully amortized in September 2003. The decrease in Tiger Bay amortization was partially offset by additional depreciation for assets placed in service, including depreciation for Hines Unit 2, of approximately $9 million. This depreciation expense is being recovered through the fuel cost recovery clause as allowed by the FPSC. See discussion of the return on Hines 2 in the revenues analysis above. Depreciation and amortization was $307 million in 2003, which represents an increase of $12 million when compared to 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. Taxes Other than on Income Taxes other than on income were $254 million in 2004, which represents an increase of $13 million compared to the prior year. This increase is due to increases in gross receipts and franchise taxes of $8 million and $7 million, respectively, related to an increase in revenues and an increase in property taxes of $5 million due to increases in property placed in service and tax rates. These increases were partially offset by a reduction in payroll taxes of $7 million. Taxes other than on income were $241 million in 2003, which represents an increase of $13 million compared to prior year. This increase was due to increases in payroll taxes of $10 million and increases in gross receipts and franchise taxes of $4 million combined. Interest Expense Interest charges, net were $114 million in 2004, which represents an increase of $23 million compared to the prior year. Interest charges, net were $91 million in 2003, which represents a $15 million decrease compared to the prior year. The fluctuations were primarily due to interest costs in 2003 being favorably impacted by the reversal of interest expense due to the resolution of certain tax matters. Income Tax Expense Income tax expense was $174 million, $147 million and $163 million in 2004, 2003 and 2002, respectively. In 2004, 2003 and 2002, $14 million, $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, certain holding company tax benefits are allocated to profitable subsidiaries. Other fluctuations in income taxes are primarily due to changes in pre-tax income. 52 Diversified Businesses The Company's diversified businesses consist of the Fuels segment, the CCO segment and the Rail Services segment. Fuels The Fuels' segment operations include synthetic fuels production, natural gas production, coal extraction and terminal operations. Beginning in the fourth quarter of 2003, the Company ceased recording portions of Fuels' segment operations, primarily synthetic fuel facilities, one month in arrears. As a result, earnings for the year ended December 31, 2003, included 13 months of operations, resulting in a net income increase of $2 million for the year. The following summarizes Fuels' segment profits: - --------------------------------------------------------------------- (in millions) 2004 2003 2002 - --------------------------------------------------------------------- Synthetic fuel operations $ 91 $ 205 $ 156 Natural gas operations 85 34 10 Coal fuel and other operations 4 (4) 10 - --------------------------------------------------------------------- Segment profits $ 180 $ 235 $ 176 - --------------------------------------------------------------------- SYNTHETIC FUEL OPERATIONS The production and sale of synthetic fuel generate operating losses, but qualify for tax credits under Section 29 of the Code, which more than offset the effect of such losses (See Note 23E). The operations resulted in the following losses (prior to tax credits): - ------------------------------------------------------------------------- (in millions) 2004 2003 2002 - ------------------------------------------------------------------------- Tons sold 8.3 12.4 11.2 After-tax losses (excluding tax credits) $ (124) $ (141) $ (135) Tax credits 215 346 291 - ------------------------------------------------------------------------- Net profit $ 91 $ 205 $ 156 - ------------------------------------------------------------------------- The Company's synthetic fuel production levels and the amount of tax credits it can claim each year are a function of the Company's projected consolidated regular federal income tax liability. Synthetic fuel operations' net profits decreased in 2004 as compared to 2003 due primarily to a decrease in synthetic fuel production and an increase in operating expenses in 2004. The Company's total synthetic fuel production of approximately eight million tons in 2004 is down compared to 2003 production levels of approximately 12 million tons as a result of hurricane costs, which reduced the Company's projected 2004 regular tax liability and its corresponding ability to record tax credits from its synthetic fuel production. In addition, earnings in 2003 include a $13 million favorable tax credit true-up related to 2002. As of September 30, 2004, the Company anticipated an ability to record approximately five million tons of synthetic fuels production based on the Company's projected regular tax liability for 2004. This estimate was based upon the Company's projected casualty loss as a result of the storms. Therefore, the Company recorded a charge of $79 million in the third quarter for tax credits associated with approximately 2.7 million tons sold during the year that the Company anticipated it would not be able to use. On November 2, 2004, PEF filed a petition with the FPSC to recover $252 million of storm costs plus interest from customers over a two-year period. Based on a reasonable expectation at December 31, 2004, that the FPSC will grant the requested recovery of the storm costs, the Company's loss from the casualty is less than originally anticipated. Accordingly, as of December 31, 2004, the Company's anticipated 2004 tax liability supported credits on approximately eight million tons. Therefore, the Company recorded tax credits of $90 million for the quarter ended December 31, 2004, for tax credits associated with approximately three million tons sold during the year that the Company now anticipates can be used. As of December 31, 2004, the Company anticipates that approximately $7 million of tax credits associated with approximately 0.2 million tons sold during the year could not be used (See Note 23E). The Company ceased operations at its Earthco facilities for the last three months of 2004 due to the decrease in the Company's projected 2004 tax liability, and these facilities were restarted in January 2005. 53 The Company believes its right to recover storm costs is well established; however, the Company cannot predict the timing or outcome of this matter. If the FPSC should deny PEF's petition for the recovery of storm costs in 2005, there could be a material impact on the amount of 2005 synthetic fuel production and results of operations. 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 $13 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. NATURAL GAS OPERATIONS Natural gas operations generated profits of $85 million, $34 million and $10 million for the years ended December 31, 2004, 2003 and 2002, respectively. Natural gas profits increased $51 million in 2004 compared to 2003. This increase is attributable primarily to the gain recognized on the sale of gas assets during the year. In December 2004, the Company sold certain gas-producing properties and related assets owned by Winchester Production Company, Ltd. (North Texas gas operations). Because the sale significantly altered the ongoing relationship between capitalized costs and remaining proved reserves, under the full-cost method of accounting the pre-tax gain of $56 million ($31 million net of taxes) was recognized in earnings rather than as a reduction of the basis of the Company's remaining oil and gas properties. In addition, an increase in production, coupled with higher gas prices in 2004, contributed to the increased earnings in 2004 as compared to 2003. Production levels increased resulting from the acquisition of North Texas Gas in late February 2003 and increased drilling in 2004. Volume and prices have increased 21% and 16%, respectively, for 2004 compared to 2003. Natural gas profits increased to $34 million in 2003 compared to $10 million in 2002. The increase in production and price resulting from the acquisitions of Westchester in 2002 (renamed Winchester Energy in 2004) and North Texas Gas in the first quarter of 2003 drove increased revenue and earnings in 2003 compared to 2002. In October 2003, the Company completed the sale of certain gas-producing properties owned by Mesa Hydrocarbons, LLC (Mesa). See Notes 5B and 4D to the Progress Energy Consolidated Financial Statements for discussions of the North Texas Gas acquisitions and the Mesa disposition. The following table summarizes the production and revenues of the natural gas operations by location: - ------------------------------------------------------------------------------ 2004 2003 2002 - ------------------------------------------------------------------------------ Production in Bcf equivalent East Texas/LA gas operations 20 13 6 North Texas gas operations 10 7 - Mesa - 5 7 - ------------------------------------------------------------------------------ Total production 30 25 13 - ------------------------------------------------------------------------------ Revenues in millions East Texas/LA gas operations $110 $ 65 $24 North Texas gas operations 52 38 - Mesa - 13 15 - ------------------------------------------------------------------------------ Total revenues $162 $ 116 $39 - ------------------------------------------------------------------------------ Gross margin In millions of $ $ 126 $ 91 $29 As a % of revenues 78% 78% 74% - ------------------------------------------------------------------------------ COAL FUEL AND OTHER OPERATIONS Coal fuel and other operations generated profits of $4 million, losses of $4 million and profits of $10 million for the years ended December 31, 2004, 2003 and 2002, respectively. The increase in profits for 2004 is primarily due to higher volumes and margins for coal fuel operations of $16 million after-tax. In addition, coal results in 2003 included the recording of an impairment of certain assets at the Kentucky May coal mine totaling $11 million after-tax. This favorability was offset by a reduction in profits of $7 million after-tax for fuel transportation operations related to the waterborne transportation ruling by the FPSC (See Note 8C). Profits were also negatively impacted by higher corporate costs of $10 million in 2004. Corporate costs in the prior year included $4 million of favorability related to the reduction of an environmental reserve (See Note 22). The remaining unfavorability in corporate costs is attributable to increased interest expense related to unresolved tax matters and higher professional fees. 54 Coal fuel and other operations 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. The decrease in profits is also due to the impact of the retroactive Service Company allocation in 2003. The Company is exploring strategic alternatives regarding the Fuels' coal mining business, which could include divesting these assets. As of December 31, 2004, the carrying value of long-lived assets of the coal mining business was $66 million. The Company cannot currently predict the outcome of this matter. Competitive Commercial Operations CCO generates and sells electricity to the wholesale market from nonregulated plants. These operations also include marketing activities. The following summarizes the annual revenues, gross margin and segment profits from the CCO plants: - ------------------------------------------------------- (in millions) 2004 2003 2002 - ------------------------------------------------------- Total revenues $ 240 $ 170 $ 92 Gross margin In millions of $ $ 158 $ 141 $ 83 As a % of revenues 66% 83% 90% Segment profits (losses) $ (4) $ 20 $ 27 - ------------------------------------------------------- CCO's operations generated segment losses of $4 million in 2004 compared to segment profits of $20 million in 2003. Results for 2004 were favorably impacted by increased gross margin, which was more than offset by higher fixed costs and costs associated with the extinguishment of debt. Revenues increased for 2004 due to increased revenues from marketing and tolling contracts offset by a termination payment received on a marketing contract in 2003. Expenses for the cost of fuel and purchased power to supply marketing contracts partially offset the increased revenues netting to an increase in gross margin for 2004 as compared to 2003. Fixed costs increased $16 million pre-tax from additional depreciation and amortization on plants placed into service in 2003 and from an increase in interest expense of $13 million pre-tax due primarily to interest no longer being capitalized due to the completion of construction in the prior year. In addition, plant operating expenses increased $12 million pre-tax primarily due to higher gas transportation service charges, which increased over prior year due to a full period of expenses being reflected in current year results. CCO results for 2004 also include losses of $15 million pre-tax associated with the extinguishment of a debt obligation. CCO terminated the Genco financing arrangement in December 2004. The $15 million pre-tax loss is comprised of a $9 million write-off of remaining unamortized debt issuance costs and a $6 million realized loss on exiting the related interest rate hedge. Expenses were favorably impacted by a reduction in Service Company allocations. Results for 2003 were negatively impacted by the retroactive reallocation of Service Company costs of $3 million ($2 million after-tax). CCO's operations generated segment profits of $20 million in 2003 compared to segment profits of $27 million in 2002. 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 MW at December 31, 2002, to 3,100 MW 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 Electric Membership Corporation 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 Company has contracts for its planned production capacity, which includes callable resources from the cooperatives, of approximately 77% for 2005, approximately 81% for 2006 and approximately 75% for 2007. The Company continues to seek opportunities to optimize its nonregulated generation portfolio. Rail Services Rail Services' (Rail) operations represent the activities of Progress Rail and include railcar and locomotive repair, track-work, rail parts reconditioning and sales, scrap metal recycling, railcar leasing and other rail-related services. 55 Rail-contributed segment profits of $16 million for 2004 compared with segment losses of $1 million and $42 million for the years ended December 31, 2003, and 2002, respectively. Results in 2004 were favorably impacted by the strong scrap metal market in 2004. Revenues were $1.131 billion in 2004, which represents an increase of $284 million compared to prior year. This increase is due primarily to increased volumes and higher prices in recycling operations and in part to increased production and sales in locomotive and railcar services and engineering and track services. Tonnage for recycling operations is up approximately 35% on an annualized basis compared to 2003. The increase in tonnage, coupled with an increase in the average index price of approximately 80%, accounts for the significant increase in revenues year over year. The American Metal Market index price for #1 railroad heavy melt (which is used as the index for buying and selling of railcars) has increased to $191 as of December 31, 2004, from $106 as of December 31, 2003. Cost of goods sold was $990 million in 2004, which represents an increase of $252 million compared to the prior year. The increase in costs of goods sold is due to increased costs for inventory, labor and operations as a result of the increased volume in the recycling operations, locomotive and railcar services and engineering and track services. In addition, results in 2003 were negatively impacted by the retroactive reallocation of Service Company costs of $3 million after-tax. The favorability related to the reallocation was offset by an increase in general and administrative costs in 2004 related primarily to higher professional fees associated with divestiture efforts. See discussion below. Rail's operations generated segment losses of $1 million in 2003 compared to segment losses of $42 million in 2002. The reduction in losses in 2003 compared to 2002 is due primarily to an impairment charge recorded in 2002. 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 (See Note 4D). Excluding the impairment recorded in 2002, profits for Rail were flat year over year 2003 compared to 2002. In February 2005, Progress Energy signed a definitive agreement to sell its Progress Rail subsidiary to subsidiaries of One Equity Partners LLC for a sales price of $405 million. Proceeds from the sale are expected to be used to reduce debt. See Note 24 for more information. Corporate & Other Corporate and Other consists of the operations of Progress Energy Holding Company (the holding company), Progress Energy Service Company and other consolidating and nonoperating entities. Corporate and Other also includes other nonregulated business areas including the operations of SRS and the telecommunication operations. OTHER NONREGULATED BUSINESS AREAS Progress Energy's other business areas include the operations of SRS and the telecommunications operations. SRS was engaged in providing energy services to industrial, commercial and institutional customers to help manage energy costs primarily in the southeastern United States. During 2004, SRS sold its subsidiary, Progress Energy Solutions (PES). With the disposition of PES, the Company exited this business area. 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 telecommunication subsidiaries of Progress Energy, and EPIK, a wholly owned subsidiary of Odyssey, contributed substantially all of their assets and transferred certain liabilities to PT LLC, a subsidiary of PTC. The accounts of PT LLC have been included in the Company's Consolidated Financial Statements since the transaction date. See additional discussion on the telecommunication business combination in Note 5A. Other nonregulated business areas contributed segment losses of $38 million compared to losses of $24 million for the years ended December 31, 2004, and 2003, respectively. SRS recorded a net loss of $27 million for 2004 compared to a net loss of $6 million for 2003. The increased loss compared to the prior year is due primarily to the recording of the litigation settlement reached with San Francisco United School District (the District) related to civil proceedings. In June 2004, SRS reached a settlement with the District that settled all outstanding claims for approximately $43 million pre-tax ($29 million after-tax). The reduction in earnings due to the settlement was offset partially by a gain recognized on the sale of Progress Energy Solutions. Telecommunication operations recorded a net loss of $5 million in 2004 compared to a net profit of $2 million in 2003. The increase in losses compared to prior year is due to an increase in fixed costs, mainly depreciation expense, and professional fees related to the merger with EPIK. The increased losses at SRS and telecommunication operations were offset partially by a reduction in losses at the nonutility subsidiaries of PEC. The nonutility subsidiaries of PEC contributed segment losses of $6 million and $18 million for the years ended December 31, 2004, and 2003, respectively. 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 (See Note 10B). A reduction in investment losses accounted for the remaining favorability compared to prior year. 56 Other nonregulated business areas contributed segment losses of $24 million in 2003 compared to $250 million for the year ended December 31, 2002. The 2002 segment losses include an asset impairment and other charges in the telecommunications business of $225 million after-tax. See discussion of impairments at Note 10 of the Consolidated Financial Statements. 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) - ------------------------------------------------------------------------------------------------ 2004 Change 2003 Change 2002 - ------------------------------------------------------------------------------------------------ Other interest expense $ (270) $ 15 $ (285) $ (10) $ (275) Contingent value obligations 9 18 (9) (37) 28 Tax reallocation (37) 1 (38) 18 (56) Other income taxes 102 (22) 124 11 113 Other income (expense) (2) 19 (21) (16) (5) - ------------------------------------------------------------------------------------------------ Segment loss $ (198) $ 31 $ (229) $ (34) $ (195) - ------------------------------------------------------------------------------------------------
The other interest expense decrease for 2004 compared to 2003 is partially due to the repayment of a $500 million unsecured note by the Holding Company on March 1, 2004, which reduced interest expense by $27 million pre-tax for 2004. This reduction was offset by interest no longer being capitalized due to the completion of construction in the CCO segment in 2003. Approximately $10 million ($6 million after-tax) was capitalized in 2003. No interest expense was capitalized during 2004. 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 the construction of plants by CCO which was completed in 2003. Progress Energy issued 98.6 million contingent value obligations (CVOs) in connection with the acquisition of FPC in 2000. 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, 2004, 2003 and 2002, the CVOs had a fair market value of approximately $13 million, $23 million and $14 million, respectively. Progress Energy recorded unrealized losses of $9 million for 2003 and an unrealized gain of $9 million and $28 million for 2004 and 2002, respectively, to record the changes in fair value of CVOs, which had average unit prices of $0.14, $0.23 and $0.14 at December 31, 2004, 2003 and 2002, respectively. Progress Energy and its affiliates file a consolidated federal income tax return. The consolidated income tax of Progress Energy is allocated to subsidiaries in accordance with the Intercompany Income Tax Allocation Agreement (Tax Agreement). The Tax Agreement provided an allocation that recognizes positive and negative corporate taxable income. The Tax Agreement provides for an equitable method of apportioning the carryover 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 Public Utility Holding Company Act of 1935, as amended (PUHCA) order. Other income taxes benefit decreased for 2004 compared to 2003 due primarily to increased taxes booked at the Holding Company of $21 million. Income taxes increased an additional $9 million at the Holding Company as a result of a reserve booked related to identified state tax deficiencies. Other income taxes benefit decreased for 2003 compared to 2002 primarily for the tax allocation to the profitable subsidiaries. Other fluctuations in income taxes are primarily due to changes in pre-tax income. 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. In September 2003, Progress Energy completed the sale of NCNG and ENCNG for net proceeds of approximately $450 million in September 2003. Progress Energy incurred a loss from discontinued operations of $8 million for 2003 compared with a loss of $24 million for 2002. During the year ended December 31, 2004, the Company recorded a reduction to the loss on the sale of NCNG of approximately $6 million related to deferred taxes (See Note 4E). Cumulative Effect of Accounting Changes In 2003, 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 57 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 2003 for $23 million after-tax (See Note 18A). 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 As discussed in Note 8, 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 rate-making 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 8 provides additional information related to the impact of utility regulation on the Company. Asset Impairments As discussed in Note 10, 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). Fair value was determined based on discounted cash flows. During 2002, the Company recorded pre-tax long-lived asset impairments of $305 million related to its telecommunications business. The fair value of these assets was determined considering various factors, including a valuation study heavily weighted on a discounted cash flow methodology and using market approaches as supporting information. 58 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 2003. PEC also recorded an impairment of $3 million for a cost investment. During 2002, the Company recorded pre-tax impairments to its cost method investment in Interpath of $25 million. The fair value of this investment was determined considering various factors, including a 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. Under the full-cost method of accounting for oil and gas 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. The ceiling test takes into consideration the prices of qualifying cash flow hedges as of the balance sheet date. 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 2004, 2003 or 2002. Goodwill As discussed in Note 9, effective January 1, 2002, the Company adopted FASB Statement No. 142, "Goodwill and Other Intangible Assets," which requires that goodwill be tested for impairment at least annually and more frequently when indicators of impairment exist. 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 Company performed the annual goodwill impairment test for the CCO segment in the first quarters of 2004 and 2003, and the annual goodwill impairment test for the PEC Electric and PEF segments in the second quarters of 2004 and 2003, each of which indicated no impairment. If the fair values for the utility segments were lower by approximately 10%, there still would be no impact on the reported value of their goodwill. The carrying amounts of goodwill at December 31, 2004 and 2003, for reportable segments PEC Electric, PEF and CCO, are $1,922 million, $1,733 million and $64 million, respectively. In December 2003, $7 million in goodwill was acquired as part of Progress Telecommunications Corporation's partial acquisition of EPIK and was reported in the Corporate and Other segment. The Company revised the preliminary EPIK purchase price allocation as of September 2004, and the $7 million of goodwill was reallocated to certain tangible assets acquired based on the results of valuations and appraisals. Synthetic Fuels Tax Credits As discussed in Note 23E, Progress Energy, through the Fuels business unit, owns facilities that produce synthetic fuel as defined under the Internal Revenue Code. The production and sale of the synthetic fuels from these facilities qualifies for tax credits under Section 29 if certain requirements are satisfied, including a requirement that the synthetic fuels differs significantly in chemical composition from the coal used to produce such synthetic fuels and that the fuel was produced from a facility placed in service before July 1, 1998. The amount of Section 29 credits that the Company is allowed to claim in any calendar year is limited by the amount of the Company's regular federal income tax liability. Synthetic fuels tax credit amounts allowed but not utilized are carried forward indefinitely as deferred alternative minimum tax credits on the Consolidated Balance Sheets. All of Progress Energy's synthetic fuel facilities have received PLRs from the IRS with respect to their operations, although these do not address placed-in-service date determinations. The PLRs do not limit the production on which synthetic fuel credits may be claimed. The current Section 29 tax credit program expires at the end of 2007. 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. Additionally, the ability to use tax credits currently being carried forward could be denied. See further discussion in "OTHER MATTERS" below, Note 23E and in the "Risk Factors" section. Pension Costs As discussed in Note 17A, Progress Energy maintains qualified noncontributory 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. 59 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 used to present value future benefit payments, the Company lowered the discount rate to 5.9% at December 31, 2004, which will increase the 2005 benefit costs recognized, all other factors remaining constant. Plan assets performed well in 2004, with returns of approximately 14%. That positive asset performance will result in decreased pension costs in 2005, all other factors remaining constant. Evaluations of the effects of these and other factors have not been completed, but the Company estimates that the total cost recognized for pensions in 2005 will be approximately $12 to $20 million higher than the amount recorded in 2004. The Company has pension plan assets with a fair value of approximately $1.8 billion at December 31, 2004. 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 adjust that return only 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 and 2004. A 0.25% change in the expected rate of return for 2004 would have changed 2004 pension costs by approximately $4 million. Another factor affecting the Company's pension costs, and sensitivity of the costs 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 costs sooner under the fair value method than the five-year averaging method, and, therefore, pension costs tend to be more volatile using the fair value method. For example, in 2004 the expected return for assets subject to the averaging method was 2% lower than in 2003, whereas the expected return for assets subject to the fair value method was 24% higher than in 2003. 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. The Company's primary cash needs at the holding company level are its common stock dividend and interest expense and principal payments on its $4.3 billion of senior unsecured debt. The ability to meet these needs is 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 the Company arise primarily from the capital-intensive nature of its electric utility operations and expenditures for its diversified businesses, primarily those of the Fuels segment. The Company relies upon its operating cash flow, primarily generated by its two regulated electric utility subsidiaries, commercial paper and bank facilities, and its ability to access long-term debt and equity capital markets for sources of liquidity. The majority of the Company's operating costs are related to its two regulated electric utilities, and a significant portion of these costs is 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. A nonutility money pool allows Progress Energy's nonregulated operations to lend and borrow funds among each other. Progress Energy can lend money to the utility and nonutility money pools but cannot borrow funds. 60 Cash from operations, asset sales and the issuance of common stock are expected to fund capital expenditures and common dividends for 2005. Any excess cash proceeds would be used to reduce debt. To the extent necessary, short- and long-term debt may also be used as a source of liquidity. The Company 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 the Company's liquidity and capital resources is on a consolidated basis. HISTORICAL FOR 2004 AS COMPARED TO 2003 AND 2003 AS COMPARED TO 2002 Cash Flows from Operations Cash from operations is the primary source used to meet operating requirements and capital expenditures. Net cash provided by operating activities from continuing operations for the three years ending December 31, 2004, 2003 and 2002 were $1.6 billion, $1.7 billion and $1.6 billion, respectively. Cash from operating activities for 2004 when compared with 2003 decreased $117 million, as the net result of the impact of hurricane costs, partially offset by the impact of an under-recovery of fuel costs in 2003. The increase in cash from operating activities for 2003 when compared with 2002 is largely the result of improved operating results at PEC. During the third quarter of 2004, four hurricanes struck significant portions of the Company's service territories, with the most significant impact on PEF's territory. Restoration of the Company's systems from storm-related damage cost an estimated $398 million. PEC's cost totaled $13 million, of which $12 million was charged to O&M and $1 million was charged to capital. PEF's cost totaled $385 million, of which $338 million was charged to Storm Damage Reserve pursuant to a regulatory order and $47 million was charged to capital. On November 2, 2004, PEF filed a petition with the Florida Public Service Commission (FPSC) to recover $252 million of storm costs plus interest from retail rate payers over a two-year period (See Note 3). Progress Energy is allowed to recover fuel costs incurred by PEC and PEF through their respective fuel cost recovery surcharges. Fuel price volatility can lead to over- or under-recovery of fuel costs, as changes in fuel prices are not immediately reflected in fuel surcharges due to regulatory lag in setting the surcharges. As a result, fuel price volatility can be both a source of and a drag on liquidity resources, depending on what phase of the cycle of price volatility the Company is experiencing. In addition, in 2004 PEF agreed with the FPSC to use a two-year period to determine the surcharge for the underrecovered fuel costs incurred in 2004 (See Note 8C). Investing Activities Net cash used in investing activities for the three years ending December 31, 2004, 2003 and 2002 were $0.9 billion, $1.5 billion and $2.2 billion, respectively. Utility property additions for the Company's regulated electric operations were $1.0 billion or approximately 75% of consolidated capital expenditures in 2004 and $1.0 billion or approximately 58% of consolidated capital expenditures in 2003, excluding proceeds from asset sales. Capital expenditures for the regulated electric operations are primarily for normal construction activity and ongoing capital expenditures related to environmental compliance programs. Capital expenditures for the nonregulated operations are primarily for natural gas development activities and normal construction activity. Excluding proceeds from sales of subsidiaries and other investments, cash used in investing activities decreased approximately $887 million in 2004 when compared with 2003. The decrease is due primarily to the acquisition of a nonregulated generation contract and acquisition of gas assets in 2003 and net proceeds from short-term investments in 2004, compared to net purchases of short-term investments in 2003. Excluding proceeds from sales of subsidiaries and other investments, cash used in investing activities was $2.1 billion in 2003, down approximately $119 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. 61 During 2004, sales of subsidiaries and other investments primarily included proceeds from the sale of Railcar Ltd. assets of approximately $75 million and proceeds of approximately $251 million related to the sale of natural gas assets in the Forth Worth basin of Texas. Progress Energy used the proceeds from these sales to reduce indebtedness, including $241 million to pay off the Progress Genco Ventures, LLC, bank facility. 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 in Colorado. Progress Energy used the proceeds from these sales to reduce indebtedness, primarily commercial paper, then outstanding. During 2003, the Company acquired approximately 200 natural gas-producing wells for a cash purchase price of $168 million. The Company also acquired a long-term full-requirements power supply agreement with Jackson Electric Membership Corporation for a cash payment of $188 million. During 2002, the Company purchased two electric generation projects for a cash purchase price of $348 million. Financing Activities Net cash (used in) provided by financing activities for the three years ending December 31, 2004, 2003 and 2002 were $(720), $(192) million and $581 million, respectively. See Note 13 for details of debt and credit facilities. For 2004 and 2003, cash from operations exceeded net cash used in investing activities by $735 million and $178 million, respectively, due primarily to asset sales, which allowed for a net decrease in cash provided by financing activities. For 2002, net cash used in investing activity exceeded cash from operations by $574 million, which resulted in net cash from financing activities of $581 million. In addition to the financing activities discussed under "Overview," the financing activities of the Company included: 2005 o In January 2005, the Company used proceeds from the issuance of commercial paper to pay off $260 million of revolving credit agreement (RCA) loans. o On January 31, 2005, Progress Energy, Inc. entered into a new $600 million revolving credit agreement, which expires December 30, 2005. This facility was added to provide additional liquidity during 2005 due in part to the uncertainty of the timing of storm restoration cost recovery from the hurricanes in Florida during 2004. The credit agreement includes a defined maximum total debt to total capital ratio of 68% and a minimum interest coverage ratio of 2.5 to 1. The credit agreement also contains various cross-default and other acceleration provisions. On February 4, 2005, $300 million was drawn under the new facility to reduce commercial paper and pay off the remaining amount of RCA loans outstanding. o In March 2005, Progress Energy, Inc.'s five-year credit facility was amended to increase the maximum total debt to total capital ratio from 65% to 68% in anticipation of the potential impacts of proposed accounting rules for uncertain tax positions. See Notes 2 and 23E. 2004 o During the fourth quarter of 2004, Progress Energy and its subsidiaries PEC and PEF borrowed a net total of $475 million under certain revolving credit facilities. The borrowed funds were used to pay off maturing commercial paper and for other cash needs. A summary of RCA loans and available capacity as of December 31, 2004, is as follows: 62 - -------------------------------------------------------------------------------------------------------------- (in millions) Company Description Total Outstanding Available - -------------------------------------------------------------------------------------------------------------- Progress Energy, Inc. 5-Year (expiring 8/5/09) $ 1,130 $ 160 $ 970 Progress Energy Carolinas, Inc. 364-Day (expiring 7/27/05) 165 90 75 Progress Energy Carolinas, Inc. 3-Year (expiring 7/31/05) 285 - 285 Progress Energy Florida, Inc. 364-Day (expiring 3/29/05) 200 170 30 Progress Energy Florida, Inc. 3-Year (expiring 4/01/06) 200 55 145 Less: amounts reserved(a) - - (574) - -------------------------------------------------------------------------------------------------------------- Total credit facilities $ 1,980 $ 475 $ 931 - --------------------------------------------------------------------------------------------------------------
(a) To the extent amounts are reserved for commercial paper outstanding or backing letters of credit, they are not available for additional borrowings. o On December 17, 2004, the Company used proceeds from the sale of natural gas assets to extinguish Progress Genco Ventures, LLC's $241 million bank facility (See Note 13D). o Progress Energy took advantage of favorable market conditions and entered into a new $1.1 billion five-year line of credit, effective August 5, 2004, and expiring August 5, 2009. This facility replaced Progress Energy's $250 million 364-day line of credit and its three-year $450 million line of credit, which were both scheduled to expire in November 2004. o On July 28, 2004, PEC extended its $165 million 364-day line of credit, which was scheduled to expire on July 29, 2004. The line of credit will expire on July 27, 2005. o On July 1, 2004, PEF paid at maturity $40 million 6.69% Medium-Term Notes Series B with commercial paper proceeds and cash from operations. o On April 30, 2004, PEC redeemed $35 million of Darlington County 6.6% Series Pollution Control Bonds at 102.5% of par, $2 million of New Hanover County 6.3% Series Pollution Control Bonds at 101.5% of par, and $2 million of Chatham County 6.3% Series Pollution Control Bonds at 101.5% of par with cash from operations. o On March 1, 2004, Progress Energy used available cash and proceeds from the issuance of commercial paper to pay at maturity $500 million 6.55% senior unsecured notes. Cash and commercial paper capacity for this retirement was created primarily from proceeds of the sale of assets in 2003. o On February 9, 2004, Progress Capital Holdings, Inc., paid at maturity $25 million 6.48% medium term notes with available cash from operations. o On January 15, 2004, PEC paid at maturity $150 million 5.875% First Mortgage Bonds with commercial paper proceeds. On April 15, 2004, PEC also paid at maturity $150 million 7.875% First Mortgage Bonds with commercial paper proceeds and cash from operations. o For 2004, the Company issued approximately 1 million shares of its common stock for approximately $73 million in net proceeds from its Investor Plus Stock Purchase Plan and its employee benefit and stock option plans, net of purchases of restricted shares. For 2004, the dividends paid on common stock were approximately $558 million. 2003 o Progress Energy obtained a three-year financing order, allowing it to issue up to $2.8 billion of long-term securities, $1.5 billion of short-term debt, and $3 billion in parent guarantees. Progress Energy issued approximately 8 million shares of common stock for approximately $304 million in net proceeds from its Investor Plus Stock Purchase Plan and its employee benefit plans, net of purchases of restricted shares. For 2003, the dividends paid on common stock were approximately $541 million. o PEC redeemed $250 million and issued $600 million in first mortgage bonds. 63 o PEF redeemed $250 million, issued $950 million and paid at maturity $180 million in first mortgage bonds. PEF also paid at maturity $35 million in medium-term notes. o Progress Capital Holdings, Inc., paid at maturity $58 million in medium-term notes. o Progress Genco Ventures, LLC, terminated its $50 million working capital credit facility. Under its related construction facility, Genco had drawn $241 million at December 31, 2003. 2002 o Progress Energy issued $800 million in senior unsecured notes. Progress Energy issued approximately 2 million shares representing approximately $86 million in proceeds from its Investor Plus Stock Purchase Plan and its employee benefit plans. o PEC issued and redeemed $500 million in senior unsecured notes and $48.5 million in pollution control obligations. PEC also redeemed $150 million and paid at maturity $100 million in first mortgage bonds. o PEF issued and redeemed $241 million in pollution control obligations and paid at maturity $30 million in medium-term notes. o Progress Capital Holdings, Inc., paid at maturity $50 million in medium-term notes. o Progress Genco Ventures, LLC, obtained a $440 million bank facility, including $50 million for working capital. During the year, $130 million of the facility was terminated. The amount outstanding at December 31, 2002, was $225 million. o 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. For 2002, the dividends paid on common stock were approximately $480 million. FUTURE LIQUIDITY AND CAPITAL RESOURCES The Company's two electric utilities produced over 100% of consolidated cash from operations in 2004. 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 increase their operating cash flows. PEF notified the FPSC in January 2005 of its intent to file for an increase in its base rates effective January 1, 2006. If approved by the FPSC, an increase in PEF's base rates would increase future operating cash flows. PEF has faced significant cost increases over the past decade and expects its operational costs to continue to increase. These costs include the costs associated with completion of the Hines 3 generation facility, extraordinary hurricane damage costs including capital costs not expected to be directly recoverable, the need to replenish the depleted storm reserve and the expected infrastructure investment necessary to meet high customer expectations, coupled with the demands placed on PEF as a result of strong customer growth. If the FPSC does not approve PEF's request to increase base rates, the Company's results of operations and financial condition could be negatively impacted. The Company cannot predict the outcome of this matter. Related risks are described in more detail in the "Risk Factors" section. In addition, Fuels' synthetic fuel operations do not currently produce positive operating cash flow 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. See Note 23E for further discussion. Capital Expenditures Total cash from operations provided the funding for the Company's capital expenditures, including property additions, nuclear fuel expenditures and diversified business property additions during 2004, excluding proceeds from asset sales of $366 million. 64 As shown in the table below, Progress Energy expects the majority of its capital expenditures to be incurred at its regulated operations. See Note 8F for a discussion of expected impacts on future capital expenditures due to changes in capitalization practice for regulated operations. The Company anticipates its regulated capital expenditures will increase in 2005 due to increased spending on Clean Air initiatives. Forecasted nonregulated expenditures relate primarily to Progress Fuels and its gas operations, mainly for drilling new wells. - ---------------------------------------------------------------------------------------------- Actual Forecasted ----------- ------------------------------------------- (in millions) 2004 2005 2006 2007 - ---------------------------------------------------------------------------------------------- Regulated capital expenditures $ 998 $ 1,030 $ 1,040 $ 1,090 Nuclear fuel expenditures 101 120 90 150 AFUDC - borrowed funds (6) (10) (10) (10) Nonregulated capital expenditures 236 190 180 190 - ---------------------------------------------------------------------------------------------- Total $ 1,329 $ 1,330 $ 1,300 $ 1,420 - ----------------------------------------------------------------------------------------------
Regulated capital expenditures in the table above include total expenditures from 2005 through 2006 of approximately $65 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. The Company also expects to incur expenditures of approximately $15 million ($10 million at PEC and $5 million at PEF) from 2005 through 2007 and additional expenditures of approximately $70 million to $100 million ($10 million to $20 million at PEC and $60 million to $80 million at PEF) from 2008 through 2009 for compliance with the Section 316(b) requirements of the Clean Water Act (See Note 22). 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 $895 million by 2013. For the years 2005 through 2007, the Company expects to incur approximately $475 million of total capital costs associated with this legislation, which is included in the table above (See Note 22). 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. Other Cash Needs As of December 31, 2004, on a consolidated basis, the Company had $349 million of long-term debt maturing in 2005. Progress Energy expects to pay these maturities using funds from operations, issuance of new long-term debt, commercial paper borrowings and/or issuance of new equity securities. In 2006, $800 million of Progress Energy senior unsecured notes will mature. The Company expects to fund the maturity using proceeds from the sale of the Progress Rail subsidiary, issuance of new long-term debt, commercial paper borrowings and/or issuance of new equity securities. During the fourth quarter of 2004, Progress Energy announced the launch of a new cost management initiative aimed at achieving nonfuel O&M expense reductions of $75 million to $100 million annually by the end of 2007. In connection with this cost management initiative, the Company expects to incur one-time pre-tax charges of approximately $130 million. Approximately $30 million of that amount relates to payments for severance benefits, which will be recognized in the first quarter of 2005 and paid over time. The remaining approximately $100 million will be recognized in the second quarter of 2005 and relates primarily to postretirement benefits that will be paid over time to those eligible employees who elect to participate in the voluntary enhanced retirement program (See Note 24). Credit Facilities At December 31, 2004, the Company and its subsidiaries had committed lines of credit and outstanding balances as shown in the table in Note 13. All of the credit facilities supporting the credit were arranged through a syndication of financial institutions. There are no bilateral contracts associated with these facilities. 65 The Company's financial policy precludes issuing commercial paper in excess of its supporting lines of credit. At December 31, 2004, the Company had $424 million of commercial paper outstanding, $150 million reserved for backing of letters of credit and an additional $475 million drawn directly from the credit facilities, leaving $931 million available for issuance or drawdown. In addition, the Company has requirements to pay minimal annual commitment fees to maintain its credit facilities. At December 31, 2003, the Company had $4 million of commercial paper outstanding. The Company expects to continue to use commercial paper issuances as a source of liquidity as long as it maintains its current short-term ratings. All of the credit facilities include a defined maximum total debt-to-total capital ratio (leverage) and coverage ratios. The Company is in compliance with these covenants at December 31, 2004. See Note 13 for a discussion of the credit facilities' financial covenants, material adverse change clause provisions and cross-default provisions. At December 31, 2004, the calculated ratios for the companies, pursuant to the terms of the agreements, are as disclosed in Note 13. Both PEC and PEF plan to enter into new five-year lines of credit in 2005 to replace their existing credit facilities. 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, 2004, the Company had approximately $1.1 billion available under this shelf registration. Progress Energy and PEF each have an uncommitted bank bid facility authorizing each of them to borrow and reborrow, and have loans outstanding at any time, up to $300 million and $100 million, respectively. At December 31, 2004, 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, 2004, PEC and PEF could issue up to $2.9 billion and $3.7 billion, respectively, based on property additions and $2.2 billion and $176 million, respectively, based upon retirements. The following table shows Progress Energy's and Progress Energy Carolinas' capital structure at December 31: - -------------------------------------------------------------------------------- Progress Energy PEC ------------------------- --------------------------- 2004 2003 2004 2003 - -------------------------------------------------------------------------------- Common stock 41.7% 40.5% 47.1% 48.2% Preferred stock and minority interest 0.7% 0.7% 0.9% 0.9% Total debt 57.6% 58.8% 52.0% 50.9% - -------------------------------------------------------------------------------- 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. 66 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. Outlook Negative Negative Stable Corporate credit rating n/a BBB n/a Senior unsecured debt Baa2 BBB- BBB- Commercial paper P-2 A-3 n/a - --------------------------------------------------------------------------------------------------- Progress Energy Carolinas, Inc. Corporate credit rating n/a BBB n/a Commercial paper P-2 A-3 F2 Senior secured debt A3 BBB A- Senior unsecured debt Baa1 BBB BBB+ - --------------------------------------------------------------------------------------------------- Progress Energy Florida, Inc. Corporate credit rating n/a BBB n/a Commercial paper P-2 A-3 F2 Senior secured debt A2 BBB A- Senior unsecured debt A3 BBB BBB+ - --------------------------------------------------------------------------------------------------- FPC Capital I Preferred stock* Baa2 BB+ n/a - -------------------------------------------------------------------------------------------------- Progress Capital Holdings, Inc. Senior unsecured debt* Baa1 BBB- n/a - ---------------------------------------------------------------------------------------------------
*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. On February 11, 2005, Moody's credit rating agency announced that it lowered the ratings of PEF, Progress Capital Holdings and FPC Capital Trust I and changed their rating outlooks to stable from negative. Moody's affirmed the ratings of Progress Energy and PEC. The rating outlooks continue to be stable at PEC and negative at Progress Energy. Moody's stated that it took this action primarily due to declining cash flow coverages and rising leverage, higher O&M costs, uncertainty regarding the timing of hurricane cost recovery, regulatory risks associated with the upcoming rate case in Florida and ongoing capital requirements to meet Florida's growing demand. On October 19, 2004, S&P changed Progress Energy's outlook from stable to negative. S&P cited the uncertainties regarding the timing of the recovery of hurricane costs, the Company's debt reduction plans and the IRS audit of the Company's Earthco synthetic fuels facilities as the reasons for the change in outlook. On October 25, 2004, S&P reduced the short-term debt rating of Progress Energy, PEC and PEF to A-3 from A-2, as a result of their change in outlook discussed above. On October 20, 2004, Moody's changed its outlook for Progress Energy from stable to negative and placed the ratings of PEF under review for possible downgrade. PEC's ratings were affirmed by Moody's. Moody's cited the following reasons for its change in the outlook for Progress Energy: financial ratios that are weak for its current rating category; rising O&M, pension, benefit and insurance costs; and delays in executing its deleveraging plan. With respect to PEF, Moody's cited declining cash flow coverages and rising leverage over the last several years, expected funding needs for a large capital expenditure program, risks with regard to its upcoming 2005 rate case and the timing of hurricane cost recovery as reasons for putting its ratings under review. The changes by S&P and Moody's do not trigger any debt or guarantee collateral requirements, nor do they have any material impact on the overall liquidity of Progress Energy or any of its affiliates. To date, Progress Energy's, PEC's and PEF's access to the commercial paper markets has not been materially impacted by the rating agencies' actions. However, the changes have increased the interest rate incurred on its short-term borrowings by 0.25% to 0.875%. 67 If Standard & Poor's lowers Progress Energy's senior unsecured rating one ratings category to BB+ from its current rating, it would be a noninvestment grade rating. The effect of a noninvestment grade rating would primarily be to increase borrowing costs. The Company's liquidity would essentially remain unchanged, as the Company believes it could borrow under its revolving credit facilities instead of issuing commercial paper for its short-term borrowing needs. However, there would be additional funding requirements of approximately $450 million due to ratings triggers embedded in various contracts, as more fully described below under "Guarantees" and "Risk Factors." 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. In addition, the Company and its subsidiaries have certain contracts that have provisions triggered by a ratings downgrade to a rating below investment grade. These contracts include counterparty trade agreements, derivative contracts, certain Progress Energy guarantees and various types of third-party purchase agreements. OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS The Company's off-balance sheet arrangements and contractual obligations are described below. Guarantees As a part of normal business, Progress Energy and certain wholly owned subsidiaries enter into various agreements providing future financial or performance assurances to third parties that are outside the scope of Financial Accounting Standards Board (FASB) Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN No. 45). These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to Progress Energy and subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended commercial purposes. The Company's guarantees include performance obligations under power supply agreements, tolling agreements, transmission agreements, gas agreements, fuel procurement agreements and trading operations. The Company's guarantees also include standby letters of credit, surety bonds and guarantees in support of nuclear decommissioning. At December 31, 2004, the Company had issued $1.3 billion of guarantees for future financial or performance assurance. Management does not believe conditions are likely for significant performance under the guarantees of performance issued by or on behalf of affiliates. The majority of contracts supported by the guarantees contain provisions that trigger guarantee obligations based on downgrade events to below investment grade (below BBB- or Baa3), ratings triggers, monthly netting of exposure and/or payments and offset provisions in the event of a default. The recent outlook changes from S&P and Moody's do not trigger any guarantee obligations. As of December 31, 2004, if the guarantee obligations were triggered, the maximum amount of liquidity requirements to support ongoing operations within a 90-day period, associated with guarantees for the Company's nonregulated portfolio and power supply agreements was $450 million. The Company would meet this obligation with cash or letters of credit. As of December 31, 2004, Progress Energy had guarantees issued on behalf of third parties of approximately $10 million. See Note 23D for a discussion of guarantees in accordance with FIN No. 45. Market Risk and Derivatives 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. See Note 18 and Item 7A, "Quantitative and Qualitative Disclosures About Market Risk," for a discussion of market risk and derivatives. Contractual Obligations The Company is party to numerous contracts and arrangements obligating it to make cash payments in future years. These contracts include financial arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services. Amounts in the following table are estimated based upon contractual terms and actual amounts will likely differ from amounts presented below. Further disclosure regarding the Company's contractual obligations is included in the respective notes. The Company takes into consideration the future commitments when assessing its liquidity and future financing needs. The following table reflects Progress Energy's contractual cash obligations and other commercial commitments at December 31, 2004, in the respective periods in which they are due: 68 - ------------------------------------------------------------------------------------------------------------------- Less than 1 More than 5 (in millions) Total year 1-3 years 3-5 years years - ------------------------------------------------------------------------------------------------------------------- Long-term debt (a) (See Note 13) $ 9,942 $ 349 $ 1,637 $ 1,387 $ 6,569 Interest payments on long-term debt and interest rate derivatives (b) 3,064 301 489 423 1,851 Capital lease obligations (See Note 23C) 50 4 8 7 31 Operating leases (See Note 23C) 597 66 113 112 306 Fuel and purchased power (c) (See Note 23A) 13,010 2,692 3,088 1,346 5,884 Other purchase obligations (See Note 23A) 633 151 134 80 268 NC Clean Air capital commitments (See Note 22) 764 170 297 143 154 Other commitments (d)(e) 243 42 70 26 105 - ------------------------------------------------------------------------------------------------------------------- Total $ 28,303 $ 3,775 $ 5,836 $ 3,524 $ 15,168 - -------------------------------------------------------------------------------------------------------------------
a. 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 debt to total capitalization leverage by one to two percentage points over the next few years through selected asset sales, free cash flow and increased equity from retained earnings and ongoing equity issuances. b. Interest payments on long-term debt and interest rate derivatives are based on the interest rate effective as of December 31, 2004, and the LIBOR forward curve as of December 31, 2004, respectively. c. 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. d. 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. e. The Company has certain future commitments related to four synthetic fuel facilities purchased that provide for contingent payments (royalties) through 2007 (See Note 23B). OTHER MATTERS Synthetic Fuels Tax Credits The Company has substantial operations associated with the production of coal-based synthetic fuels. The production and sale of these products qualifies for federal income tax credits so long as certain requirements are satisfied. These operations are subject to numerous risks. Although the Company believes that it operates its synthetic fuel facilities in compliance with applicable legal requirements for claiming the credits, its four Earthco facilities are under audit by the IRS. IRS field auditors have taken an adverse position with respect to the Company's compliance with one of these legal requirements, and if the Company fails to prevail with respect to this position, it could incur significant liability and/or lose the ability to claim the benefit of tax credits carried forward or generated in the future. Similarly, the Financial Accounting Standards Board may issue new accounting rules that would require that uncertain tax benefits (such as those associated with the Earthco plants) be probable of being sustained in order to be recorded on the financial statements; if adopted, this provision could have an adverse financial impact on the Company. The Company's ability to utilize tax credits is dependent on having sufficient tax liability. Any conditions that negatively impact the Company's tax liability, such as weather, could also diminish the Company's ability to utilize credits, including those previously generated, and the synthetic fuel is generally not economical to produce absent the credits. Finally, the tax credits associated with synthetic fuels may be phased out if market prices for crude oil exceed certain prices. The Company's synthetic fuel operations and related risks are described in more detail in Note 23E and in the "Risk Factors" section. 69 Hurricane Costs Hurricanes Charley, Frances, Ivan and Jeanne struck significant portions of the Company's service territories during the third quarter of 2004, significantly impacting PEF's territory. As of December 31, 2004, restoration of the Company's systems from hurricane-related damage was estimated at $398 million. PEC incurred restoration costs of $13 million, of which $12 million was charged to operation and maintenance expense and $1 million was charged to capital expenditures. PEF had estimated total costs of $385 million, of which $47 million was charged to capital expenditures, and $338 million was charged to the storm damage reserve pursuant to a regulatory order. In accordance with a regulatory order, PEF accrues $6 million annually to a storm damage reserve and is allowed to defer losses in excess of the accumulated reserve for major storms. Under the order, the storm reserve is charged with operation and maintenance expenses related to storm restoration and with capital expenditures related to storm restoration that are in excess of expenditures assuming normal operating conditions. As of December 31, 2004, $291 million of hurricane restoration costs in excess of the previously recorded storm reserve of $47 million had been classified as a regulatory asset recognizing the probable recoverability of these costs. On November 2, 2004, PEF filed a petition with the FPSC to recover $252 million of storm costs plus interest from retail ratepayers over a two-year period. Storm reserve costs of $13 million were attributable to wholesale customers. The Company has received approval from the FERC to amortize these costs consistent with recovery of such amounts in wholesale rates. PEF continues to review the restoration cost invoices received. Given that not all invoices have been received as of December 31, 2004, PEF will update its petition with the FPSC upon receipt and audit of all actual charges incurred. Hearings on PEF's petition for recovery of $252 million of storm costs filed with the FPSC are scheduled to begin on March 30, 2005. On November 17, 2004, the Citizens of the State of Florida, by and through Harold McLean, Public Counsel, and the Florida Industrial Power Users Group (FIPUG), (collectively, Joint Movants), filed a Motion to Dismiss PEF's petition to recover the $252 million in storm costs. On November 24, 2004, PEF responded in opposition to the motion, which was also the FPSC staff's position in its recommendation to the Commission on December 21, 2004, that it should deny the Motion to Dismiss. On January 4, 2005, the Commission ruled in favor of PEF and denied the Joint Movant's Motion to Dismiss. PEF's January 2005 notice to the FPSC of its intent to file for an increase in its base rates effective January 1, 2006, anticipates the need to replenish the depleted storm reserve balance and adjust the annual $6 million accrual in light of recent storm history to restore the reserve to an adequate level over a reasonable time period. PEC does not have an ongoing regulatory mechanism to recover storm costs; therefore, hurricane restoration costs recorded in the third quarter of 2004 were charged to operations and maintenance expenses or capital expenditures based on the nature of the work performed. In connection with other storms, PEC has previously sought and received permission from the NCUC and the SCPSC to defer storm expenses and amortize them over a five-year period. PEC did not seek deferral of 2004 storm costs from the NCUC (See Note 8B). Regulatory Environment and Matters 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. 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. The retail rate matters affected by the regulatory authorities are discussed in detail in Notes 8B and 8C. This discussion identifies specific retail rate matters, the status of the issues and the associated effects to the Company's consolidated financial statements. 70 The regulatory authorities continue to evaluate issues related to the formation of Regional Transmission Organizations. The Company cannot predict the outcome of these matters on the Company's earnings, revenues or prices or the investments in GridSouth and GridFlorida (See Note 8D). A FERC order issued in November 2001 on certain unaffiliated utilities' triennial market-based wholesale power rate authorization updates required certain mitigation actions that those utilities would need to take for sales/purchases within their control areas and required those utilities to post information on their Web sites regarding their power systems' status. As a result of a request for rehearing filed by certain market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. In April 2004, the FERC issued two orders concerning utilities' ability to sell wholesale electricity at market-based rates. In the first order, the FERC adopted two new interim screens for assessing potential generation market power of applicants for wholesale market-based rates, and described additional analyses and mitigation measures that could be presented if an applicant does not pass one of these interim screens. In July 2004, the FERC issued an order on rehearing affirming its conclusions in the April order. In the second order, the FERC initiated a rulemaking to consider whether the FERC's current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in any way. PEF does not have market-based rate authority for wholesale sales in peninsular Florida. Given the difficulty PEC believes it would experience in passing one of the interim screens, on August 12, 2004, PEC notified the FERC that it would revise its Market-based Rate tariff to restrict it to sales outside PEC's control area and file a new cost-based tariff for sales within PEC's control area that incorporates the FERC's default cost-based rate methodologies for sales of one year or less. PEC anticipates making this filing in the first quarter of 2005. Although the Company cannot predict the ultimate outcome of these changes, the Company does not anticipate that the current operations of PEC or PEF would be impacted materially if they were unable to sell power at market-based rates in their respective control areas. Franchise Litigation Three cities, with a total of approximately 18,000 customers, have litigation pending against PEF in various circuit courts in Florida. As previously reported, 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. The circuit courts in those cases 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 the cities to determine the value of PEF's electric distribution system within the cities through arbitration. Arbitration in one of the cases (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 (the City) at approximately $32 million, not including separation and reintegration 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, which, according to the award, decrease over time. 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. While the City has not yet definitively decided whether it will acquire the system, on April 26, 2004, the City Commission voted to proceed with the acquisition. The City sought and received wholesale power supply bids and on June 24, 2004, executed a wholesale power supply contract with PEF. On May 12, 2004, the City solicited bids to operate and maintain the distribution system and awarded a contract in January 2005. The City has indicated that its goal is to begin electric operations in June 2005. On February 10, 2005, PEF filed a petition with the Florida Public Service Commission to relieve the Company of its statutory obligation to serve customers in Winter Park on June 1, 2005, or at such time when the City is able to provide retail service. At this time, whether and when there will be further proceedings regarding the City of Winter Park cannot be determined. 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 $2 million in stranded costs. 71 The Town has not yet decided whether it will attempt to acquire the system; however, on January 18, 2005, it issued a request for proposals for wholesale power supply and to operate and maintain the distribution system. Proposals are due in early March 2005. In February 2005, the Town Commission also voted to put the issue of whether to acquire the distribution system to a voter referendum on or before October 2, 2005. At this time, whether and when there will be further proceedings regarding the Town of Belleair cannot be determined. Arbitration in the remaining city's litigation (the 1,500-customer City of Edgewood) has not yet been scheduled. On February 17, 2005, the parties filed a joint motion to stay the litigation for a 90-day period during which the parties will discuss potential settlement. A fourth city (the 7,000-customer City of Maitland) is contemplating municipalization and has indicated its intent to proceed with arbitration to determine the value of PEF's electric distribution system within the City. Maitland's franchise expires in August 2005. At this time, whether and when there will be further proceedings regarding the City of Maitland cannot be determined. As part of the above litigation, two appellate courts 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 filed an appeal with the Florida Supreme Court to resolve the conflict between the two appellate courts. On October 28, 2004, the Court issued a decision holding that PEF must collect from its customers and remit to the cities franchise fees during the interim period when the city exercises its purchase option or executes a new franchise. The Court's decision should not have a material impact on the Company. Legal The Company is subject to federal, state and local legislation and court orders. These matters are discussed in detail in Note 23E. This discussion identifies specific issues, the status of the issues, accruals associated with issue resolutions and the associated exposures to the Company. Nuclear Nuclear generating units are regulated by the NRC. 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 (See Notes 6 and 23E). 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 22. This discussion identifies specific environmental issues, the status of the issues, accruals associated with issue resolutions and the associated exposures to the Company. The Company accrues costs to the extent they are probable and can be reasonably estimated. It is reasonably possible that additional losses, which could be material, may be incurred in the future. New Accounting Standards See Note 2 for a discussion of the impact of new accounting standards. 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. 72 RESULTS OF OPERATIONS The results of operations for the PEC consolidated for the years ended December 31 are summarized in the table below. The results of operations for the PEC Electric segment are identical in all material respects 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 relate to the nonelectric operations, as summarized below: - -------------------------------------------------------------------------------- (in millions) 2004 2003 2002 - -------------------------------------------------------------------------------- PEC Electric income before cumulative effect $ 464 $ 515 $ 513 Caronet net income (loss) - 5 (79) Other nonelectric net loss (6) (18) (6) Cumulative effect of accounting change - (23) - - -------------------------------------------------------------------------------- Earnings for common stock $ 458 $ 479 $ 428 - -------------------------------------------------------------------------------- Caronet's results of operations for 2002 includes after-tax impairments of $87 million for other-than-temporary declines in the value of the assets of Caronet and Caronet's investment in Interpath (See Note 7A to the PEC Consolidated Financial Statements). The stock of Caronet was sold in December 2003 (See Note 1A to the PEC Consolidated Financial Statements). The other nonelectric subsidiaries of PEC contributed segment losses of $6 million and $18 million for the years ended December 31, 2004 and 2003, respectively. The Other nonelectric results for 2003 include investment impairments of $6 million after-tax on the Affordable Housing portfolio held by the nonutility subsidiaries of PEC. (See Note 7B to the PEC Consolidated Financial Statements.) A reduction in investment losses accounted for the remaining favorability compared to prior year. In 2003, 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 due primarily to the new FASB guidance related to the accounting for the purchase power contract with Broad River LLC (See Note 13A to the PEC Consolidated Financial Statements). Note 1D to the PEC Consolidated Financial Statements discusses its significant accounting policies. The most critical accounting policies and estimates that impact PEC's consolidated financial statements are the economic impacts of utility regulation and asset impairment policies, described in more detail in the Progress Energy Management's Discussion and Analysis section. LIQUIDITY AND CAPITAL RESOURCES Overview PEC has primarily used a combination of unsecured notes, first mortgage bonds, pollution control bonds, commercial paper facilities and revolving credit agreements for liquidity needs in excess of cash provided by operations. During 2004, PEC extended its $165 million 364-day line of credit to July 27, 2005 and PEC's three-year $285 million line of credit expires July 31, 2005. As discussed above in the Progress Energy "Overview," in October 2004, S&P reduced the short-term debt rating of PEC to A-3 from A-2. As a result of the impact of these actions on PEC's ability to access the commercial paper markets, PEC has borrowed on its revolving credit agreements. As of December 31, 2004, the total amount of outstanding borrowings on PEC's revolving credit agreements was $90 million. The borrowed funds were used to pay off maturing commercial paper and for other cash needs. The changes by S&P do not trigger any debt or guarantee collateral requirements, nor do they have any material impact on the overall liquidity of PEC. To date, PEC's access to the commercial paper markets has not been materially impacted by the rating agencies' actions. However, the changes have increased the interest rate incurred on its short-term borrowings by 0.25% to 0.875%. 73 PEC expects to have sufficient resources to meet its future obligations either through internally generated funds, its short term-term borrowing facilities or through the issuance of long-term debt. HISTORICAL FOR 2004 AS COMPARED TO 2003 AND 2003 AS COMPARED TO 2002 In 2004, cash provided by operating activities decreased when compared to 2003. The decrease was caused primarily by a $89 million under-recovery of fuel costs and a $76 million decrease in payables to affiliates. In 2003, cash provided by operating activities increased when compared to 2002, largely as a result of improved operating results. In 2004, cash used in investing activities decreased approximately $257 million in 2004 when compared with 2003. The decrease is primarily to net proceeds from short-term investments in 2004, compared to net purchases in 2003. The decrease is partially offset by an increase in capital expenditures, primarily related to increased spending for NC Clean Air legislation, and an increase in nuclear fuel additions. See the discussion above for Progress Energy under "Financing Activities" for information regarding PEC's financing activities. FUTURE LIQUIDITY AND CAPITAL RESOURCES PEC's estimated capital requirements for 2005, 2006 and 2007 are $650 million, $670 million and $680 million, respectively, and primarily reflect construction expenditures to support customer growth, add regulated generation and upgrade existing facilities. See Note 6E to the PEC Consolidated Financial Statements for a discussion of expected impacts on future capital expenditures due to changes in capitalization practice for PEC. PEC expects to fund its capital requirements primarily through internally generated funds. In addition, PEC has $450 million in credit facilities that support 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. PEC plans to enter into a new five-year line of credit in 2005 that will replace these two expiring facilities. See Note 9 to the PEC Consolidated Financial Statements for information on PEC's available credit facilities at December 31, 2004. OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS PEC's off-balance sheet arrangements and contractual obligations are described below. Market Risk and Derivatives 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. See Note 13 and Item 7A, "Quantitative and Qualitative Disclosures About Market Risk," for a discussion of market risk and derivatives. Contractual Obligations PEC is party to numerous contracts and arrangements obligating it to make cash payments in future years. These contracts include financial arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services. Amounts in the following table are estimated based upon contractual terms and will likely differ from amounts presented below. Further disclosure regarding PEC's contractual obligations is included in the respective notes to the PEC Consolidated Financial Statements. PEC takes into consideration the future commitments when assessing its liquidity and future financing needs. The following table reflects Progress Energy's contractual cash obligations and other commercial commitments at December 31, 2004, in the respective periods in which they are due: 74 - -------------------------------------------------------------------------------------------------------- Less than More than (in millions) Total 1 year 1-3 years 3-5 years 5 years - -------------------------------------------------------------------------------------------------------- Long-term debt (a) (See Note 9) $ 3,069 $ 300 $ 200 $ 700 $ 1,869 Interest payments on long-term debt and interest rate derivatives (b) 1,342 150 285 207 700 Capital lease obligations (See Note 18B) 35 2 4 4 25 Operating leases (See Note 18B) 187 28 37 25 97 Fuel and purchased power (c) (See Note 18A) 3,427 786 1,098 431 1,112 Other purchase obligations (See Note 18A) 25 12 - - 13 North Carolina clean air capital commitments (See Note 17) 764 170 297 143 154 Other commitments (d) 131 - - 26 105 - -------------------------------------------------------------------------------------------------------- Total $ 8,980 $ 1,448 $ 1,921 $ 1,536 $ 4,075 - --------------------------------------------------------------------------------------------------------
a. 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 debt to total capitalization leverage by one to two percentage points over the next few years through selected asset sales, free cash flow and increased equity from retained earnings and ongoing equity issuances. b. Interest payments on long-term debt and interest rate derivatives are based on the interest rate effective as of December 31, 2004, and the LIBOR forward curve as of December 31, 2004, respectively. c. 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. d. 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. 75 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, 2004 and 2003, 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 for 2005-2009 and thereafter and the fair value of the related hedges. 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 Note 18 for more information on interest rate derivatives. - ----------------------------------------------------------------------------------------------------------------------- December 31, 2004 Fair Value December 31, (dollars in millions) 2005 2006 2007 2008 2009 Thereafter Total 2004 - ----------------------------------------------------------------------------------------------------------------------- Fixed rate long-term debt $ 349 $ 908 $ 674 $ 827 $ 400 $ 5,399 $ 8,557 $ 9,454 Average interest rate 7.38% 6.78% 6.41% 6.27% 5.95% 6.55% 6.54% Variable rate long-term debt - $ 55 - - $ 160 $ 861 $ 1,076 $ 1,077 Average interest rate - 2.95% - - 3.19% 1.70% 1.99% Debt to affiliated trust(a) - - - - - $ 309 $ 309 $ 312 Interest rate - - - - - 7.10% 7.10% Interest rate derivatives: Pay variable /receive fixed - - - $(100) - $ (50) $ (150) $ 3 Average pay rate - - - (b) - (b) (b) Average receive rate - - - 4.10% - 4.65% 4.28% Interest rate forward contracts $ 200 - - - - $ 131 $ 331 $ (2) Average pay rate 3.07% - - - - 4.90% 3.79% Average receive rate (c) - - - - (b) (b)(c) - -----------------------------------------------------------------------------------------------------------------------
(a) FPC Capital I - Quarterly Income Preferred Securities. (b) Rate is 3-month LIBOR, which was 2.56% at December 31, 2004. (c) Rate is 1-month LIBOR, which was 2.40% at December 31, 2004. 76 - ----------------------------------------------------------------------------------------------------------------------- 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(a) - - - - - $ 309 $ 309 $ 313 Interest rate - - - - - 7.10% 7.10% Interest rate derivatives: Pay variable/receive fixed - - $(300) $ (350) $ (200) - $ (850) $ (4) Average pay rate (b) (b) (b) (b) Average receive rate 2.75% 3.35% 2.93% 3.04% Payer swaptions - - - - $ 400 - $ 400 $ 5 Average pay rate 4.75% Average receive rate (b) Interest rate collars(c) $ 65 - - $ 130 - - $ 195 $ (11) Cap rate 6.00% 6.50% Floor rate 4.13% 5.13% - -----------------------------------------------------------------------------------------------------------------------
(a) FPC Capital I - Quarterly Income Preferred Securities. (b) Rate is 3-month LIBOR, which was 1.15% at December 31, 2003. (c) Notional amount is varying with a maximum of $195 million, decreasing to $130 million after December 2004. 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 $1.044 billion and $938 million at December 31, 2004 and 2003, 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 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, 2004 and 2003, the fair value of these CVOs was $13 million and $23 million, respectively. A hypothetical 10% decrease in the December 31, 2004, market price would result in a $1 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, coal, fuel oil, 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. Each state commission allows electric utilities to recover certain of these costs through various cost recovery clauses to the extent the respective commission determines that such costs are prudent. Therefore, while there may be a delay in the timing between when these costs are incurred and when these costs are recovered from the ratepayers, changes from year to year have no material impact on operating results. In addition, many of the Company's long-term power sales contracts shift substantially all fuel responsibility to the purchaser. The Company also has oil price risk exposure related to synfuel tax credits. See discussion in Note 23E. 77 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 activity using natural gas and electricity financial instruments. In 2004, PEF entered into derivative instruments related to its exposure to price fluctuations on fuel oil purchases. At December 31, 2004, the fair values of these instruments were a $2 million long-term derivative asset position included in other assets and deferred debits and a $5 million short-term derivative liability position included in other current liabilities. These instruments receive regulatory accounting treatment. Gains are recorded in regulatory liabilities and losses are recorded in regulatory assets. Refer to Note 18 for additional information with regard to the Company's commodity contracts and use of derivative financial instruments. The Company performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% increase or decrease in quoted market prices in the near term on the Company's derivative commodity instruments would not have had a material effect on the Company's consolidated financial position, results of operations or cash flows as of December 31, 2004. PEC PEC has certain market risks inherent in its financial instruments, which arise from transactions entered into in the normal course of business. PEC's primary exposures are changes in interest rates, with respect to long-term debt and commercial paper, and fluctuations in the return on marketable securities, with respect to its nuclear decommissioning trust funds. The information required by this item is incorporated herein by reference to the Quantitative and Qualitative Disclosures About Market Risk insofar as it relates to PEC. Interest Rate Risk The following tables provide information at about PEC's interest rate risk sensitive instruments: - --------------------------------------------------------------------------------------------------------------------------- December 31, 2004 Fair Value December 31, (dollars in millions) 2005 2006 2007 2008 2009 Thereafter Total 2004 - --------------------------------------------------------------------------------------------------------------------------- Fixed rate long-term debt $ 300 - $ 200 $ 300 $ 400 $ 1,249 $ 2,449 $ 2,686 Average interest rate 7.50% - 6.80% 6.65% 5.95% 6.13% 6.38% Variable rate long-term debt - - - - - $ 620 $ 620 $ 621 Average interest rate - - - - - 1.71% 1.71% Interest rate forward contracts - - - - - $ 131 $ 131 $ (2) Average pay rate 4.90% 4.90% Average receive rate (a) (a) - --------------------------------------------------------------------------------------------------------------------------- (a) Rate is 3-month LIBOR, which was 2.56% at December 31, 2004 - -------------------------------------------------------------------------------------------------------------------------- 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% - --------------------------------------------------------------------------------------------------------------------------
78 Commodity Price Risk PEC is exposed to the effects of market fluctuations in the price of natural gas, coal, fuel oil, 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. Each state commission allows electric utilities to recover certain of these costs through various cost recovery clauses to the extent the respective commission determines that such costs are prudent. Therefore, while there may be a delay in the timing between when these costs are incurred and when these costs are recovered from the ratepayers, changes from year to year have no material impact on operating results. PEC may engage in limited economic hedging activity using natural gas and electricity financial instruments. Refer to Note 13 to the PEC Consolidated Financial Statements for additional information with regard to PEC's commodity contracts and use of derivative financial instruments. PEC performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% increase or decrease in quoted market prices in the near term on its derivative commodity instruments would not have had a material effect on PEC's consolidated financial position, results of operations or cash flows as of December 31, 2004. 79 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. Reports of Independent Registered Public Accounting Firm Consolidated Financial Statements - Progress Energy, Inc.: Consolidated Statements of Income for the Years Ended December 31, 2004, 2003 and 2002 83 Consolidated Balance Sheets at December 31, 2004 and 2003 84-85 Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002 86 Consolidated Statements of Changes in Common Stock Equity for the Years Ended December 31, 2004, 2003 and 2002 87 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2004, 2003 and 2002 87 Notes to the Consolidated Financial Statements Note 1 - Organization and Summary of Significant Accounting Policies 88 Note 2 - New Accounting Standards 94 Note 3 - Hurricane Related Costs 95 Note 4 - Divestitures 95 Note 5 - Acquisitions and Business Combinations 97 Note 6 - Property, Plant and Equipment 99 Note 7 - Current Assets 103 Note 8 - Regulatory Matters 103 Note 9 - Goodwill and Other Intangible Assets 108 Note 10 - Impairments of Long-Lived Assets and Investments 109 Note 11 - Equity 109 Note 12 - Preferred Stock of Subsidiaries - Not Subject to Mandatory Redemption 113 Note 13 - Debt and Credit Facilities 113 Note 14 - Fair Value of Financial Instruments 117 Note 15 - Income Taxes 117 Note 16 - Contingent Value Obligations 119 Note 17 - Benefit Plans 119 Note 18 - Risk Management Activities and Derivatives Transactions 123 Note 19 - Related Party Transactions 125 Note 20 - Financial Information by Business Segment 126 Note 21 - Other Income and Other Expense 128 Note 22 - Environmental Matters 128 Note 23 - Commitments and Contingencies 133 Note 24 - Subsequent Events 141 Note 25 - Consolidated Quarterly Financial Data (Unaudited) 142
80 Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. Report of Independent Registered Public Accounting Firm Consolidated Financial Statements - Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.: Consolidated Statements of Income for the Years Ended December 31, 2004, 2003 and 2002 144 Consolidated Balance Sheets at December 31, 2004 and 2003 145 Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002 146 Consolidated Statements of Retained Earnings for the Years Ended December 31, 2004, 2003 and 2002 147 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2004, 2003 and 2002 147 Notes to the Consolidated Financial Statements Note 1 - Organization and Summary of Significant Accounting Policies 148 Note 2 - New Accounting Standards 153 Note 3 - Hurricane Related Costs 154 Note 4 - Property, Plant and Equipment 154 Note 5 - Current Assets 157 Note 6 - Regulatory Matters 157 Note 7 - Impairments of Long-Lived Assets and Investments 160 Note 8 - Equity 160 Note 9 - Debt and Credit Facilities 162 Note 10 - Fair Value of Financial Instruments 164 Note 11 - Income Taxes 164 Note 12 - Benefit Plans 166 Note 13 - Risk Management Activities and Derivatives Transactions 169 Note 14 - Related Party Transactions 170 Note 15 - Financial Information by Business Segment 171 Note 16 - Other Income and Other Expense 172 Note 17 - Environmental Matters 172 Note 18 - Commitments and Contingencies 175 Note 19 - Subsequent Event 179 Note 20 - Consolidated Quarterly Financial Data (Unaudited) 179 Report of Independent Registered Public Accounting Firm on Consolidated Financial Statement Schedule - Progress Energy, Inc. 180 Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. 181 Consolidated Financial Statement Schedules for the Years Ended December 31, 2004, 2003 and 2002: II-Valuation and Qualifying Accounts - Progress Energy, Inc. 182 II-Valuation and Qualifying Accounts - Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. 183
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 Notes to the Consolidated Financial Statements. 81 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC. We have audited the accompanying consolidated balance sheets of Progress Energy, Inc., and its subsidiaries (the Company) at December 31, 2004 and 2003, and the related consolidated statements of income, comprehensive income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2004. 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 the standards of the Public Company Accounting Oversight Board (United States). 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 the Company at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. As discussed in Notes 1D and 18A to the consolidated financial statements, in 2003, the Company adopted Statement of Financial Accounting Standards No. 143 and Derivatives Implementation Group Issue C20. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 7, 2005, expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting. Deloitte & Touche LLP 82 Raleigh, North Carolina March 7, 2005 PROGRESS ENERGY, INC. CONSOLIDATED STATEMENTS of INCOME - ----------------------------------------------------------------------------------------------------- (in millions except per share data) Years ended December 31 2004 2003 2002 - ----------------------------------------------------------------------------------------------------- Operating Revenues Electric $ 7,153 $ 6,741 $ 6,601 Diversified business 2,619 2,000 1,490 - ----------------------------------------------------------------------------------------------------- Total Operating Revenues 9,772 8,741 8,091 - ----------------------------------------------------------------------------------------------------- Operating Expenses Utility Fuel used in electric generation 2,011 1,695 1,586 Purchased power 868 862 862 Operation and maintenance 1,475 1,421 1,390 Depreciation and amortization 878 883 820 Taxes other than on income 425 405 386 Diversified business Cost of sales 2,288 1,748 1,410 Depreciation and amortization 190 157 118 Impairment of long-lived assets - 17 364 (Gain)/loss on the sale of assets (57) 1 - Other 218 195 145 - ----------------------------------------------------------------------------------------------------- Total Operating Expenses 8,296 7,384 7,081 - ----------------------------------------------------------------------------------------------------- Operating Income 1,476 1,357 1,010 - ----------------------------------------------------------------------------------------------------- Other Income (Expense) Interest income 14 11 15 Impairment of investments - (21) (25) Other, net 8 (16) 27 - ----------------------------------------------------------------------------------------------------- Total Other Income (Expense) 22 (26) 17 - ----------------------------------------------------------------------------------------------------- Interest Charges Net interest charges 653 635 641 Allowance for borrowed funds used during construction (6) (7) (8) - ----------------------------------------------------------------------------------------------------- Total Interest Charges, Net 647 628 633 - ----------------------------------------------------------------------------------------------------- Income from Continuing Operations before Income Tax, Minority Interest, and Cumulative Effect of Changes in Accounting Principles 851 703 394 Income Tax Expense (Benefit) 115 (111) (158) - ----------------------------------------------------------------------------------------------------- Income from Continuing Operations before Minority Interest and Cumulative Effect of Changes in Accounting Principles 736 814 552 Minority Interest, Net of Tax (17) 3 - - ----------------------------------------------------------------------------------------------------- Income from Continuing Operations Before Cumulative Effect of 753 811 552 Change in Accounting Principles Discontinued Operations, Net of Tax 6 (8) (24) Cumulative Effect of Changes in Accounting Principles, Net of Tax - (21) - - ----------------------------------------------------------------------------------------------------- Net Income $ 759 $ 782 $ 528 - ----------------------------------------------------------------------------------------------------- Average Common Shares Outstanding 242 237 217 - ----------------------------------------------------------------------------------------------------- Basic Earnings per Common Share Income from Continuing Operations before Cumulative Effect of Changes in Accounting Principles $ 3.11 $ 3.42 $ 2.54 Discontinued Operations, Net of Tax .02 (.03) (.11) Cumulative Effect of Changes in Accounting Principles, Net of Tax - (.09) - - ----------------------------------------------------------------------------------------------------- Net Income $ 3.13 $ 3.30 $ 2.43 - ----------------------------------------------------------------------------------------------------- Diluted Earnings per Common Share Income from Continuing Operations before Cumulative Effect of Changes in Accounting Principles $ 3.10 $ 3.40 $ 2.53 Discontinued Operations, Net of Tax .02 (.03) (.11) Cumulative Effect of Changes in Accounting Principles, Net of Tax - (.09) - - ----------------------------------------------------------------------------------------------------- Net Income $ 3.12 $ 3.28 $ 2.42 - ----------------------------------------------------------------------------------------------------- Dividends Declared per Common Share $ 2.32 $ 2.26 $ 2.20 - -----------------------------------------------------------------------------------------------------
83 See Notes to Consolidated Financial Statements. PROGRESS ENERGY, INC. CONSOLIDATED BALANCE SHEETS (continued) - ---------------------------------------------------------------------------------------- (in millions) December 31 2004 2003 - ---------------------------------------------------------------------------------------- ASSETS Utility Plant Utility plant in service $ 22,103 $ 21,680 Accumulated depreciation (8,783) (8,174) - ---------------------------------------------------------------------------------------- Utility plant in service, net 13,320 13,506 Held for future use 13 13 Construction work in progress 799 559 Nuclear fuel, net of amortization 231 228 - ---------------------------------------------------------------------------------------- Total Utility Plant, Net 14,363 14,306 - ---------------------------------------------------------------------------------------- Current Assets Cash and cash equivalents 62 47 Short-term investments 82 226 Receivables 1,084 1,084 Inventory 982 907 Deferred fuel cost 229 270 Deferred income taxes 121 87 Prepayments and other current assets 175 268 - ---------------------------------------------------------------------------------------- Total Current Assets 2,735 2,889 - ---------------------------------------------------------------------------------------- Deferred Debits and Other Assets Regulatory assets 1,064 598 Nuclear decommissioning trust funds 1,044 938 Diversified business property, net 2,010 2,095 Miscellaneous other property and investments 446 464 Goodwill 3,719 3,726 Prepaid pension costs 42 462 Intangibles, net 337 357 Other assets and deferred debits 233 258 - ---------------------------------------------------------------------------------------- Total Deferred Debits and Other Assets 8,895 8,898 - ---------------------------------------------------------------------------------------- Total Assets $ 25,993 $ 26,093 - ---------------------------------------------------------------------------------------- See Notes to Consolidated Financial Statements.
84 PROGRESS ENERGY, INC. CONSOLIDATED BALANCE SHEETS (concluded) - ------------------------------------------------------------------------------------------------------------ (in millions) December 31 2004 2003 - ------------------------------------------------------------------------------------------------------------ CAPITALIZATION AND LIABILITIES - ------------------------------------------------------------------------------------------------------------ Common Stock Equity Common stock without par value, 500 million shares authorized, 247 and 246 million shares issued and outstanding, respectively) $ 5,360 $ 5,270 Unearned restricted shares (1 and 1 million shares, respectively) (13) (17) Unearned ESOP shares (3 and 4 million shares, respectively) (76) (89) Accumulated other comprehensive loss (164) (50) Retained earnings 2,526 2,330 - ------------------------------------------------------------------------------------------------------------ Total Common Stock Equity 7,633 7,444 - ------------------------------------------------------------------------------------------------------------ Preferred Stock of Subsidiaries - Not Subject to Mandatory Redemption 93 93 Minority Interest 36 30 Long-Term Debt, Affiliate 270 270 Long-Term Debt, Net 9,251 9,664 - ------------------------------------------------------------------------------------------------------------ Total Capitalization 17,283 17,501 - ------------------------------------------------------------------------------------------------------------ Current Liabilities Current portion of long-term debt 349 868 Accounts payable 742 635 Interest accrued 219 228 Dividends declared 145 140 Short-term obligations 684 4 Customer deposits 180 167 Other current liabilities 742 608 - ------------------------------------------------------------------------------------------------------------ Total Current Liabilities 3,061 2,650 - ------------------------------------------------------------------------------------------------------------ Deferred Credits and Other Liabilities Noncurrent income tax liabilities 599 701 Accumulated deferred investment tax credits 176 190 Regulatory liabilities 2,654 2,879 Asset retirement obligations 1,282 1,271 Accrued pension and other benefits 562 508 Other liabilities and deferred credits 376 393 - ------------------------------------------------------------------------------------------------------------ Total Deferred Credits and Other Liabilities 5,649 5,942 - ------------------------------------------------------------------------------------------------------------ Commitments and Contingencies (Notes 22 and 23) - ------------------------------------------------------------------------------------------------------------ Total Capitalization and Liabilities $ 25,993 $ 26,093 - ------------------------------------------------------------------------------------------------------------ See Notes to Consolidated Financial Statements.
85 PROGRESS ENERGY, INC. CONSOLIDATED STATEMENTS of CASH FLOWS - ------------------------------------------------------------------------------------------------------------------------ (in millions) Years ended December 31 2004 2003 2002 - ------------------------------------------------------------------------------------------------------------------------ Operating Activities Net income $ 759 $ 782 $ 528 Adjustments to reconcile net income to net cash provided by operating activities (Income) loss from discontinued operations (6) 8 24 Net (gain) loss on sale of operating assets (57) 1 - Impairment of long-lived assets and investments - 38 389 Cumulative effect of changes in accounting principles - 21 - Depreciation and amortization 1,181 1,146 1,099 Deferred income taxes (74) (276) (402) Investment tax credit (14) (16) (18) Deferred fuel credit (19) (133) (37) Cash provided (used) by changes in operating assets and liabilities Receivables (35) (158) (50) Inventory (108) 8 (66) Prepayments and other current assets (18) 39 (24) Accounts payable 33 37 100 Other current liabilities 82 121 56 Regulatory assets and liabilities (284) (21) 46 Other 167 127 (18) - ------------------------------------------------------------------------------------------------------------------------ Net Cash Provided by Operating Activities 1,607 1,724 1,627 - ------------------------------------------------------------------------------------------------------------------------ Investing Activities Gross utility property additions (998) (972) (1,169) Diversified business property additions (236) (584) (558) Nuclear fuel additions (101) (117) (81) Proceeds from sales of subsidiaries and other investments 366 579 43 Acquisition of businesses, net of cash - - (365) Purchases of short-term investments (2,108) (2,813) (2,962) Proceeds from sales of short-term investments 2,252 2,587 2,962 Acquisition of intangibles (1) (200) (10) Other (46) (26) (61) - ------------------------------------------------------------------------------------------------------------------------ Net Cash Used in Investing Activities (872) (1,546) (2,201) - ------------------------------------------------------------------------------------------------------------------------ Financing Activities Issuance of common stock, net 73 304 687 Issuance of long-term debt, net 421 1,539 1,783 Net increase (decrease) in short-term indebtedness 680 (696) (247) Retirement of long-term debt (1,353) (810) (1,157) Dividends paid on common stock (558) (541) (480) Other 17 12 (5) - ------------------------------------------------------------------------------------------------------------------------ Net Cash (Used in) Provided by Financing Activities (720) (192) 581 - ------------------------------------------------------------------------------------------------------------------------ Net Increase (Decrease) in Cash and Cash Equivalents 15 (14) 7 - ------------------------------------------------------------------------------------------------------------------------ Cash and Cash Equivalents at Beginning of Year 47 61 54 - ------------------------------------------------------------------------------------------------------------------------ Cash and Cash Equivalents at End of Year $ 62 $ 47 $ 61 - ------------------------------------------------------------------------------------------------------------------------ Supplemental Disclosures of Cash Flow Information Cash paid during the year - interest (net of amount capitalized) $ 657 $ 643 $ 651 income taxes (net of refunds) $ 189 $ 177 $ 219 - ------------------------------------------------------------------------------------------------------------------------ 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 5D). 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 5A). - ------------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements. 86 PROGRESS ENERGY, INC. CONSOLIDATED STATEMENTS of CHANGES in COMMON STOCK EQUITY - --------------------------------------------------------------------------------------------------------------------------- Accumulated Total Common Stock Unearned Unearned Other Common Outstanding Restricted ESOP Comprehensive Retained Stock (in millions except per share data) Shares Amount Shares Shares Income (Loss) Earnings Equity - --------------------------------------------------------------------------------------------------------------------------- Balance, January 1, 2002 219 $ 4,121 $ (14) $ (114) $ (32) $ 2,043 $ 6,004 Net income 528 528 Other comprehensive loss (206) (206) ----------- 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 Other comprehensive income 188 188 ----------- Issuance of shares 8 305 305 Stock options exercised 4 4 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 Net income 759 759 Other comprehensive loss (114) (114) ----------- Issuance of shares 1 62 62 Stock options exercised 18 18 Purchase of restricted stock (7) (7) Restricted stock expense recognition 7 7 Cancellation of restricted shares (4) 4 - Allocation of ESOP shares 14 13 27 Dividends ($2.32 per share) (563) (563) - --------------------------------------------------------------------------------------------------------------------------- Balance, December 31, 2004 247 $ 5,360 $ (13) $ (76) $ (164) $ 2,526 $ 7,633 - ---------------------------------------------------------------------------------------------------------------------------
PROGRESS ENERGY, INC. CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME - ------------------------------------------------------------------------------------------------------------------------ (in millions) Years ended December 31 2004 2003 2002 - ------------------------------------------------------------------------------------------------------------------------ Net Income $ 759 $ 782 $ 528 Other Comprehensive Income (Loss) Changes in net unrealized losses on cash flow hedges (net of tax benefit of $10, $7 and $18, respectively) (18) (12) (28) Reclassification adjustment for amounts included in net income (net of tax expense of ($16), ($11) and ($10), respectively) 26 19 16 Reclassification of minimum pension liability to regulatory assets (net of tax expense of ($2)) 4 - - Minimum pension liability adjustment (net of tax benefit (expense) of $78, ($112) and $121, respectively) (130) 177 (192) Foreign currency translation and other 4 4 (2) - ------------------------------------------------------------------------------------------------------------------------ Other Comprehensive Income (Loss) $ (114) $ 188 $ (206) - ------------------------------------------------------------------------------------------------------------------------ Comprehensive Income $ 645 $ 970 $ 322 - ------------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements. 87 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. 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 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. The consolidated financial statements of the Company and its subsidiaries include the majority-owned and controlled subsidiaries. Noncontrolling interests in the subsidiaries along with the income or loss attributed to these interests are included in minority interest in both the Consolidated Balance Sheets and in the Consolidated Statements of Income. The results of operations for minority interest are reported on a net of tax basis if the underlying subsidiary is structured as a taxable entity. 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. These investments are primarily in limited liability corporations and limited liability partnerships, and the earnings from these investments are recorded on a pre-tax basis (See Note 21). These equity method investments are included in miscellaneous other property and investments in the Consolidated Balance Sheets. At December 31, 2004 and 2003, the Company has equity method investments of approximately $27 million and $36 million, respectively. 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 as available-for-sale securities at fair value in accordance with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." These investments include investments held in trust funds, pursuant to United States Nuclear Regulatory Commission (NRC) requirements, to fund certain costs of decommissioning nuclear plants. The fair value of these trust funds was $1.044 billion and $938 million at December 31, 2004 and 2003, respectively. The Company also actively invests available cash balances in various financial instruments, such as tax-exempt debt securities that have stated maturities of 20 years or more. These instruments provide for a high degree of liquidity through arrangements with banks that provide daily and weekly liquidity and 7, 28 and 35 day auctions that allow for the redemption of the investment at its face amount plus earned income. As the Company intends to sell these instruments generally within 30 days from the balance sheet date, they are 88 classified as current assets. At December 31, 2004 and 2003, the fair value of these investments was $82 million and $226 million, respectively. Other investments in debt and equity securities are included in miscellaneous other property and investments in the Consolidated Balance Sheets. At December 31, 2004 and 2003, the fair value of these other investments was $39 million and $39 million, respectively. Other investments are stated principally at cost. These cost method investments are included in miscellaneous other property and investments in the Consolidated Balance Sheets. At December 31, 2004, and 2003, the Company has approximately $14 million and $14 million, respectively, of cost method investments. 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 2003 and 2002 have been reclassified to conform to the 2004 presentation. Reclassifications include the reclassification of instruments used in PEC's cash management program from cash and cash equivalents to short-term investments of $226 million at December 31, 2003, in the Consolidated Balance Sheets. In the Consolidated Statements of Cash Flow for each of the three years in the period ended December 31, 2004, total cash balances and total cash flows used in investing activities were revised to reflect the reclassification of these instruments from cash and cash equivalents to short-term investments. C. Consolidation of Variable Interest Entities The Company consolidates all voting interest entities in which it owns a majority voting interest and all variable interest entities for which it is the primary beneficiary in accordance with FASB Interpretation No. 46R, "Consolidation of Variable Interest Entities - An Interpretation of ARB No. 51" (FIN No. 46R). The Company is the primary beneficiary of and consolidates two limited partnerships that qualify for federal affordable housing and historic tax credits under Section 42 of the Internal Revenue Code (Code). As of December 31, 2004, the total assets of the two entities were $37 million, the majority of which are collateral for the entities' obligations and are included in other current assets and miscellaneous other property and investments in the Consolidated Balance Sheets. The Company is the primary beneficiary of a limited partnership that invests in 17 low-income housing partnerships that qualify for federal and state tax credits. The Company has requested but has not received all the necessary information to determine the primary beneficiary of the limited partnership's underlying 17 partnership investments, and has applied the information scope exception in FIN No. 46R, paragraph 4(g) to the 17 partnerships. The Company has no direct exposure to loss from the 17 partnerships; the Company's only exposure to loss is from its investment of less than $1 million in the consolidated limited partnership. The Company will continue its efforts to obtain the necessary information to fully apply FIN No. 46R to the 17 partnerships. The Company believes that if the limited partnership is determined to be the primary beneficiary of the 17 partnerships, the effect of consolidating the 17 partnerships would not be significant to the Company's Consolidated Balance Sheets. The Company has variable interests in two power plants resulting from long-term power purchase contracts. The Company has requested the necessary information to determine if the counterparties are variable interest entities or to identify the primary beneficiaries. Both entities declined to provide the Company with the necessary financial information, and the Company has applied the information scope exception in FIN No. 46R, paragraph 4(g). The Company's only significant exposure to variability from these contracts results from fluctuations in the market price of fuel used by the two entities' plants to produce the power purchased by the Company. The Company is able to recover these fuel costs under PEC's fuel clause. Total purchases from these counterparties were approximately $58 million, $53 million and $53 million in 2004, 2003 and 2002, respectively. The Company will continue its efforts to obtain the necessary information to fully apply FIN No. 46R to these contracts. The combined generation capacity of the two entities' power plants is approximately 880 MW. The Company believes that if it is determined to be the primary beneficiary of these two entities, the effect of consolidating the entities would result in increases to total assets, long-term debt and other liabilities, but would have an insignificant or no impact on the Company's common stock equity, net earnings or cash flows. However, because the Company has not received any financial information from these two counterparties, the impact cannot be determined at this time. The Company also has interests in several other variable interest entities for which the Company is not the primary beneficiary. These arrangements include investments in approximately 28 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, 2004, that the Company could be required to record in its income statement as a result of these arrangements totals approximately $38 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. 89 D. 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." 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. These deferred fuel costs are recognized in revenues and fuel expenses as they are billable to customers. 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, 2004, 2003 and 2002, gross receipts tax, franchise taxes and other excise taxes of approximately $240 million, $217 million and $212 million, respectively, are included in utility revenues and taxes other than on income in the Consolidated Statements of Income. 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: 90 - --------------------------------------------------------------------------------------------------------------- (in millions except per share data) 2004 2003 2002 - --------------------------------------------------------------------------------------------------------------- Net income, as reported $ 759 $ 782 $ 528 Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects 10 11 8 - --------------------------------------------------------------------------------------------------------------- Pro forma net income $ 749 $ 771 $ 520 - --------------------------------------------------------------------------------------------------------------- Earnings per share Basic - as reported $ 3.13 $ 3.30 $ 2.43 Basic - pro forma $ 3.09 $ 3.25 $ 2.40 Diluted - as reported $ 3.12 $ 3.28 $ 2.42 Diluted - pro forma $ 3.08 $ 3.24 $ 2.39 - ---------------------------------------------------------------------------------------------------------------
See Note 2 for a discussion of newly issued accounting guidance related to stock-based compensation. 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. Certain costs that would otherwise not be capitalized under GAAP are capitalized in accordance with regulatory treatment. The cost of renewals and betterments is also capitalized. Maintenance and repairs of property (including planned major maintenance activities), and replacements and renewals of items determined to be less than units of property, are charged to maintenance expense as incurred, with the exception of nuclear outages at PEF. Pursuant to a regulatory order, PEF accrues for nuclear outage costs in advance of scheduled outages, which occur every two years. The cost of units of property replaced or retired, less salvage, is charged to accumulated depreciation. Removal or disposal costs that do not represent SFAS No. 143, "Accounting for Asset Retirement Obligations," (SFAS No. 143) are charged to a regulatory liability. 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 system 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. ASSET RETIREMENT OBLIGATIONS Effective January 1, 2003, the Company adopted the guidance in SFAS No. 143 to account for legal obligations associated with the retirement of certain tangible long-lived assets. The present value of retirement costs for which the Company has a legal obligation are 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. 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 (See Note 8A). The North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (SCPSC) and the Florida Public Service Commission (FPSC) issued orders to authorize deferral of all prospective effects related to SFAS No. 143 as a regulatory asset or liability (See Note 8A). Therefore, SFAS No. 143 has no impact on the income of the regulated entities. 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 6A). Pursuant to their rate-setting authority, the NCUC, SCPSC and FPSC can also grant approval to accelerate or reduce depreciation and amortization of utility assets (See Note 8). Amortization of nuclear fuel costs is computed primarily on the units-of-production method. 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). 91 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. INVENTORY The Company accounts for inventory using the average-cost method. Inventories are valued at the lower of average cost or market. 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 Consolidated Balance Sheets as regulatory assets and regulatory liabilities (See Note 8A). 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. For properties other than oil and gas properties, depreciation is computed on a straight-line basis using the estimated useful lives disclosed in Note 6B. 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 oil and gas properties. Under the full-cost method, substantially all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. These capitalized costs include the costs of all unproved properties and internal costs directly related to acquisition and exploration activities. The amortization base also includes the estimated future cost 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 on a country by country basis over the life of the Company's proved reserves. Accordingly, all property acquisition, exploration, and development costs of proved oil and gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized as incurred, including internal costs directly attributable to such activities. Related interest expense incurred during property development activities is capitalized as a cost of such activity. Net capitalized costs of unproved property are reclassified as proved property and well costs when related proved reserves are found. Costs to operate and maintain wells and field equipment are expensed as incurred. In accordance with Rule 4-10 of Regulation S-X, sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless certain significance tests are met. GOODWILL AND INTANGIBLE ASSETS 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. 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 are amortized over the terms of the debt issues. 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 (See Note 8A). 92 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 as AMT credits to the extent they cannot be or have not been utilized in the annual consolidated federal income tax returns, and are included in income tax expense (benefit) in the Consolidated Statements of Income. DERIVATIVES The Company accounts for derivative instruments in accordance with 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, unless the derivatives meet the SFAS No. 133 criteria for normal purchases or normal sales and are designated as such. The Company generally designates derivative instruments as normal purchases or normal sales whenever the SFAS No. 133 criteria are met. If normal purchase or normal sale criteria are not met, the Company will generally designate the derivative instruments as cash flow or fair value hedges if the related SFAS No. 133 hedge criteria are met. During 2003, the FASB reconsidered an interpretation of SFAS No. 133. See Note 18 for the effect of the interpretation and additional information regarding risk management activities and derivative transactions. ENVIRONMENTAL As discussed in Note 22, the Company accrues environmental remediation liabilities when the criteria for SFAS No. 5, "Accounting for Contingencies" (SFAS No. 5), have been met. Environmental 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. Environmental expenditures that have future economic benefits are capitalized in accordance with the Company's asset capitalization policy. IMPAIRMENT OF LONG-LIVED ASSETS AND INVESTMENTS As discussed in Note 10, 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." 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. Under the full-cost method of accounting for oil and gas 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. The ceiling test takes into consideration the prices of qualifying cash flow hedges as of the balance sheet date. 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 2004, 2003 or 2002. 93 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 Staff Accounting Bulletin No. 51, "Accounting for Sales of Stock by a Subsidiary." 2. NEW ACCOUNTING STANDARDS FASB STAFF POSITION 106-2, "ACCOUNTING AND DISCLOSURE REQUIREMENTS RELATED TO THE MEDICARE PRESCRIPTION DRUG IMPROVEMENT AND MODERNIZATION ACT OF 2003" In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law. In accordance with guidance issued by the Financial Accounting Standards Board (FASB) in FASB Staff Position 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003," (FASB Staff Position 106-1) the Company elected to defer accounting for the effects of the Medicare Act due to uncertainties regarding the effects of the implementation of the Medicare Act and the accounting for certain provisions of the Medicare Act. In May 2004, the FASB issued definitive accounting guidance for the Medicare Act in FASB Staff Position 106-2, which was effective for the Company in the third quarter of 2004. FASB Staff Position 106-2 results in the recognition of lower other postretirement employment benefit (OPEB) costs to reflect prescription drug-related federal subsidies to be received under the Medicare Act. As a result of the Medicare Act, the Company's accumulated postretirement benefit obligation as of January 1, 2004, was reduced by approximately $83 million, and the Company's 2004 net periodic cost was reduced by approximately $13 million. SFAS NO. 123 (REVISED 2004), "SHARE-BASED PAYMENT" (SFAS NO. 123R) In December 2004, the FASB issued SFAS No. 123R, which revises SFAS No. 123, "Accounting for Stock-Based Compensation," and supersedes Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees." The key requirement of SFAS No. 123R is that the cost of share-based awards to employees will be measured based on an award's fair value at the grant date, with such cost to be amortized over the appropriate service period. Previously, entities could elect to continue accounting for such awards at their grant date intrinsic value under APB Opinion No. 25, and the Company made that election. The intrinsic value method resulted in the Company recording no compensation expense for stock options granted to employees (See Note 11). SFAS No. 123R will be effective for the Company on July 1, 2005. The Company intends to implement the standard using the required modified prospective method. Under that method, the Company will record compensation expense under SFAS No. 123R for all awards it grants after July 1, 2005, and it will record compensation expense (as previous awards continue to vest) for the unvested portion of previously granted awards that remain outstanding at July 1, 2005. In 2004, the Company made the decision to cease granting stock options and intends to replace that compensation program with other programs. Therefore, the amount of stock option expense expected to be recorded in 2005 is below the amount that would have been recorded if the stock option program had continued. The Company expects to record approximately $3 million of pre-tax expense for stock options in 2005. PROPOSED FASB INTERPRETATION OF SFAS NO. 109, "ACCOUNTING FOR INCOME TAXES" In July 2004, the FASB stated that it plans to issue an exposure draft of a proposed interpretation of SFAS No. 109, "Accounting for Income Taxes" (SFAS No. 109), that would address the accounting for uncertain tax positions. The FASB has indicated that the interpretation would require that uncertain tax benefits be probable of being sustained in order to record such benefits in the consolidated financial statements. The exposure draft is expected to be issued in the first quarter of 2005. The Company cannot predict what actions the FASB will take or how any such actions might ultimately affect the Company's financial position or results of operations, but such changes could have a material impact on the Company's evaluation and recognition of Section 29 tax credits (See Note 23E). 94 3. HURRICANE RELATED COSTS Hurricanes Charley, Frances, Ivan and Jeanne struck significant portions of the Company's service territories during the third quarter of 2004, significantly impacting PEF's territory. As of December 31, 2004, restoration of the Company's systems from hurricane-related damage was estimated at $398 million. PEC incurred restoration costs of $13 million, of which $12 million was charged to operation and maintenance expense and $1 million was charged to capital expenditures. PEF had estimated total costs of $385 million, of which $47 million was charged to capital expenditures, and $338 million was charged to the storm damage reserve pursuant to a regulatory order. In accordance with a regulatory order, PEF accrues $6 million annually to a storm damage reserve and is allowed to defer losses in excess of the accumulated reserve for major storms. Under the order, the storm reserve is charged with operation and maintenance expenses related to storm restoration and with capital expenditures related to storm restoration that are in excess of expenditures assuming normal operating conditions. As of December 31, 2004, $291 million of hurricane restoration costs in excess of the previously recorded storm reserve of $47 million had been classified as a regulatory asset recognizing the probable recoverability of these costs. On November 2, 2004, PEF filed a petition with the FPSC to recover $252 million of storm costs plus interest from retail ratepayers over a two-year period. Storm reserve costs of $13 million were attributable to wholesale customers. The Company has received approval from the FERC to amortize these costs consistent with recovery of such amounts in wholesale rates. PEF continues to review the restoration cost invoices received. Given that not all invoices have been received as of December 31, 2004, PEF will update its petition with the FPSC upon receipt and audit of all actual charges incurred. Hearings on PEF's petition for recovery of $252 million of storm costs filed with the FPSC are scheduled to begin on March 30, 2005. On November 17, 2004, the Citizens of the State of Florida, by and through Harold McLean, Public Counsel, and the Florida Industrial Power Users Group (FIPUG), (collectively, Joint Movants), filed a Motion to Dismiss PEF's petition to recover the $252 million in storm costs. On November 24, 2004, PEF responded in opposition to the motion, which was also the FPSC staff's position in its recommendation to the Commission on December 21, 2004, that it should deny the Motion to Dismiss. On January 4, 2005, the Commission ruled in favor of PEF and denied Joint Movant's Motion to Dismiss. PEF's January 2005 notice to the FPSC of its intent to file for an increase in its base rates effective January 1, 2006, anticipates the need to replenish the depleted storm reserve balance and adjust the annual $6 million accrual in light of recent storm history to restore the reserve to an adequate level over a reasonable time period (See Note 8C). PEC does not have an ongoing regulatory mechanism to recover storm costs; therefore, hurricane restoration costs recorded in the third quarter of 2004 were charged to operations and maintenance expenses or capital expenditures based on the nature of the work performed. In connection with other storms, PEC has previously sought and received permission from the NCUC and the SCPSC to defer storm expenses and amortize them over a five-year period. PEC did not seek deferral of 2004 storm costs from the NCUC (See Note 8B). 4. DIVESTITURES A. Sale of Natural Gas Assets In December 2004, the Company sold certain gas-producing properties and related assets owned by Winchester Production Company, Ltd. (Winchester Production), an indirectly wholly owned subsidiary of Progress Fuels Corporation (Progress Fuels), which is included in the Fuels segment. Net proceeds of approximately $251 million were used to reduce debt. Because the sale significantly altered the ongoing relationship between capitalized costs and remaining proved reserves, under the full-cost method of accounting, the pre-tax gain of $56 million was recognized in earnings rather than as a reduction of the basis of the Company's remaining oil and gas properties. The pre-tax gain has been included in (gain)/loss on the sale of assets in the Consolidated Statements of Income. 95 B. Divestiture of Synthetic Fuel Partnership Interests In June 2004, the Company through its subsidiary, Progress Fuels, sold, in two transactions, a combined 49.8% partnership interest in Colona Synfuel Limited Partnership, LLLP, one of its synthetic fuel facilities. Substantially all proceeds from the sales will be received over time, which is typical of such sales in the industry. Gain from the sales will be recognized on a cost recovery basis. The Company's book value of the interests sold totaled approximately $5 million. The Company received total gross proceeds of $10 million in 2004. Based on projected production and tax credit levels, the Company anticipates receiving approximately $24 million in 2005, approximately $31 million in 2006, approximately $32 million in 2007, and approximately $8 million through the second quarter of 2008. In the event that the synthetic fuel tax credits from the Colona facility are reduced, including an increase in the price of oil that could limit or eliminate synthetic fuel tax credits, the amount of proceeds realized from the sale could be significantly impacted. C. 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. 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 10A). In March 2003, the Company signed a letter of intent to sell the majority of Railcar Ltd. assets to The Andersons, Inc., and the transaction closed in February 2004. Proceeds from the sale were approximately $82 million before transaction costs and taxes of approximately $13 million. In July 2004, the Company sold the remaining assets classified as held for sale to a third-party for net proceeds of $6 million. The assets of Railcar Ltd. were grouped as assets held for sale and were included in other current assets on the Consolidated Balance Sheets at December 31, 2003, at approximately $75 million, which reflected the Company's estimates of the fair value expected to be realized from the sale of these assets less costs to sell. D. 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. 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. E. 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 approximately $443 million were used to reduce debt. The 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 and $16 million for the years ended December 31, 2003 and 2002, 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 October 1, 2002, upon classification of the assets as discontinued operations. After-tax depreciation expense recorded by NCNG for the year ended December 31, 2002, was $9 million. Results of discontinued operations for years ended December 31 were as follows: 96 - ---------------------------------------------------------------------------------------------- (in millions) 2004 2003 2002 - ---------------------------------------------------------------------------------------------- Revenues $ - $ 284 $ 300 - ---------------------------------------------------------------------------------------------- Earnings before income taxes $ - $ 6 $ 9 Income tax expense - 2 4 - ---------------------------------------------------------------------------------------------- Net earnings from discontinued operations - 4 5 - ---------------------------------------------------------------------------------------------- Gain/(Loss) on disposal of discontinued operations, including applicable income tax benefit / (expense) of $6, $1 and $3, respectively 6 (12) (29) - ---------------------------------------------------------------------------------------------- Earnings (loss) from discontinued operations $ 6 $ (8) $ (24) - ----------------------------------------------------------------------------------------------
During 2004, the Company recorded an additional tax gain of approximately $6 million due to final tax adjustments related to the divestiture of NCNG. 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 Consolidated Statements of Income for the year ended December 31, 2003. 5. 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 (PT 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, PT LLC. Odyssey holds a combined 45% ownership interest in PT LLC through EPIK and Caronet. The accounts of PT LLC have been included in the Company's Consolidated Financial Statements since the transaction date. 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. No gain or loss was recognized on the transaction. The EPIK purchase price was initially allocated as follows: property and equipment - $27 million; other current assets - $9 million; current liabilities - $21 million; and goodwill - $7 million. During 2004, PT LLC developed a restructuring plan to exit certain leasing arrangements of EPIK and finalized its valuation of acquired assets and liabilities. Management considered a number of factors, including valuations and appraisals, when making these determinations. Based on the results of these activities, the preliminary purchase price allocation for EPIK was revised as follows at December 31, 2004: property and equipment - $36 million; other current assets - $7 million; intangible assets - $1 million; current liabilities - $18 million; and exit costs - $4 million. The exit costs consist primarily of lease termination penalties and noncancelable lease payments made after certain leased properties are vacated. The pro forma results of operations reflecting the acquisition would not be materially different than the reported results of operations for 2003 or 2002. 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. The pro forma results of operations reflecting the acquisition would not be materially different from the reported results of operations for the years ended December 31, 2003 and 2002. 97 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 9). 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 open market purchases and 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. Westchester Acquisition In April 2002, Progress Fuels, a subsidiary of Progress Energy, acquired 100% of Westchester Gas Company (Westchester). During 2004 the name of the company was changed to Winchester Energy Co. Ltd.. 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 relates to customer contracts (See Note 9). 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 from the reported results of operations for the year ended December 31, 2002. E. 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 $228 million, $56 million and $64 million, respectively (See Note 9). 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 $23 million was assigned to interconnection contracts. 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 from the reported results of operations for the year ended December 31, 2002. 98 6. 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) 2004 2003 - ------------------------------------------------------------------------- Production plant (7-33 years) $ 11,966 $ 12,044 Transmission plant (30-75 years) 2,282 2,167 Distribution plant (12-50 years) 6,749 6,432 General plant and other (8-75 years) 1,106 1,037 - ------------------------------------------------------------------------- Utility plant in service $ 22,103 $ 21,680 - ------------------------------------------------------------------------- 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 7.2% in 2004, 4.0% in 2003 and 6.2% in 2002, respectively. The composite AFUDC rate for PEF's electric utility plant was 7.8% in 2004, 2003 and 2002. Depreciation provisions on utility plant, as a percent of average depreciable property other than nuclear fuel, were 2.2%, 2.5% and 2.6% in 2004, 2003 and 2002, respectively. The depreciation provisions related to utility plant were $463 million, $517 million and $488 million in 2004, 2003 and 2002, 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 6D), regulatory approved expenses (See Note 8 and Note 22) and NC Clean Air Legislation amortization (See Note 8B). During 2004, PEC met the requirements of both the NCUC and the SCPSC for the implementation of two depreciation studies that allowed the utility to reduce the rates used to calculate depreciation expense. The annual reduction in depreciation expense is approximately $82 million. The reduction is due primarily to extended lives at each of PEC's nuclear units. The new depreciation rates were effective January 1, 2004. 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, for the years ended December 31, 2004, 2003 and 2002 were $140 million, $143 million and $141 million, respectively, and are included in fuel used for electric generation in the Consolidated Statements of Income. B. Diversified Business Property The balances of diversified business property at December 31 are listed below, with a range of depreciable lives for each: 99 - ------------------------------------------------------------------------------------------- (in millions) 2004 2003 - ------------------------------------------------------------------------------------------- Equipment (3-25 years) $ 383 $ 246 Nonregulated generation plant and equipment (3-40 years) 1,302 1,299 Land and mineral rights 107 93 Buildings and plants (5-40 years) 131 125 Oil and gas properties (units-of-production) 336 412 Telecommunications equipment (5-20 years) 80 63 Rail equipment (3-20 years) 29 125 Marine equipment (3-35 years) 87 83 Computers, office equipment and software (3-10 years) 36 36 Construction work in progress 26 13 Accumulated depreciation (507) (400) - ------------------------------------------------------------------------------------------- Diversified business property, net $ 2,010 $ 2,095 - -------------------------------------------------------------------------------------------
The synthetic fuel facilities are being depreciated through 2007 when the Section 29 tax credits will expire. The Company's nonregulated businesses capitalize interest costs under SFAS No. 34, "Capitalization of Interest Costs." During the years ended December 31, 2004, 2003 and 2002, respectively, the Company capitalized $7 million, $20 million and $38 million, respectively, of its interest cost of $660 million, $655 million and $679 million. Capitalized interest for 2004 is related to the expansion of Fuels' gas operations. Capitalized interest in 2003 and 2002 is 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 $148 million, $120 million and $85 million for December 31, 2004, 2003 and 2002, respectively. C. Joint Ownership of Generating Facilities PEC and PEF hold ownership interests in certain jointly owned generating facilities. Each is entitled to shares of the generating capability and output of each unit equal to their respective ownership interests. Each also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. PEC's and PEF's share of expenses for the jointly owned facilities is included in the appropriate expense category. The co-owner of Intercession City Unit P11 (P11) has exclusive rights to the output of the unit during the months of June through September. PEF has that right for the remainder of the year. PEC's and PEF's ownership interests in the jointly owned generating facilities are listed below with related information at December 31 ($ in millions): - ----------------------------------------------------------------------------------------------------------------- 2004 Company Construction Ownership Plant Accumulated Work in Subsidiary Facility Interest Investment Depreciation Progress - ----------------------------------------------------------------------------------------------------------------- PEC Mayo Plant 83.83% $ 516 $ 249 $ 1 PEC Harris Plant 83.83% 3,185 1,387 13 PEC Brunswick Plant 81.67% 1,624 888 28 PEC Roxboro Unit 4 87.06% 323 147 1 PEF Crystal River Unit 3 91.78% 889 443 9 PEF Intercession City Unit P11 66.67% 22 7 8 - ----------------------------------------------------------------------------------------------------------------- - ----------------------------------------------------------------------------------------------------------------- 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 1,424 7 PEC Brunswick Plant 81.67% 1,611 885 21 PEC Roxboro Unit 4 87.06% 323 139 1 PEF Crystal River Unit 3 91.78% 875 442 46 PEF Intercession City Unit P11 66.67% 22 6 6 - -----------------------------------------------------------------------------------------------------------------
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). 100 D. Asset Retirement Obligations At December 31, 2004 and 2003, the asset retirement costs related to nuclear decommissioning of irradiated plant, net of accumulated depreciation, totaled $277 million and $354 million, respectively. Funds set aside in the Company's nuclear decommissioning trust funds for the nuclear decommissioning liability totaled $1.044 billion and $938 million at December 31, 2004 and 2003, respectively. Net nuclear decommissioning trust unrealized gains are included in regulatory liabilities (See Note 8A). Decommissioning cost provisions, which are included in depreciation and amortization expense, were $31 million in each of 2004, 2003 and 2002. 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. The Company's expenses recognized for the disposal or removal of utility assets that are not SFAS No. 143 asset removal obligations, which are included in depreciation and amortization expense, were $160 million, $158 million and $149 million in 2004, 2003 and 2002, respectively. The utilities recognize removal, nonirradiated decommissioning and dismantlement costs in regulatory liabilities on the Consolidated Balance Sheets (See Note 8A). At December 31, 2004, such costs consist of removal costs of $1.606 billion, removal costs for nonirradiated areas at nuclear facilities of $131 million and amounts previously collected for dismantlement of fossil generation plants of $144 million. At December 31, 2003, such costs consist of removal costs of $1.846 billion, removal costs for nonirradiated areas at nuclear facilities of $129 million and amounts previously collected for dismantlement of fossil generation plants of $143 million. During 2004, PEC reduced its estimated removal costs to take into account the estimates used in the depreciation studies implemented during 2004 (See Note 6A). This resulted in a downward revision in the PEC estimated removal costs and equal increase in accumulated depreciation of approximately $345 million. PEC's most recent site-specific estimates of decommissioning costs were developed in 2004, using 2004 cost factors, and are based on prompt dismantlement decommissioning, which reflects the cost of removal of all radioactive and other structures currently at the site, with such removal occurring after operating license expiration. These estimates, in 2004 dollars, are $294 million for Robinson Unit No. 2, $290 million for Brunswick Unit No. 1, $313 million for Brunswick Unit No. 2 and $359 million for the Harris Plant. The estimates are subject to change based on a variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning and changes in federal, state or local regulations. The cost estimates exclude the portion attributable to North Carolina Eastern Municipal Power Agency (Power Agency), which holds an undivided ownership interest in the Brunswick and Harris nuclear generating facilities. NRC operating licenses held by PEC currently expire in December 2014 and September 2016 for Brunswick Units 2 and 1, respectively. An application to extend these licenses 20 years was submitted in October 2004. The NRC operating license held by PEC for the Shearon Harris Nuclear Plant (Harris Plant) currently expires in October 2026. An application to extend this license 20 years is expected to be submitted in the fourth quarter of 2006. On April 19, 2004, the NRC announced that it has renewed the operating license for PEC's Robinson Nuclear Plant (Robinson) for an additional 20 years through July 2030. PEF's most recent site-specific estimate of decommissioning costs for the Crystal River Nuclear Plant (CR3) was developed in 2000 based on prompt dismantlement decommissioning. The estimate, in 2000 dollars, is $491 million and is subject to change based on the same factors as discussed above for PEC's estimates. The cost estimate excludes the portion attributable to other co-owners of CR3. The NRC operating license held by PEF for Crystal River Unit No. 3 (CR3) currently expires in December 2016. An application to extend this license 20 years is expected to be submitted in the first quarter of 2009. 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 require retirement action only upon abandonment or cessation of use of the property for the specified purpose. The ARO 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 would be recorded at that time. The Company's nonregulated AROs relate to coal mine operations, synthetic fuel operations and gas production of Progress Fuels. The related asset retirement costs, net of accumulated depreciation, totaled $10 million and $5 million at December 31, 2004 and 2003, respectively. 101 The following table shows the changes to the asset retirement obligations. Additions relate primarily to additional reclamation obligations at coal mine operations of Progress Fuels. The deductions to regulated ARO related to PEC re-measuring the nuclear decommissioning costs of irradiated plants to take into account updated site-specific decommissioning cost studies, which are required by the NCUC every five years. - ------------------------------------------------------------------------------------------ (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 Additions - 6 Accretion expense 73 2 Deductions (63) (7) - ------------------------------------------------------------------------------------------ Asset retirement obligations as of December 31, 2004 $ 1,261 $ 21 - ------------------------------------------------------------------------------------------
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. 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. 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 under NEIL, following a 12-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 (71 weeks for CR3) 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 $29.3 million with respect to the primary coverage, $32.4 million with respect to the decontamination, decommissioning and excess property coverage, and $20.2 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 $10.8 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 could possibly approve revisions to the Price Anderson Act during 2005 that could include increased limits and assessments per reactor owned. The final outcome of this matter cannot be predicted at this time. 102 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 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 Notes 3 and 8A). 7. CURRENT ASSETS RECEIVABLES At December 31, receivables were comprised of: - ---------------------------------------------------------------------------- (in millions) 2004 2003 - ---------------------------------------------------------------------------- Trade accounts receivable $ 689 $ 705 Unbilled accounts receivable 271 293 Notes receivable 98 61 Other receivables 27 47 Unbilled other receivables 28 10 Allowance for doubtful accounts receivable (29) (32) - ---------------------------------------------------------------------------- Total receivables $ 1,084 $ 1,084 - ---------------------------------------------------------------------------- Income tax receivables and interest income receivables are not included in this classification. These amounts are in prepaids and other current assets on the Consolidated Balance Sheet. INVENTORY At December 31, inventory was comprised of: - ------------------------------------------------------------ (in millions) 2004 2003 - ------------------------------------------------------------ Fuel for production $ 235 $ 210 Inventory for sale 230 167 Materials and supplies 517 530 - ------------------------------------------------------------ Total inventory $ 982 $ 907 - ------------------------------------------------------------ 8. 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 that 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. 103 At December 31, the balances of regulatory assets (liabilities) were as follows: - --------------------------------------------------------------------------------------------------- (in millions) 2004 2003 - --------------------------------------------------------------------------------------------------- Deferred fuel cost - current (Note 8B and 8C) $ 229 $ 270 - --------------------------------------------------------------------------------------------------- Deferred fuel cost - long-term (Note 8B and 8C) 107 47 Deferred impact of ARO - PEC (Note 1D) 305 291 Income taxes recoverable through future rates (Note 15) 84 75 Loss on reacquired debt (Note 1D) 53 55 Deferred DOE enrichment facilities-related costs 16 24 Storm deferral (Notes 3 and 8B) 316 21 Postretirement benefits (Note 17) 74 9 Other 109 76 - --------------------------------------------------------------------------------------------------- Total long-term regulatory assets 1,064 598 - --------------------------------------------------------------------------------------------------- Deferred energy conservation cost - current (8) (7) - --------------------------------------------------------------------------------------------------- Non-ARO cost of removal (Note 6D) (1,881) (2,118) Deferred impact of ARO (Note 1D) (221) (212) Net nuclear decommissioning trust unrealized gains (Note 6D) (224) (204) Postretirement benefits (Note 17B) (45) (211) Storm reserve (Note 3) - (41) Clean air compliance (Note 8B) (248) (74) Other (35) (19) - --------------------------------------------------------------------------------------------------- Total long-term regulatory liabilities (2,654) (2,879) - --------------------------------------------------------------------------------------------------- Net regulatory assets (liabilities) $ (1,369) $ (2,018) - ---------------------------------------------------------------------------------------------------
Except for portions of deferred fuel costs and deferred storm costs, 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. PEC Retail Rate Matters As of December 31, 2004, PEC's North Carolina retail fuel costs were underrecovered by $145 million. This amount is comprised of $117 million eligible for recovery in 2005 and $28 million deferred from a 2001 order from the NCUC that cannot be collected during 2005, and has therefore been classified as a long-term asset. PEC intends to collect this amount by October 31, 2007. On October 15, 2004, the SCPSC approved PEC's request to leave fuel rates unchanged. The deferred fuel balance at December 31, 2004, is $23 million. This amount is eligible for recovery in PEC's 2005 South Carolina fuel review. PEC obtained SCPSC and NCUC approval of fuel factors in annual fuel-adjustment proceedings. The NCUC approved an annual increase of $62 million, $20 million and $46 million by orders issued in September 2004, 2003 and 2002, respectively. The SCPSC approved PEC's petition each year and the changes were insignificant. PEC filed with the SCPSC seeking permission to defer expenses incurred from the first quarter 2004 winter storm. The SCPSC approved PEC's request to defer the costs and amortize them ratably over five years beginning in January 2005. Approximately $9 million related to storm costs was deferred in 2004. In October 2003, PEC filed with the NCUC seeking permission to defer expenses incurred from Hurricane Isabel and the February 2003 winter storms. In December 2003, the NCUC approved PEC's request to defer the costs associated with Hurricane Isabel and the February 2003 ice storm and amortize them over a period of five years. PEC charged approximately $24 million in 2003 from Hurricane Isabel and from ice storms to the deferred account. PEC recognized $5 million and $3 million of NC storm amortization during 2004 and 2003, respectively. 104 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 2004 and 2003 and additional depreciation expense of approximately $53 million in 2002. Total accelerated depreciation recorded through December 31, 2004, was $403 million. The North Carolina Clean Smokestacks Act enacted in June 2002 (NC Clean Air), 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. The legislation provides for significant flexibility in the amount of annual amortization recorded, which allows the utilities to vary the amount amortized within certain limits. This flexibility provides a utility with the opportunity to consider the impacts of other factors on its regulatory return on equity when setting the amortization amount for each year. PEC recognized $174 million and $74 million of clean air amortization during 2004 and 2003, respectively. This legislation freezes PEC's base rates in North Carolina for five years, subject to certain conditions (See Note 22). 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 nonreal time pricing customers in the amounts of $3 million in 2002, $5 million in 2003 and $6 million in both 2004 and 2005. In conjunction with the acquisition of NCNG in 1999, PEC agreed not to seek a base retail electric rate increase in North Carolina and South Carolina through December 2004. The agreement not to seek a base retail electric rate increase in South Carolina was extended to December 2005 in conjunction with regulatory approval to form a holding company. C. PEF Retail Rate Matters On November 9, 2004, the FPSC approved PEF's underrecovered fuel costs of $156 million for 2004, of which PEF plans to defer $79 million until 2006 to mitigate the impact on customers resulting from the need to also recover hurricane-related costs. Therefore, $79 million of deferred fuel costs has been classified as a long-term asset. As of December 31, 2004, PEF was underrecovered in fuel costs by $168 million. The additional $12 million over and above the $156 million approved by the FPSC will be included in PEF's 2005 fuel filing. On June 29, 2004, the FPSC approved a Stipulation and Settlement Agreement, executed on April 29, 2004, by PEF, the Office of Public Counsel and the Florida Industrial Power Users Group. The stipulation and settlement resolved the issue pending before the FPSC regarding the costs PEF will be allowed to recover through its Fuel and Purchased Power Cost Recovery clause in 2004 and beyond for waterborne coal deliveries by the Company's affiliated coal supplier, Progress Fuels Corporation. The settlement sets fixed per ton prices based on point of origin for all waterborne coal deliveries in 2004, and establishes a market-based pricing methodology for determining recoverable waterborne coal transportation costs through a competitive solicitation process or market price proxies in 2005 and thereafter. The settlement reduces the amount that PEF will charge to the Fuel and Purchased Power Cost Recovery clause for waterborne transportation by approximately $11 million beginning in 2004. On November 3, 2004, the FPSC approved PEF's petition for Determination of Need for the construction of a fourth unit at PEF's Hines Energy Complex. Hines Unit 4 is needed to maintain electric system reliability and integrity and to continue to provide adequate electricity to its ratepayers at a reasonable cost. Hines Unit 4 will be a combined cycle unit with a generating capacity of 461 MW (summer rating). The estimated total in-service cost of Hines Unit 4 is $286 million, and the unit is planned for commercial operation in December 2007. If the actual cost is less than the estimate, customers will receive the benefit of such cost underruns. Any costs that exceed this estimate will not be recoverable absent extraordinary circumstances as found by the FPSC in subsequent proceedings. See Note 3 for information on PEF's petition for storm cost recovery. 105 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 2004, 2003 and 2002 were $1.370 billion, $1.333 billion and $1.296 billion, respectively, and will increase $37 million in 2005. 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 caps for 2004, 2003 and 2002 were $1.430 billion, $1.393 billion and $1.356 billion, respectively, and will increase $37 million in 2005. Any amounts above the retail base revenue caps will be refunded 100% to customers. At December 31, 2004, $9 million has been accrued and will be refunded to retail customers by March 2005. The 2003 revenue sharing amount was $18 million, and was refunded to customers by April 30, 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. In 2004, PEF recovered $36 million through this clause related to Hines Unit 2. In addition, PEF suspended retail 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. No accelerated depreciation expense was recorded during 2004 and 2003. In addition, PEF is authorized, at its discretion, to accelerate the amortization of certain regulatory assets over the term of the Agreement. Under the terms of the Agreement, PEF agreed to continue the implementation of its four-year Commitment to Excellence Reliability Plan and expected to achieve a 20% improvement in its annual System Average Interruption Duration Index by no later than 2004. If this improvement level was not achieved for calendar years 2004 or 2005, PEF would have provided 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. PEF achieved this improvement level in 2004. In January 2005, in anticipation of the expiration of its Stipulation and Settlement approved by the FPSC in 2002 to conclude PEF's then-pending rate case, PEF notified the FPSC that it intends to request an increase in its base rates, effective January 1, 2006. In its notice, PEF requested the FPSC to approve calendar year 2006 as the projected test period for setting new base rates. The request for increased base rates is based on the fact that PEF has faced significant cost increases over the past decade and expects its operational costs to continue to increase. These costs include the costs associated with completion of the Hines 3 generation facility, extraordinary hurricane damage costs including capital costs which are not expected to be directly recoverable, the need to replenish the depleted storm reserve and the expected infrastructure investment necessary to meet high customer expectations, coupled with the demands placed on PEF as a result of strong customer growth. On February 7, 2005, the FPSC acknowledged receipt of PEF's notice and authorized minimum filing requirements and testimony to be filed May 1, 2005. 106 D. Regional Transmission Organizations and Standard Market Design In 2000, the Federal Energy Regulatory Commission (FERC) issued Order No. 2000 regarding regional transmission organizations (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 have materially altered the manner in which transmission and generation services are provided and paid for. In April 2003, the FERC released a White Paper on the Wholesale Market Platform. The White Paper provided an overview of what the FERC intended to include in a final rule in the SMD NOPR docket. The White Paper retained 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 GridSouth and GridFlorida proceedings currently ongoing before the FERC. By order issued December 22, 2004, the FERC terminated a portion of the proceedings regarding GridSouth. The GridSouth Companies asked the FERC for further clarification as to the portions of the GridSouth docket it intended to address. On March 2, 2005, the FERC affirmed that it only intended to close the mediation portion of the GridSouth docket. It is unknown what impact the future proceedings will have on the Company's earnings, revenues or prices. The Florida Public Service Commission (FPSC) ruled in December 2001 that the formation of GridFlorida by the three major investor-owned utilities in Florida, including PEF, was prudent but ordered changes in the structure and market design of the proposed organization. In September 2002, the FPSC set a hearing for market design issues; this order was appealed to the Florida Supreme Court by the consumer advocate of the state of Florida. In June 2003, the Florida Supreme Court dismissed the appeal without prejudice. In September 2003, the FERC held a Joint Technical Conference with the FPSC to consider issues related to formation of an RTO for peninsular Florida. In December 2003, the FPSC ordered further state proceedings and established a collaborative workshop process to be conducted during 2004. In June 2004, the workshop process was abated pending completion of a cost-benefit study currently scheduled to be presented at a FPSC workshop on May 25, 2005, with subsequent action by the FPSC to be thereafter determined. The Company has $33 million and $4 million invested in GridSouth and GridFlorida, respectively, related to startup costs at December 31, 2004. The Company expects to recover these startup costs in conjunction with the GridSouth and GridFlorida original structures or in conjunction with any alternate combined transmission structures that emerge. E. FERC Market Power Mitigation A FERC order issued in November 2001 on certain unaffiliated utilities' triennial market-based wholesale power rate authorization updates required certain mitigation actions that those utilities would need to take for sales/purchases within their control areas and required those utilities to post information on their Web sites regarding their power systems' status. As a result of a request for rehearing filed by certain market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. In April 2004, the FERC issued two orders concerning utilities' ability to sell wholesale electricity at market-based rates. In the first order, the FERC adopted two new interim screens for assessing potential generation market power of applicants for wholesale market-based rates, and described additional analyses and mitigation measures that could be presented if an applicant does not pass one of these interim screens. In July 2004, the FERC issued an order on rehearing affirming its conclusions in the April order. In the second order, the FERC initiated a rulemaking to consider whether the FERC's current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in any way. PEF does not have market-based rate authority for wholesale sales in peninsular Florida. Given the difficulty PEC believes it would experience in passing one of the interim screens, on August 12, 2004, PEC notified the FERC that it would revise its Market-based Rate tariff to restrict it to sales outside PEC's control area and file a new cost-based tariff for sales within PEC's control area that incorporates the FERC's default cost-based rate methodologies for sales of one year or less. PEC anticipates making this filing in the first quarter of 2005. PEC does not anticipate that the current operations will be materially impacted by this change. Although the Company cannot predict the ultimate outcome of these changes, the Company does not anticipate that the current operations of PEC or PEF would be impacted materially if they were unable to sell power at market-based rates in their respective control areas. 107 F. Energy Delivery Capitalization Practice The Company has reviewed its capitalization policies for its Energy Delivery business units in PEC and PEF. That review indicated that in the areas of outage and emergency work not associated with major storms and allocation of indirect costs, both PEC and PEF should revise the way that they estimate the amount of capital costs associated with such work. The Company has implemented such changes effective January 1, 2005, which include more detailed classification of outage and emergency work and result in more precise estimation and a process of retesting accounting estimates on an annual basis. As a result of the changes in accounting estimates for the outage and emergency work and indirect costs, a lesser proportion of PEC's and PEF's costs will be capitalized on a prospective basis. The Company estimates that the combined impact for both utilities in 2005 will be that approximately $55 million of costs that would have been capitalized under the previous policies will be expensed. Pursuant to SFAS No. 71, PEC and PEF have informed the state regulators having jurisdiction over them of this change and that the new estimation process will be implemented effective January 1, 2005. The Company has also requested a method change from the IRS. 9. GOODWILL AND OTHER INTANGIBLE ASSETS The Company performed the annual goodwill impairment test in accordance with FASB Statement No. 142, Goodwill and Other Intangible Assets, for the CCO segment in the first quarter of 2004, and the annual goodwill impairment test for the PEC Electric and PEF segments in the second quarter of 2004, each of which indicated no impairment. The changes in the carrying amount of goodwill, by reportable segment, are as follows: - ------------------------------------------------------------------------------------------------------------- Corporate (in millions) PEC Electric PEF CCO and Other Total - ------------------------------------------------------------------------------------------------------------- Balance as of January 1, 2003 $ 1,922 $ 1,733 $ 64 $ - $ 3,719 Acquisitions - - - 7 7 - ------------------------------------------------------------------------------------------------------------- Balance as of December 31, 2003 $ 1,922 $ 1,733 $ 64 $ 7 $ 3,726 Purchase accounting adjustment - - - (7) (7) - ------------------------------------------------------------------------------------------------------------- Balance as of December 31, 2004 $ 1,922 $ 1,733 $ 64 $ - $ 3,719 - -------------------------------------------------------------------------------------------------------------
In December 2003, $7 million in goodwill was recorded based on a preliminary purchase price allocation as part of the Progress Telecommunications Corporation partial acquisition of EPIK and was reported in the Other segment. As discussed in Note 5A, the Company revised the preliminary EPIK purchase price allocation as of September 2004, and the $7 million of goodwill was reallocated to certain tangible assets acquired based on the results of valuations and appraisals. The gross carrying amount and accumulated amortization of the Company's intangible assets at December 31 are as follows: - ---------------------------------------------------------------------------------------------------------- 2004 2003 ---------------------------------- ------------------------------------ Gross Carrying Accumulated Gross Carrying Accumulated (in millions) Amount Amortization Amount Amortization - ---------------------------------------------------------------------------------------------------------- Synthetic fuel intangibles $ 134 $ (80) $ 140 $ (64) Power agreements acquired 221 (39) 221 (20) Other 119 (18) 93 (13) - ---------------------------------------------------------------------------------------------------------- Total $ 474 $(137) $ 454 $ (97) - ----------------------------------------------------------------------------------------------------------
In June 2004, the Company sold, in two transactions, a combined 49.8% partnership interest in Colona Synfuel Limited Partnership, LLLP, one of its synthetic fuel operations. Approximately $6 million in synthetic fuel intangibles and $3 million in related accumulated amortization were included in the basis of the partnership interest sold. 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 23E). The intangibles related to power agreements acquired are being amortized based on the economic 108 benefits of the contracts (See Notes 5C and 5D). Other intangibles are primarily acquired customer contracts and permits that are amortized over their respective lives. Of the increase in other intangible assets, $24 million resulted from the minimum pension liability adjustment at December 31, 2004 (See Note 17). Amortization expense recorded on intangible assets for the years ended December 31, 2004, 2003 and 2002 was, in millions, $42, $37 and $33, respectively. The estimated annual amortization expense for intangible assets for 2005 through 2009, in millions, is approximately $35, $36, $36, $18 and $18, respectively. 10. IMPAIRMENTS OF LONG-LIVED ASSETS AND INVESTMENTS The Company applies SFAS No. 144 for the accounting and reporting of impairment or disposal of long-lived assets. In 2003 and 2002, the Company recorded pre-tax long-lived asset and investment impairments and other charges of approximately $38 million and $414 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 4C). 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. 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 May 2002, Interpath Communication, Inc., 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. 11. EQUITY A. Common Stock At December 31, 2004, the Company had approximately 63 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. During 2004, 2003 and 2002, respectively, the Company issued approximately 1 million, 8 million and 2 million shares under these plans for net proceeds of approximately $62 million, $305 million and $86 million. The Company continues to meet the requirements of the restricted stock plan with issued and outstanding shares. 109 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 5D). There are various provisions limiting the use of retained earnings for the payment of dividends under certain circumstances. At December 31, 2004, 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 nonbargaining unit employees and certain part-time nonbargaining 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 PT LLC/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 that 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 3.5 million and 4.0 million ESOP suspense shares at December 31, 2004 and 2003, respectively, with a fair value of $156 million and $183 million, respectively. ESOP shares allocated to plan participants totaled 12.6 million and 13.1 million in December 31, 2004 and 2003, 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 costs, which were met and will be met with shares released from the suspense account, totaled approximately $21 million, $20 million and $20 million for the years ended December 31, 2004, 2003 and 2002, respectively. Total matching and incentive cost totaled approximately $32 million, $35 million and $30 million for the years ended December 31, 2004, 2003 and 2002, respectively. The Company has a long-term note receivable from the 401(k) Trustee related to the purchase of common stock from the Company in 1989. The balance of the note receivable from the 401(k) Trustee is included in the determination of unearned ESOP common stock, which reduces common stock equity. ESOP shares that have not been committed to be released to participants' accounts are not considered outstanding for the determination of earnings per common share. Interest income on the note receivable and dividends on unallocated ESOP shares are not recognized for financial statement purposes. 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 10 years from the date of grant. All option grants have an exercise price equal to the fair market value of the Company's common stock on the grant date. 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 2004, 2003 and 2002. The 110 Company will begin expensing stock options on July 1, 2005, based on SFAS No. 123R (See Note 2). In 2004, however, the Company made the decision to cease granting stock options and intends to replace that compensation program with other programs. Therefore, the amount of stock option expense expected to be recorded in 2005 is below the amount that would have been recorded if the stock option program had continued. 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: --------------------------------------------------------------------------------------------- 2004 2003 2002 --------------------------------------------------------------------------------------------- Risk-free interest rate 4.22% 4.25% 4.14% Dividend yield 5.19% 4.75% 5.20% Volatility factor 20.30% 22.28% 24.98% 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, 2004, 2003 and 2002 had a weighted-average remaining contractual life of 7.6, 8.7 and 9.3 years, respectively, and had exercise prices that ranged from $40.41 to $51.85. The tabular information for the option activity is as follows: - ---------------------------------------------------------------------------------------------------------------------- 2004 2003 2002 --------------------------------------------------------------------------- Weighted- Weighted- Weighted- Number of Average Number of Average Number of Average Options Exercise Options Exercise Options Exercise (option quantities in millions) Price Price Price - ---------------------------------------------------------------------------------------------------------------------- Options outstanding, January 1 8.0 $ 43.54 5.2 $ 42.84 2.3 $ 43.49 Granted - - 3.0 $ 44.70 2.9 $ 42.34 Forfeited (0.1) $ 43.76 (0.1) $ 43.64 - $ 43.71 Canceled (0.1) $ 43.67 (0.1) $ 43.62 - - Exercised (0.4) $ 42.82 - $ 43.00 - - Options outstanding, December 31 7.4 $ 43.57 8.0 $ 43.54 5.2 $ 42.84 Options exercisable, December 31 with a remaining contractual life of 7.6 years 4.6 $ 43.35 2.4 $ 43.09 0.8 $ 43.49 Weighted-average grant date fair value of options granted during the year - $ 7.16 $ 6.83 - ----------------------------------------------------------------------------------------------------------------------
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 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 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 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 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 and is reduced by any forfeitures. Effective January 1, 2005, new awards granted pursuant to the PSSP will be payable in Company common stock rather than in cash. 111 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 $46.95, $39.53 and $44.27 in 2004, 2003 and 2002, 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: - -------------------------------------------------------------- 2004 2003 2002 - -------------------------------------------------------------- Beginning balance 944,883 950,180 674,511 Granted 154,500 180,200 365,920 Vested (367,107) (151,677) (75,200) Forfeited (87,100) (33,820) (15,051) - -------------------------------------------------------------- Ending balance 645,176 944,883 950,180 - -------------------------------------------------------------- The total amount expensed for other stock-based compensation plans was $10 million, $27 million and $17 million in 2004, 2003 and 2002, 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 nonvested 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) 2004 2003 2002 - --------------------------------------------------------------------------- Weighted-average common shares - basic 242.2 237.2 217.2 Restricted stock awards .8 1.0 .8 Stock options .1 - .2 - --------------------------------------------------------------------------- Weighted-average shares - fully diluted 243.1 238.2 218.2 - --------------------------------------------------------------------------- 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 3.6 million, 4.1 million and 4.8 million for the years ended December 31, 2004, 2003 and 2002, respectively. There were 3.0 million, 5.3 million and 92 thousand stock options outstanding at December 31, 2004, 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) 2004 2003 - ----------------------------------------------------------------------------- Loss on cash flow hedges $ (28) $ (36) Minimum pension liability adjustments (142) (16) Foreign currency translation and other 6 2 - ----------------------------------------------------------------------------- Total accumulated other comprehensive loss $ (164) $ (50) - ----------------------------------------------------------------------------- 112 12. 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, 2004 and 2003 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 - ---------------------------------------------------------------------------------------------------------------
13. DEBT AND CREDIT FACILITIES A. Debt and Credit Facilities At December 31, the Company's long-term debt consisted of the following (maturities and weighted-average interest rates at December 31, 2004): 113 - ----------------------------------------------------------------------------------------------- (in millions) 2004 2003 - ----------------------------------------------------------------------------------------------- Progress Energy, Inc. Senior unsecured notes, maturing 2006-2031 6.90% $ 4,300 $ 4,800 Draws on revolving credit agreement, expiring 2009 3.19% 160 - Unamortized fair value hedge gain, net 12 19 Unamortized premium and discount, net (23) (27) - ----------------------------------------------------------------------------------------------- 4,449 4,792 - ----------------------------------------------------------------------------------------------- Progress Energy Carolinas, Inc. First mortgage bonds, maturing 2005-2033 6.33% 1,600 1,900 Pollution control obligations, maturing 2017-2024 1.98% 669 708 Unsecured notes, maturing 2012 6.50% 500 500 Medium-term notes, maturing 2008 6.65% 300 300 Unamortized premium and discount, net (19) (22) - ----------------------------------------------------------------------------------------------- 3,050 3,386 - ----------------------------------------------------------------------------------------------- Progress Energy Florida, Inc. First mortgage bonds, maturing 2008-2033 5.60% 1,330 1,330 Pollution control obligations, maturing 2018-2027 1.67% 241 241 Medium-term notes, maturing 2005-2028 6.76% 337 379 Draws on revolving credit agreement, expiring 2006 2.95% 55 - Unamortized premium and discount, net (3) (3) - ----------------------------------------------------------------------------------------------- 1,960 1,947 - ----------------------------------------------------------------------------------------------- Florida Progress Funding Corporation (See Note 19) Debt to affiliated trust, maturing 2039 7.10% 309 309 Unamortized premium and discount, net (39) (39) - ----------------------------------------------------------------------------------------------- 270 270 - ----------------------------------------------------------------------------------------------- Progress Capital Holdings, Inc. Medium-term notes, maturing 2006-2008 6.84% 140 165 Miscellaneous notes 1 1 - ----------------------------------------------------------------------------------------------- 141 166 - ----------------------------------------------------------------------------------------------- Progress Genco Ventures, LLC Variable rate project financing, maturing 2007 - 241 - ----------------------------------------------------------------------------------------------- Current portion of long-term debt (349) (868) - ----------------------------------------------------------------------------------------------- Total long-term debt $ 9,521 $ 9,934 - -----------------------------------------------------------------------------------------------
At December 31, 2004, the Company had committed lines of credit used to support its commercial paper borrowings. The Progress Energy five-year credit facility and the PEF three-year credit facility are included in long-term debt. All other credit facilities are included in short-term obligations. At December 31, 2004, the Company had $260 million outstanding under its credit facilities classified as short-term obligations at a weighted-average interest rate of 3.18%. No amount was outstanding under the Company's committed lines of credit at December 31, 2003. The Company is required to pay minimal annual commitment fees to maintain its credit facilities. The following table summarizes the Company's credit facilities: -------------------------------------------------------------------------------------------------------------- (in millions) Company Description Total Outstanding Available -------------------------------------------------------------------------------------------------------------- Progress Energy, Inc. 5-Year (expiring 8/5/09) $ 1,130 $ 160 $ 970 Progress Energy Carolinas, Inc. 364-Day (expiring 7/27/05) 165 90 75 Progress Energy Carolinas, Inc. 3-Year (expiring 7/31/05) 285 - 285 Progress Energy Florida, Inc. 364-Day (expiring 3/29/05) 200 170 30 Progress Energy Florida, Inc. 3-Year (expiring 4/01/06) 200 55 145 Less: amounts reserved(a) (574) -------------------------------------------------------------------------------------------------------------- Total credit facilities $ 1,980 $ 475 $ 931 --------------------------------------------------------------------------------------------------------------
(a) To the extent amounts are reserved for commercial paper outstanding or backing letters of credit, they are not available for additional borrowings. 114 At December 31, 2004 and 2003, the Company had $424 million and $4 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, 2004 and 2003 were 2.77% and 2.25%, respectively. At December 31, 2004, the Company has reserved $150 million of its lines of credit for backing of letters of credit. Both Progress Energy and PEF 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, 2004. On January 31, 2005, Progress Energy, Inc., entered into a new $600 million revolving credit agreement, which expires December 30, 2005. This facility was added to provide additional liquidity during 2005 due in part to storm restoration costs incurred in Florida during 2004. The credit agreement includes a defined maximum total debt to total capital ratio of 68% and a minimum interest coverage ratio of 2.5 to 1. The credit agreement also contains various cross-default and other acceleration provisions. On February 4, 2005, $300 million was drawn under the new facility to reduce commercial paper and bank loans outstanding. The combined aggregate maturities of long-term debt for 2005 through 2009 are approximately $349 million, $963 million, $674 million, $827 million and $560 million, respectively. B. Covenants and Default Provisions FINANCIAL COVENANTS Progress Energy's, PEC's and PEF's credit lines 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 include a defined maximum total debt to total capital ratio. At December 31, 2004, the maximum and calculated ratios for the companies, pursuant to the terms of the agreements, are as follows: - ------------------------------------------------------------------------- Company Maximum Ratio Actual Ratio (a) - ------------------------------------------------------------------------- Progress Energy, Inc. 65% 60.7% Progress Energy Carolinas, Inc. 65% 52.3% Progress Energy Florida, Inc. 65% 50.8% - ------------------------------------------------------------------------- (a) Indebtedness as defined by the bank agreements includes certain letters of credit and guarantees that are not recorded on the Consolidated Balance Sheets. Progress Energy's 364-day credit facility and both PEF's 364-day and three-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, 2004, the ratios were 4.00 to 1 and 7.93 to 1 for the Company and PEF, respectively. In March 2005, Progress Energy, Inc.'s five-year credit facility was amended to increase the maximum total debt to total capital ratio from 65% to 68% in anticipation of the potential impacts of proposed accounting rules for uncertain tax positions. See Notes 2 and 23E. MATERIAL ADVERSE CHANGE CLAUSE The credit facilities of Progress Energy, PEC, and PEF include a provision under which lenders could refuse to advance funds in the event of a material adverse change (MAC) in the borrower's financial condition. Pursuant to the terms of Progress Energy's five-year credit facility, even in the event of a MAC, Progress Energy may continue to borrow funds so long as the proceeds are used to repay maturing commercial paper balances. CROSS-DEFAULT PROVISIONS 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 applies only to Progress Energy and its significant subsidiaries (i.e., PEC, Florida Progress, PEF, Progress Capital Holdings, Inc. (PCH) and Progress Fuels). 115 Additionally, certain of Progress Energy's long-term debt indentures contain cross-default provisions for defaults of indebtedness in excess of $25 million; these provisions apply only to other obligations of Progress Energy, 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. 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, 2004, none of PEC's retained earnings was 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, 2004, PEC's common stock equity was approximately 52.2% 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, 2004, none of PEF's retained earnings was 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, 2004, PEF's common stock equity was approximately 54.4% of total capitalization. C. Collateralized Obligations PEC's and PEF's first mortgage bonds are collateralized 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, 2004, PEC and PEF had a total of approximately $3.84 billion 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. D. Progress Genco Ventures, LLC (Genco) Bank Facility In December 2004, Genco repaid its bank facility and recorded a $9 million pre-tax loss ($6 million after-tax) in other, net on the extinguishment. At that time, the related $195 million notional amount of interest rate collars in place to hedge floating interest rate exposure on the bank facility was terminated and pre-tax deferred losses of $6 million ($4 million after-tax) were reclassified into earnings in other, net due to the discontinuance of the hedges. The facility was obtained to be used exclusively for expansion of its nonregulated generation portfolio. Borrowings under this facility were secured by the assets in the generation portfolio. The facility was for up to $260 million, of which $241 million had been drawn at December 31, 2003. Borrowings under the facility were restricted for the operations, construction, repayments and other related charges of the credit facility for the development projects. Cash held and 116 restricted to operations was $24 million at December 31, 2003, and was included in other current assets. Cash held and restricted for long-term purposes was $9 million at December 31, 2003, respectively, and was included in other assets and deferred debits on the Consolidated Balance Sheets. E. Guarantees of Subsidiary Debt See Note 19 on related party transactions for a discussion of obligations guaranteed or secured by affiliates. F. 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 18. 14. 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, 2004, and 2003, investments in company-owned life insurance and other benefit plan assets, with carrying amounts of approximately $220 million and $210 million, respectively, are included in miscellaneous other property and investments in the Consolidated Balance Sheets and approximate fair value due to the short maturity of the instruments. Other instruments, including short-term investments, are presented at fair value in accordance with GAAP. The carrying amount of the Company's long-term debt, including current maturities, was $9.870 billion and $10.802 billion at December 31, 2004 and 2003, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $10.843 billion and $11.917 billion at December 31, 2004 and 2003, respectively. External trust funds have been established to fund certain costs of nuclear decommissioning (See Note 6D). 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. 15. INCOME TAXES Deferred income taxes have been provided for temporary differences. These occur when there are differences between 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. To the extent that the establishment of deferred income taxes under SFAS No. 109, "Accounting for Income Taxes," (SFAS No. 109) 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. 117 Accumulated deferred income tax assets (liabilities) at December 31 are: - ----------------------------------------------------------------------------------------- (in millions) 2004 2003 - ----------------------------------------------------------------------------------------- Current deferred tax asset Unbilled revenue $ 35 $ 18 Other 86 69 - ----------------------------------------------------------------------------------------- Total current deferred tax asset 121 87 - ----------------------------------------------------------------------------------------- Noncurrent deferred tax asset (liability) Investments 73 8 Supplemental executive retirement plans 31 30 Other post-employment benefits (OPEB) 126 119 Other pension plans (15) (97) Goodwill 34 46 Accumulated depreciation and property cost differences (1,374) (1,436) Deferred costs (13) 26 Deferred storm costs (113) - Deferred fuel (55) 31 Federal income tax credit carry forward 779 683 State net operating loss carry forward 47 42 Valuation allowance (47) (42) Miscellaneous other temporary differences, net 43 (16) - ----------------------------------------------------------------------------------------- Total noncurrent deferred tax liabilities (484) (606) - ----------------------------------------------------------------------------------------- Less amount included in other assets and deferred debits 10 9 - ----------------------------------------------------------------------------------------- Net noncurrent deferred tax liabilities $ (494) $ (615) - -----------------------------------------------------------------------------------------
Total deferred income tax liabilities were $2,797 million and $2,662 million at December 31, 2004 and 2003, respectively. Total deferred income tax assets were $2,434 million and $2,143 million at December 31, 2004 and 2003, respectively. Total noncurrent income tax liabilities on the Consolidated Balance Sheets at December 31, 2004 and 2003 include $105 million and $86 million, respectively, related to probable tax liabilities on which the Company accrues interest that would be payable with the related tax amount in future years. The federal income tax credit carry forward at December 31, 2004, consists of $749 million of alternative minimum tax credit with an indefinite carry forward period and $30 million of general business credit with a carry forward period that will begin to expire in 2020. As of December 31, 2004, the Company had a state net operating loss carry forward of $79 million, which will begin to expire in 2007. The Company established additional valuation allowances of $5 million during 2004 and 2003 and $12 million during 2002, due to the uncertainty of realizing certain future state tax benefits. 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. Progress Energy decreased its 2004 beginning of the year valuation allowance by $8 million for a change in circumstances related to net operating losses. The Company establishes accruals for certain tax contingencies when, despite the belief that the Company's tax return positions are fully supported, the Company believes that certain positions may be challenged and that it is probable the Company's positions may not be fully sustained. The Company is under continuous examination by the Internal Revenue Service and other tax authorities and accounts for potential losses of tax benefits in accordance with SFAS No. 5. At December 31, 2004 and 2003, respectively, the Company had recorded $60 million and $56 million of tax contingency reserves, excluding accrued interest and penalties, which are included in other current liabilities on the Consolidated Balance Sheets. Considering all tax contingency reserves, the Company does not expect the resolution of these matters to have a material impact on its financial position or result of operations. All tax contingency reserves relate to capitalization and basis issues and do not relate to any potential disallowances of tax credits from synthetic fuel production (See Note 23E). 118 Reconciliations of the Company's effective income tax rate to the statutory federal income tax rate are: - ------------------------------------------------------------------------------------ 2004 2003 2002 - ------------------------------------------------------------------------------------ Effective income tax rate 13.5% (15.8)% (40.0)% State income taxes, net of federal benefit (6.9) (3.3) (8.2) AFUDC amortization (0.5) (1.4) (5.2) Federal tax credits 25.6 50.4 78.0 Investment tax credit amortization 1.6 2.3 4.7 ESOP dividend deduction 1.8 2.1 3.8 Other differences, net (0.1) 0.7 1.9 - ------------------------------------------------------------------------------------ Statutory federal income tax rate 35.0% 35.0% 35.0% - ------------------------------------------------------------------------------------ Income tax expense (benefit) applicable to continuing operations is comprised of: - ------------------------------------------------------------------------------------ (in millions) 2004 2003 2002 - ------------------------------------------------------------------------------------ Current - federal $ 127 $ 127 $ 195 state 76 54 67 Deferred - federal (84) (255) (379) state 10 (21) (23) Investment tax credit (14) (16) (18) - ------------------------------------------------------------------------------------ Total income tax expense (benefit) $ 115 $ (111) $ (158) - ------------------------------------------------------------------------------------
The company has recognized tax benefits from state net operating loss carry forwards in the amount of $7 million during 2004 and $3 million during 2003 and 2002. 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 (See Note 23E). 16. 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 unrealized loss/gain recognized due to these market fluctuations is recorded in other, net on the consolidated statements of income (See Note 21). The liability, included in other liabilities and deferred credits, at December 31, 2004 and 2003, was $13 million and $23 million, respectively. 17. BENEFIT PLANS A. Postretirement Benefits The Company and some of its subsidiaries have a noncontributory 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. 119 The components of net periodic benefit cost for the years ended December 31 are: - ---------------------------------------------------------------------------------------------------------------------- Pension Benefits Other Postretirement Benefits --------------------------------- ----------------------------- (in millions) 2004 2003 2002 2004 2003 2002 - ---------------------------------------------------------------------------------------------------------------------- Service cost $ 54 $ 52 $ 45 $ 12 $ 15 $ 13 Interest cost 110 108 106 31 33 32 Expected return on plan assets (155) (144) (161) (5) (4) (5) Amortization of actuarial (gain) loss 21 25 2 4 5 1 Other amortization, net - - - 1 4 4 - ---------------------------------------------------------------------------------------------------------------------- Net periodic cost / (benefit) $ 30 $ 41 $ (8) $ 43 $ 53 $ 45 Additional cost / (benefit) recognition (Note 17B) (16) (18) (7) 2 2 2 - ---------------------------------------------------------------------------------------------------------------------- Net periodic cost / (benefit) recognized $ 14 $ 23 $ (15) $ 45 $ 55 $ 47 - ----------------------------------------------------------------------------------------------------------------------
The net periodic cost for other postretirement benefits decreased during 2004 due to the implementation of FASB Staff Position 106-2 (See Note 2). 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 five-year averaging method for a portion of its pension assets and fair value for the remaining portion. The Company has historically used the five- 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) 2004 2003 2004 2003 - -------------------------------------------------------------------------------------------------------- Projected benefit obligation at January 1 $ 1,772 $ 1,694 $ 472 $ 514 Service cost 54 52 12 15 Interest cost 110 108 31 33 Disposition of NCNG - (39) - (13) Benefit payments (98) (94) (23) (24) Plan amendment 21 - - - Actuarial loss (gain) 102 51 46 (53) - -------------------------------------------------------------------------------------------------------- Obligation at December 31 1,961 1,772 538 472 Fair value of plan assets at December 31 1,774 1,631 70 65 - -------------------------------------------------------------------------------------------------------- Funded status (187) (141) (468) (407) Unrecognized transition obligation - - 10 25 Unrecognized prior service cost 24 4 6 7 Unrecognized net actuarial loss 530 505 94 40 Minimum pension liability adjustment (470) (23) - - - -------------------------------------------------------------------------------------------------------- Prepaid (accrued) cost at December 31, net $ (103) $ 345 $ (358) $ (335) (Note 17B) - --------------------------------------------------------------------------------------------------------
The 2003 OPEB obligation information above has been restated due to the implementation of FASB Staff Position 106-2 (See Note 2). 120 The net accrued pension cost of $103 million at December 31, 2004, is recognized in the Consolidated Balance Sheets as prepaid pension cost of $42 million and accrued benefit cost of $145 million, which is included in accrued pension and other benefits. 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 accrued pension and other benefits. The defined benefit pension plans with accumulated benefit obligations in excess of plan assets had projected benefit obligations totaling $1.72 billion and $125 million at December 31, 2004 and 2003, respectively. Those plans had accumulated benefit obligations totaling $1.71 billion and $117 million at December 31, 2004 and 2003, respectively, $1.57 billion of plan assets at December 31, 2004, and no plan assets at December 31, 2003. The total accumulated benefit obligation for pension plans was $1.90 billion and $1.72 billion at December 31, 2004 and 2003, respectively. The accrued OPEB cost is included in accrued pension and other benefits in the Consolidated Balance Sheets. A minimum pension liability adjustment of $470 million was recorded at December 31, 2004. This adjustment resulted in a charge of $24 million to intangible assets, a $150 million charge to a pension-related regulatory liability (See Note 17B), a $67 million charge to a regulatory asset pursuant to a recent FPSC order and a pre-tax charge of $229 million to accumulated other comprehensive loss, a component of common stock equity. 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. Reconciliations of the fair value of plan assets are: - --------------------------------------------------------------------------------------------------- Other Postretirement Pension Benefits Benefits ----------------------------- --------------------- (in millions) 2004 2003 2004 2003 - --------------------------------------------------------------------------------------------------- Fair value of plan assets January 1 $ 1,631 $ 1,364 $ 65 $ 52 Actual return on plan assets 211 391 8 12 Disposition of NCNG - (35) - - Benefit payments (98) (94) (23) (24) Employer contributions 30 5 20 25 - --------------------------------------------------------------------------------------------------- Fair value of plan assets at December 31 $ 1,774 $ 1,631 $ 70 $ 65 - ---------------------------------------------------------------------------------------------------
In the table above, substantially all employer contributions represent benefit payments made directly from Company assets except for the 2004 pension amount. The remaining benefits payments were made directly from plan assets. In 2004, the Company made a required contribution of approximately $24 million directly to pension 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 2004 and 2003 and the target allocation for the plans, by asset category, are as follows: - ------------------------------------------------------------------------------------------------------------- Pension Benefits Other Postretirement Benefits --------------------------------------------------------------------------------- Target Percentage of Plan Target Percentage of Plan Allocations Assets at Year End Allocations Assets at Year End ------------- -------------------- -------------- ------------------------ Asset Category 2005 2004 2003 2005 2004 2003 - ------------------------------------------------------------------------------------------------------------- Equity - domestic 48% 47% 49% 34% 34% 35% Equity - international 15% 21% 22% 11% 15% 16% Debt - domestic 12% 9% 11% 37% 35% 37% Debt - international 10% 11% 11% 7% 8% 7% Other 15% 12% 7% 11% 8% 5% - ------------------------------------------------------------------------------------------------------------- Total 100% 100% 100% 100% 100% 100% - -------------------------------------------------------------------------------------------------------------
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. 121 In 2005, the Company expects to make no 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 2005 through 2009 and in total for 2010-2014, in millions, are approximately $113, $110, $115, $124, $131 and $794, respectively. The expected benefit payments for the OPEB plan for 2005 through 2009 and in total for 2010-2014, in millions, are approximately $32, $34, $37, $39, $41 and $230, 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 Company expects to begin receiving prescription drug-related federal subsidies in 2006 (See Note 2), and the expected subsidies for 2006 through 2009 and in total for 2010-2014, in millions, are approximately $3, $3, $3, $4 and $24, respectively. The expected benefit payments above do not reflect the potential effects of a 2005 voluntary enhanced retirement program (See Note 24). The following weighted-average actuarial assumptions were used in the calculation of the year-end obligation: - --------------------------------------------------------------------------------------------------------- Other Postretirement Pension Benefits Benefits ---------------------- ------------------------ (in millions) 2004 2003 2004 2003 - --------------------------------------------------------------------------------------------------------- Discount rate 5.90% 6.30% 5.9% 6.30% Rate of increase in future compensation Bargaining 3.50% 3.50% - - Supplementary plans 5.25% 5.00% - - Initial medical cost trend rate for pre-Medicare benefits - - 7.25% 7.25% Initial medical cost trend rate for post-Medicare benefits - - 7.25% 7.25% Ultimate medical cost trend rate - - 5.00% 5.25% Year ultimate medical cost trend rate is achieved - - 2008 2009 - ---------------------------------------------------------------------------------------------------------
The Company's primary defined benefit retirement plan for nonbargaining 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. 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 ----------------------------- ------------------------------ (in millions) 2004 2003 2002 2004 2003 2002 - ------------------------------------------------------------------------------------------------------------------- Discount rate 6.30% 6.60% 7.50% 6.30% 6.60% 7.50% Rate of increase in future compensation Bargaining 3.50% 3.50% 3.50% - - - Nonbargaining - 4.00% 4.00% - - - Supplementary plans 5.00% 4.00% 4.00% - - - Expected long-term rate of return on plan assets 9.25% 9.25% 9.25% 8.50% 8.45% 8.20% - -------------------------------------------------------------------------------------------------------------------
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 9.0% and 9.5%. The Company has chosen to use an expected long-term rate of 9.25%. 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 2004 would increase by $1 million, and the OPEB obligation at December 31, 2004, would increase by $30 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 2004 would decrease by $1 million, and the OPEB obligation at December 31, 2004, would decrease by $26 million. 122 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 nonbargaining 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, 2004, and 2003 (See Note 8A). In addition, a portion of the prepaid pension cost reflected in the table above has a corresponding regulatory liability (See Note 8A). 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. 18. 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 Derivatives 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 original liability of $38 million associated with the fair value loss is being amortized to earnings over the term of the related contract. At December 31, 2004 and 2003, the remaining liability was $26 million and $35 million, respectively. ECONOMIC DERIVATIVES Derivative products, primarily electricity and natural gas contracts, are entered into 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 to results of operations during 2004, 2003 or 2002, and the Company did not have material outstanding positions in such contracts at December 31, 2004 and 2003. In 2004, PEF entered into derivative instruments related to its exposure to price fluctuations on fuel oil purchases. At December 31, 2004, the fair values of these instruments were a $2 million long-term derivative asset position included in other assets and deferred debits and a $5 million short-term derivative liability position included in other current liabilities. These instruments receive regulatory accounting treatment. Gains are recorded in regulatory liabilities and losses are recorded in regulatory assets. 123 CASH FLOW HEDGES Progress Energy's subsidiaries designate a portion of commodity derivative instruments as cash flow hedges under SFAS No. 133. The objective for holding these instruments is to hedge exposure to market risk associated with fluctuations in the price of natural gas for the Company's forecasted purchases and sales. At December 31, 2004, the maximum period over which the Company is hedging exposures to the price variability of natural gas is 10 years. The total fair value of commodity cash flow hedges at December 31, 2004 and 2003 was as follows: - ----------------------------------------------- (millions of dollars) 2004 2003 - ----------------------------------------------- Fair value of assets $ - $ - Fair value of liabilities (15) (12) - ----------------------------------------------- Fair value, net $ (15) $ (12) - ----------------------------------------------- The ineffective portion of commodity cash flow hedges was not material to the Company's results of operations for 2004, 2003 or 2002. At December 31, 2004, there were $9 million of after-tax deferred losses in accumulated other comprehensive income (OCI), of which $5 million is expected to be reclassified to earnings during the next 12 months as the hedged transactions occur. Gains and losses are recorded net in operating revenues. As part of the divestiture of Winchester Production Company, Ltd., assets in 2004, $7 million of after-tax deferred losses were reclassified into earnings due to discontinuance of the related cash flow hedges and recorded against the gain on sale. Due to the volatility of the commodities markets, the value in OCI is subject to change prior to its reclassification into earnings. B. Interest Rate Derivatives - Fair Value or Cash Flow Hedges 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. Gains and losses are recorded in OCI and amounts reclassified to earnings are included in net interest charges as the hedged transactions occur. The Company uses fair value hedging strategies to manage its exposure to fixed interest rates on long-term debt. For interest rate fair value hedges, the change in the fair value of the hedging derivative is recorded in net interest charges and is offset by the change in the fair value of the hedged item. The fair values of open position interest rate hedges at December 31, 2004 and 2003 were as follows: - ------------------------------------------------------- (in millions) 2004 2003 - ------------------------------------------------------- Interest rate cash flow hedges $ (2) $ (6) Interest rate fair value hedges $ 3 $ (4) - ------------------------------------------------------- CASH FLOW HEDGES The following table presents selected information related to the Company's interest rate cash flow hedges included in accumulated OCI at December 31, 2004: - ----------------------------------------------------------------------------- Accumulated Other Comprehensive Income/(Loss), net of tax(a) Portion Expected to be Reclassified to Earnings during (millions of dollars) the Next 12 Months(b) - ----------------------------------------------------------------------------- $ (19) $ (4) - ----------------------------------------------------------------------------- (a) Includes amounts related to terminated hedges. (b) Actual amounts that will be reclassified to earnings may vary from the expected amounts presented above as a result of changes in interest rates. 124 As of December 31, 2004, PEC had $110 million notional amount of pay-fixed forward swaps to hedge its exposure to interest rates with regard to future issuances of debt (pre-issue hedges) and $21 million notional amount of pay-fixed forward starting swaps to hedge its exposure to interest rates with regard to an upcoming railcar lease. On February 4, 2005, PEC entered another $50 million notional amount of its pre-issue hedges. All the swaps have a computational period of 10 years. PEC held no interest rate cash flow hedges at December 31, 2003. The ineffective portion of interest rate cash flow hedges was not material to the Company's results of operations for 2004 and 2003. In December 2004, Progress Ventures, Inc. (PVI), a wholly owned subsidiary of Progress Energy, terminated $195 million notional amount of interest rate collars in place to hedge floating interest rate exposure associated with variable-rate long-term debt. The related debt was also extinguished in December 2004 (See Note 13). Pre-tax deferred losses of $6 million ($4 million after-tax) were reclassified into earnings in other, net due to discontinuance of these cash flow hedges. At December 31, 2004 and 2003, Progress Energy, Inc., held interest rate cash flow hedges, with a total notional amount of $200 million and $400 million, respectively, related to projected outstanding balances of commercial paper. The fair value of the hedges at December 31, 2004, was not material to the Company's financial condition and at December 31, 2003, was $5 million. The hedges held at December 31, 2003, were terminated during the year. Amounts in accumulated other comprehensive income related to these terminated hedges will be reclassified to earnings as the hedged interest payments occur. FAIR VALUE HEDGES As of December 31, 2004 and 2003, Progress Energy had $150 million notional amount and $850 million notional amount, respectively, of fixed rate debt swapped to floating rate debt by executing interest rate derivative agreements. These agreements expire on various dates through March 2011. During 2004, Progress Energy entered into $350 million notional amount and terminated $1.05 billion notional amount of interest rate swap agreements. At December 31, 2004 and 2003, the Company had $9 million and $23 million, respectively, of basis adjustments in long-term debt related to terminated interest rate fair value hedges, which are being amortized over periods ending in 2006 through 2011 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. 19. RELATED PARTY TRANSACTIONS As a part of normal business, Progress Energy and certain subsidiaries enter into various agreements providing financial or performance assurances to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended commercial purposes. As of December 31, 2004, Progress Energy and its subsidiaries' guarantees include: $270 million supporting commodity transactions, $181 million to support nuclear decommissioning, $536 million related to power supply agreements and $182 million for guarantees supporting other agreements of subsidiaries. Progress Energy also purchased $92 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $50 million. Florida Progress also fully guarantees the medium term notes outstanding for Progress Capital, a wholly owned subsidiary of Florida Progress (See Note 13). At December 31, 2004, management does not believe conditions are likely for significant performance under these agreements. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included in the Balance Sheets. Progress Fuels sells coal to PEF for an insignificant profit. These intercompany revenues and expenses 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 sales price through the ratemaking process is probable. Sales, net of insignificant profits, of $331 million, $346 million and $329 million for the years ended December 31, 2004, 2003 and 2002, respectively, are included in fuel used in electric generation on the Consolidated Statements of Income. Florida Progress Funding Corporation (Funding Corp.) $309 million 7.10% Junior Subordinated Deferrable Interest Notes (Subordinated Notes) are due to FPC Capital I (the Trust). The Trust was established for the sole purpose of issuing $300 million Preferred Securities and using the proceeds thereof to purchase from Funding Corp. its Subordinated Notes due 2039. The Company has fully and unconditionally guaranteed the obligations of Funding Corp. under the Subordinated Notes (the Notes Guarantee). In addition, the Company 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 125 (Preferred Securities Guarantee). The Preferred Securities Guarantee, considered together with the Notes Guarantee, constitutes a full and unconditional guarantee by the Company of the Trust's obligations under the Preferred Securities. The Subordinated Notes and the Notes Guarantee are the sole assets of the Trust. The Subordinated Notes may be redeemed at the option of Funding Corp. 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. The yearly interest expense is $21 million and is reflected in the Consolidated Statements of Income. The Company sold NCNG to Piedmont Natural Gas Company, Inc. on September 30, 2003 (See Note 4E). Prior to disposition, NCNG sold natural gas to affiliates. During the years ended December 31, 2003 and 2002, sales of natural gas to affiliates amounted to $11 million and $20 million, respectively. These revenues are included in discontinued operations on the Consolidated Statements of Income. 20. FINANCIAL INFORMATION BY BUSINESS SEGMENT The Company currently provides services through the following business segments: PEC Electric, PEF, Fuels, CCO and Rail Services. Prior to 2004, other nonregulated business activities were reported separately in the Other segment. These reportable segment changes reflect the current reporting structure. For comparative purposes, the results have been restated to align with the current presentation. 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 and 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. In addition to these reportable operating segments, the Company has Corporate and other activities that include holding company and service company operations as well as other nonregulated business areas. These nonregulated business areas include 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 the 2004 losses is a $43 million pre-tax ($29 million after-tax) settlement agreement that SRS reached with the San Francisco United School District related to civil proceedings. Included in the 2002 losses are asset impairments and certain other after-tax charges related to the telecommunications operations of $225 million. The operations of NCNG were reclassified to discontinued operations and therefore are not included in the results from continuing operations during the periods reported. The profit or loss of the identified segments plus the loss of Corporate and Other represents the Company's total income from continuing operations. Products and services are sold between the various reportable segments. All intersegment transactions are at cost except for transactions between Fuels and PEF, which are at rates set by the FPSC. In accordance with SFAS No. 71, profits on intercompany sales between PEF and Fuels are not eliminated if the sales price is reasonable and the future recovery of sales price through the ratemaking process is probable. The profits for all three years presented were not significant. 126 - ------------------------------------------------------------------------------------------------------------------- PEC Rail Corporate (in millions) Electric PEF Fuels CCO Services and Other Eliminations Totals - ------------------------------------------------------------------------------------------------------------------- Year ended December 31, 2004 Revenues Unaffiliated $ 3,628 $ 3,525 $ 1,179 $ 240 $ 1,130 $ 70 $ - $ 9,772 Intersegment - - 331 - 1 441 (773) - - ------------------------------------------------------------------------------------------------------------------- Total revenues 3,628 3,525 1,510 240 1,131 511 (773) 9,772 - ------------------------------------------------------------------------------------------------------------------- Depreciation and amortization 570 281 93 58 21 45 - 1,068 Total interest charges, net 192 114 22 17 27 361 (86) 647 Gain on sale of assets - - 54 - - 3 - 57 Income tax expense (benefit) (a) 237 174 (230) (1) 15 (80) - 115 Segment profit (loss) 464 333 180 (4) 16 (236) - 753 Total assets 10,590 7,924 986 1,709 596 17,741 (13,553) 25,993 Capital and investment expenditures 519 480 157 25 40 14 - 1,235 - ------------------------------------------------------------------------------------------------------------------- Year ended December 31, 2003 Revenues Unaffiliated $ 3,589 $ 3,152 $ 928 $ 170 $ 846 $ 56 $ - $ 8,741 Intersegment - - 346 - 1 446 (793) - - ------------------------------------------------------------------------------------------------------------------- Total revenues 3,589 3,152 1,274 170 847 502 (793) 8,741 - ------------------------------------------------------------------------------------------------------------------- Depreciation and amortization 562 307 80 42 20 29 - 1,040 Total interest charges, 197 91 23 4 29 356 (72) 628 net Impairment of long-lived assets and investments 11 - 17 - - 10 - 38 Income tax expense 238 147 (415) 8 2 (46) (45) (111) (benefit) (a) Segment profit (loss) 515 295 235 20 (1) (253) - 811 Total assets 10,748 7,280 1,142 1,747 586 17,955 (13,365) 26,093 Capital and investment expenditures 445 526 309 338 103 35 - 1,756 - ------------------------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------------------------- Year ended December 31, 2002 Revenues Unaffiliated $ 3,539 $ 3,062 $ 607 $ 92 $ 714 $ 77 $ - $ 8,091 Intersegment - - 329 - 5 418 (752) - - ------------------------------------------------------------------------------------------------------------------- Total revenues 3,539 3,062 936 92 719 495 (752) 8,091 - ------------------------------------------------------------------------------------------------------------------- Depreciation and amortization 524 295 47 20 20 32 - 938 Total interest charges, 212 106 24 (12) 33 351 (81) 633 net Impairment of long- lived assets and - - - - 59 330 - 389 investments Income tax expense 237 163 (373) 16 (16) (191) 6 (158) (benefit) (a) Segment profit (loss) 513 323 176 27 (42) (445) - 552 Total assets 10,139 6,678 934 1,452 529 15,872 (11,886) 23,718 Capital and investment expenditures 619 550 170 682 8 73 - 2,102 - -------------------------------------------------------------------------------------------------------------------
(a) Amounts include income tax benefit reallocation from holding company to profitable subsidiaries according to an SEC order. 127 Geographic Data ----------------------------------------------------------------------------- (in millions) U.S. Canada Mexico Consolidated ----------------------------------------------------------------------------- 2004 Consolidated revenues $ 9,644 $ 112 $ 16 $ 9,772 ----------------------------------------------------------------------------- 2003 Consolidated revenues $ 8,624 $ 103 $ 14 $ 8,741 ----------------------------------------------------------------------------- 2002 Consolidated revenues $ 7,984 $ 93 $ 14 $ 8,091 -----------------------------------------------------------------------------
21. OTHER INCOME AND OTHER EXPENSE Other income and expense includes interest income, 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: - --------------------------------------------------------------------------------------------- (in millions) 2004 2003 2002 - --------------------------------------------------------------------------------------------- Other income Nonregulated energy and delivery services income $ 32 $ 27 $ 33 DIG Issue C20 amortization (Note 18A) 9 2 - Contingent value obligation unrealized gain (Note 16) 9 - 28 Investment gains - 5 - AFUDC equity 11 14 8 Gain on sale of property and partnership investment 12 25 12 Other 34 17 42 - ------------------------------------------------------------------------------------------- Total other income $ 107 $ 90 $ 123 - ------------------------------------------------------------------------------------------- Other expense Nonregulated energy and delivery services expenses $ 20 $ 20 $ 29 Donations 10 12 19 Investment losses 6 - - Contingent value obligation unrealized loss (Note 16) - 9 - Loss from equity investments 6 40 21 Loss on debt extinguishment and interest rate collars (Note 13D) 15 - - Other 42 25 27 - ------------------------------------------------------------------------------------------- Total other expense $ 99 $ 106 $ 96 - ------------------------------------------------------------------------------------------- Other, net $ 8 $ (16) $ 27 - -------------------------------------------------------------------------------------------
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. 22. ENVIRONMENTAL MATTERS 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 The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liabilities. Some states, including North and South Carolina, have similar types of legislation. The Company and its subsidiaries are periodically notified by regulators including the EPA and various state agencies of their involvement or potential involvement in sites that may require investigation and/or remediation. 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. The Company also is currently in the process of assessing potential costs and exposures at other sites. For all sites, as 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. A discussion of sites by legal entity follows. 128 Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. PEC and PEF are each potentially responsible parties (PRPs) at several manufactured gas plant (MGP) sites. PEC, PEF and Progress Fuels Corporation have filed claims with the Company's general liability insurance carriers to recover costs arising from 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. PEC There are nine former MGP sites and a number of other sites associated with PEC that have required or are anticipated to require investigation and/or remediation costs. During the fourth quarter of 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site located in Raleigh, North Carolina. The EPA offered PEC and 34 other PRPs the opportunity to negotiate cleanup of the site and reimbursement of less than $2 million to the EPA for EPA's past expenditures in addressing conditions at the site. Although a loss is considered probable, an agreement among PRPs has not been reached; consequently, it is not possible at this time to reasonably estimate the total amount of PEC's obligation for remediation of the Ward Transformer site. At December 31, 2004 and 2003, PEC's accruals for probable and estimable costs related to various environmental sites, which are included in other liabilities and deferred credits and are expected to be paid out over many years, were: - ----------------------------------------------------------------- (in millions) 2004 2003 - ----------------------------------------------------------------- Insurance fund $ 7 $ 9 Transferred from NCNG at time of sale 2 2 - ----------------------------------------------------------------- Total accrual for environmental sites $ 9 $ 11 - ----------------------------------------------------------------- PEC received insurance proceeds to address costs associated with environmental liabilities related to its involvement with some sites. All eligible expenses related to these are charged against a specific fund containing these proceeds. PEC spent approximately $2 million related to environmental remediation in 2004. PEC is unable to provide an estimate of the reasonably possible total remediation costs beyond what is currently accrued because 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. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet reached the stage where a reasonable estimate of the remediation costs can be made, PEC cannot determine the total costs that may be incurred in connection with the remediation of all sites at this time. It is anticipated that sufficient information will become available for several sites during 2005 to allow a reasonable estimate of PEC's obligation for those sites to be made. PEF At December 31, 2004 and 2003, PEF's accruals for probable and estimable costs related to various environmental sites, which are included in other liabilities and deferred credits and are expected to be paid out over many years, were: - ------------------------------------------------------------------------------ (in millions) 2004 2003 - ------------------------------------------------------------------------------ Remediation of distribution and substation transformers $ 27 $ 12 MGP and other sites 18 6 - ------------------------------------------------------------------------------ Total accrual for environmental sites $ 45 $ 18 - ------------------------------------------------------------------------------ 129 PEF has received approval from the FPSC for recovery of costs associated with the remediation of distribution and substation transformers through the Environmental Cost Recovery Clause (ECRC). Under agreements with the Florida Department of Environmental Protection (FDEP), PEF is in the process of examining distribution transformer sites and substation sites for potential equipment integrity issues that could result in the need for mineral oil impacted soil remediation. Through 2004 PEF has reviewed a number of distribution transformer sites and substation sites. PEF expects to have completed its review of distribution transformer sites by the end of 2007 and has completed the review of substation sites in 2004. Should further sites be identified, PEF believes that any estimated costs would also be recovered through the ECRC clause. In 2004, PEF accrued an additional $19 million due to identification of additional sites requiring remediation, and spent approximately $4 million related to the remediation of transformers. PEF has recorded a regulatory asset for the probable recovery of these costs through the ECRC. The amounts for MGP and other sites, in the table above, relate to two former MGP sites and other sites associated with PEF that have required or are anticipated to require investigation and/or remediation. In 2004, PEF received approximately $12 million in insurance claim settlement proceeds and recorded a related accrual for associated environmental expenses. The proceeds are restricted for use in addressing costs associated with environmental liabilities. Expenditures for the year were less than $1 million. 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. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet advanced to the stage where a reasonable estimate of the remediation costs can be made, at this time PEF is unable to provide an estimate of its obligation to remediate these sites beyond what is currently accrued. As more activity occurs at these sites, PEF will assess the need to adjust the accruals. It is anticipated that sufficient information will become available in 2005 to make a reasonable estimate of PEF's obligation for one of the MGP sites. The Florida Legislature passed risk-based corrective action (RBCA, known as Global RBCA) legislation in the 2003 regular session. Risk-based corrective action generally means that the corrective action prescribed for contaminated sites can correlate to the level of human health risk imposed by the contamination at the property. The Global RBCA law expands the use of the risk-based corrective action to all contaminated sites in the state that are not currently in one of the state's waste cleanup programs. The FDEP developed the rules required by the RBCA statute, holding meetings with interested stakeholders and hosting public workshops. The rules have the potential for making future cleanups in Florida more costly to complete. The Global RBCA rule was adopted at the February 2, 2005, Environmental Review Commission hearing. The effective date of the Global RBCA rule is expected to be announced in April 2005. The Company and PEF are in the process of assessing the impact of this matter. FLORIDA PROGRESS CORPORATION In 2001, FPC established a $10 million accrual to address indemnities and retained an environmental liability associated with the sale of its Inland Marine Transportation business. In 2003, the accrual was reduced to $4 million based on a change in estimate. During 2004, expenditures related to this liability were not material to the Company's financial condition. As of December 31, 2004, the remaining accrual balance was approximately $3 million. FPC measures its liability for these exposures based on estimable and probable remediation scenarios. Certain historical sites are being addressed voluntarily by FPC. An immaterial accrual has been established to address investigation expenses related to these sites. At this time, the Company cannot determine the total costs that may be incurred in connection with these sites. RAIL Rail Services is voluntarily addressing certain historical waste sites. At this time, the Company cannot determine the total costs that may be incurred in connection with these sites. 130 AIR QUALITY Congress is considering legislation that would require reductions in air emissions of 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 that could be material to the Company's consolidated financial position or results of operations. Control equipment that will be installed on North Carolina fossil generating facilities as part of the NC Clean Air 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 changes at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The Company was asked to provide information to the EPA as part of this initiative and cooperated in supplying 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, in excess of $1.0 billion. 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 the Federal Appeals Court and its implementation stayed. In July 2004, the EPA announced it will reconsider certain issues arising from the final routine equipment replacement rule. The comment period closed on August 30, 2004. The Company cannot predict the outcome of this matter. In 1998, the EPA published a final rule under Section 110 of the Clean Air Act addressing the regional transport of ozone (NOx SIP Call). Total capital expenditures to meet the requirements of the NOx SIP Call Rule in North and South Carolina could reach approximately $370 million. To date, the Company has spent approximately $282 million related to these projected amounts. 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. Parties unrelated to the Company have undertaken efforts to have Georgia excluded from the rule and its requirements. Georgia has not yet submitted a state implementation plan to comply with the Section 110 NOx SIP Call. The Company cannot predict the outcome of this matter in Georgia. In 1997, the EPA issued final regulations establishing a new 8-hour ozone standard. In April 2004, the EPA identified areas that do not meet the standard. The states with identified areas, including North and South Carolina, are proceeding with the implementation of the federal 8-hour ozone standard. Both states promulgated final regulations, which will require PEC to install NOx controls under the states' programs to comply with the 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 requirements for additional controls at some units. The Company cannot predict the outcome of this matter. In June 2002, the NC Clean Air 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 projects that its capital costs to meet these emission targets will total approximately $895 million by the end of 2013. PEC has expended approximately $108 million of these capital costs through December 31, 2004. PEC currently has approximately 5,100 MW of coal-fired generation capacity in North Carolina that is affected by this Act. The law 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 law 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. The law requires PEC to amortize $569 million, representing 70% of the original cost estimate of $813 million, during the five-year rate freeze period. PEC recognized amortization of $174 million and $74 million for the years ended December 31, 2004, and 2003, respectively, and has recognized $248 million in cumulative amortization through December 31, 2004. The remaining amortization requirement of $321 million will be recorded over the three-year period ending December 31, 2007. The law permits PEC the flexibility to vary the amortization schedule for recording of the compliance costs from none up to $174 million per year. The NCUC will hold a hearing prior to December 31, 2007, to determine cost recovery amounts for 2008 and future periods. Pursuant to the law, PEC entered into an agreement with the State of North Carolina to transfer to the State certain NOx and SO2 emissions allowances that result from compliance with the collective NOx and SO2 emissions limitations set out in the law. 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. 131 In 1997, the EPA's Mercury Study Report and Utility Report to Congress concluded that mercury is not a risk to the average person in America 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 alternative control plans that would limit mercury emissions from coal-fired power plants. The final rule was released on March 15, 2005. The EPA's rule establishes a mercury cap and trade program for coal-fired power plants that requires limits to be met in two phases, in 2010 and 2018. The Company is reviewing the final rule. Installation of additional air quality controls is likely to be needed to meet the mercury rule's requirements. Compliance plans and the cost to comply with the rule will be determined once the Company completes its review. 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. As proposed, the rule may require the Company to install additional pollution controls on its residual oil-fired units, resulting in significant capital expenditures. PEC does not have units impacted by this proposal; PEF has eight units that are affected, and they currently do not have pollution controls in place that would meet the proposed requirements of the nickel rule. The EPA expects to finalize the nickel rule in March 2005. Compliance costs will be determined following promulgation of the rule. In December 2003, the EPA released its proposed Interstate Air Quality Rule, currently referred to as the Clean Air Interstate Rule (CAIR). The final rule was released on March 10, 2005. The EPA's rule requires 28 states and the District of Columbia, including North Carolina, South Carolina, Georgia and Florida, to reduce NOx and SO2 emissions in order to attain preset state NOx and SO2 emissions levels. The Company is reviewing the final rule. Installation of additional air quality controls is likely to be needed to meet the CAIR requirements. Compliance plans and the cost to comply with the rule will be determined once the Company completes its review. The air quality controls already installed for compliance with the NOx SIP Call and currently planned by the Company to comply with the NC Clean Air legislation will reduce the costs required to meet the CAIR requirements for the Company's North Carolina units. In March 2004, the North Carolina Attorney General filed a petition with the EPA under Section 126 of the Clean Air Act, asking the federal government to force coal-fired power plants in 13 other states, including South Carolina, to reduce their NOx and SO2 emissions. The state of North Carolina contends these out-of-state emissions interfere with North Carolina's ability to meet national air quality standards for ozone and particulate matter. The EPA has agreed to make a determination on the petition by August 1, 2005. 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 at the affected facilities. Integration of these new wastewater streams into the existing wastewater treatment processes may result in permitting, construction and treatment requirements imposed on PEC and PEF in the immediate and extended future. After many years of litigation and settlement negotiations, the EPA adopted regulations in February 2004 to implement Section 316(b) of the Clean Water Act. These regulations became effective September 7, 2004. 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. The Company currently estimates that from 2005 through 2009 the range of its expenditures to meet the Section 316(b) requirements of the Clean Water Act will be $85 million to $115 million. The range includes $20 million to $30 million at PEC and $65 million to $85 million at PEF. 132 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. In 2004, Russia ratified the Protocol, and the treaty went into effect on February 16, 2005. The United States has not adopted the Kyoto Protocol, and the Bush administration has stated it favors voluntary programs. A number of carbon dioxide emissions control proposals have been advanced in Congress. 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 of control or limitation cannot be recovered from customers. The Company favors the voluntary program approach recommended by the administration and continually evaluates options for the reduction, avoidance and sequestration of greenhouse gases. However, the Company cannot predict the outcome of this matter. Progress Energy has announced its plan to issue a report on the Company's activities associated with current and future environmental requirements. The report will include a discussion of the environmental requirements that the Company currently faces and expects to face in the future, as well as an assessment of potential mandatory constraints on carbon dioxide emissions. The report will be issued by March 31, 2006. 23. COMMITMENTS AND CONTINGENCIES A. Purchase Obligations At December 31, 2004, 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) 2005 2006 2007 2008 2009 Thereafter - ------------------------------------------------------------------------------------------------------ Fuel $ 2,219 $ 1,473 $ 663 $ 229 $ 252 $ 1,270 Purchased power 473 473 479 449 416 4,614 Construction obligations 51 - - - - - Other purchase obligations 100 70 64 41 39 268 - ------------------------------------------------------------------------------------------------------ Total $ 2,843 $ 2,016 $ 1,206 $ 719 $ 707 $ 6,152 - ------------------------------------------------------------------------------------------------------
FUEL AND PURCHASED POWER FPC, PEC and Fuels have entered into various long-term contracts for coal, oil and gas. Payments under these commitments were $2,097 million, $1,719 million and $1,414 million for 2004, 2003 and 2002, respectively. 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 and energy costs, total approximately $38 million. These contractual purchases totaled $39 million, $36 million and $36 million for 2004, 2003 and 2002, 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, 2004, 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 estimated minimum annual payments of approximately $43 million, representing capital-related capacity costs. Estimated annual payments for energy and capacity costs are approximately $72 million through 2009. Total purchases (including energy and transmission use charges) under the Rockport agreement amounted to $63 million, $66 million and $59 million for 2004, 2003 and 2002, respectively. 133 PEC executed two long-term agreements for the purchase of power from Broad River LLC's Broad River facility. One 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. The second 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 for both capacity and energy under the Broad River agreements amounted to $42 million, $37 million and $38 million in 2004, 2003 and 2002 respectively. PEF has long-term contracts for approximately 489 MW of purchased power with other utilities, including a contract with The Southern Company for approximately 414 MW of purchased power annually through 2015. Total purchases, for both energy and capacity, under these agreements amounted to $129 million, $124 million and $109 million for 2004, 2003 and 2002, respectively. Total capacity payments were $56 million, $55 million and $50 million for 2004, 2003 and 2002, respectively. Minimum purchases under these contracts, representing capital-related capacity costs, at December 31, 2004 are $60 million, $63 million, $65 million, $66 million and $67 million for 2005 through 2009, respectively, and $244 million thereafter. Both PEC and PEF have ongoing purchased power contracts with certain cogenerators (qualifying facilities) with expiration dates ranging from 2005 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 $248 million, $244 million and $235 million for 2004, 2003 and 2002, respectively. Minimum expected future capacity payments under these contracts at December 31, 2004, are $271 million, $279 million, $289 million, $298 million and $263 million for 2005 through 2009, respectively, and $3.8 billion 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 $91 million in 2004, $113 million in 2003 and $145 million in 2002. On December 2, 2004, PEF entered into precedent and related agreements with Southern Natural Gas Company (SNG), Florida Gas Transmission Company (FGT), and BG LNG Services, LLC for the supply of natural gas and associated firm pipeline transportation to augment PEF's gas supply needs for the period from May 1, 2007, to April 30, 2027. The total cost to PEF associated with the agreements is approximately $3.3 billion. The transactions are subject to several conditions precedent, which include obtaining the Florida Public Service Commission's approval of the agreements, the completion and commencement of operation of the necessary related expansions to SNG's and FGT's respective natural gas pipeline systems, and other standard closing conditions. Due to the conditions in the agreements, the estimated costs associated with these agreements are not included in the contractual cash obligations table above. CONSTRUCTION OBLIGATIONS The Company has purchase obligations related to various capital construction projects. Total payments under these contracts were $102 million, $158 million and $143 million for 2004, 2003 and 2002, respectively. OTHER PURCHASE OBLIGATIONS The Company has entered into various other contractual obligations primarily related to service contracts for operational services entered into by PESC, a PVI parts and services contract, and a PEF service agreement related to the Hines Complex. Payments under these agreements were $69 million, $31 million and $420 million for 2004, 2003 and 2002, respectively. 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. During 2004 and 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). The related agreements and their amendments require the payment of minimum annual royalties of approximately $7 million for each plant through 2007. 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 $73 million and $94 million at December 31, 2004 and 2003, respectively, representing the minimum amounts due through 2007, discounted at 6.05%. At December 31, 2004 and 2003, the portions of the asset and liability recorded that were classified as current were 134 approximately $26 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 none in 2004, $2 million in 2003 and $51 million in 2002. Future expected minimum royalty payments are approximately $26 million for 2005 through 2007. The Company has the 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 2004 and 2003 royalty payments of approximately $42 million and $48 million, respectively, pending the establishment of the necessary escrow accounts. Once established, those funds will be placed into escrow. During 2004 Progress Energy made the first installment of $10 million for a contract dispute. The installments for 2005 and 2006, respectively, are $16 million and $17 million (See Note 20). 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 $65 million, $60 million and $71 million for 2004, 2003 and 2002, respectively. Purchased power expense under agreements classified as operating leases were approximately $24 million in 2004 and $5 million in 2003. Assets recorded under capital leases at December 31 consist of: - ------------------------------------------------------------------- (in millions) 2004 2003 - ------------------------------------------------------------------- Buildings $ 30 $ 30 Equipment and other 2 3 Less: Accumulated amortization (11) (10) - ------------------------------------------------------------------- $ 21 $ 23 - ------------------------------------------------------------------- Minimum annual payments, excluding executory costs such as property taxes, insurance and maintenance, under long-term noncancelable leases at December 31, 2004, are: - ----------------------------------------------------------------------------------------- (in millions) Capital Leases Operating Leases - ----------------------------------------------------------------------------------------- 2005 $ 4 $ 66 2006 4 55 2007 4 58 2008 4 58 2009 3 54 Thereafter 31 307 - ----------------------------------------------------------------------------------------- $ 50 $ 598 ------------------- Less amount representing imputed interest (21) - ---------------------------------------------------------------------- Present value of net minimum lease payments under capital leases $ 29 - -----------------------------------------------------------------------------------------
In 2003, the Company entered into a new operating lease for a building, for which minimum annual rental payments are included in the table above. The lease terms provide for no rental payments during the last 15 years of the lease, during which period $53 million of rental expense will be recorded in the Consolidated Statements of Income. The Company, excluding PEC and PEF, is also a lessor of land, buildings and other types of properties it owns under operating leases with various terms and expiration dates. The leased buildings are depreciated under the same terms as other buildings included in diversified business property. Minimum rentals receivable under noncancelable leases for 2005 through 2009 are approximately $32 million, $22 million, $14 million, $9 million and $6 million, respectively, with $17 million receivable thereafter. Rents received under these operating leases totaled $63 million, $46 million and $53 million for 2004, 2003 and 2002, respectively. PEC is the lessor of electric poles, streetlights and other facilities. Minimum rentals under noncancelable leases are $9 million for 2005 and none thereafter. Rents received totaled $32 million, $31 million and $28 million for 2004, 2003 and 2002, respectively. 135 PEF is the lessor of electric poles, streetlights and other facilities. Rents received are based on a fixed minimum rental where price varies by type of equipment and totaled $63 million, $56 million and $52 million for 2004, 2003 and 2002, respectively. Minimum rentals receivable (excluding streetlights) under noncancelable leases for 2005 is $5 million, for 2006 through 2009 $1 million, and $8 million thereafter. Streetlight rentals were $40 million, $38 million and $34 million for 2004, 2003 and 2002 respectively. Future streetlight rentals would approximate 2004 revenues. D. Guarantees To facilitate commercial transactions of the Company's subsidiaries, Progress Energy and certain wholly owned subsidiaries enter into agreements providing future financial or performance assurances to third parties (See Note 19). At December 31, 2004, the Company had issued guarantees on behalf of third parties with an estimated maximum exposure of approximately $10 million. These guarantees support synthetic fuel operations. At December 31, 2004, management does not believe conditions are likely for significant performance under these agreements. In connection with the sale of partnership interests in Colona (See Note 4B), Progress Fuels indemnified the buyers against any claims related to Colona resulting from violations of any environmental laws. Although the terms of the agreement provide for no limitation to the maximum potential future payments under the indemnification, the Company has estimated that the maximum total of such payments would not be material. E. Claims and Uncertainties OTHER CONTINGENCIES 1. Pursuant to the Nuclear Waste Policy Act of 1982, the predecessors to PEF and PEC entered into contracts with the U.S. Department of Energy (DOE) under which the DOE agreed to begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract. DOE failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004, PEC and PEF filed a complaint in the United States Court of Federal Claims against the DOE, claiming that the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel (SNF) by failing to accept SNF from various Progress Energy facilities on or before January 31, 1998. Damages due to DOE's breach will likely exceed $100 million. Approximately 60 cases involving the Government's actions in connection with spent nuclear fuel are currently pending in the Court of Federal Claims. DOE and the PEC/PEF parties have agreed to a stay of the lawsuit, including discovery. The parties agreed to, and the trial court entered, a stay of proceedings, in order to allow for possible efficiencies due to the resolution of legal and factual issues in previously filed cases in which similar claims are being pursued by other plaintiffs. These issues may include, among others, so-called "rate issues," or the minimum mandatory schedule for the acceptance of SNF and high level waste (HLW) by which the Government was contractually obligated to accept contract holders' SNF and/or HLW, and issues regarding recovery of damages under a partial breach of contract theory that will be alleged to occur in the future. These issues have been or are expected to be presented in the trials that are currently scheduled to occur during 2005. Resolution of these issues in other cases could facilitate agreements by the parties in the PEC/PEF lawsuit, or at a minimum, inform the Court of decisions reached by other courts if they remain contested and require resolution in this case. The trial court has continued this stay until June 24, 2005. With certain modifications and additional approval by the NRC, including the installation of onsite dry storage facilities at Robinson and Brunswick, 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 operating licenses for all of PEC's nuclear generating units. With certain modifications and additional approval by the NRC, including the installation of onsite dry storage facilities at PEF's nuclear unit, Crystal River Unit No. 3 (CR3), PEF's spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on PEF's system through the expiration of the operating license for CR3. 136 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. In January 2003, the State of Nevada, Clark County, Nevada, and the City of Las Vegas petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of the Congressional override resolution. These same parties also challenged EPA's radiation standards for Yucca Mountain. On July 9, 2004, the Court rejected the challenge to the constitutionality of the resolution approving Yucca Mountain, but ruled that the EPA was wrong to set a 10,000-year compliance period in the radiation protection standard. EPA is currently reworking the standard but has not stated when the work will be complete. DOE originally planned to submit a license application to the NRC to construct the Yucca Mountain facility by the end of 2004. However, in November 2004, DOE announced it would not submit the license application until mid-2005 or later. Also in November 2004, Congressional negotiators approved $577 million for fiscal year 2005 for the Yucca Mountain project, approximately $300 million less than requested by DOE but approximately the same as approved in 2004. The DOE continues to state it plans to begin operation of the repository at Yucca Mountain in 2010. PEC and PEF cannot predict the outcome of this matter. 2. In 2001, PEC entered into a contract to purchase coal from Dynegy Marketing and Trade (DMT). After DMT experienced financial difficulties, including credit ratings downgrades by certain credit reporting agencies, PEC requested credit enhancements in accordance with the terms of the coal purchase agreement in July 2002. When DMT did not offer credit enhancements, as required by a provision in the contract, PEC terminated the contract in July 2002. PEC initiated a lawsuit seeking a declaratory judgment that the termination was lawful. DMT counterclaimed, stating the termination was a breach of contract and an unfair and deceptive trade practice. On March 23, 2004, the United States District Court for the Eastern District of North Carolina ruled that PEC was liable for breach of contract, but ruled against DMT on its unfair and deceptive trade practices claim. On April 6, 2004, the Court entered a judgment against PEC in the amount of approximately $10 million. The Court did not rule on DMT's request under the contract for pending legal costs. On May 4, 2004, PEC authorized its outside counsel to file a notice of appeal of the April 6, 2004, judgment, and on May 7, 2004, the notice of appeal was filed with the United States Court of Appeals for the Fourth Circuit. On June 8, 2004, DMT filed a motion to dismiss the appeal on the ground that PEC's notice of appeal should have been filed on or before May 6, 2004. On June 16, 2004, PEC filed a motion with the trial court requesting an extension of the deadline for the filing of the notice of appeal. By order dated September 10, 2004, the trial court denied the extension request. On September 15, 2004, PEC filed a notice of appeal of the September 10, 2004, order, and by order dated September 29, 2004, the appellate court consolidated the first and second appeals. DMT's motion to dismiss the first appeal remains pending. The consolidated appeal has been fully briefed, and the court of appeals has indicated that it will hear arguments, which tentatively have been scheduled for the week of May 23, 2005. In the first quarter of 2004, PEC recorded a liability for the judgment of approximately $10 million and a regulatory asset for the probable recovery through its fuel adjustment clause. The Company cannot predict the outcome of this matter. 3. On February 1, 2002, the Company filed a complaint with the Surface Transportation Board (STB) challenging the rates charged by Norfolk Southern Railway Company (Norfolk Southern) for coal transportation to certain generating plants. In a decision dated December 23, 2003, the STB found that the rates were unreasonable, awarded reparations and prescribed maximum rates. Both parties petitioned the STB for reconsideration of the December 23, 2003 decision. On October 20, 2004, the STB reconsidered its December 23, 2003 decision and concluded that the rates charged by Norfolk Southern were not unreasonable. Because the Company paid the maximum rates prescribed by the STB in its December 23, 2003 decision for several months during 2004, which were less than the rates ultimately found to be reasonable, the STB ordered the Company to pay to Norfolk Southern the difference between the rate levels plus interest. The Company subsequently filed a petition with the STB to phase in the new rates over a period of time, and filed a notice of appeal with the U.S. Court of Appeals for the D.C. Circuit. Pursuant to an order issued by the STB on January 6, 2005, the phasing proceeding will proceed on a schedule that appears likely to produce an STB decision before the end of 2005. On January 12, 2005, the STB filed a Motion to Dismiss the Company's appeal on the grounds that its October 20, 2004, order is not "final" until the Company's phasing application has been decided. 137 As of December 31, 2004, the Company has accrued a liability of $42 million, of which $23 million represents reparations previously remitted to PEC by Norfolk Southern that are now subject to refund. Of the remaining $19 million, $17 million has been recorded as deferred fuel cost on the Consolidated Balance Sheet, while the remaining $2 million attributable to wholesale customers has been charged to fuel used in electric generation on the Consolidated Statements of Income. The Company cannot predict the outcome of this matter. 4. 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 qualify 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. The amount of Section 29 credits that the Company is allowed to claim in any calendar year is limited by the amount of the Company's regular federal income tax liability. Synthetic fuel tax credit amounts allowed but not utilized are carried forward indefinitely as deferred alternative minimum tax credits. All entities have received PLRs from the IRS with respect to their synthetic fuel operations. However, these PLRs do not address the placed-in-service date determination. The PLRs do not limit the production on which synthetic fuel credits may be claimed. Total Section 29 credits generated to date (including those generated by FPC prior to its acquisition by the Company) are approximately $1.5 billion, of which $713 million has been used to offset regular federal income tax liability and $745 million is being carried forward as deferred alternative minimum tax credits. Also, $7 million has not been recognized due to the decrease in tax liability resulting from expenses incurred for the 2004 hurricane damage. The current Section 29 tax credit program expires at the end of 2007. IMPACT OF HURRICANES For the year ended December 31, 2004, the Company's synthetic fuel facilities sold 8.3 million tons of synthetic fuel and the Company recorded $215 million of Section 29 tax credits. The amount of synthetic fuel sold and tax credits recorded in 2004 was impacted by hurricane costs that reduced the Company's projected 2004 regular tax liability. For the nine months ended September 30, 2004, the Company's synthetic fuel facilities sold 7.7 million tons of synthetic fuel, which generated an estimated $204 million of Section 29 tax credits. Due to the anticipated decrease in the Company's tax liability as a result of expenses incurred for the 2004 hurricane damage, the Company estimated that it would be able to use in 2004, or carry forward to future years, only $125 million of these Section 29 tax credits at September 30, 2004. As a result, the Company recorded a charge of $79 million related to Section 29 tax credits at September 30, 2004. On November 2, 2004, PEF filed a petition with the FPSC to recover $252 million of storm costs plus interest from customers over a two-year period. Based on a reasonable expectation at December 31, 2004, that the FPSC will grant the requested recovery of the storm costs, the Company's loss from the casualty is less than originally anticipated. As of December 31, 2004, the Company estimates that it will be able to use in 2004, or carry forward to future years, $215 million of these Section 29 tax credits. Therefore, the Company recorded tax credits of $90 million for the quarter ended December 31, 2004, which the Company now anticipates can be used. For the year ended December 31, 2004, the Company's synthetic fuel facilities sold 8.3 million tons of synthetic fuel, which generated an estimated $222 million of Section 29 tax credits. As of December 31, 2004, the Company anticipates that approximately $7 million of tax credits related to synthetic fuel sold during the year could not be used and have not been recognized. The Company believes its right to recover storm costs is well established; however, the Company cannot predict the timing or outcome of this matter. If the FPSC should deny PEF's petition for the recovery of storm costs in 2005, there could be a material impact on the amount of 2005 synthetic fuels production and results of operations. IRS PROCEEDINGS In September 2002, all of Progress Energy's majority-owned synthetic fuel entities 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. 138 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 concluded the PFA program with respect to Colona. In July 2004, Progress Energy was notified that the IRS field auditors anticipated taking an adverse position regarding the placed-in-service date of the Company's four Earthco synthetic fuel facilities. Due to the auditors' position, the IRS decided to exercise its right to withdraw from the PFA program with Progress Energy. With the IRS's withdrawal from the PFA program, the review of Progress Energy's Earthco facilities is back on the normal procedural audit path of the Company's tax returns. Through December 31, 2004, the Company, on a consolidated basis, has used or carried forward approximately $1.0 billion of tax credits generated by Earthco facilities. If these credits were disallowed, the Company's one-time exposure for cash tax payments would be $294 million (excluding interest), and earnings and equity would be reduced by approximately $1.0 billion, excluding interest. Progress Energy's amended $1.13 billion credit facility includes a covenant that limits the maximum debt-to-total capital ratio to 68%. This ratio includes other forms of indebtedness such as guarantees issued by PGN, letters of credit and capital leases. As of December 31, 2004, the Company's debt-to-total capital ratio was 60.7% based on the credit agreement definition for this ratio. The impact on this ratio of reversing approximately $1.0 billion of tax credits and paying $294 million for taxes would be to increase the ratio to 65.7%. On October 29, 2004, Progress Energy received the IRS field auditors' report concluding that the Earthco facilities had not been placed in service before July 1, 1998, and that the tax credits generated by those facilities should be disallowed. The Company disagrees with the field audit team's factual findings and believes that the Earthco facilities were placed in service before July 1, 1998. The Company also believes that the report applies an inappropriate legal standard concerning what constitutes "placed in service." The Company intends to contest the field auditors' findings and their proposed disallowance of the tax credits. Because of the disagreement between the Company and the field auditors as to the proper legal standard to apply, the Company believes that it is appropriate and helpful to have this issue reviewed by the National Office of the IRS, just as the National Office reviewed the issues involving chemical change. Therefore, the Company is asking the National Office to clarify the legal standard and has initiated this process with the National Office. The Company believes that the appeals process, including proceedings before the National Office, could take up to two years to complete; however, it cannot control the actual timing of resolution and cannot predict the outcome of this matter. In management's opinion, the Company is complying with all the necessary requirements to be allowed such credits under Section 29, and, although it cannot provide certainty, it believes that it will prevail in these matters. Accordingly, while the Company adjusted its synthetic fuel production for 2004 in response to the effects of expenses incurred due to the hurricane damage and its impact on 2004 tax liability, it has no current plans to alter its synthetic fuel production schedule for future years as a result of the IRS field auditors' report. However, should the Company fail to prevail in these matters, there could be material liability for previously taken Section 29 tax credits, with a material adverse impact on earnings and cash flows. PROPOSED ACCOUNTING RULES FOR UNCERTAIN TAX POSITIONS In July 2004, the FASB stated that it plans to issue an exposure draft of a proposed interpretation of SFAS No. 109, "Accounting for Income Taxes," (SFAS No. 109) that would address the accounting for uncertain tax positions. The FASB has indicated that the interpretation would require that uncertain tax benefits be probable of being sustained in order to record such benefits in the financial statements. The exposure draft is expected to be issued in the first quarter of 2005. The Company cannot predict what actions the FASB will take or how any such actions might ultimately affect the Company's financial position or results of operations, but such changes could have a material impact on the Company's evaluation and recognition of Section 29 tax credits. 139 PERMANENT SUBCOMMITTEE 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. SALE OF PARTNERSHIP INTEREST In June 2004, the Company, through its subsidiary, Progress Fuels, sold, in two transactions, a combined 49.8% partnership interest in Colona Synfuel Limited Partnership, LLLP, one of its synthetic fuel facilities. Substantially all proceeds from the sales will be received over time, which is typical of such sales in the industry. Gain from the sales will be recognized on a cost recovery basis. The Company's book value of the interests sold totaled approximately $5 million. The company received total gross proceeds of $10 million in 2004. Based on projected production and tax credit levels, the Company anticipates receiving approximately $24 million in 2005, approximately $31 million in 2006, approximately $32 million in 2007 and approximately $8 million through the second quarter of 2008. In the event that the synthetic fuel tax credits from the Colona facility are reduced, including an increase in the price of oil that could limit or eliminate synthetic fuel tax credits, the amount of proceeds realized from the sale could be significantly impacted. IMPACT OF CRUDE OIL PRICES Although the Internal Revenue Code Section 29 tax credit program is expected to continue through 2007, recent unprecedented and unanticipated increases in the price of oil could limit the amount of those credits or eliminate them altogether for one or more of the years following 2004. This possibility is due to a provision of Section 29 that provides that if the average wellhead price per barrel for unregulated domestic crude oil for the year (the "Annual Average Price") exceeds a certain threshold value (the "Threshold Price"), the amount of Section 29 tax credits are reduced for that year. Also, if the Annual Average Price increases high enough (the "Phase Out Price"), the Section 29 tax credits are eliminated for that year. For 2003, the Threshold Price was $50.14 per barrel and the Phase Out Price was $62.94 per barrel. The Threshold Price and the Phase Out Price are adjusted annually for inflation. If the Annual Average Price falls between the Threshold Price and the Phase Out Price for a year, the amount by which Section 29 tax credits are reduced will depend on where the Average Annual Price falls in that continuum. For example, for 2003, if the Annual Average Price had been $56.54 per barrel, there would have been a 50% reduction in the amount of Section 29 tax credits for that year. The Secretary of the Treasury calculates the Annual Average Price based on the Domestic Crude Oil First Purchases Prices published by the Energy Information Agency (EIA). Because the EIA publishes its information on a three-month lag, the Secretary of the Treasury finalizes its calculations three months after the year in question ends. Thus, the Annual Average Price for calendar year 2003 was published in April 2004. Although the official notice for 2004 is not expected to be published until April 2005, the Company does not believe that the Annual Average Price for 2004 will reach the Threshold Price for 2004. Consequently, the Company does not expect the amount of its 2004 Section 29 tax credits to be adversely affected by oil prices. The Company cannot predict with any certainty the Annual Average Price for 2005 or beyond. Therefore, it cannot predict whether the price of oil will have a material effect on its synthetic fuel business after 2004. However, if during 2005 through 2007, oil prices remain at historically high levels or increase, the Company's synthetic fuel business may be adversely affected for those years, and, depending on the magnitude of such increases in oil prices, the adverse affect for those years could be material and could have an impact on the Company's synthetic fuel results of operations and production plans. 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 and disclosures have been made in accordance with SFAS No. 5, "Accounting for Contingencies," to provide for such matters. In the opinion of management, the final disposition of pending litigation would not have a material adverse effect on the Company's consolidated results of operations or financial position. 140 24. SUBSEQUENT EVENTS Sale of Progress Rail On February 18, 2005, the Company announced it has entered into a definitive agreement to sell Progress Rail to One Equity Partners LLC, a private equity firm unit of J.P. Morgan Chase & Co. Gross cash proceeds from the transaction will be $405 million, subject to working capital adjustments. The sale is expected to close by mid-2005, and is subject to various closing conditions customary to such transactions. Proceeds from the sale are expected to be used to reduce debt. The Company expects to report Progress Rail as a discontinued operation in the first quarter of 2005. The carrying amounts for the assets and liabilities of the discontinued operations disposal group included in the Consolidated Balance Sheets as of December 31, are as follows: - ------------------------------------------------------------------------ (in millions) 2004 2003 - ------------------------------------------------------------------------ Total current assets $ 378 $ 373 Total property, plant & equipment (net) 173 151 Total other assets 40 77 Total current liabilities 156 114 Total long-term liabilities 3 3 Total capitalization 432 484 - ------------------------------------------------------------------------ Cost Management Initiative On February 28, 2005, as part of a previously announced cost management initiative, the executive officers of the Company approved a workforce restructuring. The restructuring will result in a reduction of approximately 450 positions and is expected to be completed in September 2005. The cost management initiative is designed to permanently reduce by $75-100 million the projected growth in the Company's annual operation and maintenance expenses by the end of 2007. In addition to the workforce restructuring, the cost management initiative includes a voluntary enhanced retirement program. In connection with the cost management initiative, the Company expects to incur one-time pre-tax charges of approximately $130 million. Approximately $30 million of that amount relates to payments for severance benefits, and will be recognized in the first quarter of 2005 and paid over time. The remaining approximately $100 million will be recognized in the second quarter of 2005 and relates primarily to postretirement benefits that will be paid over time to those eligible employees who elect to participate in the voluntary enhanced retirement program. Approximately 3,500 of the Company's 15,700 employees are eligible to participate in the voluntary enhanced retirement program. The total cost management initiative charges could change significantly depending upon how many eligible employees elect early retirement under the voluntary enhanced retirement program and the salary, service years and age of such employees. 141 25. CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized quarterly financial data is as follows: - ---------------------------------------------------------------------------------------------------------------------- (in millions except per share data) First Second Third Quarter Fourth Quarter Quarter Quarter - ---------------------------------------------------------------------------------------------------------------------- Year ended December 31, 2004 Operating revenues $ 2,245 $ 2,408 $ 2,761 $ 2,358 Operating income 296 305 584 291 Income from continuing operations before cumulative effect of changes in accounting principles 108 153 303 189 Net income 108 154 303 194 Common stock data: Basic earnings per common share Income from continuing operations before cumulative effect of changes in accounting principles 0.45 0.63 1.25 0.78 Net income 0.45 0.63 1.25 0.80 Diluted earnings per common share Income from continuing operations before cumulative effect of changes in accounting principles 0.45 0.63 1.24 0.78 Net income 0.45 0.63 1.24 0.80 Dividends declared per common share 0.575 0.575 0.575 0.590 Market price per share - High 47.95 47.50 44.32 46.10 Low 43.02 40.09 40.76 40.47 - ------------------------------------------------------------------------------------------------------------------- Year ended December 31, 2003 Operating revenues $ 2,187 $ 2,050 $ 2,457 $ 2,047 Operating income 357 274 478 248 Income from continuing operations before cumulative effect of changes in accounting principles 207 154 337 113 Net income 219 157 318 88 Common stock data: Basic earnings per common share Income from continuing operations before cumulative effect of changes in accounting principles 0.89 0.65 1.41 0.47 Net income 0.94 0.66 1.33 0.37 Diluted earnings per common share Income from continuing operations before cumulative effect of changes in accounting principles 0.89 0.65 1.39 0.47 Net income 0.94 0.66 1.31 0.37 Dividends declared per common share 0.560 0.560 0.560 0.575 Market price per share - High 46.10 48.00 45.15 46.00 - Low 37.45 38.99 39.60 41.60 - -------------------------------------------------------------------------------------------------------------------
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. Fourth quarter 2004 includes a $31 million after-tax gain on sale of natural gas assets (See Note 4A) and the recording of $90 million of Section 29 tax credit (See Note 23E). Third quarter 2004 includes the reversal of $79 million of Section 29 tax credits (See Note 23E). Second quarter 2004 includes the settlement of civil proceeding related to SRS of $43 million ($29 million after-tax) (See Note 20). Fourth quarter 2003 includes impairment charges related to Kentucky May and certain Affordable Housing investments of $38 million ($24 million after-tax) (See Note 10). Fourth quarter 2003 includes the impact of a cumulative effect for DIG Issue 20 of $38 million ($23 million after-tax) (See Note 18). 142 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 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, 2004 and 2003, and the related consolidated statements of income, retained earnings, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. PEC is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of PEC's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. As discussed in Notes 1D and 13A to the consolidated financial statements, in 2003, PEC adopted Statement of Financial Accounting Standards No. 143 and Derivative Implementation Group Issue C20. /s/ Deloitte & Touche LLP Raleigh, North Carolina March 7, 2005 143 CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC. CONSOLIDATED STATEMENTS of INCOME - ----------------------------------------------------------------------------------------------------------- (in millions) Years ended December 31 2004 2003 2002 - ----------------------------------------------------------------------------------------------------------- Operating Revenues Electric $ 3,628 $ 3,589 $ 3,539 Diversified business 1 11 15 - ----------------------------------------------------------------------------------------------------------- Total Operating Revenues 3,629 3,600 3,554 - ----------------------------------------------------------------------------------------------------------- Operating Expenses Fuel used in electric generation 836 825 752 Purchased power 301 296 347 Operation and maintenance 871 782 802 Depreciation and amortization 570 562 524 Taxes other than on income 173 162 158 Diversified business 1 4 15 Impairment of diversified business long-lived assets - - 101 - ----------------------------------------------------------------------------------------------------------- Total Operating Expenses 2,752 2,631 2,699 - ----------------------------------------------------------------------------------------------------------- Operating Income 877 969 855 - ----------------------------------------------------------------------------------------------------------- Other Income (Expense) Interest income 4 6 7 Impairment of investments - (21) (25) Other, net 11 (11) 13 - ----------------------------------------------------------------------------------------------------------- Total Other Income (Expense) 15 (26) (5) - ----------------------------------------------------------------------------------------------------------- Interest Charges Interest charges 195 198 217 Allowance for borrowed funds used during construction (3) (1) (5) - ----------------------------------------------------------------------------------------------------------- Total Interest Charges, Net 192 197 212 - ----------------------------------------------------------------------------------------------------------- Income before Income Tax and Cumulative Effect of Change in Accounting Principles 700 746 638 Income Tax Expense 239 241 207 - ----------------------------------------------------------------------------------------------------------- Income before Cumulative Effect of Change in Accounting 461 505 431 Principles Cumulative Effect of Change in Accounting Principles, Net of Tax - (23) - - ----------------------------------------------------------------------------------------------------------- Net Income 461 482 431 Preferred Stock Dividend Requirement 3 3 3 - ----------------------------------------------------------------------------------------------------------- Earnings for Common Stock $ 458 $ 479 $ 428 - -----------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements. 144 CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC. CONSOLIDATED BALANCE SHEETS - --------------------------------------------------------------------------------------------------- (in millions) December 31 2004 2003 - --------------------------------------------------------------------------------------------------- ASSETS Utility Plant Utility plant in service $ 13,521 $ 13,331 Accumulated depreciation (5,806) (5,307) - --------------------------------------------------------------------------------------------------- Utility plant in service, net 7,715 8,024 Held for future use 5 5 Construction work in progress 379 267 Nuclear fuel, net of amortization 186 159 - --------------------------------------------------------------------------------------------------- Total Utility Plant, Net 8,285 8,455 - --------------------------------------------------------------------------------------------------- Current Assets Cash and cash equivalents 18 12 Short-term investments 82 226 Receivables 397 410 Receivables from affiliated companies 20 27 Inventory 390 387 Deferred fuel cost 140 66 Income taxes receivable 59 37 Prepayments and other current assets 76 63 - --------------------------------------------------------------------------------------------------- Total Current Assets 1,182 1,228 - --------------------------------------------------------------------------------------------------- Deferred Debits and Other Assets Regulatory assets 473 463 Nuclear decommissioning trust funds 581 505 Miscellaneous other property and investments 158 169 Other assets and deferred debits 108 118 - --------------------------------------------------------------------------------------------------- Total Deferred Debits and Other Assets 1,320 1,255 - --------------------------------------------------------------------------------------------------- Total Assets $ 10,787 $ 10,938 - --------------------------------------------------------------------------------------------------- CAPITALIZATION AND LIABILITIES Common Stock Equity Common stock without par value, authorized 200 million shares, 160 million shares issued and outstanding at December 31 $ 1,975 $ 1,953 Unearned ESOP common stock (76) (89) Accumulated other comprehensive loss (114) (7) Retained earnings 1,287 1,380 - --------------------------------------------------------------------------------------------------- Total Common Stock Equity 3,072 3,237 Preferred Stock - Not Subject to Mandatory Redemption 59 59 Long-Term Debt, Net 2,750 3,086 - --------------------------------------------------------------------------------------------------- Total Capitalization 5,881 6,382 - --------------------------------------------------------------------------------------------------- Current Liabilities Current portion of long-term debt 300 300 Accounts payable 254 188 Payables to affiliated companies 83 136 Notes payable to affiliated companies 116 25 Interest accrued 77 80 Short-term obligations 221 4 Customer deposits 45 40 Other current liabilities 179 133 - --------------------------------------------------------------------------------------------------- Total Current Liabilities 1,275 906 - --------------------------------------------------------------------------------------------------- Deferred Credits and Other Liabilities Noncurrent income tax liabilities 991 1,057 Accumulated deferred investment tax credits 140 148 Regulatory liabilities 1,052 1,149 Asset retirement obligations 924 932 Accrued pension and other benefits 383 207 Other liabilities and deferred credits 141 157 - --------------------------------------------------------------------------------------------------- Total Deferred Credits and Other Liabilities 3,631 3,650 - --------------------------------------------------------------------------------------------------- Commitments and Contingencies (Notes 17 and 18) - --------------------------------------------------------------------------------------------------- Total Capitalization and Liabilities $ 10,787 $ 10,938 - --------------------------------------------------------------------------------------------------- See Notes to Consolidated Financial Statements.
145 CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC. CONSOLIDATED STATEMENTS of CASH FLOWS - ------------------------------------------------------------------------------------------------------------------- (in millions) Years ended December 31 2004 2003 2002 - ------------------------------------------------------------------------------------------------------------------- Operating Activities Net income $ 461 $ 482 $ 431 Adjustments to reconcile net income to net cash provided by operating activities: Impairment of long-lived assets and investments - 21 126 Depreciation and amortization 658 660 631 Cumulative effect of change in accounting principles - 23 - Deferred income taxes (19) (69) (82) Investment tax credit (7) (10) (12) Deferred fuel credit (56) 33 (15) Cash provided (used) by changes in operating assets and liabilities: Receivables (4) 10 (13) Receivables from affiliated companies 7 20 (8) Inventory (18) (21) 5 Prepayments and other current assets 13 21 (15) Accounts payable 35 (56) 39 Accounts payable to affiliated companies (53) 24 (19) Other current liabilities 9 57 (2) Other 50 38 32 - ------------------------------------------------------------------------------------------------------------------- Net Cash Provided by Operating Activities 1,076 1,233 1,098 - ------------------------------------------------------------------------------------------------------------------- Investing Activities Gross property additions (519) (445) (619) Proceeds from sale of subsidiaries and other investments 25 28 244 Diversified business property additions and acquisitions - (1) (12) Nuclear fuel additions (101) (66) (81) Net contributions to nuclear decommissioning trust (31) (31) (31) Purchases of short-term investments (2,108) (2,813) (2,962) Proceeds from sales of short-term investments 2,252 2,587 2,962 Other investing activities (3) (1) (17) - ------------------------------------------------------------------------------------------------------------------- Net Cash Used in Investing Activities (485) (742) (516) - ------------------------------------------------------------------------------------------------------------------- Financing Activities Proceeds from issuance of long-term debt - 588 542 Net increase (decrease) in short-term obligations 217 (437) 177 Net change in intercompany notes 91 74 (97) Retirement of long-term debt (339) (276) (807) Dividends paid to parent (551) (443) (397) Dividends paid on preferred stock (3) (3) (3) - ------------------------------------------------------------------------------------------------------------------- Net Cash Used in Financing Activities (585) (497) (585) - ------------------------------------------------------------------------------------------------------------------- Net Increase (Decrease) in Cash and Cash Equivalents 6 (6) (3) - ------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at Beginning of Year 12 18 21 - ------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Year $ 18 $ 12 $ 18 - ------------------------------------------------------------------------------------------------------------------- Supplemental Disclosures of Cash Flow Information Cash paid during the year - interest (net of amount capitalized) $ 185 $ 180 $ 203 income taxes (net of refunds) $ 286 $ 296 $ 319 - -------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements. 146 CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC. CONSOLIDATED STATEMENTS of RETAINED EARNINGS - ---------------------------------------------------------------------------------------- (in millions) Years ended December 31 2004 2003 2002 - ---------------------------------------------------------------------------------------- Retained Earnings at Beginning of Year $ 1,380 $ 1,344 $ 1,313 Net income 461 482 431 Preferred stock dividends at stated rates (3) (3) (3) Common stock dividends (551) (443) (397) - ---------------------------------------------------------------------------------------- Retained Earnings at End of Year $ 1,287 $ 1,380 $ 1,344 - ----------------------------------------------------------------------------------------
CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC. CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME - ------------------------------------------------------------------------------------------------------------------------ (in millions) Years ended December 31 2004 2003 2002 - ------------------------------------------------------------------------------------------------------------------------ Net Income $ 461 $ 482 $ 431 Other Comprehensive Income Changes in net unrealized losses on cash flow hedges (net of tax (expense) benefit of $1, ($1) and $9, respectively) (1) 3 (14) Reclassification adjustment for amounts included in net income (net of tax benefit of $0, $0 and $8, respectively) - 1 11 Minimum pension liability adjustment (net of tax (expense) benefit of $68, ($47) and $47, respectively) (106) 72 (73) - ------------------------------------------------------------------------------------------------------------------------ Other Comprehensive Income $ (107) $ 76 $ (76) - ------------------------------------------------------------------------------------------------------------------------ Comprehensive Income $ 354 $ 558 $ 355 - ------------------------------------------------------------------------------------------------------------------------
147 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 was 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 Caronet, Inc. (Caronet), 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, 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 (PT 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. The consolidated financial statements of PEC and its subsidiaries include the majority owned and controlled subsidiaries. Noncontrolling interests in the subsidiaries are included in other liabilities and deferred credits in the Consolidated Balance Sheets. Income or losses from these interests are included in other income in the Consolidated Statements of Income. The results of operations for minority interest are reported on a net of tax basis if the underlying subsidiary is structured as a taxable entity. 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. These investments are primarily in limited liability corporations and limited liability partnerships, and the earnings from these investments are recorded on a pre-tax basis (See Note 16). These equity method investments are included in miscellaneous other property and investments in the Consolidated Balance Sheets. At December 31, 2004 and 2003, PEC has equity method investments of approximately $15 million and $24 million, respectively. Certain investments in debt and equity securities that have readily determinable market values, and for which PEC does not have control, are accounted for as available-for-sale securities at fair value in accordance with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." These investments include investments held in trust funds, pursuant to United States Nuclear Regulatory Commission (NRC) requirements, to fund certain costs of decommissioning nuclear plants. The fair value of these trust funds was $581 million and $505 million at December 31, 2004 and 2003, respectively. PEC also actively invests available cash balances in various financial instruments, such as tax-exempt debt securities that have stated maturities of 20 years or more. These instruments provide for a high degree of liquidity through arrangements with banks that provide daily and weekly liquidity and 7, 28 and 35 day auctions which allow for the redemption of the investment at its face amount plus earned income. As PEC intends to sell these instruments generally within 30 days from the balance sheet date, they are classified as current assets. At December 31, 2004 and 2003, the fair value of these investments was $82 million and $226 million, respectively. Other investments in debt and equity securities are included in miscellaneous other property and investments in the Consolidated Balance Sheets. At December 31, 2004 and 2003, the fair value of these other investments was $3 million and $2 million, respectively. Other investments are stated principally at cost. These cost method investments are included in miscellaneous other property and investments in the Consolidated Balance Sheets. At December 31, 2004 and 2003, PEC has approximately $1 million and $1 million, respectively, of cost method investments. 148 Certain amounts for 2003 and 2002 have been reclassified to conform to the 2004 presentation. Reclassifications include the reclassification of instruments used in PEC's cash management program from cash and cash equivalents to short-term investments of $226 million at December 31, 2003 in the Consolidated Balance Sheets. In the Consolidated Statements of Cash Flow for each of the three years in the period ended December 31, 2004, total cash balances and total cash flows used in investing activities were revised to reflect the reclassification of these instruments from cash and cash equivalents to short-term investments. C. Consolidation of Variable Interest Entities PEC consolidates all voting interest entities in which it owns a majority voting interest and all variable interest entities for which it is the primary beneficiary in accordance with FASB Interpretation No. 46R, "Consolidation of Variable Interest Entities - An Interpretation of ARB No. 51" (FIN No. 46R). PEC is the primary beneficiary of and consolidates two limited partnerships that qualify for federal affordable housing and historic tax credits under Section 42 of the Internal Revenue Code. As of December 31, 2004, the total assets of the two entities were $37 million, the majority of which are collateral for the entities' obligations and are included in other current assets and miscellaneous other property and investments in the Consolidated Balance Sheet. PEC is the primary beneficiary of a limited partnership that invests in 17 low-income housing partnerships that qualify for federal and state tax credits. PEC has requested but has not received all the necessary information to determine the primary beneficiary of the limited partnership's underlying 17 partnership investments, and has applied the information scope exception in FIN No. 46R, paragraph 4(g) to the 17 partnerships. PEC has no direct exposure to loss from the 17 partnerships; PEC's only exposure to loss is from its investment of less than $1 million in the consolidated limited partnership. PEC will continue its efforts to obtain the necessary information to fully apply FIN No. 46R to the 17 partnerships. PEC believes that if the limited partnership is determined to be the primary beneficiary of the 17 partnerships, the effect of consolidating the 17 partnerships would not be significant to PEC's Consolidated Balance Sheets. PEC has variable interests in two power plants resulting from long-term power purchase contracts. PEC has requested the necessary information to determine if the counterparties are variable interest entities or to identify the primary beneficiaries. Both entities declined to provide PEC with the necessary financial information, and PEC has applied the information scope exception in FIN No. 46R, paragraph 4(g). PEC's only significant exposure to variability from these contracts results from fluctuations in the market price of fuel used by the two entities' plants to produce the power purchased by PEC. PEC is able to recover these fuel costs under its fuel clause. Total purchases from these counterparties were approximately $58 million, $53 million and $53 million in 2004, 2003 and 2002, respectively. PEC will continue its efforts to obtain the necessary information to fully apply FIN No. 46R to these contracts. The combined generation capacity of the two entities' power plants is approximately 880 MW. PEC believes that if it is determined to be the primary beneficiary of these two entities, the effect of consolidating the entities would result in increases to total assets, long-term debt and other liabilities, but would have an insignificant or no impact on PEC's common stock equity, net earnings or cash flows. However, because PEC has not received any financial information from these two counterparties, the impact cannot be determined at this time. PEC also has interests in several other variable interest entities for which PEC is not the primary beneficiary. These arrangements include investments in approximately 22 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, 2004, that PEC could be required to record in its income statement as a result of 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. 149 D. 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 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. These deferred fuel costs are recognized in revenues and fuel expenses as they are billable to customers. 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, 2004, 2003 and 2002, gross receipts tax and other excise taxes of approximately $89 million, $81 million and $80 million, respectively, are included in electric revenue and taxes other than on income on the Consolidated Statements of Income. 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 Intercompany 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 carryover 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. Except for the allocation of this Progress Energy tax benefit, 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 11). STOCK-BASED COMPENSATION PEC participates in the stock option programs offered by Progress Energy (See Note 8B). PEC measures compensation expense for stock options as the difference between the market price of Progress Energy's common stock and the exercise price of the option at the grant date. The exercise price at which options are granted by Progress Energy 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 Progress Energy'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. 150 - ----------------------------------------------------------------------------------------------------- (in millions) 2004 2003 2002 - ----------------------------------------------------------------------------------------------------- Net income, as reported $ 461 $ 482 $ 431 Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects 7 6 5 - ----------------------------------------------------------------------------------------------------- Pro forma net income $ 454 $ 476 $ 426 - -----------------------------------------------------------------------------------------------------
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. Certain costs that would otherwise not be capitalized under GAAP are capitalized in accordance with regulatory treatment. The cost of renewals and betterments is also capitalized. Maintenance and repairs of property (including planned major maintenance activities), 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, disposal or decommissioning costs that do not represent ARO's under SFAS No. 143 "Accounting for Asset Retirement Obligations," (SFAS No. 143) are charged to regulatory liabilities. 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 system 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. ASSET RETIREMENT OBLIGATIONS Effective January 1, 2003, PEC adopted the guidance in SFAS No. 143 to account for legal obligations associated with the retirement of certain tangible long-lived assets. The present value of retirement costs for which PEC has a legal obligation are 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. The adoption of this statement had no impact on the income of PEC, as the effects were offset by the establishment of a regulatory asset pursuant to SFAS No. 71 and related orders by the North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (SCPSC) (See Note 6A). The NCUC and SCPSC also issued an order to authorize deferral of all prospective effects related to SFAS No. 143 as a regulatory asset or liability. Therefore, SFAS No. 143 has no impact on the income of PEC. 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 4A). Pursuant to their rate-setting authority, the NCUC and SCPSC can also grant approval to accelerate or reduce depreciation and amortization of utility assets. Amortization of nuclear fuel costs is computed primarily on the units-of-production method. 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. 151 INVENTORY PEC accounts for inventory using the average-cost method. Inventories are valued at the lower cost or market. 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 Consolidated Balance Sheets as regulatory assets and regulatory liabilities (See Note 6A). 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 4B. 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 (See Note 6A). 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, unless the derivatives meet the SFAS No. 133 criteria for normal purchases or normal sales and are designated as such. PEC generally designates derivative instruments as normal purchases or normal sales whenever the SFAS No. 133 criteria are met. If normal purchase or normal sale criteria are not met, PEC will generally designate the derivative instruments as cash flow or fair value hedges if the related SFAS No. 133 hedge criteria are met. During 2003, the FASB reconsidered an interpretation of SFAS No. 133. See Note 13 for the effect of the interpretation and additional information regarding risk management activities and derivative transactions. ENVIRONMENTAL As discussed in Note 17, PEC accrues environmental remediation liabilities when the criteria for SFAS No. 5, "Accounting for Contingencies," has been met. Environmental 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. Environmental expenditures that have future economic benefits are capitalized in accordance with PEC's asset capitalization policy. IMPAIRMENT OF LONG-LIVED ASSETS AND INVESTMENTS PEC 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 152 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." 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 7 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, except for any transactions that must be credited directly to equity in accordance with the provisions of Staff Accounting Bulletin No. 51, "Accounting for Sales of Stock by a Subsidiary." 2. NEW ACCOUNTING STANDARDS FASB STAFF POSITION 106-2, "ACCOUNTING AND DISCLOSURE REQUIREMENTS RELATED TO THE MEDICARE PRESCRIPTION DRUG IMPROVEMENT AND MODERNIZATION ACT OF 2003" In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law. In accordance with guidance issued by the FASB in FASB Staff Position 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003" (FASB Staff Position 106-1), PEC elected to defer accounting for the effects of the Medicare Act due to uncertainties regarding the effects of the implementation of the Medicare Act and the accounting for certain provisions of the Medicare Act. In May 2004, the FASB issued definitive accounting guidance for the Medicare Act in FASB Staff Position 106-2, which was effective for PEC in the third quarter of 2004. FASB Staff Position 106-2 results in the recognition of lower other postretirement employee benefit (OPEB) costs to reflect prescription drug-related federal subsidies to be received under the Medicare Act. As a result of the Medicare Act, PEC's accumulated postretirement benefit obligation as of January 1, 2004, was reduced by approximately $42 million, and PEC's 2004 net periodic cost was reduced by approximately $7 million. STATEMENT OF FINANCIAL ACCOUNTING STANDARDS NO. 123 (REVISED 2004), "SHARE-BASED PAYMENT" (SFAS NO. 123R) In December 2004, the FASB issued SFAS No. 123R, which revises SFAS No. 123, "Accounting for Stock-Based Compensation" and supersedes Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees." The key requirement of SFAS No. 123R is that the cost of share-based awards to employees will be measured based on an award's fair value at the grant date, with such cost to be amortized over the appropriate service period. Previously, entities could elect to continue accounting for such awards at their grant date intrinsic value under APB Opinion No. 25, and PEC made that election. The intrinsic value method resulted in PEC recording no compensation expense for stock options granted to employees (See Note 1D). SFAS No. 123R will be effective for PEC on July 1, 2005. PEC intends to implement the standard using the required modified prospective method. Under that method, PEC will record compensation expense under SFAS No. 123R for all awards it grants after July 1, 2005, and it will record compensation expense (as previous awards continue to vest) for the unvested portion of previously granted awards that remain outstanding at July 1, 2005. In 2004, Progress Energy made the decision to cease granting stock options and intends to replace that compensation program with other programs. Therefore, the amount of stock option expense expected to be recorded in 2005 is below the amount that would have been recorded if the stock option program had continued. PEC expects to record approximately $1 million of pre-tax expense for stock options in 2005. 153 3. HURRICANE RELATED COSTS Hurricanes Charley and Ivan struck significant portions of PEC's service territories during the third quarter of 2004. PEC incurred restoration costs of $13 million, of which $12 million was charged to operation and maintenance expense and $1 million was charged to capital expenditures. PEC does not have an ongoing regulatory mechanism to recover storm costs; and therefore, hurricane restoration costs recorded in the third quarter of 2004 were charged to operations and maintenance expenses or capital expenditures based on the nature of the work performed. In connection with other storms, PEC has previously sought and received permission from the NCUC and the SCPSC to defer storm expenses and amortize them over a five-year period. PEC did not seek deferral of 2004 hurricane restoration costs (See Note 6B). 4. 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) 2004 2003 - ----------------------------------------------------------------------------- Production plant (7-33 years) $ 7,954 $ 8,024 Transmission plant (30-75 years) 1,212 1,155 Distribution plant (12-50 years) 3,701 3,538 General plant and other (8-75 years) 654 614 - ----------------------------------------------------------------------------- Utility plant in service $ 13,521 $ 13,331 - ----------------------------------------------------------------------------- Generally, electric utility plant, other than nuclear fuel, is pledged as collateral for the first mortgage bonds of PEC (See Note 9). 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 7.2% in 2004, 4.0% in 2003 and 6.2% in 2002. Depreciation provisions on utility plant, as a percent of average depreciable property other than nuclear fuel, were 2.1% in 2004, and 2.7% in 2003 and 2002, respectively. The depreciation provisions related to utility plant were $275 million, $345 million and $326 million in 2004, 2003 and 2002, 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 4D), regulatory approved expenses (See Note 6) and clean air amortization (See Note 6B). During 2004, PEC met the requirements of both the NCUC and the SCPSC for the implementation of a depreciation study which allowed the utility to reduce the rates used to calculate depreciation expense. The annual reduction in depreciation expense is approximately $82 million. The reduction is due primarily to extended lives at each of PEC's nuclear units. The new depreciation rates were effective January 1, 2004. 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, for the years ended December 31, 2004, 2003 and 2002 were $106 million, $112 million and $109 million, respectively, and are included in fuel used for electric generation. B. Diversified Business Property Gross diversified business property was $7 million at December 31, 2004 and 2003, respectively. These amounts consist primarily of buildings and equipment that are being depreciated over periods ranging from 31 to 65 years. Accumulated depreciation was $2 million and $1 million at December 31, 2004 and 2003, respectively. Diversified business depreciation expense was $1 million in 2004 and 2003, and $4 million in 2002. Net diversified business property is included in miscellaneous other property and investments on the Consolidated Balance Sheets. 154 C. Joint Ownership of Generating Facilities PEC holds ownership interests in certain jointly owned generating facilities. PEC is entitled to shares of the generating capability and output of each unit equal to their respective ownership interests. PEC also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. PEC's share of expenses for the jointly owned facilities is included in the appropriate expense category. PEC's ownership interest in the jointly owned generating facilities is listed below with related information at December 31 ($ in millions): - ------------------------------------------------------------------------------------------------------------- 2004 Company Ownership Plant Accumulated Construction Facility Interest Investment Depreciation Work in Progress - ------------------------------------------------------------------------------------------------------------- Mayo Plant 83.83% $ 516 $ 249 $ 1 Harris Plant 83.83% 3,185 1,387 13 Brunswick Plant 81.67% 1,624 888 28 Roxboro Unit No. 4 87.06% 323 147 1 - ------------------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------------------- 2003 Company Ownership Plant Accumulated Construction Facility Interest Investment Depreciation Work In Progress - ------------------------------------------------------------------------------------------------------------- Mayo Plant 83.83% $ 464 $ 242 $ 50 Harris Plant 83.83% 3,248 1,424 7 Brunswick Plant 81.67% 1,611 885 21 Roxboro Unit No. 4 87.06% 323 139 1 - -------------------------------------------------------------------------------------------------------------
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. Asset Retirement Obligations At December 31, 2004 and 2003, the asset retirement costs related to nuclear decommissioning of irradiated plant, net of accumulated depreciation, totaled $46 million and $113 million, respectively. Funds set aside in PEC's nuclear decommissioning trust funds for the nuclear decommissioning liability totaled $580 million and $505 million at December 31, 2004 and 2003, respectively. Net nuclear decommissioning trust unrealized gains are included in regulatory liabilities (See Note 6A). Decommissioning cost provisions, which are included in depreciation and amortization expense, were $31 million in each of 2004, 2003 and 2002. 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 expense recognized for the disposal or removal of utility assets that are not SFAS No. 143 asset removal obligations, which are included in depreciation and amortization expense, were $83 million, $86 million and $81 million in 2004, 2003 and 2002, respectively. PEC recognizes removal, nonirradiated decommissioning and dismantlement costs in regulatory liabilities on the Consolidated Balance Sheets (See Note 6A). At December 31, 2004, such costs consist of removal costs of $601 million and removal costs for nonirradiated areas at nuclear facilities of $70 million. At December 31, 2003, such costs consist of removal costs of $901 million and removal costs for nonirradiated areas at nuclear facilities of $67 million. During 2004, PEC reduced its estimated removal costs to take into account the estimates used in the depreciation studies implemented during 2004 (See Note 4A). This resulted in a downward revision in the PEC estimated removal costs and equal increase in accumulated depreciation of approximately $345 million. PEC re-measured its ARO for the nuclear decommissioning of irradiated plants to take into account updated site-specific decommissioning cost studies, which are required by the NCUC every five years. The ARO for nuclear decommissioning was reduced by $63 million to $924 million. PEC's most recent site-specific estimates of decommissioning costs were developed in 2004, using 2004 cost factors, and are based on prompt dismantlement decommissioning, which reflects the cost of removal of all radioactive and other structures currently at the site, with such removal occurring after operating license expiration. These estimates, in 2004 dollars, are $294 million for Robinson Unit No. 2, $290 million for Brunswick Unit No. 1, $313 million for Brunswick Unit No. 2 and $359 million for the Harris Plant. The estimates are subject to change based on a variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning and changes in federal, state or local regulations. The cost estimates exclude the portion attributable to North Carolina Eastern Municipal Power Agency (Power Agency), which holds an undivided ownership interest in the Brunswick and Harris nuclear generating facilities. NRC operating licenses held by PEC currently expire in December 2014 and September 2016 for Brunswick Units 2 155 and 1, respectively. An application to extend these licenses 20 years was submitted in October 2004. The NRC operating license held by PEC for the Shearon Harris Nuclear Plant (Harris Plant) currently expires in October 2026. An application to extend this license 20 years is expected to be submitted in the fourth quarter of 2006. On April 19, 2004, the NRC announced that it has renewed the operating license for PEC's Robinson Nuclear Plant (Robinson) for an additional 20 years through July 2030. PEC has identified but not recognized AROs related to electric transmission and distribution assets as the result of easements over property not owned by PEC. These easements are generally perpetual and require retirement action only upon abandonment or cessation of use of the property for the specified purpose. The ARO 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 would be recorded at that time. The following table shows the changes to the asset retirement obligations: - -------------------------------------------------------------------- (in millions) - -------------------------------------------------------------------- Asset retirement obligations as of January 1, 2003 $ 880 Accretion expense 52 - -------------------------------------------------------------------- Asset retirement obligations as of December 31, 2003 932 Accretion expense 55 Deductions (63) - -------------------------------------------------------------------- Asset retirement obligations as of December 31, 2004 $ 924 - -------------------------------------------------------------------- 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 there under, following a 12-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 $23 million with respect to the primary coverage, $27 million with respect to the decontamination, decommissioning and excess property coverage, and $15 million for the incremental replacement power costs coverage, in the event covered losses at insured facilities exceed premiums, reserves, reinsurance and other NEIL resources. Pursuant to regulations of the NRC, 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. PEC is insured against public liability for a nuclear incident up to $10.8 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 could possibly approve revisions to the Price Anderson Act during 2005 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. 156 PEC self-insures its transmission and distribution lines against loss due to storm damage and other natural disasters. 5. CURRENT ASSETS RECEIVABLES At December 31, receivables were comprised of: - ------------------------------------------------------------------------------ (in millions) 2004 2003 - ------------------------------------------------------------------------------ Trade accounts receivable $ 240 $ 254 Unbilled accounts receivable 155 145 Other receivables 12 28 Allowance for doubtful accounts receivable (10) (17) - ------------------------------------------------------------------------------ Total receivables $ 397 $ 410 - ------------------------------------------------------------------------------ Income tax receivables and interest income receivables are not included in this classification. These amounts are included in prepayments and other current assets on the Consolidated Balance Sheets. INVENTORY At December 31, inventory was comprised of: - ---------------------------------------------------------------------- (in millions) 2004 2003 - ---------------------------------------------------------------------- Fuel for production $ 127 $ 117 Materials and supplies 263 270 - ---------------------------------------------------------------------- Total inventory $ 390 $ 387 - ---------------------------------------------------------------------- 6. 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 that 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 1D). 157 At December 31, the balances of PEC's regulatory assets (liabilities) were as follows: - --------------------------------------------------------------------------------------------- (in millions) 2004 2003 - --------------------------------------------------------------------------------------------- Deferred fuel cost - current (Note 6B) $ 140 $ 66 - --------------------------------------------------------------------------------------------- Deferred fuel cost - long-term (Note 6B) 28 47 Deferred impact of ARO (Note 1D) 305 291 Income taxes recoverable through future rates (Note 11) 36 33 Loss on reacquired debt (Note 1D) 22 22 Storm deferral (Note 3 and 6B) 25 21 Deferred DOE enrichment facilities-related costs 12 19 Other 45 30 - --------------------------------------------------------------------------------------------- Total long-term regulatory assets 473 463 - --------------------------------------------------------------------------------------------- Non-ARO cost of removal (Note 4D) (671) (968) Emission allowance (8) (8) Net nuclear decommissioning trust unrealized gains (Note 4D) (125) (99) Clean air compliance (Note 6B) (248) (74) - --------------------------------------------------------------------------------------------- Total long-term regulatory liabilities (1,052) (1,149) - --------------------------------------------------------------------------------------------- Net regulatory assets (liabilities) $ (439) $ (620) - ---------------------------------------------------------------------------------------------
Except for portions of deferred fuel, all assets earn a return on the cash that has not yet been expended, in which case the assets are offset by liabilities that do not incur a carrying cost. PEC expects to fully recover these assets and refund the liabilities through customer rates under current regulatory practice. B. Retail Rate Matters As of December 31, 2004, PEC's North Carolina retail fuel costs were under-recovered by $145 million. This amount is comprised of $117 million eligible for recovery in 2005 and $28 million deferred from a 2001 order from the NCUC that cannot be collected during 2005, and has therefore been classified as a long-term asset. PEC intends to collect this amount by October 31, 2007. On October 15, 2004, the SCPSC approved PEC's request to leave fuel rates unchanged. The deferred fuel balance at December 31, 2004, is $23 million. This amount is eligible for recovery in PEC's 2005 South Carolina fuel review. PEC obtained SCPSC and NCUC approval of fuel factors in annual fuel-adjustment proceedings. The NCUC approved an annual increase of $62 million, $20 million and $46 million by orders issued in September 2004, 2003 and 2002, respectively. The SCPSC approved PEC's petition each year and the changes were insignificant. PEC filed with the SCPSC seeking permission to defer expenses incurred from the first quarter 2004 winter storm. The SCPSC approved PEC's request to defer the costs and amortize them ratably over five years beginning in January 2005. Approximately $9 million related to storm costs was deferred in 2004. In October 2003, PEC filed with the NCUC seeking permission to defer expenses incurred from Hurricane Isabel and the February 2003 winter storms. In December 2003, the NCUC approved PEC's request to defer the costs associated with Hurricane Isabel and the February 2003 ice storm and amortize them over a period of five years. PEC charged approximately $24 million in 2003 from Hurricane Isabel and from ice storms to the deferred account. PEC recognized $5 million and $3 million of NC storm amortization during 2004 and 2003, respectively. 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 2004 and 2003 and additional depreciation expense of approximately $53 million 2002. Total accelerated depreciation recorded through December 31, 2004 was $403 million. The North Carolina Clean Smokestacks Act enacted in June 2002 (NC Clean Air), 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. The legislation provides for significant flexibility in the amount of annual amortization recorded, which allows the utilities to vary the amount amortized within certain limits. This flexibility provides a utility with the opportunity to consider the impacts of other factors on its regulatory return on equity when setting the amortization amount for each year. PEC recognized $174 million and $74 million of clean air amortization during 2004 and 2003, respectively. This legislation freezes PEC's base rates in North Carolina for five years, subject to certain conditions (See Note 17). 158 In conjunction with the Florida Progress Corporation (FPC) merger, PEC reached a settlement with the Public Staff of the NCUC in which it agreed to provide credits to its nonreal time pricing customers in the amounts of $3 million in 2002, $5 million in 2003 and $6 million in both 2004 and 2005. In conjunction with the acquisition of NCNG in 1999, PEC agreed not to seek a base retail electric rate increase in North Carolina and South Carolina through December 2004. The agreement not to seek a base retail electric rate increase in South Carolina was extended to December 2005 in conjunction with regulatory approval to form a holding company. C. Regional Transmission Organizations and Standard Market Design In 2000, the FERC issued Order No. 2000 on RTOs, which 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 have materially alter the manner in which transmission and generation services are provided and paid for. In April 2003, the FERC released a White Paper on the Wholesale Market Platform. The White Paper provided an overview of what the FERC intended to include in a final rule in the SMD NOPR docket. The White Paper retained 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 cannot predict the outcome of these matters or the effect that they may have on the GridSouth proceedings currently ongoing before the FERC. However, by order issued December 22, 2004, the FERC terminated a portion of the proceedings regarding GridSouth. The GridSouth Companies asked the FERC for further clarification to the portions of the GridSouth docket it intended to address. On March 2, 2005, the FERC affirmed that it only intended to close the mediation portion of the GridSouth docket. It is unknown what impact the future proceedings will have on PEC's earnings, revenues or prices. PEC had $33 million invested in GridSouth related to startup costs at December 31, 2004. PEC expects to recover these startup costs in conjunction with the GridSouth original structure or in conjunction with any alternate combined transmission structures that emerge. D. FERC Market Power Mitigation A FERC order issued in November 2001 on certain unaffiliated utilities' triennial market-based wholesale power rate authorization updates required certain mitigation actions that those utilities would need to take for sales/purchases within their control areas and required those utilities to post information on their Web sites regarding their power systems' status. As a result of a request for rehearing filed by certain market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. In April 2004, the FERC issued two orders concerning utilities' ability to sell wholesale electricity at market-based rates. In the first order, the FERC adopted two new interim screens for assessing potential generation market power of applicants for wholesale market-based rates, and described additional analyses and mitigation measures that could be presented if an applicant does not pass one of these interim screens. In July 2004, the FERC issued an order on rehearing affirming its conclusions in the April order. In the second order, the FERC initiated a rulemaking to consider whether the FERC's current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in any way. Given the difficulty PEC believes it would experience in passing one of the interim screens, on August 12, 2004, PEC notified the FERC that it would revise its Market-based Rate tariff to restrict it to sales outside PEC's control area and file a new cost-based tariff for sales within PEC's control area that incorporates the FERC's default cost-based rate methodologies for sales of one year or less. PEC anticipates making this filing first quarter of 2005. Although PEC cannot predict the ultimate outcome of these changes, PEC does not anticipate that its current operations would be impacted materially if PEC were unable to sell power at market-based rates in its respective control areas. 159 E. Energy Delivery Capitalization Practice PEC has reviewed its capitalization policy for its Energy Delivery business unit. That review indicated that in the areas of outage and emergency work not associated with major storms and allocation of indirect costs, PEC should revise the way that it estimates the amount of capital costs associated with such work. PEC has implemented such changes effective January 1, 2005, which include more detailed classification of outage and emergency work and result in more precise estimation and a process of retesting accounting estimates on an annual basis. As a result of the changes in accounting estimates for the outage and emergency work and indirect costs, a lesser proportion of PEC's costs will be capitalized on a going forward basis. PEC estimates that the impact in 2005 will be that approximately $25 million of costs that would have been capitalized under the previous policies will be expensed. Pursuant to SFAS No. 71, PEC has informed the state regulators having jurisdiction over them of this change and that the new estimation process will be implemented effective January 1, 2005. 7. IMPAIRMENTS OF LONG-LIVED ASSETS AND INVESTMENTS PEC applies SFAS No. 144 for the accounting and reporting of impairment or disposal of long-lived assets. In 2003 and 2002, PEC recorded pre-tax long-lived asset and investment impairments and other charges of approximately $21 million and $133 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. 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 a pre-tax impairment of $3 million on a cost investment. 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. 8. EQUITY A. Capitalization At December 31, 2004, PEC was authorized to issue up to 200 million shares of common stock. All shares issued and outstanding are held by Progress Energy. 160 Preferred stock outstanding at December 31, 2004 and 2003 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 - -----------------------------------------------------------------------------------------------
PEC's common stock increased by $22 million, $23 million and $26 million for the years ended December 31, 2004, 2003 and 2002, respectively, related primarily to the allocation of ESOP shares. There are various provisions limiting the use of retained earnings for the payment of dividends under certain circumstances. At December 31, 2004, 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, 2004, PEC's common stock equity was approximately 52.2% of total capitalization. Refer to Note 9 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 nonbargaining unit employees and certain part-time nonbargaining 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 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 3.5 million and 4.0 million ESOP suspense shares at December 31, 2004 and 2003, respectively, with a fair value of $156 million and $183 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 $12 million, $11 million and $13 million for the years ended December 31, 2004, 2003 and 2002, respectively. Matching and incentive cost totaled approximately $18 million, $16 million and $14 million for the years ended December 31, 2004, 2003 and 2002, 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, 2004, 2003 and 2002, respectively, approximately 28 thousand, 3.0 million and 2.9 million common stock options were granted. Of these amounts, approximately 1.9 million and 1.2 million options were granted to officers and eligible employees of PEC in 2003 and 2002, respectively. No stock options were 161 granted to officers and employees of PEC in 2004. PEC expects to begin expensing stock options on July 1, 2005, by adopting new FASB guidance on accounting for stock-based compensation (See Note 2). In 2004, however, Progress Energy made the decision to cease granting stock options and intends to replace that compensation program with other programs. Therefore, the amount of stock option expense expected to be recorded in 2005 is below the amount that would have been recorded if the stock option program had continued. The pro forma information presented in Note 1D regarding net income 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 1D have been determined as if PEC had accounted for its employee stock options under SFAS No. 123. 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 Progress Energy to grant shares of restricted common stock to officers and key employees of PEC. 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 $7 million, $15 million and $11 million in 2004, 2003 and 2002, respectively. C. Accumulated Other Comprehensive Loss Components of accumulated other comprehensive loss are as follows: - ------------------------------------------------------------------------ (in millions) 2004 2003 - ------------------------------------------------------------------------ Loss on cash flow hedges $ (7) $ (6) Minimum pension liability adjustments (107) (1) - ------------------------------------------------------------------------ Total accumulated other comprehensive loss $ (114) $ (7) - ------------------------------------------------------------------------ 9. 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, 2004): 162 - ----------------------------------------------------------------------------------- (in millions) 2004 2003 - ----------------------------------------------------------------------------------- First mortgage bonds, maturing 2005-2033 6.33% $ 1,600 $ 1,900 Pollution control obligations, maturing 2017-2024 1.98% 669 708 Unsecured notes, maturing 2012 6.50% 500 500 Medium-term notes, maturing 2008 6.65% 300 300 Unamortized premium and discount, net (19) (22) Current portion of long-term debt (300) (300) - ----------------------------------------------------------------------------------- Total Long-Term Debt, Net $ 2,750 $ 3,086 - -----------------------------------------------------------------------------------
At December 31, 2004, PEC had committed lines of credit, which are used to support its commercial paper borrowings and are included in short-term obligations. At December 31, 2004, the weighted average interest rate on borrowings under the lines of credit was 3.29%. PEC is required to pay minimal annual commitment fees to maintain its credit facilities. The following table summarizes PEC's credit facilities (in millions): - ------------------------------------------------------------------------- Desscription Total Outstanding Available - ------------------------------------------------------------------------- 364-Day (expiring 7/27/05) $ 165 $ 90 $ 75 3-Year (expiring 7/31/05) 285 - 285 Less: amounts reserved(a) (131) - ------------------------------------------------------------------------- $ 450 $ 90 $ 229 - ------------------------------------------------------------------------- (a) To the extent amounts are reserved for commercial paper outstanding or backing letters of credit, they are not available for additional borrowings. At December 31, 2004 and 2003, PEC had $131 million and $4 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, 2004 and 2003 were 2.77% and 2.25%, respectively. The combined aggregate maturities of long-term debt for 2005 through 2009 are approximately, in millions, $300, $0, $200, $300 and $400, 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 that are not recorded on the Consolidated Balance Sheets. At December 31, 2004, PEC's total debt to total capital ratio was 52.3%. 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. CROSS-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 apply only to defaults of indebtedness by Progress Energy and its significant subsidiaries, which includes PEC. 163 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, 2004, none of PEC's retained earnings was restricted. Refer to Note 8 for additional dividend restrictions related to PEC's Articles of Incorporation. C. Collateralized Obligations PEC's first mortgage bonds are collateralized 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, 2004, PEC had approximately $2.269 billion 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 13. 10. 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, 2004 and 2003, there were miscellaneous investments consisting primarily of investments in company-owned life insurance and other benefit plan assets with carrying amounts totaling approximately $94 million and $90 million, respectively, included in miscellaneous other property and investments in the Consolidated Balance Sheets. The carrying amount of these investments approximates fair value due to the short maturity of certain instruments. Other instruments, including short-term investments, are presented at fair value in accordance with GAAP. The carrying amount of PEC's long-term debt, including current maturities, was $3.050 billion and $3.386 billion at December 31, 2004 and 2003, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $3.307 billion and $3.686 billion at December 31, 2004 and 2003, 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. 11. INCOME TAXES Deferred income taxes have been provided for temporary differences. These occur when there are differences between 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. To the extent that the establishment of deferred income taxes under SFAS No. 109, "Accounting for Income Taxes," (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 utility pursuant to rate orders. 164 Accumulated deferred income tax assets (liabilities) at December 31 are: - --------------------------------------------------------------------------------------- (in millions) 2004 2003 - --------------------------------------------------------------------------------------- Current deferred tax asset - other Included in prepayments and other current assets 36 16 - --------------------------------------------------------------------------------------- Noncurrent deferred tax asset (liability) Investments 4 5 Supplemental executive retirement plans 9 7 Other post-employment benefits (OPEB) 52 46 Other pension plans 56 (8) Income tax credit carry forward 21 22 Accumulated depreciation and property cost differences (960) (1,066) Deferred costs (13) 26 Deferred fuel (55) 31 Valuation allowance (1) (1) Miscellaneous other temporary differences, net (1) (39) - --------------------------------------------------------------------------------------- Total noncurrent deferred tax liability (888) (977) - ---------------------------------------------------------------------------------------
Total deferred income tax liabilities were $1,713 million and $1,758 million at December 31, 2004 and 2003, respectively. Total deferred income tax assets were $861 million and $797 million at December 31, 2004 and 2003, respectively. Total noncurrent income tax liabilities on the Consolidated Balance Sheets at December 31, 2004 and 2003 include $103 million and $80 million, respectively, related to probable tax liabilities, on which PEC accrues interest that would be payable with the related tax amount in future years. All tax contingency reserves relate to capitalization and basis issues. The federal income tax credit carry forward at December 31, 2004 consists of $21 million of general business credit with a carry forward period that will begin to expire in 2020. PEC did not establish any additional valuation allowances in 2004. PEC established additional valuation allowances of $1 million and $4 million during 2003 and 2002, respectively, due to the uncertainty of realizing certain future state tax benefits. 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: - ------------------------------------------------------------------------------ 2004 2003 2002 - ------------------------------------------------------------------------------ Effective income tax rate 34. 1% 32.3% 32.5% State income taxes, net of federal benefit (2.9) (1.9) (3.1) Investment tax credit amortization 1.1 1.4 1.9 Progress Energy tax benefit allocation 3.0 3.0 5.0 AFUDC amortization (0.5) (1.5) (5.8) Other differences, net 0.2 1.7 4.5 - ------------------------------------------------------------------------------ Statutory federal income tax rate 35.0% 35.0% 35.0% - ------------------------------------------------------------------------------ 165 Income tax expense (benefit) applicable to continuing operations is comprised of: - ----------------------------------------------------------------------------- (in millions) 2004 2003 2002 - ----------------------------------------------------------------------------- Income tax expense (credit): Current - federal $ 232 $ 283 $ 265 state 33 37 36 Deferred - federal (18) (56) (76) state (1) (13) (6) Investment tax credit (7) (10) (12) - ----------------------------------------------------------------------------- Total income tax expense $ 239 $ 241 $ 207 - ----------------------------------------------------------------------------- PEC and each of its wholly owned subsidiaries have entered into a Tax Agreement with Progress Energy (See Note 1D). PEC's intercompany tax receivable was $62 million and $40 million at December 31, 2004 and 2003, respectively. 12. BENEFIT PLANS PEC and some of its subsidiaries have a noncontributory 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) 2004 2003 2002 2004 2003 2002 - -------------------------------------------------------------------------------------------------------- Service cost $ 24 $ 23 $ 19 $ 6 $ 7 $ 6 Interest cost 52 51 51 15 15 14 Expected return on plan assets (69) (70) (73) (4) (3) (3) Amortization, net 1 - 1 3 5 2 - -------------------------------------------------------------------------------------------------------- Net periodic cost / (benefit) $ 8 $ 4 $ (2) $ 20 $ 24 $ 19 - --------------------------------------------------------------------------------------------------------
Net periodic cost for other postretirement benefits decreased during 2004 due to the implementation of FASB Staff Position 106-2 (See Note 2). 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. 166 Reconciliations of the changes in the plans' benefit obligations and the plans' funded status are: - ------------------------------------------------------------------------- --------------------------------- Pension Benefits Other Postretirement Benefits ------------------------- ------------------------------- (in millions) 2004 2003 2004 2003 - ----------------------------------------------------------------------------------------------------------- Obligation at January 1 $ 837 $ 802 $ 218 $ 234 Service cost 24 23 6 7 Interest cost 52 51 15 15 Plan amendment 14 - - - Benefit payments (50) (46) (5) (8) Actuarial loss (gain) 51 7 28 (30) - ----------------------------------------------------------------------------------------------------------- Obligation at December 31 928 837 262 218 Fair value of plan assets at December 31 753 694 45 43 - ----------------------------------------------------------------------------------------------------------- Funded status (175) (143) (217) (175) Unrecognized transition obligation - - 9 23 Unrecognized prior service cost 18 4 - - Unrecognized net actuarial (gain) loss 181 150 36 (1) Minimum pension liability adjustment (194) (2) - - - ----------------------------------------------------------------------------------------------------------- Prepaid (accrued) cost at December 31, net $ (170) $ 9 $ (172) $ (153) - -----------------------------------------------------------------------------------------------------------
The 2003 OPEB obligation information above has been restated due to the implementation of FASB Staff Position 106-2 (See Note 2). The net accrued pension cost of $170 million at December 31, 2004, is included in accrued pension and other benefits in the Consolidated Balance Sheets. The net prepaid pension cost of $9 million at December 31, 2003, is recognized in the 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 accrued pension and other benefits. The defined benefit pension plans with accumulated benefit obligations in excess of plan assets had projected benefit obligations totaling $928 million and $22 million at December 31, 2004 and 2003, respectively. Those plans had accumulated benefit obligations totaling $923 million and $19 million, at December 31, 2004 and 2003, respectively, plan assets of $753 million at December 31, 2004 and no plan assets at December 31, 2003. The total accumulated benefit obligation for pension plans was $923 million and $834 million at December 31, 2004 and 2003, respectively. The accrued OPEB cost is included in accrued pension and other benefits in the Consolidated Balance Sheets. A minimum pension liability adjustment of $194 million was recorded at December 31, 2004. This adjustment resulted in a charge of $18 million to intangible assets, included in other assets and deferred debits, and a pre-tax charge of $176 million to accumulated other comprehensive loss, a component of common stock equity. A minimum pension liability adjustment of $2 million was recorded at December 31, 2003. This adjustment was offset by a corresponding pre-tax charge 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) 2004 2003 2004 2003 - -------------------------------------------------------------------------------------------- Fair value of plan assets January 1 $ 693 $ 574 $ 43 $ 33 Actual return on plan assets 89 165 5 10 Benefit payments (50) (46) (5) (8) Employer contributions 21 1 2 8 - -------------------------------------------------------------------------------------------- Fair value of plan assets at December 31 $ 753 $ 694 $ 45 $ 43 - --------------------------------------------------------------------------------------------
In the table above, substantially all employer contributions represent benefit payments made directly from PEC assets except for the 2004 pension amount. The remaining benefits payments were made directly from plan assets. In 2004, PEC made a contribution directly to pension plan assets of approximately $20 million, which represented its allocated share of a required Progress Energy contribution. The OPEB benefit payments represent the net PEC cost after participant contributions. Participant contributions represent approximately 40% of gross benefit payments. 167 The asset allocation for PEC's plans at the end of 2004 and 2003 and the target allocation for the plans, by asset category, are as follows: - ---------------------------------------------------------------------------------------------------- Pension Benefits Other Postretirement Benefits ------------------------------------ --------------------------------- Target Percentage of Plan Target Percentage of Plan Allocations Assets at Year End Allocations Assets at Year End ------------- -------------------- ----------- ------------------ Asset Category 2005 2004 2003 2005 2004 2003 - ---------------------------------------------------------------------------------------------------- Equity - domestic 48% 47% 49% 48% 47% 49% Equity - international 15% 21% 22% 15% 21% 22% Debt - domestic 12% 9% 11% 12% 9% 11% Debt - international 10% 11% 11% 10% 11% 11% Other 15% 12% 7% 15% 12% 7% - ---------------------------------------------------------------------------------------------------- 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 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 2005, PEC expects to make no contributions directly to pension plan assets. The expected benefit payments for the pension benefit plan for 2005 through 2009 and in total for 2010-2014, in millions, are approximately $59, $57, $58, $62, $64 and $375, respectively. The expected benefit payments for the OPEB plan for 2005 through 2009 and in total for 2010-2014, in millions, are approximately $14, $15, $16, $16, $17, and $98, 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. PEC expects to begin receiving prescription drug-related federal subsidies in 2006 (See Note 2), and the expected subsidies for 2006 through 2009 and in total for 2010-2014, in millions, are approximately $1, $1, $1, $2 and $10, respectively. The expected benefit payments above do not reflect the potential effects of the 2005 voluntary enhanced retirement program (See Note 18). The following weighted-average actuarial assumptions were used in the calculation of the year-end obligation: - ------------------------------------------------------------------------------------------------------------------- Pension Benefits Other Postretirement Benefits ---------------- ----------------------------- 2004 2003 2004 2003 - ------------------------------------------------------------------------------------------------------------------- Discount rate 5.90% 6.30% 5.90% 6.30% Rate of increase in future compensation - supplementary plan 5.25% 5.00% - - Initial medical cost trend rate for pre-Medicare benefits - - 7.25% 7.25% Initial medical cost trend rate for post-Medicare benefits - - 7.25% 7.25% Ultimate medical cost trend rate - - 5.00% 5.25% Year ultimate medical cost trend rate is achieved - - 2008 2009 - --------------------------------------------------------------------------------------------------- ---------------
PEC's primary defined benefit retirement plan for nonbargaining 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. 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. 168 The following weighted-average actuarial assumptions were used in the calculation of the net periodic cost: - ------------------------------------------------------------------------------------------------------------------------- Pension Benefits Other Postretirement Benefits ------------------------- ------------------------------- 2004 2003 2002 2004 2003 2002 - -------------------------------------------------------------------------------------------------- --------- ------------ Discount rate 6.30% 6.60% 7.50% 6.30% 6.60% 7.50% Rate of increase in future compensation - nonbargaining - 4.00% 4.00% - - - Rate of increase in future compensation - supplementary plan 5.00% 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% - -------------------------------------------------------------------------------------------------- --------- ------------
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 9.0% and 9.5%. PEC has chosen to use an expected long-term rate of 9.25%. 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 2004 would increase by $1 million, and the OPEB obligation at December 31, 2004, would increase by $14 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 2004 would decrease by $1 million and the OPEB obligation at December 31, 2004, would decrease by $13 million. 13. 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 nonperformance by counterparties is not expected to have a material effect on the consolidated financial position or consolidated results of operations of PEC. A. Commodity Derivatives GENERAL Most of PEC'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 PEC. 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 original liability of $38 million associated with the fair value loss is being amortized to earnings over the term of the related contract. At December 31, 2004 and 2003, the remaining liability was $26 million and $35 million, respectively. ECONOMIC DERIVATIVES Derivative products, primarily electricity and natural gas contracts, are entered into 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 to results of operations during 2004, 2003 or 2002, and PEC did not have material outstanding positions in such contracts at December 31, 2004 or 2003. 169 CASH FLOW HEDGES PEC 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. As of December 31, 2004, PEC had $110 million notional amount of pay-fixed forward swaps to hedge its exposure to interest rates with regard to future issuances of debt (pre-issue hedges) and $21 million notional amount of pay-fixed forward starting swaps to hedge its exposure to interest rates with regard to an upcoming railcar lease. On February 4, 2005, PEC entered another $50 million notional amount of its pre-issue hedges. All the swaps have a computational period of ten years. These hedges had a fair value liability position of $2 million at December 31, 2004. PEC had no open cash flow hedges at December 31, 2003. The ineffective portion of interest rate cash flow hedges was not material to PEC's results of operations in 2004. As of December 31, 2004, PEC had $7 million of after-tax deferred losses in accumulated other comprehensive income (OCI), including amounts related to terminated hedges, of which $1 million is expected to be reclassified to earnings within the next 12 months. Due to the volatility of interest rates, the value in OCI is subject to change prior to its reclassification into earnings. FAIR VALUE HEDGES PEC uses fair value hedging strategies to manage its exposure to fixed interest rates on long-term debt. At December 31, 2004 and 2003, 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. 14. RELATED PARTY TRANSACTIONS The Company's subsidiaries provide and receive services, at cost, to and from Progress Energy and its subsidiaries, in accordance with agreements approved by the U.S. Securities and Exchange Commission (SEC) pursuant to Section 13(b) of the PUHCA. Services include purchasing, human resources, accounting, legal, transmission and delivery support, engineering materials, contract support, loaned employees payroll costs, constructions management and other centralized administrative, management and support services. The costs of the services are billed on a direct-charge basis, whenever possible, and on allocation factors for general costs that cannot be directly attributed. Billings from affiliates are capitalized or expensed depending on the nature of the services rendered. Amounts receivable from and/or payable to affiliated companies for these services are included in receivables from affiliated companies and payables to affiliated companies on the Consolidated Balance Sheets. Progress Energy Service Company, LLC, (PESC) provides the majority of the affiliated services under the approved agreements. Service provided by PESC during 2004, 2003 and 2002 to PEC amounted to $209 million, $184 million and $198 million, respectively. Based on a standard review by the Office of Public Utility Regulation within the SEC the method for allocating certain PESC governance costs changed and retroactive reallocations for 2002 and 2001 charges were recorded in 2003. The net after-tax impact of the reallocation of costs was a reduction of expenses at PEC by $10 million. PEC and an affiliated utility also provide and receive services at cost. Services provided by PEC during 2004, 2003 and 2002 amount to $52 million, $35 million and $72 million, respectively. Services received by PEC during 2004, 2003 and 2002 amount to $16 million, $7 million and $16 million, respectively. To facilitate commercial transactions of Progress Energy's subsidiaries, Progress Energy and certain wholly owned subsidiaries enter into agreements providing future financial or performance assurances to third parties. As of December 31, 2004, Progress Energy's guarantees include $181 million to support nuclear decommissioning. PEC determined that its external funding levels did not fully meet the nuclear decommissioning financial assurance levels required by NRC, therefore PEC obtained parent company guarantees. The Company and PEC also purchased $43 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $4 million on behalf of PEC. 170 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 is also used to settle intercompany balances. The weighted-average interest rate for the money pool was 1.72%, 1.47% and 2.18% at December 31, 2004, 2003 and 2002, respectively. Amounts payable to the money pool are included in notes payable to affiliated companies on the Consolidated Balance Sheets. PEC recorded insignificant interest expense related to the money pool for all the years presented. 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 and 2002, gas sales from NCNG to PEC amounted to $11 million and $18 million, respectively. The gas sales for 2003 indicated above exclude any sales subsequent to September 2003. Strategic Resource Solutions, Corp. and its subsidiary, which were wholly owned until 2004, managed subcontracts for PEC. Amounts for the three years presented were not significant. PEC has entered into a Tax Agreement with Progress Energy (See Note 11). 15. 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. - ------------------------------------------------------------------------------------------------- (in millions) PEC Electric Other Total - ------------------------------------------------------------------------------------------------- Year Ended December 31, 2004 Revenues $ 3,628 $ 1 $ 3,629 Depreciation and amortization 570 - 570 Total interest charges, net 192 - 192 Income tax expense (benefit) 237 2 239 Income (loss) excluding cumulative effect 464 (6) 458 Total segment assets 10,590 197 10,787 Capital and investment expenditures 519 - 519 - ------------------------------------------------------------------------------------------------- Year Ended December 31, 2003 Revenues $ 3,589 $ 11 $ 3,600 Depreciation and amortization 562 1 563 Total interest charges, net 197 - 197 Impairment of long-lived assets & investments 11 10 21 Income tax expense (benefit) 238 3 241 Income (loss) excluding cumulative effect 515 (13) 502 Total segment assets 10,748 190 10,938 Capital and investment expenditures 445 1 446 - ------------------------------------------------------------------------------------------------- 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 tax expense (benefit) 237 (30) 207 Income (loss) excluding cumulative effect 513 (85) 428 Total segment assets 10,139 266 10,405 Capital and investment expenditures 619 12 631 - -------------------------------------------------------------------------------------------------
171 16. OTHER INCOME AND OTHER EXPENSE Other income and expense includes interest income, 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 years ended December 31, are as follows: - --------------------------------------------------------------------------------------- (in millions) 2004 2003 2002 - --------------------------------------------------------------------------------------- Other income Nonregulated energy and delivery services income $ 15 $ 12 $ 16 DIG Issue C20 amortization (Note 13A) 9 2 - AFUDC equity 4 2 6 Gain on sale of property 12 6 3 Other 2 - 16 - --------------------------------------------------------------------------------------- Total other income $ 42 $ 22 $ 41 - --------------------------------------------------------------------------------------- Other expense Nonregulated energy and delivery services expenses $ 9 $ 9 $ 14 Donations 7 6 7 Losses from Equity Investments 1 16 7 Other 14 2 - - --------------------------------------------------------------------------------------- Total other expense $ 31 $ 33 $ 28 - --------------------------------------------------------------------------------------- Other, net 11 (11) 13 - ---------------------------------------------------------------------------------------
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. 17. ENVIRONMENTAL MATTERS PEC 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 The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liabilities. Some states, including North and South Carolina, have similar types of legislation. PEC is periodically notified by regulators including the EPA and various state agencies of their involvement or potential involvement in sites that may require investigation and/or remediation. There are presently several sites with respect to which PEC has been notified by the EPA and the State of North Carolina of its potential liability, as described below in greater detail. PEC is also currently in the process of assessing potential costs and exposures at other sites. For all sites, assessments are developed and analyzed, PEC will accrue costs for the sites to the extent the costs are probable and can be reasonably estimated. 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). PEC has filed claims with its general liability insurance carriers to recover costs arising from actual or potential environmental liabilities. All claims have been settled other than with insolvent carriers. These settlements have not had a material effect on the consolidated financial position or results of operations. 172 ENVIRONMENTAL LIABILITIES There are nine former MGP sites and a number of other sites associated with PEC that have required or are anticipated to require investigation and/or remediation costs. During the fourth quarter of 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site located in Raleigh, North Carolina. The EPA offered PEC and 34 other PRPs the opportunity to negotiate cleanup of the site and reimbursement of less than $2 million to the EPA for EPA's past expenditures in addressing conditions at the site. Although a loss is considered probable, an agreement among PRPs has not been reached; consequently, it is not possible at this time to reasonably estimate the total amount of PEC's obligation for remediation of the Ward Transformer site. At December 31, 2004 and 2003, PEC's accruals for probable and estimable costs related to various environmental sites, which are included in other liabilities and deferred credits and are expected to be paid out over many years, were: - ----------------------------------------------------------------------- (in millions) 2004 2003 - ----------------------------------------------------------------------- Insurance fund $ 7 $ 9 Transferred from NCNG at time of sale 2 2 - ----------------------------------------------------------------------- Total accrual for environmental sites $ 9 $ 11 - ----------------------------------------------------------------------- PEC received insurance proceeds to address costs associated with environmental liabilities related to its involvement with some sites. All eligible expenses related to these are charged against a specific fund containing these proceeds. PEC spent approximately $2 million related to environmental remediation in 2004. PEC is unable to 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. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet reached the stage where a reasonable estimate of the remediation costs can be made, PEC cannot determine the total costs that may be incurred in connection with the remediation of all sites at this time. It is anticipated that sufficient information will become available for several sites during 2005 to allow a reasonable estimate of PEC's obligation for those sites to be made. AIR QUALITY Congress is considering legislation that would require reductions in air emissions of 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 PEC's consolidated financial position or results of operations. Control equipment that will be installed on North Carolina fossil generating facilities as part of the NC Clean Air legislation discussed below may address some of the issues outlined above. However, PEC 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 changes 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 supplying 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, in excess of $1.0 billion. 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 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 the Federal Appeals Court and its implementation stayed. In July 2004, the EPA announced it will reconsider certain issues arising from the final routine equipment replacement rule. The comment period closed on August 30, 2004. PEC cannot predict the outcome of this matter. 173 In 1998, the EPA published a final rule under Section 110 of the Clean Air Act addressing the regional transport of ozone (NOx SIP Call). Total capital expenditures to meet the requirements of the NOx SIP Call Rule in North and South Carolina could reach approximately $370 million. PEC has spent approximately $282 million to date related to these projected amounts. 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. In 1997, the EPA issued final regulations establishing a new 8-hour ozone standard. In April 2004, the EPA identified areas that do not meet the standard. The states with identified areas, including North and South Carolina, are proceeding with the implementation of the federal 8-hour ozone standard. Both states promulgated final regulations, which will require PEC to install NOx controls under the states' programs to comply with the 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 requirements for additional controls at some units. PEC cannot predict the outcome of this matter. In June 2002, the NC Clean Air 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 projects that its capital costs to meet these emission targets will total approximately $895 million by the end of 2013. PEC has expended approximately $108 million of these capital costs through December 31, 2004. PEC currently has approximately 5,100 MW of coal-fired generation capacity in North Carolina that is affected by this Act. The law 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 law 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. The law requires PEC to amortize $569 million, representing 70% of the original cost estimate of $813 million, during the five-year rate freeze period. PEC recognized amortization of $174 million and $74 million for the years ended December 31, 2004, and 2003, respectively, and has recognized $248 million in cumulative amortization through December 31, 2004. The remaining amortization requirement of $321 million will be recorded over the three-year period ending December 31, 2007. The law permits PEC the flexibility to vary the amortization schedule for recording of the compliance costs from none up to $174 million per year. The NCUC will hold a hearing prior to December 31, 2007, to determine cost recovery amounts for 2008 and future periods. Pursuant to the law, PEC entered into an agreement with the State of North Carolina to transfer to the State certain NOx and SO2 emissions allowances that result from compliance with the collective NOx and SO2 emissions limitations set out in the law. 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 concluded that mercury is not a risk to the average person in America 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 alternative control plans that would limit mercury emissions from coal-fired power plants. The final rule was released on March 15, 2005. The EPA's rule establishes a mercury cap and trade program for coal-fired power plants that requires limits to be met in two phases, in 2010 and 2018. PEC is reviewing the final rule. Installation of additional air quality controls is likely to be needed to meet the mercury rule's requirements. Compliance plans and the cost to comply with the rule will be determined once PEC completes its review. 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. PEC does not have units impacted by this proposal. The EPA expects to finalize the nickel rule in March 2005. In December 2003, the EPA released its proposed Interstate Air Quality Rule, currently referred to as the Clean Air Interstate Rule (CAIR). The final rule was released on March 10, 2005. The EPA's rule requires 28 states and the District of Columbia, including North Carolina and South Carolina, to reduce NOx and SO2 emissions in order to attain preset state NOx and SO2 emissions levels. PEC is reviewing the final rule. Installation 174 of additional air quality controls is likely to be needed to meet the CAIR requirements. Compliance plans and the cost to comply with the rule will be determined once PEC completes its review. The air quality controls already installed for compliance with the NOx SIP Call and currently planned by PEC to comply with the NC Clean Air legislation will reduce the costs required to meet the CAIR requirements for PEC's North Carolina units. In March 2004, the North Carolina Attorney General filed a petition with the EPA under Section 126 of the Clean Air Act, asking the federal government to force coal-fired power plants in 13 other states, including South Carolina to reduce their NOx and SO2 emissions. The state of North Carolina contends these out-of-state emissions interfere with North Carolina's ability to meet national air quality standards for ozone and particulate matter. The EPA has agreed to make a determination on the petition by August 1, 2005. PEC 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 at the affected facilities. Integration of these new wastewater streams into the existing wastewater treatment processes may result in permitting, construction and treatment requirements imposed on PEC in the immediate and extended future. After many years of litigation and settlement negotiations, the EPA adopted regulations in February 2004 to implement Section 316(b) of the Clean Water Act. These regulations became effective September 7, 2004. 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. PEC currently estimates that from 2005 through 2009 the range of its expenditures to meet the Section 316(b) requirements of the Clean Water Act will be $20 million to $30 million. 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. In 2004, Russia ratified the Protocol, and the treaty went into effect on February 16, 2005. The United States has not adopted the Kyoto Protocol, and the Bush administration has stated it favors voluntary programs. A number of carbon dioxide emissions control proposals have been advanced in Congress. 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 of control or limitation cannot be recovered from customers. PEC favors the voluntary program approach recommended by the administration and continually evaluates options for the reduction, avoidance and sequestration of greenhouse gases. However, PEC cannot predict the outcome of this matter. Progress Energy has announced its plan to issue a report on it's activities associated with current and future environmental requirements. The report will include a discussion of the environmental requirements that the PEC currently faces and expects to face in the future, as well as an assessment of potential mandatory constraints on carbon dioxide emissions. The report will be issued by March 31, 2006. 18. COMMITMENTS AND CONTINGENCIES A. Purchase Obligations The following table reflects PEC's contractual cash obligations and other commercial commitments at December 31, 2004, in the respective periods in which they are due. - ---------------------------------------------------------------------------------------- (in millions) 2005 2006 2007 2008 2009 Thereafter - ---------------------------------------------------------------------------------------- Fuel $ 649 $ 450 $ 393 $ 126 $ 135 $ 586 Purchased power 137 130 125 84 86 526 Other Purchase Obligations 12 - - - - 13 - ---------------------------------------------------------------------------------------- Total $ 798 $ 580 $ 518 $ 210 $ 221 $ 1,125 - ----------------------------------------------------------------------------------------
175 FUEL AND PURCHASED POWER PEC has entered into various long-term fuel contracts for coal, oil and gas requirements of its generating plants. Total payments under these commitments were $477 million, $562 million and $524 million in 2004, 2003 and 2002, respectively. 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 and energy costs, total approximately $38 million. These contractual purchases totaled $39 million, $36 million and $36 million for 2004, 2003 and 2002, 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, 2004, 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 estimated minimum annual payments of approximately $43 million, representing capital-related capacity costs. Estimated annual payments for energy and capacity costs are approximately $72 million through 2009. Total purchases (including energy and transmission use charges) under the Rockport agreement amounted to $63 million, $66 million and $59 million for 2004, 2003 and 2002, respectively. PEC executed two long-term agreements for the purchase of power from Broad River LLC's Broad River facility. One 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. The second 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 for both capacity and energy under the Broad River agreements amounted to $42 million, $37 million and $38 million in 2004, 2003 and 2002 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 2012. 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 $91 million, $113 million and $145 million in 2004, 2003 and 2002, respectively. CONSTRUCTION OBLIGATIONS At December 31, 2004, PEC has no construction obligations. Total purchases under various combustion turbine construction obligations were $5 million, $21 million and $13 million for 2004, 2003 and 2002, respectively. 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. During 2004 and 2003, no capital parts have been purchased under this contract. PEC has various purchase obligations related to reactor vessel head replacements, power uprates and spent fuel storages. Total purchases under these contracts were $17 million for 2004 and $3 million for 2003. Future purchase obligations are $12 million for 2005. PEC incurred expenses related to various other purchase obligations allocated from PESC of $8 million for 2004 and 2003 and $4 million for 2002. 176 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 $20 million for 2004 and 2003 and $22 million for 2002. These amounts include rent expense allocated from PESC of $11 million, $10 million and $12 million for 2004, 2003 and 2002, respectively. Purchased power expense under agreements classified as operating leases were approximately $24 million during 2004 and $5 million during 2003. Assets recorded under capital leases consist of: - ----------------------------------------------------------------- (in millions) 2004 2003 - ----------------------------------------------------------------- Buildings $ 30 $ 30 Less: Accumulated amortization (11) (10) - ----------------------------------------------------------------- $ 19 $ 20 - ----------------------------------------------------------------- Minimum annual payments, excluding executory costs such as property taxes, insurance and maintenance, under long-term noncancelable leases at December 31, 2004, are: - ------------------------------------------------------------------------------------ (in millions) Capital Leases Operating Leases - ------------------------------------------------------------------------------------ 2005 $ 2 $ 28 2006 2 24 2007 2 13 2008 2 13 2009 2 12 Thereafter 25 97 - ------------------------------------------------------------------------------------ $ 35 $ 187 ----------------- Less amount representing imputed interest (16) - ------------------------------------------------------------------- Present value of net minimum lease payments $ 19 - ------------------------------------------------------------------------------------
PEC is the lessor of electric poles, streetlights and other facilities. Minimum rentals receivables under noncancelable leases are $9 million for 2005 and none thereafter. Rents received totaled $32 million, $31 million and $28 million for 2004, 2003 and 2002, respectively. C. Claims and Uncertainties OTHER CONTINGENCIES 1. Pursuant to the Nuclear Waste Policy Act of 1982, the predecessors to PEC entered into contracts with the U.S. Department of Energy (DOE) under which the DOE agreed to begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract. DOE failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004, PEC filed a complaint in the United States Court of Federal Claims against the DOE, claiming that the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel (SNF) by failing to accept SNF from various PEC facilities on or before January 31, 1998. Damages due to DOE's breach will likely exceed $100 million. Approximately 60 cases involving the Government's actions in connection with spent nuclear fuel are currently pending in the Court of Federal Claims. DOE and the PEC parties have agreed to a stay of the lawsuit, including discovery. The parties agreed to, and the trial court entered, a stay of proceedings, in order to allow for possible efficiencies due to the resolution of legal and factual issues in previously filed cases in which similar claims are being pursued by other plaintiffs. These issues may include, among others, so-called "rate issues," or the minimum mandatory schedule for the acceptance of SNF and high level waste (HLW) by which the Government was contractually obligated to accept contract holders' SNF and/or HLW, and issues regarding recovery of damages under a partial breach of contract theory that will be alleged to occur in the future. These issues have been or are expected to be presented in the trials that are currently scheduled to occur during 2005. Resolution of these issues in other cases could facilitate agreements by the parties in the PEC lawsuit, or at a minimum, inform the Court of decisions reached by other courts if they remain contested and require resolution in this case. The trial court has continued this stay until June 24, 2005. With certain modifications and additional approval by the NRC, including the installation of onsite dry storage facilities at Robinson and Brunswick, 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 operating licenses for all of PEC's nuclear generating units. 177 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. In January 2003, the State of Nevada, Clark County, Nevada, and the City of Las Vegas petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of the Congressional override resolution. These same parties also challenged EPA's radiation standards for Yucca Mountain. On July 9, 2004, the Court rejected the challenge to the constitutionality of the resolution approving Yucca Mountain, but ruled that the EPA was wrong to set a 10,000-year compliance period in the radiation protection standard. EPA is currently reworking the standard but has not stated when the work will be complete. DOE originally planned to submit a license application to the NRC to construct the Yucca Mountain facility by the end of 2004. However, in November 2004, DOE announced it would not submit the license application until mid-2005 or later. Also in November 2004, Congressional negotiators approved $577 million for fiscal year 2005 for the Yucca Mountain project, approximately $300 million less than requested by DOE but approximately the same as approved in 2004. The DOE continues to state it plans to begin operation of the repository at Yucca Mountain in 2010. PEC cannot predict the outcome of this matter. 2. In 2001, PEC entered into a contract to purchase coal from Dynegy Marketing and Trade (DMT). After DMT experienced financial difficulties, including credit ratings downgrades by certain credit reporting agencies, PEC requested credit enhancements in accordance with the terms of the coal purchase agreement in July 2002. When DMT did not offer credit enhancements, as required by a provision in the contract, PEC terminated the contract in July 2002. PEC initiated a lawsuit seeking a declaratory judgment that the termination was lawful. DMT counterclaimed, stating the termination was a breach of contract and an unfair and deceptive trade practice. On March 23, 2004, the United States District Court for the Eastern District of North Carolina ruled that PEC was liable for breach of contract, but ruled against DMT on its unfair and deceptive trade practices claim. On April 6, 2004, the Court entered a judgment against PEC in the amount of approximately $10 million. The Court did not rule on DMT's request under the contract for pending legal costs. On May 4, 2004, PEC authorized its outside counsel to file a notice of appeal of the April 6, 2004, judgment and on May 7, 2004, the notice of appeal was filed with the United States Court of Appeals for the Fourth Circuit. On June 8, 2004, DMT filed a motion to dismiss the appeal on the ground that PEC's notice of appeal should have been filed on or before May 6, 2004. On June 16, 2004, PEC filed a motion with the trial court requesting an extension of the deadline for the filing of the notice of appeal. By order dated September 10, 2004, the trial court denied the extension request. On September 15, 2004, PEC filed a notice of appeal of the September 10, 2004, order and by order dated September 29, 2004, the appellate court consolidated the first and second appeals. DMT's motion to dismiss the first appeal remains pending. The consolidated appeal has been fully briefed, and the court of appeals has indicated that it will hear arguments, which tentatively have been scheduled for the week of May 23, 2005. PEC recorded a liability for the judgment of approximately $10 million and a regulatory asset for the probable recovery through its fuel adjustment clause in the first quarter of 2004. PEC cannot predict the outcome of this matter. 3. On February 1, 2002, PEC filed a complaint with the Surface Transportation Board (STB) challenging the rates charged by Norfolk Southern Railway Company (Norfolk Southern) for coal transportation to certain generating plants. In a decision dated December 23, 2003, the STB found that the rates were unreasonable, awarded reparations and prescribed maximum rates. Both parties petitioned the STB for reconsideration of the December 23, 2003 decision. On October 20, 2004, the STB reconsidered its December 23, 2003 decision and concluded that the rates charged by Norfolk Southern were not unreasonable. Because PEC paid the maximum rates prescribed by the STB in its December 23, 2003 decision for several months during 2004, which were less than the rates ultimately found to be reasonable, the STB ordered PEC to pay to Norfolk Southern the difference between the rate levels plus interest. 178 PEC subsequently filed a petition with the STB to phase in the new rates over a period of time, and filed a notice of appeal with the U.S. Court of Appeals for the D.C. Circuit. Pursuant to an order issued by the STB on January 6, 2005, the phasing proceeding will proceed on a schedule that appears likely to produce an STB decision before the end of 2005. On January 12, 2005, the STB filed a Motion to Dismiss PEC's appeal on the grounds that its October 20, 2004, order is not "final" until PEC's phasing application has been decided. As of December 31, 2004, PEC has accrued a liability of $42 million, of which $23 million represents reparations previously remitted to PEC by Norfolk Southern that are now subject to refund. Of the remaining $19 million, $17 million has been recorded as deferred fuel cost on the Consolidated Balance Sheet while the remaining $2 million attributable to wholesale customers has been charged to fuel used in electric generation on the Consolidated Statements of Income. PEC cannot predict the outcome of this matter. 4. PEC and its subsidiaries are involved in various litigation matters in the ordinary course of business, some of which involve substantial amounts. Where appropriate, accruals have been made in accordance with SFAS No. 5, "Accounting for Contingencies," to provide for such matters. In the opinion of management, the final disposition of pending litigation would not have a material adverse effect on PEC's consolidated results of operations or financial position. 19. SUBSEQUENT EVENT Cost Management Initiative On February 28, 2005, as part of a previously announced cost management initiative, the executive officers of Progress Energy approved a workforce restructuring. The restructuring is expected to be completed in September of 2005. In addition to the workforce restructuring, the cost management initiative includes a voluntary enhanced retirement program. In connection with the cost management initiative, PEC expects to incur one-time pre-tax charges of approximately $55 million. Approximately $10 million of that amount relates to payments for severance benefits, and will be recognized in the first quarter of 2005 and paid over time. The remaining approximately $45 million will be recognized in the second quarter of 2005 and relates primarily to postretirement benefits that will be paid over time to those eligible employees who elect to participate in the voluntary enhanced retirement program. The total cost management initiative charges could change significantly depending upon how many eligible employees elect early retirement under the voluntary enhanced retirement program and the salary, service years and age of such employees. 20. CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized quarterly financial data is as follows: - ---------------------------------------------------------------------------------------------------------------- (in millions) First Quarter Second Quarter Third Quarter Fourth Quarter - ---------------------------------------------------------------------------------------------------------------- Year ended December 31, 2004 Operating revenues $ 901 $ 862 $ 1,014 $ 852 Operating income 236 191 317 133 Income before cumulative effect of change in accounting principles 115 96 175 75 Net income 115 96 175 75 - ---------------------------------------------------------------------------------------------------------------- Year ended December 31, 2003 Operating revenues $ 929 $ 819 $ 1,012 $ 840 Operating income 256 184 295 234 Income before cumulative effect of change in accounting principles 135 89 158 123 Net income 135 89 158 100 - ----------------------------------------------------------------------------------------------------------------
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. Fourth quarter 2004 includes approximately $99 million ($59 million after-tax) more NC Clean Air legislation amortization than the other quarters presented. Fourth quarter 2004 also includes a reduction in depreciation expense of $63 million ($38 million after-tax) resulting from a revised depreciation study due to extended lives at each of PEC's nuclear units (See Note 4A). Fourth quarter 2003 includes impairment charges related to certain investments of $21 million ($13 million after-tax) (See Note 7). Fourth quarter 2003 includes the impact of a cumulative effect for DIG Issue C20 of $38 million ($23 million after-tax) (See Note 13). 179 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.: We have audited the consolidated financial statements of Progress Energy, Inc., and its subsidiaries (the Company) as of December 31, 2004 and 2003, and for each of the three years in the period ended December 31, 2004, management's assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, and the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, and have issued our reports thereon dated March 7, 2005 (which reports express an unqualified opinion and include an explanatory paragraph concerning the adoption of new accounting principles in 2003); such reports are included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedule of the Company listed in Item 15. 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 consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. /s/ Deloitte & Touche LLP Raleigh, North Carolina March 7, 2005 180 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM TO THE BOARD OF DIRECTORS AND SHAREHOLDER OF CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.: We have audited the consolidated financial statements of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc., and its subsidiaries (PEC) as of December 31, 2004 and 2003, and for each of the three years in the period ended December 31, 2004, and have issued our report thereon dated March 7, 2005 (which expresses an unqualified opinion and includes an explanatory paragraph concerning the adoption of new accounting principles in 2003); such report is included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedule of PEC listed in Item 15. This 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 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 March 7, 2004 181 PROGRESS ENERGY, INC. Schedule II - Valuation and Qualifying Accounts For the Years Ended (in millions) - ----------------------------------------------------------------------------------------------------------------------- Balance at Additions Balance at Beginning Charged to Other End of Description of Period Expenses Additions Deductions (a) Period - ----------------------------------------------------------------------------------------------------------------------- Valuation and qualifying accounts deducted in the balance sheet from the related assets: DECEMBER 31, 2004 Uncollectible accounts $ 32 $ 17 $ (4) $ (16) $ 29 Fossil dismantlement reserve 143 1 - - 144 Nuclear refueling outage reserve 2 10 - - 12 DECEMBER 31, 2003 Uncollectible accounts $ 39 $ 24 $ 4 $ (35) $ 32 Fossil dismantlement reserve 142 1 - - 143 Nuclear refueling outage reserve 10 8 - (16) (b) 2 DECEMBER 31, 2002 Uncollectible accounts $ 39 $ 22 $ - $ (22) $ 39 Fossil dismantlement reserve 141 1 - - 142 Nuclear refueling outage reserve - 10 - - 10 - ----------------------------------------------------------------------------------------------------------------------- (a) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for uncollectible accounts, such deductions are reduced by recoveries of amounts previously written off. (b) Represents payments of actual expenditures related to the outages. - -----------------------------------------------------------------------------------------------------------------------
182 CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS Schedule II - Valuation and Qualifying Accounts For the Years Ended (in millions) - ----------------------------------------------------------------------------------------------------------------------- Balance at Additions Balance at Beginning Charged to Other End of Description of Period Expense Additions Deductions (a) Period - ----------------------------------------------------------------------------------------------------------------------- Valuation and qualifying accounts deducted in the balance sheet from the related assets: December 31, 2004 Uncollectible accounts $ 17 $ 7 $ (4) $ (10) $ 10 December 31, 2003 Uncollectible accounts $ 12 $ 12 $ 4 $ (11) $ 17 December 31, 2002 Uncollectible accounts $ 14 $ 8 $ - $ (10) $ 12 - ----------------------------------------------------------------------------------------------------------------------- (a) Deductions from provisions represent losses or expenses for which the respective provisions were created. In the case of the provision for uncollectible accounts, such deductions are reduced by recoveries of amounts previously written off. - -----------------------------------------------------------------------------------------------------------------------
183 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None ITEM 9A. CONTROLS AND PROCEDURES Progress Energy, Inc. DISCLOSURE CONTROLS AND PROCEDURES 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 to ensure that information required to be disclosed by Progress Energy in the reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to Progress Energy's management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING It is the responsibility of Progress Energy's management to establish and maintain adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15(d)-15(f) of the Securities Exchange Act of 1934, as amended. Progress Energy's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America. Internal control over financial reporting includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of Progress Energy; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles in the United States of America; (3) provide reasonable assurance that receipts and expenditures of Progress Energy are being made only in accordance with authorizations of management and directors of Progress Energy; and (4) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Progress Energy's assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Management assessed the effectiveness of Progress Energy's internal control over financial reporting as of December 31, 2004. Management based this assessment on criteria for effective internal control over financial reporting described in "Internal Control - Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management's assessment included an evaluation of the design of Progress Energy's internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of the Board of Directors. Based on our assessment, management determined that, as of December 31, 2004, Progress Energy maintained effective internal control over financial reporting. Management's assessment of the effectiveness of Progress Energy's internal control over financial reporting as of December 31, 2004, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein in Item 9A Controls and procedures of this Annual Report on Form 10-K. 184 CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING. There has been no change in Progress Energy's internal control over financial reporting during the quarter ended December 31, 2004, that has materially affected, or is reasonably likely to materially affect its internal control over financial reporting. The Company notes, however, that as part of the Company's review of internal controls for compliance with Section 404 of the Sarbanes-Oxley Act, the Company will be implementing changes related to capitalization practices for its Energy Delivery business units in PEC and PEF effective January 1, 2005. A review of these practices indicated that in the areas of outage and emergency work, not associated with major storm and allocation of indirect costs, both PEC and PEF should revise the way that they estimate the amount of capital costs associated with such work. The changes for 2005 in this area include use of more detailed accounts to segregate capital and expense items, more regular testing of accounting estimates and realignment of certain accounting functions. This matter is also discussed at Footnote 8F to the Progress Energy Consolidated Financial Statements. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC. We have audited management's assessment, included in the accompanying Management's Report on Internal Control Over Financial Reporting, that Progress Energy, Inc., and its subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions. A company's internal control over financial reporting is a process designed by, or under the supervision of, the Company's principal executive and principal financial officers, or persons performing similar functions, and effected by the Company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements. Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 185 In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2004, of the Company and our report dated March 7, 2005, expressed an unqualified opinion on those consolidated financial statements. /s/ Deloitte & Touche LLP Raleigh, North Carolina March 7, 2005 Progress Energy Carolinas, Inc. Pursuant to 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 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 to ensure that information required to be disclosed by PEC in the reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to PEC's management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in PEC's internal control over financial reporting during the quarter ended December 31, 2004, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting. As noted above, PEC will be implementing changes related to capitalization practices for its Energy Delivery business unit effective January 1, 2005. A review of these practices indicated that in the areas of outage and emergency work, not associated with major storm and allocation of indirect costs, PEC should revise the way that it estimates the amount of capital costs associated with such work. The changes for 2005 in this area include use of more detailed accounts to segregate capital and expense items, more regular testing of accounting estimates and realignment of certain accounting functions. This matter is also discussed in Note 6E to the PEC Consolidated Financial Statements. ITEM 9B. OTHER INFORMATION In March 2005, Progress Energy, Inc.'s 5-year credit facility was amended to increase the maximum total debt to total capital ratio from 65% to 68% in anticipation of the potential impacts of proposed accounting rules for uncertain tax positions. 186 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 2004 definitive proxy statement dated March 31, 2005, and incorporated by reference herein. Information on PEC's directors is set forth in the PEC 2004 definitive proxy statement dated March 31, 2005, 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 Web site 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 Web site, 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 Web site and in print at no cost: 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 2004 definitive proxy statement dated March 31, 2005, and incorporated by reference herein. Information on PEC's executive compensation is set forth in the PEC 2004 definitive proxy statement dated March 31, 2005, 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 2004 definitive proxy statement, dated March 31, 2005, and incorporated herein by reference. Information regarding any person PEC knows to be the beneficial owner of more than 5% of any class of its voting securities is set forth in its 2004 definitive proxy statement, dated March 31, 2005, and incorporated herein by reference. 187 b) Information on security ownership of the Progress Energy's and PEC's management is set forth in the Progress Energy and PEC 2004 definitive proxy statements dated March 31, 2005, and incorporated by reference herein. c) Information on the equity compensation plans of Progress Energy is set forth under the heading "Equity Compensation Plan Information" in the Progress Energy 2004 definitive proxy statement dated March 31, 2005, 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 2004 definitive proxy statements dated March 31, 2005, 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 2004 definitive proxy statements dated March 31, 2005, and incorporated by reference herein. 188 PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES 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 189 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. Most of the business information as well as the financial and operational data contained in our risk factors are updated periodically in the reports we file with the SEC. 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, financial condition and 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 subject to regulatory oversight with respect to, among other things, rates and service for electric energy sold at retail, retail service territory and issuances of securities. In addition our operating utilities are subject to regulation with respect to transmission and sales of wholesale power, accounting and certain other matters. We are also 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 2004 working on a comprehensive energy bill. While that legislation passed the House, the Senate failed to pass the legislation in 2004. There will probably be an effort to resurrect the legislation in 2005. 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 the Public Utility Holding Company Act of 1935 ("PUHCA"). The Company cannot predict the outcome or impact of the proposed or any future energy bill. 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 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, financial condition and results of operations. 190 We are subject to numerous environmental laws and regulations that require significant capital expenditures, increase our cost of operations, and which may 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. 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. Our compliance with environmental regulations requires significant capital expenditures that impact our financial condition. For example, 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. We expect the capital costs required to meet these emission targets will total approximately $895 million by 2013. Over the next three years, we expect to incur approximately $510 million of total capital costs associated with this legislation. Congress currently considering further legislation that would require reductions in air emissions of 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 our consolidated financial position or results of operations. However, the Company cannot predict the outcome, costs or impact of this matter. In December 2003, the EPA released its proposed Interstate Air Quality Rule, currently referred to as the Clean Air Interstate Rule (CAIR). The EPA's proposal requires 29 jurisdictions, including North Carolina, South Carolina, Georgia and Florida, to reduce NOx and SO2 emissions in order to attain preset state NOx and SO2 emissions levels. The rule is expected to become final in March 2005. While the air quality controls already installed and currently planned for installation to comply with the NC Clean Air legislation will reduce the costs required to meet the CAIR requirements for the our North Carolina units, additional compliance costs will be determined once the rule is finalized. In March 2004, the North Carolina Attorney General filed a petition with the EPA under Section 126 of the Clean Air Act, asking the federal government to force coal-fired power plants in thirteen other states, including South Carolina to reduce their NOx and SO2 emissions. The state of North Carolina contends these out-of-state emissions interfere with North Carolina's ability to meet national air quality standards for ozone and particulate matter. The EPA has agreed to make a determination on the petition by August 1, 2005. The Company cannot predict the outcome or costs associated with the matter. See additional discussion of these environmental matters in Note 22 to the Progress Energy Consolidated Financial Statements. 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. 191 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 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). In its current form, SMD NOPR could materially alter the manner in which transmission and generation services are provided and paid for, and includes provisions for mandatory RTOs and the FERC's assertion of jurisdiction over certain aspects of retail service. The Company cannot predict the outcome or timing of any final rules or the effect that they may have on the GridSouth and GridFlorida proceedings currently ongoing before the FERC. At the state level, significant uncertainty exists with respect to what action, if any, the NCUC or FPSC will ultimately take. The Company has $33 million and $4 million invested in GridSouth and GridFlorida, respectively, related to startup costs at December 31, 2004. These amounts are included as a regulatory asset at December 31, 2004. The Company expects to recover these startup costs in conjunction with the GridSouth and GridFlorida original structures or in conjunction with any alternate combined transmission structures that may be required. 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. 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 they will be created, or whether they 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. 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 and market prices peak during the hot summer months. 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, 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. For example, during the third quarter of 2004, four hurricanes hit our service territories, resulting in storm costs of approximately $398 million. In addition, these storm costs reduced our projected 2004 regular federal income tax liability, and consequently, our ability to benefit from the tax credits generated from our synthetic fuel operations. 192 Our ability to recover significant costs resulting from severe weather events is subject to regulatory oversight and the timing and amount of any such recovery is uncertain and may impact our financial conditions. During the third quarter of 2004, four hurricanes struck significant portions of our service territories, most significantly impacting PEF's territory. The total estimated restoration cost of these storms is $398 million. PEC incurred restoration costs of $13 million, of which $12 million was charged to operation and maintenance expense and $1 million was charged to capital expenditures. PEF had estimated total costs of $385 million, of which $47 million was charged to capital expenditures, and $338 million was charged to the storm damage reserve pursuant to a regulatory order. Under a regulatory order, PEF maintains a storm damage reserve account for major storms. With respect to storm costs in excess of the storm damage reserve account, PEF may seek recover from retail ratepayers. On November 2, 2004, PEF filed a petition with the FPSC to recover $252 million of storm costs plus interest from retail ratepayers over a two-year period. Given that not all invoices have been received as of December 31, 2004, it is PEF's position that its petition presents a fair projection of total cost and does not need to be updated at this time. PEF will update its request upon receipt and audit of all actual charges incurred. Storm reserve costs of $13 million are attributable to wholesale customers and such costs may be amortized consistent with recovery of such amounts in wholesale rates. The timing of any FPSC decision and ultimate amount recovered is uncertain at this time. PEC is not required to maintain a storm damage reserve account and does not have an on-going regulatory mechanism to recover storm costs and; therefore, hurricane restoration costs recorded in the third quarter of 2004 were charged to operations and maintenance expenses or capital expenditures based on the nature of the work performed. In connection with other storms, PEC has previously sought and received permission from the NCUC and the SCPSC to defer storm expenses and amortize them over a five-year period. PEC did not seek recovery of 2004 storm costs from the NCUC. While we believe that we are legally entitled to recover these costs, if we cannot recover these costs, or costs associated with future significant weather events, in a timely manner, or in an amount sufficient to cover our actual costs, our financial conditions and results of operations could be materially and adversely impacted. Our revenues, operating results and financial condition may fluctuate with the economy and its corresponding impact on our commercial and industrial customers as well as the demand and competitive state of the wholesale market. Our business is impacted by fluctuations in the macroeconomy. For the year ended December 31, 2004, commercial and industrial customers represented approximately 37% of our total 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 recent years, in North and South Carolina, sales to industrial customers have been affected by downturns in the textile and chemical industries. For the year ended December 31, 2004, 12% of our total electric revenues were from wholesale sales. Wholesale revenues fluctuate with regional demand, fuel prices, and contracted capacity. Our wholesale profitability is dependent upon our ability to renew or replace expiring wholesale contracts on favorable terms. During 2004, wholesale revenues decreased from expiring contracts being renegotiated by PEC at less favorable terms due to slightly depressed markets and from increased competition in the wholesale markets served by PEC. If this trend market environment persists, we may experience further declines in our wholesale revenues. In April 2004, the FERC issued two orders concerning utilities' ability to sell wholesale electricity at market-based rates. In the first order, the FERC adopted two new interim screens for assessing potential generation market power of applicants for wholesale market-based rates, and described additional analyses and mitigation measures that could be presented if an applicant does not pass one of these interim screens. In July 2004, the FERC issued an order on rehearing affirming its conclusions in the April order. In the second order, the FERC initiated a rulemaking to consider whether the FERC's current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in any way. PEF does not have market-based rate authority for wholesale sales in peninsular Florida. Given the difficulty PEC believes it would experience in passing one of the interim screens, on August 12, 2004, PEC notified the FERC that it would revise its Market-based Rate tariff to restrict it to sales outside PEC's control area and file a new cost-based tariff for sales within PEC's control area that incorporates the FERC's default cost-based rate methodologies for sales of one year or less. We anticipate making this filing the first quarter of 2005. We cannot predict what impact PEC's requirement to implement cost-based tariffs will have on our future financial condition, results of operations or cash flows. 193 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. Increased commodity prices may adversely affect the financial condition, results of operations or cash flows of us and our utilities' businesses. The Company is exposed to the effects of market fluctuations in the price of natural gas, coal, fuel oil, electricity and other energy-related products marketed and purchased as a result of its ownership of energy-related assets. While each state commission allows electric utilities to recover certain of these costs through various cost recovery clauses, there is the potential that all or a portion of these future costs could be deemed imprudent by the respective commissions. There is also a delay between the timing of when these costs are incurred by the utilities and when these costs are recovered from the ratepayers, which can adversely impact the cash flow of the Company and its subsidiaries. Prices for SO2 emission allowance credits under the EPA's emission trading program increased significantly during 2004. While SO2 allowances are eligible for annual recovery in the Company's jurisdictions in Florida and South Carolina, no such annual recovery exists in North Carolina. Future increases in the price of SO2 allowances could have a significant adverse financial impact on us and PEC and consequently on our results of operations and cash flows. Risks Related to Us and Our Business As a holding company, we are dependent on upstream cash flows from our subsidiaries, primarily our regulated utilities. 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 associated with interest charges on $4.3 billion of holding company debt 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, primarily our regulated utilities, and the ability of our subsidiaries 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. For the year ending December 31, 2004, approximately 100% of the Company's cash from operations was provided by its utility subsidiaries. Other sources of cash include the issuance of equity, short-term debt and intercompany charges for capital costs. 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. 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 (the "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. As discussed below, in January 2005, PEF petitioned the FPSC for an increase in its retail base rates. 194 Additionally, under the NC Clean Air legislation in North Carolina, passed in 2002, PEC's base retail rates were frozen 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, and PEC has agreed not to seek a base retail electric rate increase in South Carolina through 2005. 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. If the FPSC does not approve our request for increased base rates, we will be faced with a significantly increased cost structure that will not be adequately covered by our base rates and, as a result, our results of operations, financial condition and ability to pay dividends could be materially and adversely impacted. In January 2005, in anticipation of the expiration of the Agreement approved by the FPSC in 2002 to conclude PEF's then-pending rate case, PEF notified the FPSC that it intends to request an increase in its base rates, effective January 1, 2006. In its notice, PEF requested the FPSC to approve calendar year 2006 as the projected test period for setting new base rates. We have faced significant cost increases over the past decade and expect our operational costs to continue to increase. These costs include the costs associated with (i) completion of our Hines 3 generation facility, (ii) extraordinary hurricane damage costs, including approximately $50 million in capital costs which are not expected to be directly recoverable, (iii) our need to replenish our depleted storm reserve or adjust the annual accrual by approximately $50 million annually in light of recent history on a going-forward basis, and (iv) the expected infrastructure investment necessary to meet high customer expectations, coupled with the demands placed on our strong customer growth. In addition, significant additional costs include increased depreciation and fossil dismantlement expenses in excess of $70 million when the provisions of the Agreement addressing these expenses expire at the end of this year. We also face the prospect of significant compliance costs from participation in the GridFlorida regional transmission organization pursuant to FERC's transmission independence initiative and the FPSC's related directive. Finally, as is the case with most companies in our industry, we will continue to experience the pervasive upward pressure of inflation on costs in general, especially the rapidly increasing costs of employee healthcare and other benefit programs. Under the Agreement, our base rates are at a level that existed in 1983; by contrast, the Consumer Price Index has increased just over 90% since then. If the FPSC does not approve our request for increased base rates, we will be faced with a significantly increased cost structure that will not be covered by our base rates. Additionally, as discussed below, the credit ratings of PEF may be negatively impacted by the outcome of the rate case. As a result, our results of operations, financial condition and ability to pay dividends could be materially and adversely impacted. 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 4,286 MW, or 18%, of our generation capacity for the year ended December 31, 2004. 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. 195 From time to time, 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 as required. 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 hurricanes, 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. We rely on access to both short-term and long-term capital markets, and lines of credit with commercial banks 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 these sources of liquidity, 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 to below investment grade would increase our cost of borrowing and may adversely affect our ability to access one or more financial markets. Market disruptions create a unique uncertainty as they typically result from factors beyond are control. Such market disruptions could include: o an economic downturn; o the bankruptcy of an unrelated energy company; o capital market conditions generally; o allegations of corporate scandal at unrelated companies; 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. In addition, we believe that these market disruptions, unrelated to our business, could result in a ratings downgrade and, correspondingly, increase our cost of capital. Additional risks regarding the impact of a ratings downgrade are discussed below. 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, 2004, commercial paper and bank borrowings and long-term debt balances for Progress Energy and its subsidiaries were as follows (in millions): 196 ----------------------------------------------------------------------------------------- Outstanding Commercial Paper Total Long-Term Company and Bank Borrowings Debt, Net ----------------------------------------------------------------------------------------- Progress Energy, unconsolidated (a) $ 170 $ 4,449 PEC 221 2,750 PEF 293 1,912 Other Subsidiaries - 410 (b) ----------------------------------------------------------------------------------------- Progress Energy, consolidated $ 684 $ 9,521 (c) -----------------------------------------------------------------------------------------
(a) Represents solely the outstanding indebtedness of the holding company. (b) Includes the following subsidiaries: Florida Progress Funding Corporation ($270 million) and Progress Capital Holdings, Inc. ($140 million). (c) Net of current portion, which at December 31, 2004, was $349 million on a consolidated basis. At December 31, 2004, Progress Energy and its subsidiaries have an aggregate of five committed credit lines that support our commercial paper programs totaling $1.98 billion. While our financial policy precludes us from issuing commercial paper in excess of our credit lines, at December 31, 2004, we had an outstanding commercial paper balance and letters of credit of $574 million, leaving an additional $931 million available for future borrowing under our credit lines. On January 31, 2005 Progress Energy, Inc. entered into a new $600 million revolving credit agreement, which expires December 30, 2005. This facility was added to provide additional liquidity during 2005 due in part to storm restoration costs incurred in Florida during 2004. The Credit Agreement includes a defined maximum total debt to total capital ratio of 65% and a minimum interest coverage ratio of 2.5 to 1. The Credit Agreement also contains various cross-default and other acceleration provisions. On February 4, 2005, $300 million was drawn under the new facility to reduce commercial paper and bank loans outstanding. 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, 2004, the required and actual ratios were as follows: - ----------------------------------------------------------------------------- Leverage Ratios Coverage Ratios - ----------------------------------------------------------------------------- Actual Actual Company Maximum Ratio Ratio Minimum Ratio Ratio - ----------------------------------------------------------------------------- Progress Energy 65% 60.7% 2.5:1 4.00:1 PEC 65% 52.3% n/a n/a PEF 65% 50.8% 3.0:1 7.93:1 - ----------------------------------------------------------------------------- In March 2005, Progress Energy, Inc.'s 5-year credit facility was amended to increase the maximum total debt to total capital ratio from 65% to 68% in connection with the potential accounting rules for uncertain tax positions. See Notes 2 and 23E to the Progress Energy Consolidated Financial Statements. 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 PEC and PEF 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. For Progress Energy's credit lines, loan draws for the payment of maturing commercial paper are excluded from this provision. 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 and PEF'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 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. 197 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 is triggered, the debt holders could accelerate payment of approximately $4.3 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 which would cause us to be rated below investment grade would likely 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. On February 11, 2005, Moody's Investors Service (Moody's) credit rating agency announced that it lowered the ratings of Progress Energy Florida, Progress Capital Holdings and FPC Capital Trust I and changed their rating outlooks to stable from negative. Moody's affirmed the ratings of Progress Energy and PEC. The rating outlooks continue to be stable at PEC and negative at Progress Energy. Moody's stated that it took this action primarily due to declining credit metrics, higher O&M costs, uncertainty regarding the timing of hurricane cost recovery, regulatory risks associated with the upcoming rate case in Florida and ongoing capital requirements to meet Florida's growing demand. In October 2004, Moody's changed its outlook for Progress Energy from stable to negative and placed the ratings of PEF under review for possible downgrade. PEC's ratings were affirmed. Accordingly, Progress Energy's senior unsecured debt is rated "Baa2," (negative outlook) by Moody's. Moody's cited weak financial ratios relative to its current ratings category, rising O&M, pension, benefit and insurance costs, and delays in executing its deleveraging plan as the primary reasons for the change in outlook. With respect to PEF, Moody's cited declining cash flows and rising leverage over the last several years, expected funding needs for large capital expenditure programs, risks regarding its upcoming 2005 rate case and the timing of hurricane cost recovery as the primary reason for placing the PEF's credit ratings under review. In October 2004, S&P also changed Progress Energy's outlook from stable to negative. S&P cited uncertainties regarding the timing of recovery of hurricane costs, the Company's debt reduction plans, and the IRS audit of our Earthco synthetic fuel facilities as the primary reasons for the change in outlook. In addition, for similar reasons, S&P reduced the short-term debt rating of Progress Energy, PEC and PEF to "A-3" from "A-2". Progress Energy's senior unsecured debt is rated "BBB-" by S&P. 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-3" (stable outlook). The forgoing ratings actions by S&P and Moody's do not trigger any debt or collateral guarantee requirement, however our short-term cost of capital has increased by between 25 to 87.5 basis points. However, the ratings currently assigned to Progress Energy's, senior unsecured debt is S&P's lowest investment grade ratings category and has a negative outlook. Accordingly, any further downgrade by S&P of Progress Energy's senior unsecured rating will result in a noninvestment grade rating and will trigger debt and collateral guarantee requirements (as described below), and may have a material adverse impact on our cost of capital, results of operations and liquidity. 198 While the Company's long-term target credit ratings for each entity are above the minimum investment grade ranking, we cannot 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 may 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-3 or P-2, the current ratings assigned by S&P and Moody's, respectively, our access to the commercial paper market would be significantly limited. 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, 2004, Progress Energy has issued guarantees with a notional amount of approximately $809 million to support CCO's energy marketing businesses. Based upon the amount of trading positions outstanding at December 31, 2004, if Progress Energy's ratings were to decline below investment grade by either S&P or Moody's (i.e., below "BBB-" at S&P or below "Baa3" at Moody's), we would have to deposit cash or provide letters of credit or other cash collateral for approximately $450 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, 2004, the coverage amount is $275 million. These collateral requirements could adversely affect our profitability on energy trading and marketing transactions and limit our overall liquidity. In addition, if we are unable to fund or otherwise satisfy these guarantee obligations our financial condition and liquidity would be further impacted in a material adverse manner. 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. Synthetic Fuel Risks Associated With the IRS Audit 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, although these PLR's do not make any "placed-in-service" determinations. These tax credits are subject to review by the IRS. In July 2004, we were notified that the IRS field auditors anticipated taking an adverse position regarding the placed-in-service date of the Company's four Earthco synthetic fuel facilities. Due to the auditors' position, the IRS decided to exercise its right to withdraw from the PFA program with us. In October 2004, we received the IRS field auditors' report concluding that the Earthco facilities had not been placed in service before July 1, 1998, and that the tax credits generated by those facilities should be disallowed. We intend to contest the field auditors' findings and their proposed disallowance of the tax credits. We believe that the appeals process, including proceedings before the IRS's National Office, could take up to two years to complete. We cannot control the actual timing of resolution and cannot predict the outcome of this matter. 199 Through December 31, 2004, on a consolidated basis, we have or carried forward approximately $1.0 billion of tax credits generated by the Earthco facilities. If these credits were disallowed, our one-time exposure for cash tax payments would be $294 million (excluding interest), and earnings and equity would be reduced by approximately $1.0 billion, excluding interest. If we were required to reverse approximately $1.0 billion of tax credits and pay $294 million for taxes our financial condition, results of operations and liquidity would be materially and adversely impacted. Progress Energy's amended $1.13 billion credit facility includes a covenant which limits the maximum debt-to-total capital ratio to 68%. This ratio includes other forms of indebtedness such as guarantees issued by Progress Energy, letters of credit and capital leases. As of December 31, 2004, Progress Energy's debt-to-total capital ratio was 60.7% based on the credit agreement definition for this ratio. The impact on this ratio of reversing approximately $1.0 billion of tax credits and paying $294 million for taxes would be to increase the ratio to 65.7%. 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. Synthetic Fuel Risks Associated with Pending Accounting Rules for Uncertain Tax Positions In July 2004, the Financial Accounting Standards Board ("FASB") stated that it plans to issue an exposure draft of a proposed interpretation of SFAS No. 109, "Accounting for Income Taxes," that would address the accounting for uncertain tax positions. The FASB has indicated that the interpretation would require that uncertain tax benefits be probable of being sustained in order to record such benefits in the financial statements. The exposure draft is expected to be issued in the first quarter of 2005. Under the prevailing sentiment, the IRS field auditors' recommendation that the Earthco tax credits be disallowed would make it difficult to conclude that the tax benefits from the Earthco facilities are probable of being sustained. Accordingly, it is likely we would not be able to record the benefit of the Earthco tax credits on our financial statements. This could require us to create a reserve up to $1.0 billion until the IRS issue is resolved, which would immediately increase our debt to capitalization ratios. The Company cannot predict what actions the FASB will take or how any such actions might ultimately affect the Company's financial position or results of operations, but such changes could have a material impact on the Company's evaluation and recognition of Section 29 tax credits, which, in turn, may have a material impact on our results of operations and financial condition. Synthetic Fuel Risks Associated With Fluctuations in the Company's Regular Income Tax Liability The Company's synthetic fuel production levels and the amount of tax credits it can claim each year are a function of the Company's projected consolidated regular federal income tax liability. Any conditions that negatively impact the Company's tax liability, such as weather, could also diminish the Company's ability to utilize credits, including those previously generated, and the synthetic fuel is generally not economical to produce absent the credits. Synthetic Fuel Risks Associated With Crude Oil Prices Recent unprecedented and unanticipated increases in the price of oil could limit the amount of Section 29 tax credits or eliminate them altogether. Section 29 provides that if the average wellhead price per barrel for unregulated domestic crude oil for the year (the "Annual Average Price") exceeds a certain threshold value (the "Threshold Price"), the amount of Section 29 tax credits are reduced for that year. Also, if the Annual Average Price increases high enough (the "Phase Out Price"), the Section 29 tax credits are eliminated for that year. For 2003, the Threshold Price was $50.14 per barrel and the Phase Out Price was 200 $62.94 per barrel. The Threshold Price and the Phase Out Price are adjusted annually for inflation. Although data for 2004 is not yet available, we do not expect the amount of our 2004 Section 29 tax credits to be adversely affected by oil prices. We cannot predict with any certainty the Annual Average Price for 2005 or beyond. Therefore, we cannot predict whether the price of oil will have a material effect on our synthetic fuel business after 2004. However, if during 2005 through 2007, oil prices remain at historically high levels or increase, our synthetic fuel business may be adversely affected for those years and, depending on the magnitude of such increases in oil prices, the adverse affect for those years could be material and could have an impact on our synthetic fuel production plans which, in turn, may have a material impact on our results of operations and financial condition. 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. At December 31, 2004, we had approximately 3,100 MW 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 o 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. 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. 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. 201 o Our facilities seek to enter into long-term power purchase agreements to sell all or a portion of their generating capacity. CCO currently owns six electricity generation facilities with approximately 3,100 MW of generation capacity, and it has contractual rights to an additional 2,500 MW of generation capacity from mixed fuel generation facilities through its agreements with 16 Georgia electric membership cooperatives (EMCs). CCO has contracts for its combined production capacity of approximately 77% for 2005, 81% for 2006 and 75% for 2007. Three above-market tolling agreements for approximately 1,200 MW of capacity expired at the end of 2004. CCO has replaced the expired agreements with the increased cooperative load in Georgia. The increased cooperative load in Georgia will significantly increase CCO's revenue and cost of sales from 2004 to 2005 with lower margins expected. 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. More recently we have moved from tolling arrangements to full requirements contracts which have lower margins. These contracts do not guarantee us any rate of return on our 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; 202 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. Our Fuels business segment is involved in natural gas drilling and production, coal terminal services, coal mining, and fuel transportation and delivery operations that are subject to risks that may reduce our revenues and adversely impact our results of operations and financial condition. The Fuels business segment engages in businesses that have significant operational and financial risk. Operational risk includes the activities involved with natural gas drilling, coal mining, terminal and barge operations and fuel delivery. Financial risks include exposure to commodity prices, primarily fuel prices. We actively manage the operational and financial risks associated with these businesses. Nonetheless, adverse changes in fuel prices and operational issues beyond our control may result in losses in our earnings or cash flows and adversely affect our balance sheet. 203 PROGRESS ENERGY CAROLINAS, INC. RISK FACTORS In this section, unless the context indicates otherwise, references to "our," "we," "us" or similar terms refer 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. Most of the business information as well as the financial and operational data contained in our risk factors are updated periodically in the reports we file with the SEC. 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, financial condition and 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 subject to regulatory oversight with respect to, among other things, rates and service for electric energy sold at retail, retail service territory and issuances of securities. In addition our operating utilities are subject to regulation with respect to transmission and sales of wholesale power, accounting and certain other matters. We are also 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 2004 working on a comprehensive energy bill. While that legislation passed the House, the Senate failed to pass the legislation in 2004. There will probably be an effort to resurrect the legislation in 2005. 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 the Public Utility Holding Company Act of 1935 ("PUHCA"). We cannot predict the outcome or impact of the proposed or any future energy bill. 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 PUHCA, we are subject to many of the regulatory provisions of PUHCA. 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, financial condition and results of operations. We are subject to numerous environmental laws and regulations that require significant capital expenditures, increase our cost of operations, and which may 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. 204 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. Our compliance with environmental regulations requires significant capital expenditures that impact our financial condition. For example, 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. We expect the capital costs required to meet these emission targets will total approximately $895 million by 2013. Over the next three years, we expect to incur approximately $510 million of total capital costs associated with this legislation. Congress currently considering further legislation that would require reductions in air emissions of 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 our consolidated financial position or results of operations. However, we cannot predict the outcome, costs or impact of this matter. In December 2003, the EPA released its proposed Interstate Air Quality Rule, currently referred to as the Clean Air Interstate Rule (CAIR). The EPA's proposal requires 29 jurisdictions, including North Carolina, South Carolina, Georgia and Florida, to reduce NOx and SO2 emissions in order to attain preset state NOx and SO2 emissions levels. The rule is expected to become final in March 2005. While the air quality controls already installed and currently planned for installation to comply with the NC Clean Air legislation will reduce the costs required to meet the CAIR requirements for the our North Carolina units, additional compliance costs will be determined once the rule is finalized. In March 2004, the North Carolina Attorney General filed a petition with the EPA under Section 126 of the Clean Air Act, asking the federal government to force coal-fired power plants in thirteen other states, including South Carolina to reduce their NOx and SO2 emissions. The state of North Carolina contends these out-of-state emissions interfere with North Carolina's ability to meet national air quality standards for ozone and particulate matter. The EPA has agreed to make a determination on the petition by August 1, 2005. PEC cannot predict the outcome or costs associated with the matter. See additional discussion of these environmental matters in Note 17 to the Progress Energy Carolinas Consolidated Financial Statements. 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 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 SMD NOPR could materially alter the manner in which transmission and generation services are provided and paid for, and includes structural separation of transmission from other utility functions and the FERC's assertion of jurisdiction over certain aspects of retail service. We cannot predict the outcome or timing of any final rules or the effect that they may have on the GridSouth proceedings. 205 At the state level, significant uncertainty exists with respect to what action, if any, the NCUC will ultimately take. The Company has $33 million invested in GridSouth related to startup costs at December 31, 2004. These amounts are included as a regulatory asset at December 31, 2004. The Company expects to recover these startup costs in conjunction with the GridSouth original structures or in conjunction with any alternate combined transmission structures that may be required. 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. 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 it will be created, or whether it 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, cash flows and ability to pay dividends on our common stock may be affected by changing weather conditions. Weather conditions in our service territories in North Carolina and South Carolina 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 and market prices peak during the hot summer months. 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. 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, 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 ability to recover significant costs resulting from severe weather events is subject to regulatory oversight and the timing and amount of any such recovery is uncertain and may impact our financial conditions. PEC is not required to maintain a storm damage reserve account and does not have an ongoing regulatory mechanism to recover storm costs and; therefore, hurricane restoration costs recorded in the third quarter of 2004 were charged to operations and maintenance expenses or capital expenditures based on the nature of the work performed. In connection with other storms, PEC has previously sought and received permission from the NCUC and the SCPSC to defer storm expenses and amortize them over a five-year period. PEC did not seek recovery of 2004 storm costs from the NCUC. Our revenues, operating results and financial condition may fluctuate with the economy and its corresponding impact on our commercial and industrial customers as well as the demand and competitive state of the wholesale market. Our business is impacted by fluctuations in the macroeconomy. For the year ended December 31, 2004, commercial and industrial customers represented approximately 25% and 19%, respectively, of our billed 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 recent years, in North and South Carolina, sales to industrial customers have been affected by downturns in the textile and chemical industries. For the year ended December 31, 2004, 16% of our billed electric revenues were from wholesale sales. Wholesale revenues fluctuate with regional demand, fuel prices, and contracted capacity. Our wholesale profitability is dependent upon our ability to renew or replace expiring wholesale contracts on favorable terms. During 2004, wholesale revenues decreased from expiring contracts being renegotiated by us at less favorable terms due to slightly depressed markets and from increased competition in the wholesale markets served by us. If this trend market environment persists, we may experience further declines in our wholesale revenues. 206 In April 2004, the FERC issued two orders concerning utilities' ability to sell wholesale electricity at market-based rates. In the first order, the FERC adopted two new interim screens for assessing potential generation market power of applicants for wholesale market-based rates, and described additional analyses and mitigation measures that could be presented if an applicant does not pass one of these interim screens. In July 2004, the FERC issued an order on rehearing affirming its conclusions in the April order. In the second order, the FERC initiated a rulemaking to consider whether the FERC's current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in any way. Given the difficulty PEC believes it would experience in passing one of the interim screens, on August 12, 2004, PEC notified the FERC that it would revise its Market-based Rate tariff to restrict it to sales outside our control area and file a new cost-based tariff for sales within our control area that incorporates the FERC's default cost-based rate methodologies for sales of one year or less. We anticipate making this filing the first quarter of 2005. We cannot predict what impact our requirement to implement cost-based tariffs will have on our future financial condition, results of operations or cash flows. Deregulation or restructuring in the electric industry may result in increased competition and unrecovered costs that could adversely affect our financial condition, results of operations or cash flows. 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 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. Increased commodity prices may adversely affect the financial condition, results of operations or cash flows of us and our utilities' businesses. We are exposed to the effects of market fluctuations in the price of natural gas, coal, fuel oil, electricity and other energy-related products marketed and purchased as a result of its ownership of energy-related assets. While each state commission allows electric utilities to recover certain of these costs through various cost recovery clauses, there is the potential that these future costs could be deemed imprudent by the respective commissions. There is also a delay between the timing of when these costs are incurred by the utilities and when these costs are recovered from the ratepayers, which can adversely impact our cash flows. Prices for SO2 emission allowance credits under the EPA's emission trading program increased significantly during 2004. While SO2 allowances are eligible for annual recovery in our jurisdiction in South Carolina, no such annual recovery exists in North Carolina. Future increases in the price of SO2 allowances could have a significant adverse financial impact on us and consequently on our results of operations and cash flows. Risks Related to Us and Our Business The rates that we 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 do not control operating costs. The NCUC and the SCPSC each exercise 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. Additionally, under the NC Clean Air legislation in North Carolina, passed in 2002, PEC's base retail rates were frozen 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, and we have agreed not to seek a base retail electric rate increase in South Carolina 207 through 2005. The same legislation required a significant increase in capital expenditures over the next several years for clean air improvements. The cash costs incurred by us is 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 3,448 MW, or 28%, of our generation capacity for the year ended December 31, 2004. 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. From time to time, 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 as required. 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. 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 hurricanes, 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. We rely on access to both short-term and long-term capital markets, and lines of credit with commercial banks 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 these sources of liquidity, 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 to below investment grade would increase our cost of borrowing and may adversely affect our ability to access one or more financial markets. Market disruptions create a unique uncertainty as they typically result from factors beyond are control. Such market disruptions could include: o an economic downturn; o the bankruptcy of an unrelated energy company; o capital market conditions generally; 208 o allegations of corporate scandal at unrelated companies; 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. In addition, we believe that these market disruptions, unrelated to our business, could result in a ratings downgrade and, correspondingly, increase our cost of capital. Additional risks regarding the impact of a ratings downgrade are discussed below. 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, 2004, our commercial paper and bank borrowings and long-term debt balances were as follows (in millions): ---------------------------------------------------------------------- Outstanding Commercial Paper Total Long-Term Company and Bank Borrowings Debt, Net ---------------------------------------------------------------------- PEC 221 2,750 (a) ---------------------------------------------------------------------- (a) Net of current portion, which at December 31, 2004, was $300 million. At December 31, 2004, we had two committed credit lines that support our commercial paper programs totaling $450 million. While our financial policy precludes us from issuing commercial paper in excess of our credit lines, at December 31, 2004, we had outstanding borrowings on our credit facilities of $90 million and an outstanding commercial paper balance of $131 million, leaving an additional $229 million available for future borrowing under our credit lines. Our credit lines impose various limitations that could impact our liquidity. Our credit facilities include a defined maximum total debt to total capital (leverage) ratio. At December 31, 2004, the maximum and actual leverage ratios, pursuant to the terms of the credit facilities, were 65% and 52.3%, respectively. Under the credit facilities, indebtedness includes certain letters of credit and guarantees which are not recorded on our Consolidated 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 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. Our credit lines 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. Our cross-default provisions only apply to defaults of indebtedness, but not defaults by our affiliates. 209 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 which would cause us to be rated below investment grade would likely 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. 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), 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. In October 2004, S&P reduced our short-term debt rating to A-3 from A-2. As a result of the impact of these actions, we have borrowed on our revolving credit agreements. Due to the lower short-term debt rating issued by S&P, we may continue to borrow under our revolving credit facilities instead of issuing commercial paper due to the difference in investor demand for lower-rated commercial paper. 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. 210 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 16, 2005 (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. 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/ Robert B. McGehee Director March 16, 2005 - --------------------- (Robert B. McGehee, Chairman) /s/ Edwin B. Borden Director March 16, 2005 - ------------------- (Edwin B. Borden) /s/ James E. Bostic, Jr. Director March 16, 2005 - ----------------------- (James E. Bostic, Jr.) /s/ David L. Burner Director March 16, 2005 - ------------------- (David L. Burner) 211 /s/ Charles W. Coker Director March 16, 2005 - --------------------- (Charles W. Coker) /s/ Richard L. Daugherty Director March 16, 2005 (Richard L. Daugherty) /s/ W.D. Frederick, Jr. Director March 16, 2005 - ----------------------- (W.D. Frederick, Jr.) /s/ William O. McCoy Director March 16, 2005 - --------------------- (William O. McCoy) /s/ E. Marie McKee Director March 16, 2005 - ------------------- (E. Marie McKee) /s/ John H. Mullin, III Director March 16, 2005 - ----------------------- (John H. Mullin, III) /s/ Richard A. Nunis Director March 16, 2005 (Richard A. Nunis) /s/Peter S. Rummell Director March 16, 2005 (Peter S. Rummell) /s/ Carlos A. Saladrigas Director March 16, 2005 - ------------------------ (Carlos A. Saladrigas) /s/ Jean Giles Wittner Director March 16, 2005 - ---------------------- (Jean Giles Wittner) 212 EXHIBIT INDEX Progress Number Exhibit Energy, Inc. PEC *2(a) 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(b) 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). *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 March 17, 2004, (filed as Exhibit No. 3(ii)(b) to Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004, File No. 1-3382 and 1-15929). *3b(3) 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(4) By-Laws of Progress Energy, Inc., as amended on March 17, X 2004, (filed as Exhibit No. 3(ii)(a) to Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004, File No. 1-3382 and 1-15929). *3b(5) 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). 213 *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, X between 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 4(b) and 4(c), File No. 33-33431; Exhibits 4(b) and 4(c), File No. 33-38298; Exhibits 4(h) 214 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, File No. 1-3382 and 1-15929); and the Seventy-second Supplemental Indenture (Exhibit 4 to PEC Report on Form 8-K dated September 12, 2003, File No. 1-3382). *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 and Bankers Trust Company, as Trustee, with respect to Unsecured Subordinated Debt Securities (filed as Exhibit No. 4(c) to Current Report on Form 8-K dated April 13, 1995, File No. 1-3382). *4c(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 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). 215 *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). *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. $600,000,000 364-Day Revolving X Credit Agreement dated as of January 31, 2005, (filed as Exhibit 10 to Current Report on Form 8-K filed February 4, 2005, File No. 1-15929). *10b(2) Progress Energy, Inc. $1,130,000,000 5-Year Revolving X Credit Agreement dated as of August 5, 2004, (filed as Exhibit 10(i) to Quarterly Report on Form 10-Q for the period ended June 30, 2004, File No. 1-3382 and 1-15929). 216 *10b(3) Amendment and Restatement, dated as of July 30, 2003, to X the 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. 1-03382 and 1-15929). *10b(4) Notice, dated March 25, 2003, to the Agent for the X Lenders named 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(5) 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 $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. 1-03382 and 1-15929). *10b(6) Carolina Power & Light Company $272,500,000 364-Day X Revolving Credit Agreement dated as of July 31, 2002, (filed as Exhibit 10(iii) to Quarterly Report on Form 10-Q for the period ended September 30, 2002, File No. 1-3382 and 1-15929). *10b(7) Carolina Power & Light Company $272,500,000 3-Year 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 and 1-15929). *10b(8) PEF 364-Day $200,000,000 Credit Agreement dated as of X April 1, 2003 (filed as Exhibit 10(ii) to Florida Power Corporation Form 10-Q for the quarter ended March 31, 2003). *10b(9) PEF 3-Year $200,000,000 Credit Agreement, dated as of X April 1, 2003, (filed as Exhibit 10(iii) to the Florida Power Corporation Form 10-Q for the quarter ended March 31, 2003). 10b(10) Amendment, dated as of March 11, 2005, to the $1,130,000,000 X 5-Year Revolving Credit Agreement among Progress Energy, Inc., and certain lenders, dated August 5, 2004. - -+*10c(1) Retirement Plan for Outside Directors (filed as X Exhibit 10(i), File No. 33-25560). - -+*10c(2) 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(3) Resolutions of Board of Directors dated July 9, 1997, X amending the Deferred Compensation Plan for Key Management Employees of Carolina Power & Light Company. - -+*10c(4) 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.) 217 +*10c(5) 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(6) 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(7) 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(8) Progress Energy, Inc. Form of Stock Option Award (filed X X as Exhibit 4.5 to Form S-8 dated September 27, 2001, File No. 333-70332). +*10c(9) 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(10) Amended Management Incentive Compensation Plan of X X Progress Energy, Inc., effective January 1, 2005, (filed as Exhibit 10(i) to current report on Form 8-K dated December 13, 2004, File Nos. 1-3382, 1-3274, 1-15929 and 1-8349). +10c(11) Progress Energy Inc., Amended and Restated Management X X Deferred Compensation Plan, Adopted as of January 1, 2000, as Revised and Restated, effective January 1, 2005. +10c(12) Progress Energy, Inc. Management Change-in-Control Plan, X X Amended and Restated Effective as of January 1, 2005. +10c(13) Amended Performance Share Sub-Plan of the 2002 Progress X X Energy, Inc. Equity Incentive Plan effective as of January 1, 2005. +*10c(14) Form of Deferred Compensation Plan for Directors--Method X X of Payment Agreement of Progress Energy, Inc., effective as of January 1, 2005 (filed as Exhibit 10(ii) to Current Report on Form 8-K dated December 13, 2004, File Nos. 1-3382, 1-3274, 1-15929 and 1-8349). +10c(15) Amended and Restated Progress Energy, Inc. Restoration X X Retirement Plan, effective as of January 1, 2005. +10c(16) Amended and Restated Supplemental Senior Executive X X Retirement Plan of Progress Energy, Inc., amended, effective January 1, 2005. 218 +*10c(17) Amended Non-Employee Director Stock Unit Plan of Progress X X Energy, Inc., effective January 1, 2005 (filed as Exhibit 10(iii) to Current Report on Form 8-K dated December 13, 2004, File Nos. 1-3382, 1-3274, 1-15929 and 1-8349). +10c(18) Form of Progress Energy, Inc. Restricted Stock Agreement pursuant to the 2002 Progress Energy Inc. Equity Incentive Plan, as amended July 2002. +*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 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(22) 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(23) 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 (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(24) Form of Employment Agreement dated August 1, 2000, X X between Carolina Power & Light Company and Fred Day IV, C.S. "Scotty" Hinnant and E. Michael Williams (filed as Exhibit 10(vi) to Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2000, File No. 1-15929 and No. 1-3382). +*10c(25) 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(26) Form of Employment Agreement between (i) Progress Energy X X Service Company and John R. McArthur, effective January 2003; (ii) Progress Energy Florida, Inc. and Jeffrey J. Lyash, dated December 15, 2003; and (iii) Progress Energy Carolinas, Inc. and Lloyd M. Yates, effective January 2005 (filed as Exhibit 10c(27) to Annual Report on Form 10-K for the year ended December 31, 2002, File No. 1-3382 and 1-5929). 219 +*10c(27) Employment Agreement dated October 1, 2003, between X X Progress Energy Service Company LLC and Geoffrey S. Chatas (filed as Exhibit 10c(28) to the Progress Energy, Inc. Annual Report on Form 10-K for the year-ended December 31, 2003). +10c(28) Agreement dated March 31, 2004, between Progress Energy, X X Inc. and William Cavanaugh III. +10c(29) Employment Agreement dated January 1, 2005, between X X Progress Energy Carolinas, Inc. and William D. Johnson. +*10c(30) Employment Agreement dated August 1, 2000, between X X Carolina Power & Light Company and Tom Kilgore (filed as Exhibit 10(iii) to Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2000, File No. 1-15929 and No. 1-3382). 10d(1) Agreement dated November 18, 2004, between Winchester X Production Company, Ltd., TGG Pipeline Ltd., Progress Energy, Inc. and EnCana Oil & Gas (USA), Inc. *10d(2) Precedent and Related Agreements among Florida Power X Corporation d/b/a Progress Energy Florida, Inc. ("PEF"), Southern Natural Gas Company ("SNG"), Florida Gas Transmission Company ("FGT"), and BG LNG Services, LLC ("BG"), including: a) Precedent Agreement by and between SNG and PEF, dated December 2, 2004; b) Gas Sale and Purchase Contract between BG and PEF, dated December 1, 2004; c) Interim Firm Transportation Service Agreement by and between FGT and PEF, dated December 2, 2004; d) Letter Agreement between FGT and PEF, dated December 2, 2004, and Firm Transportation Service Agreement by and between FGT and PEF to be entered into upon satisfaction of certain conditions precedent; e) Discount Agreement between FGT and PEF, dated December 2, 2004; f) Amendment to Gas Sale and Purchase Contract between BG and PEF, dated January 28, 2005; and g) Letter Agreement between FGT and PEF, dated January 31, 2005, (filed as Exhibit 10.1 to Current Report on Form 8-K/A filed March 15, 2005). (Confidential treatment has been requested for portions of this exhibit. These portions have been omitted from the above-referenced Current Report and submitted separately to the SEC.) 220 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. 221 PROGRESS ENERGY, INC. EXHIBIT NO. 12 COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - -------------------------------------------------------------------------------------------------------------------------- (millions of dollars) Years Ended December 31 2004 2003 2002 2001 2000 - -------------------------------------------------------------------------------------------------------------------------- Earnings, as defined: Income from continuing operations before cumulative effect of changes in accounting principles $ 753 $ 811 $ 552 $ 541 $ 478 Fixed charges, as below 689 682 711 719 275 Amortization of capitalized interest 1 1 - - - Preferred dividend requirements (7) (7) (7) (8) (8) Minority interest 17 (3) - - - Capitalized interest (7) (20) (38) - - Income taxes, as below 110 (119) (166) (162) 188 - -------------------------------------------------------------------------------------------------------------------------- Total earnings, as defined $ 1,556 $ 1,345 $ 1,052 $ 1,090 $ 933 - -------------------------------------------------------------------------------------------------------------------------- Fixed Charges, as defined: Interest on long-term debt $ 598 $ 613 $ 600 $ 578 $ 224 Other interest 62 42 79 112 37 Imputed interest factor in rentals - charged principally to operating expenses 22 20 25 21 9 Preferred dividend requirements of subsidiaries 7 7 7 8 8 - -------------------------------------------------------------------------------------------------------------------------- Total fixed charges, as defined $ 689 $ 682 $ 711 $ 719 $ 278 - -------------------------------------------------------------------------------------------------------------------------- Income Taxes: Income tax expense (benefit) $ 115 $ (111) $ (158) $ (154) 196 Included in AFUDC - deferred taxes in book depreciation (5) (8) (8) (8) (8) - -------------------------------------------------------------------------------------------------------------------------- Total income taxes $ 110 $ (119) $ (166) $ (162) $ 188 - -------------------------------------------------------------------------------------------------------------------------- Ratio of Earnings to Fixed Charges 2.26 1.97 1.48 1.52 3.36 - --------------------------------------------------------------------------------------------------------------------------
222 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 - ------------------------------------------------------------------------------------------------------------------------ (million of dollars) Years Ended December 31 2004 2003 2002 2001 2000 - ------------------------------------------------------------------------------------------------------------------------ Earnings, as defined: Income before cumulative effect of change in accounting principles $ 461 $ 505 $ 431 $ 364 $ 461 Fixed charges, as below 202 205 224 264 246 Income taxes, as below 234 233 199 215 282 - ------------------------------------------------------------------------------------------------------------------------ Total earnings, as defined $ 897 $ 943 $ 854 $ 843 $ 989 - ------------------------------------------------------------------------------------------------------------------------ Fixed Charges, as defined: Interest on long-term debt $ 183 $ 187 $ 205 $ 246 $ 224 Other interest 12 11 12 11 17 Imputed interest factor in rentals - charged principally to operating expenses 7 7 7 7 5 - ------------------------------------------------------------------------------------------------------------------------ Total fixed charges, as defined $ 202 $ 205 $ 224 $ 264 $ 246 - ------------------------------------------------------------------------------------------------------------------------ Preferred dividends, as defined $ 5 $ 4 $ 4 $ 5 $ 5 - ------------------------------------------------------------------------------------------------------------------------ Total fixed charges and preferred dividends combined $ 207 $ 209 $ 228 $ 269 $ 251 - ------------------------------------------------------------------------------------------------------------------------ Income Taxes: Income tax expense $ 239 $ 241 $ 207 $ 223 $ 290 Included in AFUDC - deferred taxes in book depreciation (5) (8) (8) (8) (8) - ------------------------------------------------------------------------------------------------------------------------ Total income taxes $ 234 $ 233 $ 199 $ 215 $ 282 - ------------------------------------------------------------------------------------------------------------------------ Ratio of Earnings to Fixed Charges 4.44 4.60 3.81 3.19 4.02 Ratio of Earnings to Fixed Charges and Preferred Dividends Combined 4.33 4.51 3.75 3.13 3.94 - ------------------------------------------------------------------------------------------------------------------------
223 Exhibit 21 SUBSIDIARIES OF PROGRESS ENERGY, INC. AT DECEMBER 31, 2004 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
224 Exhibit 23.(a) CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in Registration Statement No. 333-114237 on Form S-3, Registration Statement No. 104952 on Form S-8, Registration Statement No. 33-33520 on Form S-8, 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 our reports dated March 7, 2005, relating to the financial statements and financial statement schedule of Progress Energy, Inc. (which report on the consolidated financial statements expresses an unqualified opinion and includes an explanatory paragraph concerning the adoption of new accounting principles in 2003) and management's report on the effectiveness of internal control over financial reporting, appearing in this Annual Report on Form 10-K of Progress Energy, Inc. for the year ended December 31, 2004. We also consent to the incorporation by reference in Post-Effective Amendment No. 1 to Registration Statement No. 333-58800 on Form S-3 and Registration Statement No. 333-103973 on Form S-3 of our reports dated March 7, 2005, relating to the financial statements and financial statement schedule of Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) (which report on the consolidated financial statements expresses 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, 2004. /s/ Deloitte & Touche LLP Raleigh, North Carolina March 15, 2005 225 EX-10 2 pei_exhibit10b10-.txt EXHIBIT 10B(10) Exhibit 10b(10) EXECUTION COPY AMENDMENT Dated as of March 11, 2005 To the Lenders parties to the Credit Agreement and the Administrative Agent referred to below Ladies and Gentlemen: Reference is made to the Credit Agreement, dated as of August 5, 2004 (the "Credit Agreement"), among Progress Energy, Inc. (the "Borrower"), the lenders parties thereto and Citibank, N.A., as Administrative Agent ("Administrative Agent"). Capitalized terms used herein and not otherwise defined herein have the meanings given such terms in the Credit Agreement. The Borrower hereby requests that the Credit Agreement be amended as provided below. Section 1. Amendments. The parties agree that, subject to the satisfaction of the conditions precedent to effectiveness set forth below, the Credit Agreement is, as of the date hereof, hereby amended as follows: (a) Subsection (j) of Section 5.01 is amended and restated in its entirety to read as follows: "(j) Indebtedness to Total Capitalization. Maintain, at all times a ratio of Consolidated Indebtedness of the Borrower and its Subsidiaries to Total Capitalization of not more than .68:1.0." Section 2. Conditions to Effectiveness. Section 1 of this Amendment shall be effective as of the date hereof when and if (i) the Borrower and the Majority Lenders shall have executed and delivered to the Administrative Agent executed counterparts of this Amendment, (ii) the Borrower shall have paid to the Administrative Agent, for the account of each Lender that shall have executed and delivered to the Administrative Agent a counterpart of this Amendment on or before 5:00 pm (New York City time) on Friday, March 11, 2005, an amendment fee of $3,500, and (iii) the representations and warranties of the Borrower set forth in Section 3 below shall be true and correct on and as of such date of effectiveness as though made on and as of such date. Section 3. Representations and Warranties. The Borrower represents and warrants that (i) the representations and warranties contained in Article IV of the Credit Agreement, as amended hereby (with each reference therein to "this Agreement", "hereunder" and words of like import referring to the Credit Agreement being deemed to be a reference to this Amendment and the Credit Agreement, as amended hereby), are true and correct on and as of the date hereof as though made on and as of such date, and (ii) no event has occurred and is continuing, or would result from the execution and delivery of this Amendment, that constitutes a Default or an Event of Default. 2 Section 4. Effect on the Credit Agreement. The execution, delivery and effectiveness of this Amendment shall not operate as a waiver of any right, power or remedy of any Lender or the Administrative Agent under the Credit Agreement, nor constitute a waiver of any provision of any of the Credit Agreement. Except as expressly amended above, the Credit Agreement is and shall continue to be in full force and effect and is hereby in all respects ratified and confirmed. This Amendment shall be binding on the parties hereto and their respective successors and permitted assigns under the Credit Agreement. Section 5. Costs, Expenses and Taxes. The Borrower agrees to pay on demand all costs and expenses of the Administrative Agent in connection with the preparation, execution and delivery of this Amendment and any other instruments and documents to be delivered hereunder, including, without limitation, the reasonable fees and out-of-pocket expenses of counsel for the Administrative Agent with respect thereto, and all costs and expenses (including, without limitation, counsel fees and expenses), if any, in connection with the enforcement (whether through negotiations, legal proceedings or otherwise) of this Amendment or such other instruments and documents. In addition, the Borrower agrees to pay any and all stamp and other taxes payable or determined to be payable in connection with the execution and delivery of this Amendment and any other instruments and documents to be delivered hereunder, and agree jointly and severally to save the Lenders and the Administrative Agent harmless from and against any and all liabilities with respect to or resulting from any delay in paying or omission to pay such taxes. Section 6. Counterparts. This Amendment may be executed in any number of counterparts and by any combination of the parties hereto in separate counterparts, each of which counterparts shall constitute an original, and all of which taken together shall constitute one and the same instrument. Section 7. Governing Law. This Amendment shall be governed by, and construed in accordance with, the laws of the State of New York. If you consent and agree to the foregoing, please evidence such consent and agreement by executing and returning four (4) counterparts of this Amendment to King & Spalding LLP, 1185 Avenue of the Americas, New York, New York 10036, Attention: Elizabeth T. Wubneh (fax no. 212-556-2222) no later than 5:00 p.m., New York City time, on Friday, March 11, 2005. Very truly yours, PROGRESS ENERGY, INC. By ------------------------------- Name: Title: 3 The undersigned hereby consent and agree to the foregoing: CITIBANK, N.A. By ----------------------------------------- Name: Title: 4 JPMORGAN CHASE BANK By ----------------------------------------- Name: Title: 5 SUNTRUST BANK By ----------------------------------------- Name: Title: 6 BANK OF AMERICA, N.A. By ----------------------------------------- Name: Title: 7 BANK OF TOKYO-MITSUBISHI TRUST COMPANY By ----------------------------------------- Name: Title: 8 BARCLAYS BANK PLC By ----------------------------------------- Name: Title: 9 THE ROYAL BANK OF SCOTLAND PLC By ----------------------------------------- Name: Title: 10 BNP PARIBAS By ----------------------------------------- Name: Title: By ----------------------------------------- Name: Title: 11 CALYON NEW YORK BRANCH By ----------------------------------------- Name: Title: By ----------------------------------------- Name: Title: 12 DEUTSCHE BANK AG, NEW YORK BRANCH By ----------------------------------------- Name: Title: By ----------------------------------------- Name: Title: 13 LEHMAN BROTHERS BANK, FSB By ----------------------------------------- Name: Title: 14 UBS LOAN FINANCE LLC By ----------------------------------------- Name: Title: By ----------------------------------------- Name: Title: 15 WACHOVIA BANK, N.A. By ----------------------------------------- Name: Title: 16 WILLIAM STREET COMMITMENT CORPORATION By ----------------------------------------- Name: Title: 17 SUMITOMO MITSUI BANKING CORPORATION By ----------------------------------------- Name: Title: 18 THE BANK OF NEW YORK By ----------------------------------------- Name: Title: 19 UFJ BANK By ----------------------------------------- Name: Title: 20 MELLON BANK, N.A. By ----------------------------------------- Name: Title: EX-10 3 pei_exhibit10c11-.txt EXHIBIT 10C(11) Exhibit 10c(11) PROGRESS ENERGY, INC. AMENDED AND RESTATED MANAGEMENT DEFERRED COMPENSATION PLAN Adopted as of January 1, 2000 (As Revised and Restated effective January 1, 2005) TABLE OF CONTENTS Page PREAMBLE......................................................................1 ARTICLE I DEFINITIONS................................................2 1.1 Account Balance................................................2 1.2 Additional Deferral Election...................................2 1.3 Affiliated Company.............................................2 1.4 Board..........................................................2 1.5 Board Committee................................................2 1.6 Change of Control..............................................2 1.7 Change of Form Election........................................4 1.8 Change-of-Investment Election..................................4 1.9 Code...........................................................5 1.10 Committee......................................................5 1.11 Company........................................................5 1.12 Company Incentive Plans........................................5 1.13 Continuing Directors...........................................5 1.14 Deemed Investment Return.......................................5 1.15 Deferral Election..............................................6 1.16 Deferrals......................................................6 1.17 Effective Date.................................................6 1.18 Eligible Employee..............................................6 1.19 Employee Stock Incentive Plan..................................6 1.20 Enrollment Form................................................6 1.21 ERISA..........................................................6 1.22 Incentive Matching Allocations.................................7 1.23 Investment Election............................................7 1.24 Matching Allocation............................................7 1.25 Net Salary.....................................................7 1.26 Participant....................................................7 1.27 Participant Accounts...........................................7 1.28 Participant Company Account....................................7 1.29 Participant Deferral Account...................................8 1.30 Participant Matchable Deferral.................................8 1.31 Payment Commencement...........................................8 1.32 Phantom Investment Fund........................................8 1.33 Phantom Funds Account..........................................9 1.34 Phantom Investment Subaccount..................................9 1.35 Phantom Stock Unit.............................................9 1.36 Plan...........................................................9 1.37 Plan Year......................................................9 1.38 Plan Year Accounts.............................................9 1.39 Progress Energy 401(k) Savings & Stock Ownership Plan.........10 1.40 Retirement Date...............................................10 1.41 Salary........................................................10 i 1.42 SMC Participant...............................................10 1.43 Sponsor.......................................................10 1.44 SSERP.........................................................10 1.45 Valuation Date................................................10 1.46 Value.........................................................11 1.47 Years of Service..............................................11 ARTICLE II PARTICIPATION.............................................12 2.1 Eligibility...................................................12 2.2 Commencement of Participation.................................12 2.3 Annual Participation Agreement................................12 2.4 Election of Phantom Investment Subaccounts....................13 ARTICLE III DEFERRAL ELECTIONS........................................14 3.1 Participant Deferred Salary Elections.........................14 3.2 Matching Allocations..........................................15 3.3 Incentive Matching Allocations................................16 ARTICLE IV ACCOUNTS..................................................17 4.1 Maintenance of Accounts.......................................17 4.2 Separate Plan Year Accounts...................................17 4.3 Phantom Investment Subaccounts................................17 4.4 Administration of Deferral Accounts...........................17 4.5 Administration of Company Accounts............................18 4.6 Change of Phantom Investment Subaccounts and Phantom Stock Units...................................................20 4.7 Transferred Accounts..........................................20 ARTICLE V VESTING...................................................22 5.1 Vesting.......................................................22 ARTICLE VI DISTRIBUTIONS.............................................23 6.1 Distribution Elections........................................23 6.2 Change-of-Form Elections and Additional Deferral Elections....24 6.3 Payment.......................................................24 6.4 Unforeseeable Emergency.......................................25 6.5 Termination of Employment.....................................26 6.6 Taxes.........................................................27 6.7 Acceleration of Payment.......................................27 ARTICLE VII DEATH BENEFITS............................................28 7.1 Designation of Beneficiaries..................................28 7.2 Death Benefit.................................................28 ARTICLE VIII CLAIMS....................................................29 8.1 Claims Procedure..............................................29 8.2 Claims Review Procedure.......................................29 ii ARTICLE IX ADMINISTRATION............................................30 9.1 Committee.....................................................30 9.2 Authority.....................................................30 ARTICLE X AMENDMENT AND TERMINATION OF THE PLAN.....................32 10.1 Amendment of the Plan.........................................32 10.2 Termination of the Plan.......................................32 10.3 No Impairment of Benefits.....................................32 ARTICLE XI FUNDING AND CLAIM STATUS..................................33 11.1 General Provisions............................................33 ARTICLE XII EFFECT ON EMPLOYMENT OR ENGAGEMENT........................35 12.1 General.......................................................35 ARTICLE XIII GOVERNING LAW.............................................36 13.1 General.......................................................36 EXHIBIT A....................................................................37 iii PREAMBLE The Progress Energy, Inc. Management Deferred Compensation Plan (the "Plan") was originally adopted by Carolina Power & Light Company effective as of January 1, 2000, and was transferred to Progress Energy, Inc. (the "Sponsor") effective August 1, 2000. The Plan is unfunded and will benefit only a select group of management or highly compensated employees within the meaning of Title I of the Employee Retirement Income Security Act of 1974, as amended ("ERISA"). 1 ARTICLE I DEFINITIONS 1.1 Account Balance The value in terms of a dollar amount of a Participant's Deferral Account or Company Account, as the case may be, as of the last Valuation Date. 1.2 Additional Deferral Election The election by a Participant under Section 6.2 to defer distribution from a Plan Year Account. 1.3 Affiliated Company Any corporation or other entity that is required to be aggregated with the Sponsor pursuant to Sections 414(b), (c), (m), or (o) of the Code. 1.4 Board The Board of Directors of the Sponsor. 1.5 Board Committee The Organization and Compensation Committee of the Board. 1.6 Change of Control The earliest of the following dates: (a) the date any person or group of persons (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934), excluding employee benefit plans of the Sponsor, becomes, directly or indirectly, the "beneficial owner" (as defined in Rule 13d-3 promulgated under the Securities Act of 1934) of securities of the Sponsor representing twenty-five percent (25%) or more of the combined voting power of the Sponsor's then outstanding securities (excluding the acquisition of securities of the Sponsor by an entity at least eighty percent (80%) of the outstanding voting securities of which are, directly or indirectly, beneficially owned by the Sponsor); or 2 (b) the date of consummation of a tender offer for the ownership of more than fifty percent (50%) of the Sponsor's then outstanding voting securities; or (c) the date of consummation of a merger, share exchange or consolidation of the Sponsor with any other corporation or entity regardless of which entity is the survivor, other than a merger, share exchange or consolidation which would result in the voting securities of the Sponsor outstanding immediately prior thereto continuing to represent (either by remaining outstanding or being converted into voting securities of the surviving or acquiring entity) more than sixty percent (60%) of the combined voting power of the voting securities of the Sponsor or such surviving or acquiring entity outstanding immediately after such merger or consolidation; or (d) the date, when as a result of a tender offer or exchange offer for the purchase of securities of the Sponsor (other than such an offer by the Sponsor for its own securities), or as a result of a proxy contest, merger, share exchange, consolidation or sale of assets, or as a result of any combination of the foregoing, individuals who are Continuing Directors cease for any reason to constitute at least two-thirds (2/3) of the members of the Board; or 3 (e) the date the shareholders of the Company approve a plan of complete liquidation or winding-up of the Company or an agreement for the sale or disposition by the Company of all or substantially all of the Company's assets; or (f) the date of any event which the Board determines should constitute a Change-of-Control. A Change-of-Control shall not be deemed to have occurred until a majority of the members of the Board receive written certification from the Board Committee that one of the events set forth in this Section 1.6 has occurred. Any determination that an event described in this Section 1.6 has occurred shall, if made in good faith on the basis of information available at that time, be conclusive and binding on the Board Committee, the Company, the Participants and their beneficiaries for all purposes of the Plan. 1.7 Change of Form Election The election by a Participant under Section 6.2 to change the form of distribution of a Plan Year Account. 1.8 Change-of-Investment Election The election by a Participant under Section 4.6 to change a Phantom Subaccount for the Participant Deferral Account or Company Account. 4 1.9 Code The Internal Revenue Code of 1986, as amended, or any successor statute. 1.10 Committee The Administrative Committee described in Section 9.1 for administering the Plan. 1.11 Company Progress Energy, Inc. or any successor to it in the ownership of substantially all of its assets and each Affiliated Company that, with the consent of the Board Committee, adopts the Plan and is included in Exhibit A, as in effect from time to time. 1.12 Company Incentive Plans The Sponsor's Management Incentive Compensation Plan, or any Company sales incentive plans, marketing incentive plans, and any other cash incentive plans as determined by the Committee. 1.13 Continuing Directors The members of the Board at the Effective Date; provided, however, that any person becoming a director subsequent to such whose election or nomination for election was supported by 75% or more of the directors who then comprised Continuing Directors shall be considered to be a Continuing Director. 1.14 Deemed Investment Return The amounts that are credited (or charged) from time to time to each Participant's Deferral Account and Company Account to reflect deemed investment gains and losses of Phantom Investment Subaccounts. 5 1.15 Deferral Election An election to defer Salary pursuant to Section 3.1. 1.16 Deferrals The deferrals of Salary of a Participant pursuant to Section 3.1. 1.17 Effective Date January 1, 2000. 1.18 Eligible Employee An employee of the Company (a) who is eligible to participate in the Sponsor's Management Incentive Compensation Plan, or (b) who is eligible to participate in any other eligible Company Incentive Plan and is determined by the Committee to be eligible to be a Participant; and who is not excluded from participation pursuant to Section 2.1(b). 1.19 Employee Stock Incentive Plan The Employee Stock Incentive Plan as adopted by the Board and any successor to such plan which provides additional matching allocations under the Progress Energy 401(k) Savings & Stock Ownership Plan. 1.20 Enrollment Form The enrollment form prepared by the Company which a Participant must execute to have Deferrals with respect to a Plan Year. 1.21 ERISA The Employee Retirement Income Security Act of 1974, as amended. 6 1.22 Incentive Matching Allocations The additional match allocation which is to be allocated to a Participant's Company Account in accordance with Section 3.3. 1.23 Investment Election The election by a Participant under Sections 2.4 and 4.6 of the Phantom Investment Subaccounts in which the Participant's Deferral Accounts and Company Accounts will be allocated. 1.24 Matching Allocation A match allocation to a Participant's Company Account of a Participant's Matchable Deferrals in accordance with Section 3.2. 1.25 Net Salary The Salary of a Participant projected to be payable (assuming no deferral elections under the Plan or the Progress Energy 401(k) Savings & Stock Ownership Plan) with respect to a Plan Year reduced by the projected Deferrals of a Participant for the Plan Year under the Plan. 1.26 Participant An Eligible Employee participating in the Plan pursuant to ARTICLE II. 1.27 Participant Accounts The aggregate of a Participant's Deferral Account and Participant's Company Accounts. 1.28 Participant Company Account The notational bookkeeping account maintained under Sections 4.1 and 4.5 to record Matching Allocations and Incentive Matching Allocations on behalf of a Participant and the Deemed Investment Return thereon pursuant to the provisions of the Plan. 7 1.29 Participant Deferral Account The notational bookkeeping account maintained under Section 4.1 of the Plan to record Deferrals of a Participant and the Deemed Investment Return thereon pursuant to the provisions of the Plan. 1.30 Participant Matchable Deferral 6% of the amount of Deferrals of a Participant for a Plan Year but no greater than 6% of (A-B) where A is the compensation limit under Section 401(a)(17) of the Code for the Plan Year and B is the Net Salary of a Participant for the Plan Year (with any negative differences equating to $0 for purposes of this calculation); provided, however, that the Participant Matchable Deferrals for an SMC Participant for a Plan Year shall be an amount equal to 6% of (C - D) where C is the projected Salary of a Participant for the Plan Year and D is the compensation limit under Section 401(a)(17) of the Code for the Plan Year. Participant Matchable Deferrals for a Plan Year shall be determined for each payroll period during the Plan Year based on projected Matchable Deferrals for the entire Plan Year. 1.31 Payment Commencement The date payments are to commence with respect to a Plan Year Account in accordance with Section 6.1. 1.32 Phantom Investment Fund A deemed investment option for purposes of the Plan, each of which shall be the same as those investment options generally available to all participants in the Progress Energy 401(k) Savings & Stock Ownership Plan, or as otherwise selected by the Committee. 8 1.33 Phantom Funds Account Notational bookkeeping accounts maintained under the Plan at the direction of the Committee representing allocations of Participants of Phantom Investment Subaccounts in a Phantom Investment Fund. 1.34 Phantom Investment Subaccount A notational bookkeeping account maintained under the Plan at the direction of the Committee representing a deemed investment in one or more Phantom Investment Funds as directed by the Participant under Sections 2.4 and 4.6. 1.35 Phantom Stock Unit A hypothetical share of common stock of the Sponsor or its parent company, as applicable. 1.36 Plan The Progress Energy, Inc. Management Deferred Compensation Plan as set forth herein and as amended from time to time. 1.37 Plan Year The twelve (12) consecutive month periods beginning January 1 and ending the following December 31 commencing with the Effective Date. 1.38 Plan Year Accounts The separate Participant Deferral Account and Participant Company Account maintained under the Plan pursuant to Section 4.2 with respect to a Participant for each Plan Year a Participant has Deferrals. 9 1.39 Progress Energy 401(k) Savings & Stock Ownership Plan The Progress Energy 401(k) Savings & Stock Ownership Plan of the Company adopted by the Board, as amended from time to time, and any successor to such plan. 1.40 Retirement Date The date a Participant retires from the Company on or after attaining (i) age 65 with 5 years of service, (ii) age 55 with 15 years of service, (iii) 35 years of service or (iv) eligibility for retirement under the SSERP if covered under such plan. 1.41 Salary The amount of an Eligible Employee's regular annual base salary, payable from time to time by the Company prior to a Deferral Election under the Plan and prior to any deferral election under the Progress Energy 401(k) Savings & Stock Ownership Plan. 1.42 SMC Participant A senior executive officer of the Company who is a member of the "Senior Management Committee" of the Sponsor. 1.43 Sponsor Progress Energy, Inc. and its successors in interest. 1.44 SSERP The Supplemental Senior Executive Retirement Plan of the Company. 1.45 Valuation Date The last day of each calendar month and such other dates as selected by the Committee, in its sole discretion. 10 1.46 Value The value of an account maintained under the Plan based on the fair market value of notational investments of Phantom Investment Subaccounts and Phantom Stock Units, as the case may be, as of the last Valuation Date. For purposes of calculating Value as of the end of a Plan Year, accrued but unallocated Incentive Matching Allocations shall be taken into consideration with respect to Participant Company Accounts. 1.47 Years of Service Years of service of a Participant as calculated under the Progress Energy 401(k) Savings & Stock Ownership Plan. 11 ARTICLE II PARTICIPATION 2.1 Eligibility (a) Participation in the Plan shall be limited to Eligible Employees. (b) The Committee, in its sole discretion, may at any time limit the participation of an Eligible Employee in the Plan so as to assure that the Plan will not be subject to the provisions of parts 2, 3 and 4 of Title I of ERISA. 2.2 Commencement of Participation Each Eligible Employee on the Effective Date may elect to become a Participant as of the Effective Date by completing and submitting an Enrollment Form to the Sponsor's designated agent by November 30, 1999. An employee of the Company first becoming an Eligible Employee after January 1, 2000, may elect to become a Participant effective as of thirty days after first becoming an Eligible Employee by completing and submitting an Enrollment Form to the Sponsor's designated agent within such thirty-day period. An Eligible Employee who is not a Participant may elect to become a Participant as of the first day of a Plan Year commencing after December 31, 2000, by completing and submitting an Enrollment Form to the Sponsor's designated agent by November 30 prior to the first day of the Plan Year as of which participation is to commence. 2.3 Annual Participation Agreement Each Participant shall complete a new Enrollment Form with respect to a Plan Year by November 30 prior to the commencement of the Plan Year. If the Participant does not complete such form and submit it to the Sponsor's designated agent by November 30, the Participant will have no Deferrals for the following Plan Year. 12 2.4 Election of Phantom Investment Subaccounts Each Participant shall elect on his Enrollment Form the allocation of his Plan Year Participant Deferral Account among the Phantom Investment Subaccounts. 13 ARTICLE III DEFERRAL ELECTIONS 3.1 Participant Deferred Salary Elections (a) A Participant completing an Enrollment Form in accordance with Sections 2.2 or 2.3 may make an election, pursuant to this Section 3.1, to defer his or her Salary (a "Deferral Election") in accordance with the Plan. A Deferral Election shall apply only to the Participant's Salary for the Plan Year specified in the Enrollment Form. (b) The amount of Salary that may be deferred by a Participant shall be based on their target incentive level under the Sponsor's Management Incentive Compensation Plan ("MICP"); or, for Participants in Company Incentive Plans other than the MICP, their target incentive level assuming that they participated in the MICP. Deferral Elections shall be made on the Enrollment Form for the applicable Plan Year pursuant to the following limitations: (i) A Participant who is (or would be) eligible for a bonus at the 20% of salary target incentive level (the "Target") for the Plan Year under the MICP may defer up to 15% of Salary. (ii) A Participant who is (or would be) eligible for a bonus at the 25% of salary Target for the Plan Year under the MICP may defer up to 25% of Salary. 14 (iii) A Participant who is (or would be) eligible for a bonus at the 35% or more of salary Target under the MICP may defer up to 50% of Salary. All Deferrals shall be in increments of 5% of Salary. The minimum projected Deferrals for a Plan Year for a Participant who commences Deferrals after the beginning of a Plan Year in accordance with Section 2.2 shall be $1,000. (c) A Deferral Election once made with respect to a Plan Year, cannot be changed or revoked. In the case of a new Participant, the Deferral Election will apply only to amounts that are both paid after the election is made and earned for services performed after the election is made. The amount of Salary that is deferred pursuant to a Deferral Election will reduce the Participant Salary proportionately throughout the applicable Plan Year or, in the case of a new Participant, throughout the portion of the Plan Year to which the Deferral Election is applicable. (d) A dollar amount equal to the Salary deferred pursuant to this Section 3.1 ("Deferrals") at each applicable payroll date shall be credited to the Participant's Deferral Account within ten business days following the applicable payroll date. 3.2 Matching Allocations A Participant who has made a Deferral Election with respect to a Plan Year and has Participant Matchable Deferrals for such Plan Year shall receive a credit to his Participant Company Account of a Matching Allocation for such Plan Year. The Matching Allocation with respect to a Plan Year shall equal 50% of the Participant Matchable Deferrals. Matching Allocations shall be credited to the Participant Company Account within ten business days following the applicable payroll date, based on a pro-rata portion of projected Matchable Deferrals for the Plan Year applicable to each payroll period during the Plan Year. 15 3.3 Incentive Matching Allocations Participants with Matchable Deferrals for a Plan Year shall receive a credit to their Participant Company Account for the Plan Year of an Incentive Matching Allocation if an "Incentive Matching Allocation" is provided under the Progress Energy 401(k) Savings & Stock Ownership Plan for the Plan Year. The Incentive Matching Allocation shall equal that percentage of the Participant Matchable Deferrals for the Plan Year equal to the "Incentive Matching Allocation" (stated as a percentage) provided (or that would have been provided if the Participant participated) under the Progress Energy 401(k) Savings & Stock Ownership Plan for such Plan Year. Incentive Matching Allocations with respect to a Plan Year, if any, shall be credited to a Participant's Company Account in accordance with Section 4.5 pursuant to rules and procedures adopted by the Committee approximately coincident with the credit under the Progress Energy 401(k) Savings & Stock Ownership Plan of "Incentive Matching Allocations" following the end of a Plan Year; provided, however, no such allocation shall be made if a Participant is not employed at the end of the applicable Plan Year, unless the Participant retired, died, or became disabled during the Plan Year. 16 ARTICLE IV ACCOUNTS 4.1 Maintenance of Accounts The Committee shall maintain a Participant Deferral Account and a Participant Company Account for each Participant. There shall be credited to a Participant's Deferral Account all Deferrals by a Participant under the Plan and there shall be credited to a Participant's Company Account all Matching Allocations and Incentive Matching Allocations with respect to a Participant under the Plan in accordance with Sections 3.2 and 3.3. 4.2 Separate Plan Year Accounts The Committee shall maintain a separate Participant Deferral Account and Participant Company Account for each Plan Year a Participant has Deferrals (separately a "Plan Year Deferral Account" and a "Plan Year Company Account" and together the "Plan Year Account"). 4.3 Phantom Investment Subaccounts The Committee shall maintain separate Phantom Investment Subaccounts representing deemed investments in Phantom Investment Funds as directed by the Participant. Phantom Investment Subaccounts shall be valued as of each Valuation Date based on the notional investments of each such account, pursuant to rules and procedures adopted by the Committee. 4.4 Administration of Deferral Accounts (a) A Participant's Deferral Accounts shall be comprised in total, of units in Phantom Investment Subaccounts. 17 (b) Participants shall allocate their Deferrals among Phantom Investment Subaccounts pursuant to elections under Section 2.4. (c) The Value of that portion of a Participant's Deferral Account allocated to a Phantom Investment Subaccount shall be changed on each Valuation Date to reflect the new Value of the Phantom Investment Subaccount. (d) The interest of a Participant's Deferral Account in a Phantom Investment Subaccount shall be stated in a unit value or dollar amount, as determined by the Committee. 4.5 Administration of Company Accounts (a) A Participant's Company Account shall be comprised of Phantom Investment Fund units which shall be recorded in Phantom Investment Subaccounts. All Matching Allocations and Incentive Matching Allocations shall be recorded in Phantom Investment Subaccounts and shall be deemed invested in Phantom Stock Units, units of other Phantom Investment Funds, or a combination of Phantom Stock Units and other Phantom Investment Funds as determined by the Committee in its sole discretion. To the extent the Matching Allocations and Incentive Matching Allocations are initially deemed to be invested in Phantom Stock Units, the number of Phantom Stock Units will be determined on the date of each allocation under the Plan based on the closing price of a share of common stock of the Sponsor on the New York Stock Exchange on the date of each allocation. To the extent the Matching Allocations and Incentive Matching Allocations are initially deemed to be invested in one or more Phantom Investment Funds (other than Phantom Stock Units), the number of units in these Phantom Investment Funds will be determined on the date of each allocation under the Plan, using the closing price of the units of the underlying investment fund on which the Phantom Investment fund is based, on the date of each allocation. 18 (b) The number of Phantom Stock Units allocated to a Participant's Company Account shall be adjusted periodically to reflect the deemed reinvestment of dividends on Sponsor common stock in additional Phantom Stock Units. (c) In the event there is any change in the common stock of the Sponsor, through merger, consolidation, reorganization, recapitalization (other than pursuant to bankruptcy proceedings), stock dividend, stock split, reverse stock split, split-up, split-off, spin-off, combination of shares, exchange of shares, dividend in kind or other like change in capital structure (an "Adjustment Event"), the number of Phantom Stock Units subject to the Plan shall be adjusted by the Committee in its sole judgment so as to give appropriate effect to such Adjustment Event. Any fractional units resulting from such adjustment may be eliminated. Each successive Adjustment Event shall result in the consideration by the Committee of whether any adjustment to the number of Phantom Stock Units subject to the Plan is necessary in the Committee's judgment. Issuance of common stock or securities convertible into common stock for value will not be deemed to be an Adjustment Event unless otherwise expressly determined by the Committee. 19 4.6 Change of Phantom Investment Subaccounts and Phantom Stock Units (a) A Participant may elect to reallocate the value of his Phantom Investment Subaccounts comprising his Deferral Accounts among other Phantom Investment Subaccounts and change the allocation of future Deferrals among Phantom Investment Subaccounts once per calendar month, pursuant to uniform rules and procedures adopted by the Committee. (b) A Participant may elect to reallocate Phantom Investment Subaccounts comprising his Company Account, once per calendar month, pursuant to uniform rules adopted by the Committee. 4.7 Transferred Accounts (a) Effective as of the Effective Date, the Value of a SMC Participant's Company Account shall include the value of such Participant's deferral account as of such date (being a "Transferred Account") under the Carolina Power & Light Executive Deferred Compensation Plan, but only to the extent the Participant acknowledges in writing he has no further interest in the Executive Deferred Compensation Plan. 20 (b) Effective on the Effective Date, the Value of any Participant's Company Account shall include the value of such Participant's additional benefits (currently recorded as phantom Company stock units) granted under Article VIII.2. (also being a "Transferred Account") under the Company's Deferred Compensation Plan for Key Management Employees, but only to the extent the Participant acknowledges in writing that he has no further interest in these benefits in the Company's Deferred Compensation Plan for key Management Employees. (c) The total value of the Transferred Accounts as described in this Section 4.7 shall be deemed a vested Company Account for all purposes of the Plan. 21 ARTICLE V VESTING 5.1 Vesting A Participant's Deferral Accounts shall be 100% vested at all times. A Participant's Company Accounts shall vest in accordance with the following schedule: Years of Service Percent of Vesting Less than 1 0 1 or more 100% 22 ARTICLE VI DISTRIBUTIONS 6.1 Distribution Elections A Participant when making a Deferral Election pursuant to an Enrollment Form with respect to a Plan Year shall elect on such Enrollment Form (a) to defer the payment of his Plan Year Accounts with respect to such Plan Year, in accordance with the Plan until (i) the April 1 following the date that is five years from the last day of such Plan Year, (ii) the April 1 following the Participant's Retirement or (iii) the April 1 following the first anniversary of the Participant's Retirement (each a "Payment Commencement Date") and (b) to provide for the payment of such Plan Year Account in the form of (i) a lump sum or (ii) approximately equal installments over a period extending from two years to ten years (by paying a fraction of the account balance each year during such period), as elected by the Participant. Except as otherwise provided in this ARTICLE VI, such elections may not be changed or revoked. Notwithstanding the foregoing, if the Participant is a "key employee" as defined in Section 416(i) of the Code (but determined without regard to the 50 employee limit on the number of officers treated as key employees), payment of amounts deferred after December 31, 2004, shall not be made pursuant to an election under Section 6.1(a)(ii) above before six months after the date of separation from service for any reason including Retirement (or, if earlier, the date of death of the Participant). For this purpose, an amount will be considered deferred after December 31, 2004, if it is not earned and vested on such date, and shall include the Matching Allocation, Incentive Matching Allocation and Deemed Investment Return with respect to such Deferrals. 23 6.2 Change-of-Form Elections and Additional Deferral Elections (a) Any Participant who has made elections under Section 6.1 with respect to amounts deferred before January 1, 2005, may change such elections pursuant to this Section 6.2(a) as in effect prior to January 1, 2005, unless such provisions are materially modified after October 3, 2004. For this purpose, an amount is considered deferred before January 1, 2005, if the amount is earned and vested before such date. Such Participant may elect at least one year prior to the Payment Commencement Date with respect to such Plan Year Accounts a new Payment Commencement Date that either is five years from the then current Payment Commencement Date or otherwise is permitted under Section 6.1(a)(ii) or (iii). Only one such Additional Deferral Election will be permitted with respect to Plan Year Accounts relating to a particular Plan Year. In addition, the Participant may elect to change the form of distribution to any of the forms permitted under Section 6.1(b) by completing a Change-of-Form Elections with respect to Plan Year Accounts at least one year prior to the applicable Payment Commencement Date for such accounts. (b) Any elections made under Section 6.1 with respect to amounts deferred after December 31, 2004, shall be irrevocable. 24 6.3 Payment Upon occurrence of an event specified in the Participant's distribution election under Section 6.1 (a "Distribution Event") with respect to Plan Year Accounts, as modified by any applicable subsequent Additional Deferral Election under Section 6.2, the Account Balance of a Participant's Plan Year Accounts shall be paid by the Company to the Participant in the form elected under Section 6.1. Such payments shall commence as soon as practicable and in no event more than 30 days following the occurrence of the Distribution Event. 6.4 Unforeseeable Emergency In case of an unforeseeable emergency, a Participant may request the Committee, on a form to be provided by the Committee or its delegate, that payment of the vested portion of Participant Accounts be made earlier than the date provided under the Plan. An "unforeseeable emergency" shall mean a severe financial hardship to the Participant resulting from an illness or accident of the Participant, the Participant's spouse or a dependent (as defined in Section 152(a) of the Code) of the Participant, loss of the Participant's property due to casualty, or other unforeseeable circumstances arising as a result of events beyond the control of the Participant. The Committee shall consider any requests for payment under this Section 6.4 on a uniform and nondiscriminatory basis and in accordance with the standards of interpretation described in Section 409A of the Code and the regulations thereunder. If the request is granted, the amounts distributed will not exceed the amounts necessary to alleviate the unforeseeable emergency plus amounts necessary to pay taxes reasonably anticipated as result of the distribution, after taking into account the extent to which the unforeseeable emergency may be relieved through reimbursement or compensation by insurance or otherwise or by liquidation of the Participant's assets (to the extent such liquidation would not itself cause severe financial hardship). 25 In the event of a hardship determination by the Committee, the Company shall pay out in a lump sum to the Participant such portion of the Participant Accounts as determined by the Committee and Deferrals by the Participant for the Plan Year in which the hardship distribution is made will cease. 6.5 Termination of Employment In the event of the termination of the employment of a Participant with the Company and any parent, subsidiary or affiliate for any reason, prior to the Retirement or death of the Participant, the vested portion of the Participant Accounts of such Participant shall be paid in a lump sum to such Participant based on the Value of such accounts as of the Valuation Date coincident with or immediately preceding the date of distribution. Such payment shall be made as soon as administratively practicable following the Participant's termination date as determined under the Company's normal administrative practices. The nonvested portion of a terminated Participant's Company Account shall be forfeited by the Participant. In the event of the termination of employment of a SMC Participant for whom no Deferral Election was made for a Plan Year, any Matching Allocation, Incentive Matching Allocation and Deemed Investment Return allocated to such Participant shall be distributed to the Participant following termination of employment in accordance with this Section 6.5. In the event of the Retirement of a Participant prior to the Payment Commencement Date elected by the Participant under Section 6.1(a)(i) with respect to a Plan Year Account, distribution of such account shall commence no later than April 1 following the first anniversary of the Participant's Retirement. Notwithstanding the foregoing, if the Participant is a "key employee" as defined in Section 416(i) of the Code (but determined without regard to the 50 employee limit on the number of officers treated as key employees), payment of amounts deferred after December 31, 2004, shall not be made before six months after the date of separation from service for any reason including Retirement (or, if earlier, the date of death of the Participant). For this purpose, an amount will be considered deferred after December 31, 2004, if it is not earned and vested on such date, and shall include the Matching Allocation, Incentive Matching Allocation and Deemed Investment Return with respect to such Deferrals. 26 6.6 Taxes The Company shall deduct from all payments under the Plan federal, state and local income and employment taxes, as required by applicable law. Deferrals will be taken into account for purposes of any tax or withholding obligation under the Federal Insurance Contributions Act and Federal Unemployment Tax Act in the year of the Deferrals, as required by Sections 3121(v) and 3306(r) of the Code and the regulations thereunder. Amounts required to be withheld in the year of the Deferrals pursuant to Sections 3121(v) and 3306(r) shall be withheld out of current wages or other compensation paid by the Company to the Participant. 6.7 Acceleration of Payment The acceleration of the time or schedule of any payment due under the Plan is prohibited except as provided in regulations and administrative guidance provided under Section 409A of the Code. It is not an acceleration of the time or schedule of payment if the Company waives or accelerates the vesting requirements applicable to a benefit under the Plan. 27 ARTICLE VII DEATH BENEFITS 7.1 Designation of Beneficiaries The Participant's beneficiary under this Plan entitled to receive benefits under the Plan in the event of the Participant's death shall be designated by the Participant on a form provided by the Committee. In the absence of such designation or in the event the designated beneficiary has predeceased the Participant, the beneficiary shall be deemed the estate of the Participant. 7.2 Death Benefit In the event of the death of a Participant prior to the payout of his Participant Accounts, the Value of the remaining portion of the Participant Accounts shall be paid by the Company in a lump sum to the Participant's beneficiary (as defined under Section 7.1) based on the Value of such accounts on the Valuation Date immediately following the date of death. Payment shall be made as soon as administratively practicable following such Valuation Date pursuant to rules and procedures adopted by the Committee. 28 ARTICLE VIII CLAIMS 8.1 Claims Procedure If any Participant or his or her beneficiary has a claim for benefits which is not being paid, such claimant may file with the Committee a written claim setting forth the amount and nature of the claim, supporting facts, and the claimant's address. The Committee shall notify each claimant of its decision in writing by registered or certified mail within sixty (60) days after its receipt of a claim or, under special circumstances, within ninety (90) days after its receipt of a claim. If a claim is denied, the written notice of denial shall set forth the reasons for such denial, refer to pertinent Plan provisions on which the denial is based, describe any additional material or information necessary for the claimant to realize the claim, and explain the claims review procedure under the Plan. 8.2 Claims Review Procedure A claimant whose claim has been denied, or such claimant's duly authorized representative, may file, within sixty (60) days after notice of such denial is received by the claimant, a written request for review of such claim by the Committee. If a request is so filed, the Committee shall review the claim and notify the claimant in writing of its decision within sixty (60) days after receipt of such request. In special circumstances, the Committee may extend for up to sixty (60) additional days the deadline for its decision. The notice of the final decision of the Committee shall include the reasons for its decision and specific references to the Plan provisions on which the decision is based. The decision of the Committee shall be final and binding on all parties. 29 ARTICLE IX ADMINISTRATION 9.1 Committee The Administrative Committee consisting of not less than three (3) or more than seven (7) persons appointed by the Board Committee or its delegate to administer the Plan. 9.2 Authority (a) The Committee shall have the exclusive right to interpret the Plan to the maximum extent permitted by law, to prescribe, amend and rescind rules and regulations relating to it, and to make all other determinations necessary or advisable for the administration of the Plan, including the determination under Section 9.2(b) herein. The decisions, actions and records of the Committee shall be conclusive and binding upon the Company and all persons having or claiming to have any right or interest in or under the Plan (b) The Committee may delegate to one or more agents, or to the Company such administrative duties as it may deem advisable. The Committee may employ such legal or other counsel and consultants as it may deem desirable for the administration of the Plan and may rely upon any opinion or determination received from counsel or consultant. (c) No member of the Committee shall be directly or indirectly responsible or otherwise liable for any action taken or any failure to take action as a member of the Committee, except for such action, default, exercise or failure to exercise resulting from such member's gross negligence or willful misconduct. No member of the Committee shall be liable in any way for the acts or defaults of any other member of the Committee, or any of its advisors, agents or representatives. 30 (d) The Company shall indemnify and hold harmless each member of the Committee against any and all expenses and liabilities arising out of his or her own activities relating to the Committee, except for expenses and liabilities arising out of a member's gross negligence or willful misconduct. (e) The Company shall furnish to the Committee all information the Committee may deem appropriate for the exercise of its powers and duties in the administration of the Plan. The Committee shall be entitled to rely on any information provided by the Company without any investigation thereof. (f) No member of the Committee may act, vote or otherwise influence a decision of such Committee relating to his or her benefits, if any, under the Plan. 31 ARTICLE X AMENDMENT AND TERMINATION OF THE PLAN 10.1 Amendment of the Plan The Plan may be wholly or partially amended or otherwise modified at any time by the Board or the Board Committee consistent with the requirements of Section 409A of the Code. 10.2 Termination of the Plan The Plan may be terminated at any time by written action of the Board or the Board Committee or by the Committee as provided under the Plan; provided, that termination of the Plan shall not affect the distribution of the Participant Accounts (except as otherwise permitted under Section 409A of the Code). Notwithstanding the foregoing, the Plan may be terminated and Participant Accounts distributed to Participants within twelve months of a "change in control" as defined for purposes of Section 409A of the Code. 10.3 No Impairment of Benefits Notwithstanding the provisions of Sections 10.1 and 10.2, no amendment to or termination of the Plan shall impair any rights to benefits which theretofore accrued hereunder; provided, however, the payout of all Plan benefits on termination of the Plan, if permitted pursuant to Section 10.2, or a change of any Phantom Investment Funds or creation of a substitute for Phantom Investment Funds as a result of a Plan amendment or action of the Committee shall not constitute an impairment of any rights or benefits. 32 ARTICLE XI FUNDING AND CLAIM STATUS 11.1 General Provisions (a) The Company shall make no provision for the funding of any Participant Accounts payable hereunder that (i) would cause the Plan to be a funded plan for purposes of Section 404(a)(5) of the Code or for purposes of Title I of ERISA, or (ii) would cause the Plan to be other than an "unfunded and unsecured promise to pay money or other property in the future" under Treasury Regulations ss. 1.83-3(e); and, except in the case of a Change of Control of the Sponsor, the Company shall have no obligation to make any arrangements for the accumulation of funds to pay any amounts under this Plan. Subject to the restrictions of this Section 11.1(a), the Company, in its sole discretion, may establish one or more grantor trusts described in Treasury Regulations ss. 1.677(a)-1(d) to accumulate funds to pay amounts under this Plan, provided that the assets of such trust(s) shall be required to be used to satisfy the claims of the Company's general creditors in the event of the Company's bankruptcy or insolvency. (b) In the case of a Change of Control, the Company shall, subject to the restrictions in this paragraph and in Section 11.1(a), irrevocably set aside funds in one or more such grantor trusts in an amount that is sufficient to pay each Participant employed by such Company (or beneficiary) the net present value as of the date on which the Change of Control occurs, of the benefits to which Participants (or their beneficiaries) would be entitled pursuant to the terms of the Plan if the Value of their Participant Account would be paid in a lump sum upon the Change of Control. 33 (c) In the event that the Company shall decide to establish an advance accrual reserve on its books against the future expense of payments from any Participant, such reserve shall not under any circumstances be deemed to be an asset of this Plan but, at all times, shall remain a part of the general assets of the Company, subject to claims of the Company's creditors. (d) Participants, their legal representatives and their beneficiaries shall have no right to anticipate, alienate, sell, assign, transfer, pledge or encumber their interests in the Plan, nor shall such interests be subject to attachment, garnishment, levy or execution by or on behalf of creditors of the Participants or of their beneficiaries. (e) Participants shall have no right, title, or interest whatsoever in or to any investments which the Company may make to aid it in meeting its obligations under the Plan. Nothing contained in the Plan, and no action taken pursuant to its provisions, shall create a trust of any kind, or a fiduciary relationship between the Company and any Participant, beneficiary, legal representative or any other person. To the extent that any person acquires a right to receive payments from the Company under the Plan, such right shall be no greater than the right of an unsecured general creditor of the Company. All payments to be made hereunder with respect to a Participant shall be paid from the general funds of the Company employing such Participant. 34 ARTICLE XII EFFECT ON EMPLOYMENT OR ENGAGEMENT 12.1 General Nothing contained in the Plan shall affect, or be construed as affecting, the terms of employment or engagement of any Participant except to the extent specifically provided herein. Nothing contained in the Plan shall impose, or be construed as imposing, an obligation on the Company to continue the employment or engagement of any Participant. 35 ARTICLE XIII GOVERNING LAW 13.1 General The Plan and all actions taken in connection with the Plan shall be governed by and construed in accordance with the laws of the State of North Carolina without reference to principles of conflict of laws, except as superseded by applicable federal law. * * * 36 EXHIBIT A Progress Energy Carolinas, Inc. Progress Energy Service Company, LLC Progress Energy Ventures, Inc. Progress Energy Florida, Inc. Progress Fuels Corporation (corporate employees only) 37 EX-10 4 pei_exhibit10c12-.txt EXHIBIT 10C(12) Exhibit 10c(12) PROGRESS ENERGY, INC. MANAGEMENT CHANGE-IN-CONTROL PLAN (Amended and Restated Effective January 1, 2005) 1.0 PURPOSE OF PLAN 1.1 Purpose. The purpose of the Progress Energy, Inc. Management Change-in-Control Plan (the "Plan") is to attract and retain certain highly qualified individuals as management employees of Progress Energy, Inc. and its subsidiaries, and to provide a benefit to such management employees if their employment is terminated in connection with a Change in Control (as defined below). This Plan is intended to qualify as a "top-hat" plan under the Employee Retirement Income Security Act of 1974, as amended ("ERISA"), in that it is intended to be an "employee pension benefit plan" (as such term is defined under Section 3(2) of ERISA) which is unfunded and provides benefits only to a select group of management or highly compensated employees of the Company or any Subsidiary. The Plan amends and restates the Plan as restated effective July 10, 2002, which amended and restated the Carolina Power & Light Company Management Change-in-Control Plan which was originally adopted effective January 1, 1998. 2.0 DEFINITIONS The following terms shall have the following meanings unless the context indicates otherwise: 2.1 "Beneficiary" shall mean a beneficiary designated in writing by a Participant to receive any payments to be made under the Plan to such Participant, and if no beneficiary is designated by the Participant, then the Participant's estate shall be deemed to be the Participant's designated beneficiary. 2.2 "Board" shall mean the Board of Directors of the Company. 2.3 "Cash Payment" shall mean a payment in cash by the Company or any Subsidiary to a Participant in accordance with Section 6.1 below. 2.4 "Cause" shall mean: (a) embezzlement or theft from the Company or any Subsidiary, or other acts of dishonesty, disloyalty or otherwise injurious to the Company or any Subsidiary; (b) disclosing without authorization proprietary or confidential information of the Company or any Subsidiary; (c) committing any act of negligence or malfeasance causing injury to the Company or any Subsidiary; (d) conviction of a crime amounting to a felony under the laws of the United States or any of the several states; (e) any violation of the Company's Code of Ethics; or (f) unacceptable job performance which has been substantiated in accordance with the normal practices and procedures of the Company or any Subsidiary. 2.5 Change-in-Control" shall mean: 2.5.1 General: Except as may be otherwise required in order to comply with Code Section 409A, a Change-in-Control shall be deemed to have occurred on the earliest of the following dates: (a) the date any person or group of persons (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934), excluding employee benefit plans of the Company, becomes, directly or indirectly, the "beneficial owner" (as defined in Rule 13d-3 promulgated under the Securities Act of 1934) of securities of the Company representing twenty-five percent (25%) or more of the combined voting power of the Company's then outstanding securities (excluding the acquisition of securities of the Company by an entity at least eighty percent (80%) of the outstanding voting securities of which are, directly or indirectly, beneficially owned by the Company); or (b) the date of consummation of a tender offer for the ownership of more than fifty percent (50%) of the Company's then outstanding voting securities; or (c) the date of consummation of a merger, share exchange or consolidation of the Company with any other corporation or entity regardless of which entity is the survivor, other than a merger, share exchange or consolidation which would result in the voting securities of the Company outstanding immediately prior thereto continuing to represent (either by remaining outstanding or being converted into voting securities of the surviving or acquiring entity) more than sixty percent (60%) of the combined voting power of the voting securities of the Company or such surviving or acquiring entity outstanding immediately after such merger or consolidation; or (d) the date, when as a result of a tender offer or exchange offer for the purchase of securities of the Company (other than such an offer by the Company for its own securities), or as a result of a proxy contest, merger, share exchange, consolidation or sale of assets, or as a result of any combination of the foregoing, individuals who are Continuing Directors cease for any reason to constitute at least two-thirds (2/3) of the members of the Board; or (e) the date the shareholders of the Company approve a plan of complete liquidation or winding-up of the Company or an agreement for the sale or disposition by the Company of all or substantially all of the Company's assets; or 2 (f) the date of any event which the Board determines should constitute a Change-in-Control. A Change-in-Control shall not be deemed to have occurred until a majority of the members of the Board receive written certification from the Committee that one of the events set forth in this Section 2.5.1 has occurred. Any determination that an event described in this Section 2.5.1 has occurred shall, if made in good faith on the basis of information available at that time, be conclusive and binding on the Committee, the Company, the Participants and their Beneficiaries for all purposes of the Plan. 2.5.2 Definition Applicable to Change-in-Control Benefits Subject to Code Section 409A: Notwithstanding the preceding provisions of Section 2.5.1, in the event that any Change-in-Control Benefits under the Plan are deemed to be deferred compensation subject to the provisions of Code Section 409A, then distributions related to such benefits may be permitted, in the Committee's discretion, upon the occurrence of one or more of the following events (as they are defined and interpreted under Code Section 409A, related regulations, or other guidance): (A) a change in the ownership of the Company, (B) a change in effective control of the Company, or (C) a change in the ownership of a substantial portion of the assets of the Company. 2.6 "Change-in-Control Benefits" shall mean the benefits described under Section 6 below provided to Terminated Participants. Except as otherwise provided herein, a Terminated Participant who is terminated in anticipation of a Change-in-Control as described in Section 5.1 shall be entitled to receive the Change-in-Control Benefits as of the Termination Date notwithstanding the fact that the anticipated Change-in-Control does not occur. 2.7 "Change-in-Control Date" shall mean the date that a Change-in-Control first occurs. 2.8 "Code" shall mean the Internal Revenue Code of 1986, as amended from time to time. 2.9 "Committee" shall mean (i) the Board or (ii) a committee or subcommittee of the Board appointed by the Board from among its members. The Committee shall be the Board's Committee on Organization and Compensation until a different Committee is appointed. On a Change-in-Control Date, and during the 36-month period following such Change-in-Control Date, the Committee shall be comprised of such persons as appointed by the Board prior to the Change-in-Control Date, with any additions or changes to the Committee following such Change-in-Control Date to be made and or approved by all Committee members then in office. 2.10 "Company" shall mean Progress Energy, Inc., a North Carolina corporation, including any successor entity or any successor to the assets of the Company that has assumed the Plan. 2.11 "Continuing Directors" shall mean the members of the Board as of the Effective Date; provided, however, that any person becoming a director subsequent to such date whose election or nomination for election was supported by seventy-five percent (75%) or more of the directors who then comprised Continuing Directors shall be considered to be a Continuing Director. 3 2.12 "Effective Date" of the Plan, as amended and restated herein, shall mean January 1, 2005. 2.13 "Good Reason" shall mean the occurrence of any of the following: (a) a reduction in the Participant's base salary without the Participant's prior written consent (other than any reduction applicable to management employees generally); (b) a material adverse change in the Participant's position, duties or responsibilities with respect to his or her employment with the Company and/or any Subsidiary without the Participant's prior written consent; (c) a material reduction in the Participant's total incentive compensation opportunity under the Company's Management Incentive Compensation Plan, the 1997 Equity Incentive Plan, the 2002 Equity Incentive Plan, the Performance Share Sub-Plans, or any other incentive compensation plan (based on the total incentive compensation opportunity previously granted to such Participant during the 12-month period preceding a Change-in-Control Date) without the Participant's prior written consent; (d) an actual change in the Participant's principal work location by more than 50 miles and more than 50 miles from the Participant's principal place of abode as of the date of such change in job location without the Participant's prior written consent; (e) the failure of the Company to obtain the assumption of its obligation under the Plan by any successor to all or substantially all of the assets of the Company within 30 days after a merger, consolidation, sale or similar transaction constituting a Change-in-Control; or (f) a material breach by the Company of any term or provision of the Plan without the Participant's prior written consent. 2.14 "Gross-Up Payment" shall mean a payment described in Section 11 below. 2.15 "Management Employee" shall mean a regular full-time employee of the Company or any Subsidiary with managerial duties and responsibilities. 2.16 "Participant" shall mean any Management Employee who has been designated to participate in the Plan under Section 3 below. 2.17 "Plan" shall mean the Progress Energy, Inc. Management Change-in-Control Plan. 2.18 "Retirement" shall mean the termination of employment of a Participant after having attained the age of 65 with five or more years of service, or the age of 55 with 15 or more years of service, or after having completed 35 or more years of service regardless of age. 2.19 "Subsidiary" shall mean a corporation of which the Company directly or indirectly owns more than fifty percent (50%) of the voting stock (meaning the capital stock of any class or classes having general voting power under ordinary circumstances, in the absence of contingencies, to elect the directors of a corporation) or any other business entity in which the Company directly or indirectly has an ownership interest of more than 50 percent. 4 2.20 "Terminated Participant" shall mean a Participant whose employment is terminated as described in Section 5 below; provided, however, that a Participant who is reemployed by the Company or any Subsidiary without an intervening break in service shall not be a Terminated Participant for purposes of this Plan. 2.21 "Termination Date" shall mean the date a Terminated Participant's employment with the Company and/or a Subsidiary is terminated as described in Section 5 below. 2.22 "Trigger Trust" shall mean a trust as described in Section 8 below. 3.0 ELIGIBILITY AND PARTICIPATION 3.1 Eligibility. An individual shall be eligible to participate in the Plan who is a Management Employee in one of the following positions: (a) Tier I - Chief Executive Officer, Chief Operating Officer, President and Executive Vice Presidents who are members of the Senior Management Committee of the Company. (b) Tier II - Senior Vice Presidents who are members of the Senior Management Committee of the Company. (c) Tier III - Vice Presidents, Department Heads and other selected Management Employees of the Company or any Subsidiary. 3.2 Participation. The Committee shall designate each eligible Management Employee who is a Participant in the Plan. The Committee may, in its sole discretion, terminate the participation of a Participant at any time prior to the date that substantive negotiations occur in connection with a potential Change-in-Control. 4.0 ADMINISTRATION 4.1 Responsibility. The Committee shall have the responsibility, in its sole discretion, to control, operate, manage and administer the Plan in accordance with its terms. 4.2 Authority of the Committee. The Committee shall have the maximum discretionary authority permitted by law that may be necessary to enable it to discharge its responsibilities with respect to the Plan, including but not limited to the following: (a) to determine eligibility for participation in the Plan; (b) to designate Participants; (c) to determine and establish the formula to be used in calculating a Participant's Change-in-Control Benefits; (d) to correct any defect, supply any omission, or reconcile any inconsistency in the Plan in such manner and to such extent as it shall deem appropriate in its sole discretion to carry the same into effect; 5 (e) to issue administrative guidelines as an aid to administer the Plan and make changes in such guidelines as it from time to time deems proper; (f) to make rules for carrying out and administering the Plan and make changes in such rules as it from time to time deems proper; (g) to the extent permitted under the Plan, grant waivers of Plan terms, conditions, restrictions, and limitations; (h) to make reasonable determinations as to a Participant's eligibility for benefits under the Plan, including determinations as to Cause and Good Reason; and (i) to take any and all other actions it deems necessary or advisable for the proper operation or administration of the Plan. 4.3 Action by the Committee. The Committee may act only by a majority of its members. Any determination of the Committee may be made, without a meeting, by a writing or writings signed by all of the members of the Committee. In addition, the Committee may authorize any one or more of its members to execute and deliver documents on behalf of the Committee. 4.4 Delegation of Authority. The Committee may delegate to one or more of its members, or to one or more agents, such administrative duties as it may deem advisable; provided, however, that any such delegation shall be in writing. In addition, the Committee, or any person to whom it has delegated duties as aforesaid, may employ one or more persons to render advice with respect to any responsibility the Committee or such person may have under the Plan. The Committee may employ such legal or other counsel, consultants and agents as it may deem desirable for the administration of the Plan and may rely upon any opinion or computation received from any such counsel, consultant or agent. Expenses incurred by the Committee in the engagement of such counsel, consultant or agent shall be paid by the Company, or the Subsidiary whose employees have benefited from the Plan, as determined by the Committee. 4.5 Determinations and Interpretations by the Committee. All determinations and interpretations made by the Committee shall be binding and conclusive to the maximum extent permitted by law on all Participants and their heirs, successors, and legal representatives. 4.6 Information. The Company shall furnish to the Committee in writing all information the Committee may deem appropriate for the exercise of its powers and duties in the administration of the Plan. Such information may include, but shall not be limited to, the full names of all Participants, their earnings and their dates of birth, employment, retirement or death. Such information shall be conclusive for all purposes of the Plan, and the Committee shall be entitled to rely thereon without any investigation thereof. 4.7 Self-Interest. No member of the Committee may act, vote or otherwise influence a decision of the Committee specifically relating to his or her benefits, if any, under the Plan. 6 5.0 TERMINATION OF EMPLOYMENT 5.1 Termination of Employment. If the Company or a Subsidiary employing a Participant terminates such Participant's employment without Cause, or if a Participant terminates his or her employment with the Company or a Subsidiary for Good Reason, and in either case such termination of employment is not due to the death or Retirement of the Participant, and such termination of employment occurs during the 24-month period following the Change-in-Control Date, or occurs prior to the Change-in-Control Date but after substantive negotiations leading to the Change-in-Control and can be demonstrated to have occurred at the request or initiation of parties to the Change-in-Control (such date of termination of employment shall be referred to herein as the "Termination Date"), the Terminated Participant shall be entitled to receive the Change-in-Control Benefits in accordance with Section 6 below. 6.0 CHANGE-IN-CONTROL BENEFITS 6.1 Cash Payment. Within ten days following the Termination Date, the Company shall pay to the Terminated Participant, in a lump sum, an amount in cash as determined under a formula established by the Committee (such formula to be established by the Committee, in its sole discretion, on the date the Committee designates such individual as a Participant in accordance with Section 3.2 above); provided, however, that such Cash Payment shall not exceed in the aggregate an amount equal to the sum of: (a) The Applicable Percentage of the Terminated Participant's annual base salary in effect on the Termination Date; plus (b) The Applicable Percentage of the greater of (i) the average of the Terminated Participant's annual incentive bonus paid to the Terminated Participant under the Company's Management Incentive Compensation Plan or otherwise with respect to the three completed calendar years immediately preceding the year in which the Termination Date occurs; provided, however, that if the Terminated Participant was not eligible to receive an annual incentive bonus with respect to each of the three calendar years immediately preceding the year in which the Termination Date occurs, the average shall be determined for that period of calendar years, if any, for which the Terminated Participant was eligible to receive an annual incentive bonus, or (ii) the Terminated Participant's target annual incentive bonus for the year in which the Termination Date occurs. For this purpose, the "Applicable Percentage" shall be determined as follows: Participant Applicable Percentage Tier I 300% Tier II 200% Tier III 150% 7 6.2 Annual Cash Incentive Compensation Plans. The Terminated Participant shall be entitled to receive an amount equal to his or her compensation under the annual cash incentive compensation plan covering the Terminated Participant based on 100 percent (100%) of his or her target bonus under such plan, which shall be paid during the 10-day period following the Termination Date. 6.3 Long Term Compensation Plan. The Terminated Participant shall be entitled to receive any awards which have been earned prior to the Termination Date under the Company's Amended and Restated Long Term Compensation Plan, which shall be paid during the 10-day period following the Termination Date. 6.4 Restricted Stock Agreements. The Terminated Participant shall become vested as of the Termination Date in any restricted share awards which have been granted to him or her under the Company's 1997 Equity Incentive Plan, the 2002 Equity Incentive Plan or any successor plans, and such shares shall be delivered to him or her without restriction during the 10-day period following the Termination Date. 6.5 Performance Share Sub-Plans. The Terminated Participant shall become vested as of the Termination Date in any awards which have been granted to such Participant under the Company's Performance Share Sub-Plans. The Terminated Participant shall be entitled to payment of any awards which have been granted to him or her under such plans prior to the Termination Date within ten days following the date that the data needed to calculate the value of the awards is available to the Company. 6.6 Stock Option Agreements. Except to the extent that greater rights are provided to the Terminated Participant under the terms of a Stock Option Agreement between the Terminated Participant and the Company, the Terminated Participant shall have the following rights under any Stock Option Agreement following the Termination Date: (a) Option Assumed by Successor. If the Stock Option Agreement has been assumed by the successor to the Company on or before the Change-in-Control Date, any options not previously forfeited shall vest in accordance with the terms of the Stock Option Agreement and any vested options may be exercised by the Terminated Participant during the remaining term of such options notwithstanding the termination of employment by the Terminated Participant. (b) Option Not Assumed by Successor. If the Stock Option Agreement has not been assumed by the successor on or before the Change-in-Control Date, any outstanding options shall be fully vested as of the Change-in-Control Date and, in lieu of exercise, the value of such options shall be paid to the Terminated Participant in an amount equal to the excess, if any, of the aggregate fair market value as of the Change-in-Control Date of the shares subject to such options over the aggregate exercise price for such shares. Such payment shall be made during the 10-day period following the later of (i) the Termination Date, or (ii) the Change-in-Control Date. Notwithstanding the foregoing, if the Terminated Participant was terminated in anticipation of a Change-in-Control as described in Section 5.1 and the anticipated Change-in-Control does not occur, this Section 6.6(b) shall not apply and the terms of the Stock Option Agreement shall control. 8 For purposes of this Section 6.6, the successor shall be deemed to have "assumed" a Stock Option Agreement if the excess of the aggregate fair market value of the shares subject to the options over the aggregate exercise price immediately after the assumption is no less than the excess of the aggregate fair market value of the shares subject to the options over the aggregate exercise price immediately prior to the assumption. 6.7 Other Company Incentive Compensation Plans. The Terminated Participant shall become vested as of the Termination Date in any awards which have been granted to such Participant under any Company incentive compensation plan, program or agreements (other than those plans or agreements specified in Sections 6.2, 6.3, 6.4, 6.5 and 6.6 above) prior to the Termination Date. A Terminated Participant shall be entitled to (i) payment of any cash awards and (ii) delivery of any unrestricted shares (if such award is in the form of restricted stock), which have been granted to him or her under such plan(s) prior to the Termination Date during the 10-day period following the Termination Date. 6.8 Payment of Change-in-Control Benefits to Beneficiaries. In the event of the Participant's death, all Change-in-Control Benefits that would have been paid to the Participant under this Section 6 but for his or her death shall be paid to the Participant's Beneficiary. 7.0 PARTICIPATION IN NONQUALIFIED PENSION AND WELFARE BENEFIT PLANS 7.1 Nonqualified Deferred Compensation Plans; Restoration Retirement Plan. The Terminated Participant shall be entitled to payment of his or her benefit in any nonqualified deferred compensation or restoration pension plan of the Company (including, but not limited to, the Management Deferred Compensation Plan, the Deferred Compensation Plan for Key Management Employees and the Restoration Retirement Plan) in accordance with the terms of such plan. 7.2 Supplemental Senior Executive Retirement Plan. A Terminated Participant who is a participant in the Company's Supplemental Senior Executive Retirement Plan shall (i) be deemed to have a minimum of three years of service on the Senior Management Committee and (ii) receive a grant of additional service so that such Terminated Participant has a minimum of ten years of service with the Company for benefit purposes. The Terminated Participant shall be entitled to payment of his or her benefit under the Supplemental Senior Executive Retirement Plan in accordance with the terms of such plan upon reaching the earliest age for receipt of benefits (including any additional credited service described in the previous sentence and as if such Terminated Participant has met the service requirements for such benefits). 7.3 Split-Dollar Life Insurance Policies. Following the Termination Date, the Terminated Participant shall be entitled to payment by the Company of all premiums due under any split-dollar life insurance arrangement of the Company (including, but not limited to, the Split Dollar Life Insurance Plan, the Executive Estate Conservation Plan and the Executive Permanent Life Insurance Plan) for any life insurance policy under which the Terminated Participant is the insured that come due during the Applicable Period following the Termination Date. 9 7.4 Employee Welfare Benefits. The Company or the applicable Subsidiary shall pay the total cost for the Terminated Participant to continue coverage after the Termination Date in the medical, dental, vision, and life insurance plans of the Company or the applicable Subsidiary in which he or she was participating on the Termination Date until the earlier of: (a) the end of the Applicable Period following the Termination Date; (b) the date, or dates, he or she receives comparable coverage and benefits under the plans, programs and/or arrangements of a subsequent employer (such coverage and benefits to be determined on a coverage-by-coverage or benefit-by-benefit basis); or (c) the Retirement of the Terminated Participant. Notwithstanding the foregoing, however, the termination of the Participant shall constitute a qualifying event with respect to the right of the Terminated Participant and any covered dependents to continue group medical, dental and vision coverage in accordance with COBRA, and the continuation period for purposes of COBRA shall run concurrently with the Applicable Period. 7.5 Applicable Period. For purposes of Section 7.3 and 7.4, the Applicable Period shall be determined as follows: Participant Applicable Period Tier I 36 Months Tier II 24 Months Tier III 18 Months 8.0 TRIGGER TRUST 8.1 Establishment of Trigger Trust. The Board may, in its sole discretion, establish or cause to be established a Trigger Trust as described in Section 8.2 below, the purpose of which is to provide a fund for the payment of some or all of the Change-in-Control Benefits and other benefits under Sections 6 and 7 above to Terminated Participants following a Change-in-Control Date, and such other benefits as may be determined by the Board from time to time. 8.2 Trigger Trust Requirements. The Trigger Trust shall be a trust: (a) of which the Company is the grantor, within the meaning of subpart E, part I, subchapter J, chapter 1, subtitle A of the Code; (b) under which all Participants as of the Change-in-Control Date are beneficiaries; and (c) the assets of which shall be subject to the claims of the Company's general creditors in accordance with Internal Revenue Service Revenue Procedure 92-64. 10 9.0 CLAIMS 9.1 Claims Procedure. If any Participant or Beneficiary, or their legal representative, has a claim for benefits which is not being paid, such claimant may file a written claim with the Committee setting forth the amount and nature of the claim, supporting facts, and the claimant's address. Written notice of the disposition of a claim by the Committee shall be furnished to the claimant within 90 days after the claim is filed. In the event of special circumstances, the Committee may extend the period for determination for up to an additional 90 days, in which case it shall so advise the claimant. If the claim is denied, the reasons for the denial shall be specifically set forth in writing, the pertinent provisions of the Plan will be cited, including an explanation of the Plan's claim review procedure, and, if the claim is perfectible, an explanation as to how the claimant can perfect the claim shall be provided. 9.2 Claims Review Procedure. If a claimant whose claim has been denied wishes further consideration of his or her claim, he or she may request the Committee to review his or her claim in a written statement of the claimant's position filed with the Committee no later than 60 days after receipt of the written notification provided for in Section 9.1 above. The Committee shall fully and fairly review the matter and shall promptly advise the claimant, in writing, of its decision within the next 60 days. Due to special circumstances, the Committee may extend the period for determination for up to an additional 60 days. 9.3 Reimbursement of Expenses. If there is any dispute between the Company and a Participant with respect to a claim under the Plan, the Company shall reimburse such Participant all reasonable fees, costs and expenses incurred by such Participant with respect to such disputed claim; provided, however, that (i) such Participant is the prevailing party with respect to such disputed claim or (ii) the disputed claim is settled. 10.0 TAXES 10.1 Withholding Taxes. The Company shall be entitled to withhold from any and all payments made to a Participant under the Plan all federal, state, local and/or other taxes or imposts which the Company determines are required to be so withheld from such payments or by reason of any other payments made to or on behalf of the Participant or for his or her benefit hereunder. 10.2 No Guarantee of Tax Consequences. No person connected with the Plan in any capacity, including, but not limited to, the Company and any Subsidiary and their directors, officers, agents and employees makes any representation, commitment, or guarantee that any tax treatment, including, but not limited to, federal, state. and local income, estate and gift tax treatment, will be applicable with respect to amounts deferred under the Plan, or paid to or for the benefit of a Participant under the Plan, or that such tax treatment will apply to or be available to a Participant on account of participation in the Plan. 11 11.0 ADDITIONAL PAYMENTS 11.1 Gross-Up Payment. In the event that any payment or benefit received or to be received by any Participant pursuant to the terms of the Plan (the "Plan Payments") or of any other plan, arrangement or agreement of the Company or any Subsidiary ("Other Payments" and, together with the Plan Payments, the "Payments") would be subject to the excise tax (the "Excise Tax") imposed by Section 4999 of the Code as determined as provided below, the Company shall pay to such Participant, at the time specified in Section 11.3 below, an additional amount (the "Gross-Up Payment") such that the net amount retained by such Participant, after deduction of the Excise Tax on Payments and any federal, state and local income tax and any additional Excise Tax upon the Gross-Up Payment, and any interest, penalties or additions to tax payable by such Participant with respect thereto, shall be equal to the total present value (using the applicable federal rate (as defined in Section 1274(d) of the Code in such calculation) of the Payments at the time such Payments are to be made. Notwithstanding the foregoing provisions of this Section 11.1, if it shall be determined that a Participant in Tier II or Tier III is entitled to a Gross-Up Payment, but that the Payments would not be subject to the Excise Tax if the Payments were reduced by an amount that does not exceed ten percent (10%) of the portion of the Payments that would be treated as "parachute payments" under Section 280G of the Code, then the Plan Payments shall be reduced (but not below zero) to the maximum amount that could be paid to the Participant without giving rise to the Excise Tax (the "Safe Harbor Cap"), and no Gross-Up Payment shall be made to the Participant. The reduction of the Plan Payments hereunder, if applicable, shall be made by reducing first the Cash Payment under Section 6.1, unless an alternative method of reduction is elected by the Participant and agreed to by the Committee. For purposes of reducing the Payments to the Safe Harbor Cap, only Plan Payments (and no other Payments) shall be reduced. If the reduction of the Plan Payments would not result in a reduction of the Payments to the Safe Harbor Cap, no amounts payable under this Plan shall be reduced pursuant to this provision. 11.2 Determination. For purposes of determining whether any of the Payments will be subject to the Excise Tax and the amounts of such Excise Tax: (a) the total amount of the Payments shall be treated as "parachute payments" within the meaning of Section 280G(b)(2) of the Code, and all "excess parachute payments" within the meaning of Section 280G(b)(1) of the Code shall be treated as subject to the Excise Tax, except to the extent that, in the opinion of independent counsel selected by the Company and reasonably acceptable to such Participant ("Independent Counsel"), a Payment (in whole or in part) does not constitute a "parachute payment" within the meaning of Section 280G(b)(2) of the Code, or such "excess parachute payments" (in whole or in part) are not subject to the Excise Tax; (b) the amount of the Payments that shall be treated as subject to the Excise Tax shall be equal to the lesser of (i) the total amount of the Payments or (ii) the amount of "excess parachute payments" within the meaning of Section 280G(b)(1) of the Code (after applying Section 11.2(a) above); and (c) the value of any noncash benefits or any deferred payment or benefit shall be determined by Independent Counsel in accordance with the principles of Sections 280G(d)(3) and (4) of the Code. 12 For purposes of determining the amount of the Gross-Up Payment, such Participant shall be deemed to pay federal income taxes at the highest marginal rates of federal income taxation applicable to the individuals in the calendar year in which the Gross-Up Payment is to be made and state and local income taxes at the highest marginal rates of taxation applicable to individuals as are in effect in the state and locality of such Participant's residence in the calendar year in which the Gross-Up Payment is to be made, net of the maximum reduction in federal income taxes that can be obtained from deduction of such state and local taxes, taking into account any limitations applicable to individuals subject to federal income tax at the highest marginal rates. 11.3 Date of Payment of Gross-Up Payments. The Gross-Up Payments provided for in Section 11.1 above shall be paid upon the earlier of (i) the payment to such Participant of any Payment or (ii) the imposition upon such Participant or payment by such Participant of any Excise Tax. 11.4 Adjustment. If it is established pursuant to a final determination of a court or an Internal Revenue Service proceeding or the opinion of Independent Counsel that the Excise Tax is less than the amount taken into account under Section 11.1 above, such Participant shall repay to the Company within 30 days of such Participant's receipt of notice of such final determination or opinion the portion of the Gross-Up Payment attributable to such reduction (plus the portion of the Gross-Up Payment attributable to the Excise Tax and federal, state and local income tax imposed on the Gross-Up Payment being repaid by such Participant if such repayment results in a reduction in Excise Tax or a federal, state and local income tax deduction) plus any interest received by such Participant on the amount of such repayment. If it is established pursuant to a final determination of a court or an Internal Revenue Service proceeding or the opinion of independent Counsel that the Excise Tax exceeds the amount taken into account hereunder (including by reason of any payment the existence or amount of which cannot be determined at the time of the Gross-Up Payment), the Company shall make an additional Gross-Up Payment in respect of such excess within 30 days of the Company's receipt of notice of such final determination or opinion. 11.5 Further Interpretation of Section 280G or 4999 of the Code. In the event of any change in, or further interpretation of, Section 280G or 4999 of the Code and the regulations promulgated thereunder, such Participant shall be entitled, by written notice to the Company, to request an opinion of Independent Counsel regarding the application of such change to any of the foregoing, and the Company shall use its best efforts to cause such opinion to be rendered as promptly as practicable. All fees and expenses of Independent Counsel incurred in connection with this agreement shall be borne by the Company. 12.0 TERM OF PLAN; AMENDMENT AND TERMINATION 12.1 Term of Plan, Amendment, Termination. The Plan shall be effective as of the Effective Date and shall remain in effect until the Board terminates the Plan. The Plan may be terminated, suspended or amended by the Board at any time with or without prior notice prior to a Change-in-Control; provided, however, that the Plan shall not be terminated, suspended or amended on a Change-in-Control Date or during the 3-year period following such Change-in-Control Date, and if the Plan is terminated, suspended or amended thereafter, such action shall not adversely affect the benefits of any Terminated Participant. 13 13.0 COMPLIANCE WITH CODE SECTION 409A 13.1 General. Notwithstanding any other provision in the Plan to the contrary, if and to the extent that Section 409A of the Code is deemed to apply to the Plan or any Change-in-Control Benefit provided under the Plan, it is the general intention of the Company that the Plan and all such benefits shall comply with Code Section 409A, related regulations or other guidance, and the Plan and any such Change-in-Control Benefit shall, to the extent practicable, be construed in accordance therewith. Without in any way limiting the effect of the foregoing, in the event that Code Section 409A, related regulations or other guidance require that any special terms, provisions or conditions be included in the Plan or any Change-in-Control Benefit, then such terms, provisions and conditions shall, to the extent practicable, be deemed to be made a part of the Plan or Change-in-Control Benefit, as applicable. Further, in the event that the Plan or any Change-in-Control Benefit shall be deemed not to comply with Code Section 409A or any related regulations or other guidance, then neither the Company, the Committee nor its or their designees or agents shall be liable to any Participant or other person for actions, decisions or determinations made in good faith. 13.2 Specific Terms Applicable to Change-in-Control Benefits Subject to Code Section 409A. Without limiting the effect of Section 13.1 above, and notwithstanding any other provision in the Plan to the contrary, the following provisions shall, to the extent required under Code Section 409A, related regulations or other guidance, apply with respect to Change-in-Control Benefits deemed to involve the deferral of compensation under Code Section 409A: (a) Distributions: Distributions may be made with respect to Change-in-Control Benefits subject to Code Section 409A not earlier than upon the occurrence of one or more of the following events: (A) separation of service; (B) disability; (C) death; (D) a specified time or pursuant to a fixed schedule; (E) a change in the ownership or effective control of the Company, or in the ownership of a substantial portion of the assets of the Company, as defined in Section 2.5.2; or (F) the occurrence of an unforeseeable emergency. Each of the preceding distribution events shall be defined and interpreted in accordance with Code Section 409A and related regulations or other guidance. (b) Key Employees: With respect to Participants who are "key employees" (as defined in Code Section 409A, related regulations or other guidance), a distribution due to separation of service may not be made before the date that is six months after the Termination Date (or, if earlier, the date of death of the Participant), except as may be otherwise permitted pursuant to Code Section 409A, related regulations or other guidance. To the extent that a Participant is subject to this section and a distribution is to be paid in installments, through an annuity, or in some other manner where payment will be periodic, the Participant shall be paid, during the seventh month following the Termination Date, the aggregate amount of payments he would have received but for the application of this section; all remaining payments shall be made in their ordinary course. (c) No Acceleration: Unless permissible under Code Section 409A, related regulations or other guidance, the acceleration of the time or schedule for the payment of any Change-in-Control Benefit under the Plan is prohibited. 14 14.0 MISCELLANEOUS 14.1 Offset. The Change-in-Control Benefits shall be reduced by any payment or benefit made or provided by the Company or any Subsidiary to the Participant pursuant to (i) any severance plan, program, policy or arrangement of the Company or any subsidiary of the Company not otherwise referred to in the Plan, (ii) any employment agreement between the Company or any Subsidiary and the Participant, and (iii) any federal, state or local statute, rule, regulation or ordinance. 14.2 No Right, Title, or Interest in Company Assets. Participants shall have no right, title, or interest whatsoever in or to any assets of the Company or any investments which the Company may make to aid it in meeting its obligations under the Plan. Nothing contained in the Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust of any kind, or a fiduciary relationship between the Company and any Participant, Beneficiary, legal representative or any other person. To the extent that any person acquires a right to receive payments from the Company under the Plan, such right shall be no greater than the right of an unsecured general creditor of the Company. Subject to Section 8 above, all payments to be made hereunder shall be paid from the general funds of the Company and no special or separate fund shall be established and no segregation of assets shall be made to assure payment of such amounts except as expressly set forth in the Plan. 14.3 No Right to Continued Employment. The Participant's rights, if any, to continue to serve the Company or any Subsidiary as an employee shall not be enlarged or otherwise affected by his or her designation as a Participant under the Plan, and the Company or the applicable Subsidiary reserves the right to terminate the employment of any employee at any time. The adoption of the Plan shall not be deemed to give any employee, or any other individual any right to be selected as a Participant or to continued employment with the Company or any Subsidiary. 14.4 Other Rights. The Plan shall not affect or impair the rights or obligations of the Company, any Subsidiary or a Participant under any other written plan, contract, arrangement, or pension, profit sharing or other compensation plan. 14.5 Governing Law. The Plan shall be governed by and construed in accordance with the laws of the State of North Carolina without reference to principles of conflict of laws, except as superseded by applicable federal law. 14.6 Severability. If any term or condition of the Plan shall be invalid or unenforceable to any extent or in any application, then the remainder of the Plan, with the exception of such invalid or unenforceable provision, shall not be affected thereby and shall continue in effect and application to its fullest extent. 14.7 Incapacity. If the Committee determines that a Participant or a Beneficiary is unable to care for his or her affairs because of illness or accident or because he or she is a minor, any benefit due the Participant or Beneficiary may be paid to the Participant's spouse or to any other person deemed by the Committee to have incurred expense for such Participant (including a duly appointed guardian, committee or other legal representative), and any such payment shall be a complete discharge of the Company's obligation hereunder. 15 14.8 Transferability of Rights. The Company shall have the unrestricted right to transfer its obligations under the Plan with respect to one or more Participants to any person, including, but not limited to, any purchaser of all or any part of the Company's business. No Participant or Beneficiary shall have any right to commute, encumber, transfer or otherwise dispose of or alienate any present or future right or expectancy which the Participant or Beneficiary may have at any time to receive payments of benefits hereunder, which benefits and the right thereto are expressly declared to be non-assignable and nontransferable, except to the extent required by law. Any attempt to transfer or assign a benefit, or any rights granted hereunder, by a Participant or the spouse of a Participant shall, in the sole discretion of the Committee (after consideration of such facts as it deems pertinent), be grounds for terminating any rights of the Participant or Beneficiary to any portion of the Plan benefits not previously paid. 16 EX-10 5 pei_exhibit10c13-.txt EXHIBIT 10C(13) Exhibit 10c(13) EXHIBIT A TO 2002 EQUITY INCENTIVE PLAN PERFORMANCE SHARE SUB-PLAN (Effective January 1, 2005) This Performance Share Sub-Plan ("Sub-Plan") sets forth the rules and regulations adopted by the Committee for issuance of Performance Share Awards under Section 10 of the 2002 Equity Incentive Plan ("Plan"). These rules and regulations shall apply to Awards granted effective on and after January 1, 2005. In addition, the rules and regulations relating to the deferral of Awards set forth in this Sub-Plan shall apply to any Awards which become vested on or after January 1, 2005. Capitalized terms used in this Sub-Plan that are not defined herein shall have the meaning given in the Plan. In the event of any conflict between this Sub-Plan and the Plan, the terms and conditions of the Plan shall control. No Award Agreement shall be required for participation in this Sub-Plan. Section 1. Definitions When used in this Sub-Plan, the following terms shall have the meanings as set forth below, and are in addition to the definitions set forth in the Plan. 1.1 "Account" means the account used to record and track the number of Performance Shares granted to each Participant as provided in Section 2.4. 1.2 "Award" as used in this Sub-Plan means each aggregate award of Performance Shares as provided in Section 2.2. 1.3 "EBITDA" means earnings before interest, taxes, depreciation, and amortization as determined from time to time by the Committee. 1.4 "EBITDA Growth" means the percentage increase (if any) in EBITDA for any Year, as compared to the previous Year as determined from time to time by the Committee. 1.5 "Peer Group" means the peer group of utilities designated by the Committee prior to the beginning of the Performance Period for which an Award is granted. 1.6 "Performance Period" for purposes of this Sub-Plan means three consecutive Years beginning with the Year in which an Award is granted. 1.7 "Performance Schedule" means Attachment 1 to this Sub-Plan, which sets forth the Performance Measures applicable to this Sub-Plan. 1.8 "Performance Share" for purposes of this Sub-Plan means each unit of an Award granted to a Participant, the value of which is equal to the value of Company Stock as hereinafter provided. 1.9 "Retire" or "Retirement" means termination of employment on or after: (a) becoming 65 years old with at least 5 years of service; (b) becoming 55 years old with at least 15 years of service; or (c) achieving at least 35 years of service, regardless of age. 1.10 "Salary" means the regular base rate of compensation payable by the Company to a Participant on an annual basis. Salary does not include bonuses, if any, or incentive compensation, if any. Such compensation shall not be reduced by any deferrals made under any other plans or programs maintained by the Company. 1.11 "Total Shareholder Return" means the total percentage return realized by the owner of a share of stock during a relevant Year or any part thereof. Total Shareholder Return is equal to the appreciation or depreciation in value of the stock (which is equal to the closing value of the stock on the last trading day of the relevant period minus the closing value of the stock on the last trading day of the preceding Year) plus the dividends declared during the relevant period, divided by the closing value of the stock on the last trading day of the preceding Year. 1.12 "Year" means a calendar year. Section 2. Sub-Plan Participation and Awards 2.1 Participant Selection. Participants under this Sub-Plan shall be selected by the Committee in its sole discretion as provided in Section 4.2 of the Plan. 2.2 Awards. Subject to any adjustments to be made under Section 2.5, the Compensation Committee may, in its sole discretion, grant Awards to some or all of the Participants in the form of a specific number of Performance Shares. The target and maximum value of any Award granted to any Participant in any calendar Year will be based upon the following: 2 -------------------------------------------------------------------------- Participant Target Award Maximum Award -------------------------------------------------------------------------- CEO* 290% of Salary 362.5% of Salary -------------------------------------------------------------------------- COO* 200% of Salary 250% of Salary -------------------------------------------------------------------------- Presidents*/Executive VPs* 133% of Salary 166.25% of Salary -------------------------------------------------------------------------- Senior VPs* 110% of Salary 137.5% of Salary -------------------------------------------------------------------------- VP/Department Heads** Level I 100% of Salary 125% of Salary Level II 80% of Salary 100% of Salary Level III 60% of Salary 75% of Salary -------------------------------------------------------------------------- Key Managers** Level I 25% of Salary 31.25% of Salary Level II 15% of Salary 18.75% of Salary -------------------------------------------------------------------------- * Senior Management Committee level position ** Levels shall be determined in the sole discretion of the Committee 2.3 Award Valuation at Grant. In calculating the value of an Award for purposes of Section 2.2, the value of each Performance Share shall be equal to the closing price of a share of Stock on the last trading day of the Year before the Performance Period begins. The Participant's Salary shall be determined as of the January 31 preceding the date the Award is granted, or such other time as is determined in the discretion of the Committee. Each Award is deemed to be granted on the day that it is approved by the Committee. 2.4 Accounting and Adjustment of Awards. The number of Performance Shares awarded to a Participant shall be recorded in a separate Account for each Participant. The number of Performance Shares recorded in a Participant's Account shall be adjusted to reflect any splits or other adjustments in the Stock. If any cash dividends are paid on the Stock, the number of Performance Shares in each Participant's Account shall be increased by a number equal to (i) the dividend multiplied by the number of Performance Shares in each Participant's Account, divided by (ii) the closing price of a share of Stock on the payment date of the dividend. No adjustment shall be made to any outstanding Awards of a Retired Participant for cash dividends paid on Stock during the Performance Period following the Retirement of the Participant. 2.5 Performance Schedule and Calculation of Awards. Except as otherwise provided, each Award shall become vested on January 1 immediately following the end of the applicable Performance Period, subject to adjustment in accordance with the following procedure: (a) One-half of the Award shall be adjusted as follows: (i) The Total Shareholder Return for the Company shall be determined for each Year during the Performance Period, and shall then be averaged (the "Company TSR"). 3 (ii) The average Total Shareholder Return for the Peer Group utilities shall be determined for each Year during the Performance Period, and shall then be averaged ( the "Peer Group TSR"). The two highest and two lowest performing utilities within the Peer Group shall be excluded for purposes of determining the Peer Group TSR. (iii)The Peer Group TSR for the Performance Period shall be subtracted from the Company TSR for the Performance Period. The remainder shall then be used to determine the number of vested Performance Shares using the Performance Schedule, based on one-half of the number of Performance Shares in the Participant's Account. (b) The other one-half of the Award shall be adjusted as follows: (i) The EBITDA Growth for the Company shall be determined for each Year during the Performance Period, and shall then be averaged (the "Company EBITDA Growth"). (ii) The average EBITDA Growth for the Peer Group utilities shall be determined for each Year during the Performance period, and shall be averaged (the "Peer Group EBITDA Growth"). The two highest and two lowest performing utilities within the Peer Group shall be excluded for purposes of determining the Peer Group EBITDA Growth. (iii)The Peer Group EBITDA Growth for the Performance Period shall be subtracted from the Company EBITDA Growth for the Performance Period. The remainder shall then be used to determine the number of vested Performance Shares using the Performance Schedule, based on one-half of the number of Performance Shares in the Participant's Account. (c) The total number of vested Performance Shares payable to the Participant shall be the sum of the amounts determined in accordance with subsections (a) and (b) above. (d) The Performance Measures and the Performance Schedule will not change during any Performance Period with regard to any Awards that have already been granted. The Committee reserves the right to modify or adjust the Performance Measures and/or the Performance Schedule in the Committee's sole discretion with regard to future grants. 2.6 Payment Options. Except as provided in Section 3, Awards shall be paid after expiration of the Performance Period. The Company will issue one share of Stock in payment for each Performance Share (rounded to the nearest whole Performance Share) credited to the Account of the Participant. Payment shall be made as follows: 4 (a) 100% during the month of April of the Year immediately following expiration of the Performance Period, or as soon as practical thereafter; or (b) in accordance with an alternative payment election made by Participant substantially in the form attached hereto as Attachment 2, provided that such election is executed by the Participant and returned to the Vice President, Human Resources Department no later than the end of the first Year of the Performance Period. Once made, this election is irrevocable. A deferral election may only be made by a Participant who is employed as a Department Head or in a higher position on the date the deferral election is solicited. 2.7 Grantor Trust. In the case of a Change in Control, the Company shall, subject to the restrictions in this Section 2.7 and Section 13.12 of the Plan, irrevocably set aside shares of Stock or cash in one or more such grantor trusts in an amount that is sufficient to pay each Participant employed by such Company (or Designated Beneficiary), the net present value as of the date on which the Change in Control occurs, of the earned benefits to which Participants (or their Designated Beneficiaries) would be entitled pursuant to the terms of the Plan if the value of their deferral account (if any) established pursuant to section 2.6(b) would be paid in a lump sum upon the Change in Control. Any such trust shall be subject to the claims of the general creditors of the Sponsor or Company in the event of bankruptcy or insolvency of the Sponsor or Company. Section 3. Early Vesting and Forfeiture 3.1 Retirement, Death or Divestiture. If the Participant Retires or dies prior to expiration of the Performance Period, or terminates employment as the result of a Divestiture during a Performance Period, any outstanding Awards of the Participant for any unexpired Performance Period shall immediately become vested. Payment of the outstanding Awards of such Participant shall be subject to the following special provisions: (a) In the event of the Retirement of the Participant, the Participant's outstanding Awards shall be adjusted in accordance with Section 2.5 and paid in accordance with Section 2.6 following the end of the Performance Period for the Award; provided, that if the Participant had elected to defer the payment of an Award until a date following Retirement, the first payment of such Award shall be deferred until the later of the date elected by the Participant or during April of the year following the end of the Performance Period for the Award. (b) In the event of the death of the Participant, or termination of employment as the result of a Divestiture during a Performance Period, the Participant's outstanding Awards shall be adjusted and paid in accordance with Section 3.3. 5 3.2 Change in Control. In the event of a Change in Control prior to the expiration of the Performance Period, any outstanding Award of the Participant for any unexpired Performance Period shall be treated as follows: (a) If the Award is assumed by the successor to the Sponsor as of the date of the Change in Control, each outstanding Award not previously forfeited shall continue to vest and shall be paid pursuant to the terms of this Sub-Plan; provided, however, that in the event the employment of the Participant is terminated by the Company without Cause following the Change in Control, any outstanding Award shall become vested as of the termination date, and the aggregate value of the Award shall be paid after being adjusted in accordance with Section 3.3. (b) If the Award is not assumed by the successor to the Sponsor as of the date of the Change in Control, any outstanding Award shall become vested as of the date of the Change in Control, and the aggregate value of the Award shall be paid after being adjusted in accordance with Section 3.3. 3.3 Adjustment of Awards. Any Award which is vested prior to the end of the Performance Period due to the death of the Participant, termination of employment as a result of a Divestiture, or Change in Control during the Performance Period, shall be adjusted pursuant to the following procedure: (a) One-half of the Award shall be adjusted as follows: (i) The Company TSR shall be determined for each Year or partial Year, and a weighted average Company TSR shall be calculated for the period between the first day of the Performance Period and the date the Participant dies, the date of termination as a result of the Divestiture or the date that the Award is vested pursuant to Section 3.2 (the "Prorated Company TSR"). (ii) The average Peer Group TSR shall be determined for each Year or partial Year, and a weighted average Peer Group TSR shall be calculated for the period between the first day of the Performance Period and the date the Participant dies, the date of termination as a result of the Divestiture or the date that the Award is vested pursuant to Section 3.2 (the "Prorated Peer Group TSR"). The two highest and two lowest performing utilities within the Peer Group shall be excluded for purposes of determining the Peer Group TSR. (iii)The Prorated Peer Group TSR for the Performance Period shall be subtracted from the Prorated Company TSR for the Performance Period. The remainder shall then be used to determine the vested Performance Shares using the Performance Schedule, based on one-half of the number of Performance Shares in the Participant's Account. 6 (b) The other one-half of the Award shall be adjusted as follows: (i) The Company EBITDA Growth shall be determined for each Year or partial Year, and a weighted average Company EBITDA Growth shall be calculated for the period between the first day of the Performance Period and the end of the calendar quarter immediately preceding the date that the Participant dies, the date of termination as a result of the Divestiture or the date that the Award is vested pursuant to Section 3.2 (the "Prorated Company EBITDA Growth"). (ii) The average Peer Group EBITDA Growth shall be determined for each Year or partial Year, and a weighted average Peer Group EBITDA Growth shall be calculated for the period between the first day of the Performance Period and the end of the calendar quarter immediately preceding the date the Participant dies, the date of termination as a result of the Divestiture or the date that the Award is vested pursuant to Section 3.2 (the "Prorated Peer Group EBITDA Growth"). The two highest and two lowest performing utilities within the Peer Group shall be excluded for purposes of determining the Peer Group EBITDA Growth. (iii)The Prorated Peer Group EBITDA Growth for the Performance Period shall be subtracted from the Prorated Company EBITDA Growth for the Performance Period. The remainder shall then be used to determine the vested Performance Shares using the Performance Schedule, based on one-half of the number of Performance Shares in the Participant's Account. (c) The total number of vested Performance Shares payable to the Participant shall be the sum of the amounts determined in accordance with subsections (a) and (b) above. (d) In the event of the death of the Participant, or in the event of the termination of employment of the Participant as a result of a Divestiture, payment shall be made within a reasonable time after the Participant dies, or within a reasonable time after the termination of the Participant, notwithstanding any election under Section 2.6. Payment upon death shall be made to the Participant's Designated Beneficiary. If the Award is vested pursuant to Section 3.2, the Award shall be paid within a reasonable time after the date of vesting, notwithstanding any election under Section 2.6. The Company will issue one share of Stock in payment for each Performance Share (rounded to the nearest whole Performance Share) credited to the Account of the Participant. 7 3.4 Termination of Employment. In the event that a Participant's employment with the Company terminates for any reason other than as provided in this Section 3, any Award made to the Participant which has not vested as provided in Section 2 or Section 3 shall be forfeited. Any vested Awards shall be paid within a reasonable time after termination (for reasons other than Retirement), notwithstanding any election to defer the payment of any Award under Section 2.6. However, if the Participant is a "key employee" as defined in Section 416(i) of the Code (but determined without regard to the 50 employee limit on the number of officers treated as key employees), payment shall not be made before six months after the date of separation from service for any reason including Retirement (or, if earlier, the date of death of the Participant) and the amount of any payment made in cash (i.e., with respect to Awards granted prior to January 1, 2005) shall be based upon the value of the Performance Shares as determined by reference to the closing price of the Stock on the trading day occurring on or next following the date that is six months after the date of separation of the Participant (or, if earlier the date of death of the Participant). Section 4. Non-Assignability of Awards The Awards and any right to receive payment under the Plan and this Sub-Plan may not be anticipated, alienated, pledged, encumbered, or subject to any charge or legal process, and if any attempt is made to do so, or a Participant becomes bankrupt, then in the sole discretion of the Committee, any Award made to the Participant which has not vested as provided in Sections 2 and 3 shall be forfeited. Section 5. Amendment and Termination This Sub-Plan shall be subject to amendment, suspension, or termination as provided in the Plan. 8 ATTACHMENT 1 PERFORMANCE SCHEDULE PERFORMANCE SHARE CALCULATION1 The following table shall be used to adjust one half of the Participant's Award in accordance with Section 2.5(a) or Section 3.3(a) of the Plan: If the Company TSR2 minus Then the 50% of the vested the Peer Group TSR2 is: Performance Share Award shall be multiplied by: 5% or better 2.00 4.0 - 4.99 1.75 3.0 - 3.99 1.50 2.0 - 2.99 1.25 1.0 - 1.99 1.00 (0.99) - 0.99 .50 (1.0) - (1.99) .25 (2.0) or less 0.00 9 The following table shall be used to adjust one half of the Participant's Award in accordance with Section 2.5(b) or Section 3.3(b) of the Plan: If the Company EBITDA Growth2 minus Then the 50% of the vested the Peer Group EBITDA Growth2 is: Performance Share Award shall be multiplied by: 5% or better 2.00 4.0 - 4.99 1.75 3.0 - 3.99 1.50 2.0 - 2.99 1.25 1.0 - 1.99 1.00 0.00 - 0.99 .50 Less than 0 0 1 The number of Performance Shares as calculated above shall be paid in accordance with the provisions of Section 2.5 and 2.6 of the Sub-Plan. 2 For purposes of Section 3, the Prorated Company TSR and EBITDA Growth and Prorated Peer Group TSR and EBITDA Growth shall be used, and the number of Performance Shares as calculated above shall be paid in accordance with the provisions of the Sub-Plan. 10 ATTACHMENT 2 Performance Share Sub-Plan 200_ Deferral Election Form As a Participant in the Performance Share Sub-Plan of the 2002 Equity Incentive Plan ("Sub-Plan"), I hereby elect to defer payment of my Award otherwise payable to me by the Company and attributable to services to be performed by me during the Performance Period beginning on January __, 200__. This election shall apply to [CHECK ONE]: [ ] 100% of the Award [ ] 50% of the Award [ ] 75% of the Award [ ] 25% of the Award Upon vesting, I understand that my Award shall continue to be recorded in my Account as Performance Shares as described in the Sub-Plan and adjusted to reflect the payment and reinvesting of the Company's common stock dividends over the deferral period, until paid in full. I hereby elect to defer receipt (or commencement of receipt) of my Award until the date specified below, or as soon as practical thereafter [CHECK ONE]:* [ ] a specific date certain at least 5 years from expiration of the Performance Period: 4 / 1 / (month/day/year) [ ] the April 1 following the date of retirement, or if later, the date which is six months after the date of my separation from service for any reason (including Retirement), if I am a "key employee" as defined in Section 416(i) of the Code (but determined without regard to the 50 employee limit on the number of officers treated as key employees). [ ] the April 1 following the first anniversary of my date of retirement * Notwithstanding any election above, if I elect a date certain distribution and I retire before that date certain, I understand that the Company will commence distribution of my Account as soon as practical on or after the later of: (i) the April 1 following the first anniversary of the date of retirement, or (ii) the April 1 of the year following the end of the Performance Period, even though said date is earlier than 5 years from the expiration of the Performance Period. I hereby elect to be paid as described in the Sub-Plan in the form of [CHECK ONE]: [ ] a single payment [ ] annual payments commencing on the date set forth above and payable on the anniversary date thereof over: [ ] a two year period [ ] a three year period [ ] a four year period [ ] a five year period I understand that I will receive "earnings" on those deferred amounts when they are paid to me. I understand that the election made as indicated herein is irrevocable and that all deferral elections are subject to the provisions of the Sub-Plan, including provisions that may affect timing of distributions. I understand that this deferral election is subject to the requirements of Section 409A of Code, and regulations and other guidance issued thereunder. The Company makes no representation or guarantee that any tax treatment, including, but not limited to, federal, state and local income, or estate and gift tax treatment, will be applicable with respect to the amounts deferred. The Company shall have no responsibility for the tax consequences that I may incur as a result of Section 409A, regulations or guidance issued thereunder, or any other provision of the Internal Revenue Code. I understand it is my responsibility to consult a legal or tax advisor regarding the tax effects of this deferral election. I further acknowledge and agree that the Company may (but shall not be required to) modify this election as necessary to comply with Section 409A and any guidance or regulations issued thereunder. I further agree to cooperate in any manner necessary to ensure that this election is in compliance with Section 409A and any guidance or regulations issued thereunder. I understand and acknowledge that my interests herein and my rights to receive distribution of the deferred amounts may not be anticipated, alienated, sold, transferred, assigned, pledged, encumbered, or subjected to any charge or legal process, and if any attempt is made to do so, or I become bankrupt, my interest may be terminated by the Committee, which, in his sole discretion. I further understand that nothing in the Sub-Plan shall be interpreted or construed to require the Company in any manner to fund any obligation to me, or to my beneficiary(ies) in the event of my death. - ----------------------------------------- --------------------------------- (Signature) (Date) - ----------------------------------------- --------------------------------- (Print Name) (Company Location) Received: Agent of Chief Executive Officer - ----------------------------------------- --------------------------------- (Signature) (Date) EX-10 6 pei_exhibit10c15-.txt EXHIBIT 10C(15) Exhibit 10c(15) Amended and Restated Progress Energy, Inc. Restoration Retirement Plan Carolina Power & Light Company established the Carolina Power & Light Company Restoration Retirement Plan (the "Plan"), effective as of January 1, 1998 ("Effective Date"), which was subsequently amended and restated as of January 1, 1999, January 1, 2000 and July 10, 2002. The Sponsor hereby amends and restates the Plan effective as of January 1, 2005. The terms of the amended and restated Plan shall govern the payment of any benefits commencing after January 1, 2005. ARTICLE I PURPOSE The purpose of the Plan is to provide a means by which certain employees may be provided benefits which otherwise would be provided under the Retirement Plan, in the absence of certain restrictions imposed by applicable law on benefits which may be provided under the Retirement Plan. The Plan is intended to constitute a nonqualified deferred compensation plan that complies with the provisions of Section 409A of the Code and an unfunded retirement plan for a select group of management or highly compensated employees within the meaning of Title I of the Employee Retirement Income Security Act of 1974, as amended. ARTICLE II DEFINITIONS Capitalized terms which are not defined herein shall have the meaning ascribed to them in the Retirement Plan. 2.1 "Actuarial Value" shall mean an equivalent lump sum value as of the Benefit Commencement Date using the average 30-year Treasury Rate for the month of August immediately preceding the calendar year the determination is made and the GAR 94 mortality table (50% male, 50% female). 2.2 "Affiliated Company" shall mean any corporation or other entity that is required to be aggregated with the Sponsor pursuant to Sections 414(b), (c), (m), or (o) of the Code, but only to the extent so required. 2.3 "Benefit Commencement Date" shall mean the first day of the month following the Termination of the Participant. Notwithstanding the foregoing, payments with respect to a Participant who is a Key Employee shall not begin earlier than six months after the date of Termination of the Participant (or, if earlier, the date of death). 2.4 "Board" shall mean the Board of Directors of the Sponsor. 2.5 "Change in Control" shall occur on the earliest of the following dates: (a) the date any person or group of persons (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934), excluding employee benefit plans of the Sponsor, becomes, directly or indirectly, the "beneficial owner" (as defined in Rule 13d-3 promulgated under the Securities Act of 1934) of securities of the Sponsor representing twenty-five percent (25%) or more of the combined voting power of the Sponsor's then outstanding securities (excluding the acquisition of securities of the Sponsor by an entity at least eighty percent (80%) of the outstanding voting securities of which are, directly or indirectly, beneficially owned by the Sponsor); or (b) the date of consummation of a tender offer for the ownership of more than fifty percent (50%) of the Sponsor's then outstanding voting securities; or (c) the date of consummation of a merger, share exchange or consolidation of the Sponsor with any other corporation or entity regardless of which entity is the survivor, other than a merger, share exchange or consolidation which would result in the voting securities of the Sponsor outstanding immediately prior thereto continuing to represent (either by remaining outstanding or being converted into voting securities of the surviving or acquiring entity) more than sixty percent (60%) of the combined voting power of the voting securities of the Sponsor or such surviving or acquiring entity outstanding immediately after such merger or consolidation; or (d) the date, when as a result of a tender offer or exchange offer for the purchase of securities of the Sponsor (other than such an offer by the Sponsor for its own securities), or as a result of a proxy contest, merger, share exchange, consolidation or sale of assets, or as a result of any combination of the foregoing, individuals who are Continuing Directors cease for any reason to constitute at least two-thirds (2/3) of the members of the Board; or (e) the date the shareholders of the Sponsor approve a plan of complete liquidation or winding-up of the Sponsor or an agreement for the sale or disposition by the Sponsor of all or substantially all of the Sponsor's assets; or (f) the date of any event which the Board determines should constitute a Change in Control. A Change in Control shall not be deemed to have occurred until a majority of the members of the Board receive written certification from the Committee on Organization and Compensation of the Board that such event has occurred. Any determination that such an event has occurred shall, if made in good faith on the basis of information available at that time, be conclusive and binding on the Board, the Sponsor, the Company, the Participants and their beneficiaries for all purposes of the Plan. 2.6 "Code" shall mean the Internal Revenue Code of 1986, as amended. 2.7 "Committee" shall mean a committee selected by the Plan Administrator to hear claim disputes under Article IV of the Plan. 2 2.8 "Company" shall mean Progress Energy, Inc. or any successor to it in the ownership of substantially all of its assets and each Affiliated Company that, with the consent of the Board, adopts the Plan and is included in Appendix A, as in effect from time to time. Appendix A shall set forth any limitations imposed on employees of Affiliated Companies that adopt the Plan including any limitations on benefit accruals, notwithstanding any provision in the Plan to the contrary. 2.9 "Compensation and Benefit Limitations" shall mean (a) the limitation on compensation under the Retirement Plan in accordance with Section 401(a)(17) of the Code and (b) any limits on benefits paid under the Retirement Plan that are necessary for compliance with Section 415 of the Code. 2.10 "Continuing Directors" shall mean the members of the Board as of July 10, 2002; provided, however, that any person becoming a director subsequent to such date whose election or nomination for election was supported by 75 percent or more of the directors who then comprised Continuing Directors shall be considered to be a Continuing Director. 2.11 "Deferrals" shall mean a Participant's deferrals of compensation under the MDCP to the extent not utilized in calculating a Participant's Accrued Benefit under the Retirement Plan. 2.12 "Eligible Employee" shall mean any member of the Retirement Plan who is not a Participant in the Sponsor's Supplemental Senior Executive Retirement Plan and who has not retired or terminated his or her employment with the Company prior to the Effective Date. 2.13 "Key Employee" shall mean a Participant who is a "key employee" as defined in Section 416(i) of the Code, but determined without regard to the 50 employee limit on the number of officers treated as key employees. 2.14 "MDCP" shall mean the Progress Energy, Inc. Amended and Restated Management Deferred Compensation Plan. 2.15 "Participant" shall mean an Eligible Employee who participates in the Plan pursuant to Article III. An Eligible Employee shall remain a Participant under the Plan until the earlier of (a) all amounts payable on his or her behalf under the Plan have been paid, (b) the Eligible Employee no longer has a Restoration Accrued Benefit, (c) the Eligible Employee has a Termination without a Vested Restoration Accrued Benefit, or (d) the Eligible Employee becomes a Participant in the Sponsor's Supplemental Senior Executive Retirement Plan. 2.16 "Restoration Accrued Benefit" shall mean, as of any determination date, the excess of (a) a Participant's Accrued Benefit calculated under the Retirement Plan (1) assuming a Participant's Compensation under the Retirement Plan includes Deferrals of a Participant and (ii) without regard to the Compensation and Benefit Limitations, over (b) a Participant's Accrued Benefit calculated under the Retirement Plan. For purposes of this Section 2.16, a Participant's Accrued Benefit for purposes of clauses (a) and (b) above shall be calculated in the form of a Single Life Annuity for a Participant who does not have a Spouse and in the form of a 50% Qualified Joint and Survivor Annuity for a Participant who has a Spouse, with such calculation performed without regard to any other form of benefit elected by a Participant under the Retirement Plan. 3 2.17 "Retirement Plan" shall mean the Progress Energy Pension Plan, as it may be amended from time to time, or any successor plan. 2.18 "Sponsor" shall mean Progress Energy, Inc. 2.19 "Spouse" shall mean the spouse of a Participant as would be determined at the applicable time under the definition of Spouse in the Retirement Plan (or any successor provisions). 2.20 "Termination" shall mean a termination of employment with the Sponsor and all Affiliated Companies. 2.21 "Vested Restoration Accrued Benefit" shall mean a Participant's Restoration Accrued Benefit when the Participant becomes fully vested under the provisions of the Retirement Plan (or any successor provisions) or as provided in Article VI of the Plan. Unless the context clearly indicates to the contrary in interpreting the Plan, any references to the masculine alone shall include the feminine and the singular shall include the plural. ARTICLE III PARTICIPATION AND BENEFITS 3.1 Participation. An Eligible Employee will participate in the Plan when he or she has a Restoration Accrued Benefit. 3.2 Amount of Benefit Payable. Subject to the forfeiture provisions of Section 3.4 and lump sum payment provisions of Section 3.5 of the Plan, a Participant who becomes eligible for the payment of a benefit under the Retirement Plan, shall be entitled to monthly benefit payments commencing as of his Benefit Commencement Date or as soon thereafter as practicable based on the Participant's Restoration Accrued Benefit calculated immediately prior to the Benefit Commencement Date and actuarially adjusted as if an annuity were being paid under the Retirement Plan as of the Benefit Commencement Date. The monthly payment shall be in the form of a Single Life Annuity if the Participant has no Spouse and in the form of a 50% Joint and Survivor Annuity if the Participant has a Spouse, with the Spouse determined at the Benefit Commencement Date entitled to any survivor benefit upon the death of the Participant. 3.3 Pre-Retirement Death Benefit. Subject to the provisions of Section 3.5, if a surviving Spouse of a deceased Participant would have been eligible for a pre-retirement death benefit under the Retirement Plan (i.e., the Spouse being married to the Participant for a one-year period prior to the date of death), then upon such Participant's death, such Spouse shall be entitled to a monthly benefit payment under the Plan equal to the amount, if any, by which (a) exceeds (b) each month, where (a) is the Spouse's monthly death benefit that would be payable in accordance with the provisions of the Retirement Plan determined as if (i) the Participant's Compensation under the Retirement Plan included 4 Deferrals and (ii) the Compensation and Benefit Limitations did not apply, and (b) is the monthly death benefit payable under the Retirement Plan, and assuming for purposes of clauses (a) and (b) that the Spouse elected a monthly annuity as a death benefit under the Retirement Plan commencing on the same date as the pre-retirement death benefit is payable to the Spouse under this Plan. The pre-retirement death benefit under this Plan shall commence as of the first day of the month following the Participant's death or as soon thereafter as practicable, and shall continue on the first day of the each month thereafter for the life of the Spouse. 3.4 Other Termination of Employment; Forfeitures. Neither Eligible Employees, Participants nor their Spouses or Beneficiaries are entitled to any benefits under the Plan except as otherwise provided in this Article III and under Article VI of the Plan. Any Participant who terminates employment with the Sponsor and any of its Affiliated Companies without being 100% vested under the Retirement Plan shall not be eligible to receive any benefits under the Plan and shall forfeit his or her Restoration Accrued Benefit. Any Participant ceasing to be an Eligible Employee because he or she becomes a Participant in the Supplemental Senior Executive Retirement Plan shall forfeit his or her Restoration Accrued Benefit. Notwithstanding any other provision of the Plan, no benefit shall be payable under the Plan with respect to an Eligible Employee whose employment with the Sponsor or any of its Affiliated Companies is terminated for Cause. As used herein, the term "Cause" shall be limited to (a) action by the Eligible Employee involving willful malfeasance having a material adverse effect on the Sponsor or any of its Affiliated Companies (b) substantial and continuing willful refusal by the Eligible Employee to perform the duties ordinarily performed by an employee in the same position and having similar duties as the Eligible Employee, (c) the Eligible Employee being convicted of a felony, or (d) willful failure to comply with the Sponsor or the applicable Affiliated Company's Code of Conduct or other Policy or Procedure. 3.5 Lump Sum Payments. The Committee shall provide for the payment under the Plan of a cash lump sum amount in lieu of the annuity otherwise payable under Sections 3.2 or 3.3, if the annuity amount to be paid is less that $100 per month. For a Participant (or spouse) whose benefit under the Retirement Plan is based upon the Participant's Cash Balance Account, the lump sum shall be equal to what the Restoration Accrued Benefit would be if "Cash Balance Account" were substituted for "Accrued Benefit" in Section 2.15 and Restoration Accrued Benefit referred to a dollar amount. For a Participant (or spouse) whose benefit under the Retirement Plan is based on the Final Average Pay Formula Pension, the lump sum shall be equal to the Actuarial Value of the annuity payments that would otherwise be made to the Participant (or spouse) under Sections 3.2 or 3.3, as the case may be. Notwithstanding the foregoing, no lump sum payment shall be made under the Plan unless (i) the payment accompanies the termination of the entirety of the Participant's interest in the Plan; (ii) the payment is made on or before the later of (A) December 31 of the calendar year in which the Termination of the Participant occurs, or (B) the date that is 2 1/2 months after the Termination of the Participant; and (iii) the payment is not greater than $10,000. 3.6 Payments to Key Employees. In the event the Benefit Commencement Date under this Plan of a Participant who is a Key Employee shall be delayed for six months following the termination of the Participant as provided in Section 2.3, the Participant (if then living) shall receive a lump sum payment as of the first day of the seventh month following the Termination in an amount equal to 5 six times the monthly payment due to the Participant under this Plan, in addition to the monthly payment then due to the Participant. If the Participant dies following Termination but prior to the commencement of payments under this Plan, the Participant's surviving Spouse, if any, shall be entitled to receive the same death benefit payable in the event the Participant had commenced receiving benefit payments as of the first day of the month prior to his death. ARTICLE IV PLAN ADMINISTRATION 4.1 Administration. The Plan shall be administered by the Sponsor's Vice President, Human Resources (the "Plan Administrator"). The Plan Administrator and the Committee shall have full authority to administer and interpret the Plan, determine eligibility for benefits, make benefit payments and maintain records hereunder, all in their sole and absolute discretion, subject to the allocation of responsibilities set forth below. 4.2 Delegated Responsibilities. The Plan Administrator shall have the authority to delegate any of his or her responsibilities to such persons as he or she deems proper. 4.3 Claims. (a) Claims Procedure. If any Participant, Spouse or Beneficiary has a claim for benefits which is not being paid, such claimant may file with the Plan Administrator a written claim setting forth the amount and nature of the claim, supporting facts, and the claimant's address. The Plan Administrator shall notify each claimant of its decision in writing by registered or certified mail within sixty (60) days after its receipt of a claim or, under special circumstances, within ninety (90) days after its receipt of a claim. If a claim is denied, the written notice of denial shall set forth the reasons for such denial, refer to pertinent Plan provisions on which the denial is based, describe any additional material or information necessary for the claimant to realize the claim, and explain the claim review procedure under the Plan. (b) Claims Review Procedure. A claimant whose claim has been denied or such claimant's duly authorized representative may file, within sixty (60) days after notice of such denial is received by the claimant, a written request for review of such claim by the Committee. If a request is so filed, the Committee shall review the claim and notify the claimant in writing of its decision within sixty (60) days after receipt of such request. In special circumstances, the Committee may extend for up to sixty (60) additional days the deadline for its decision. The notice of the final decision of the Committee shall include the reasons for its decision and specific references to the Plan provisions on which the decision is based. The decision of the Committee shall be final and binding on all parties. 6 ARTICLE V MISCELLANEOUS 5.1 Amendment and Termination. The Board may amend, modify or terminate the Plan at any time, provided, however, that no such amendment or termination shall reduce any Participant's Vested Restoration Accrued Benefit under the Plan as of the date of such amendment or termination, unless at the time of such amendment or termination, affected Participants and spouses become entitled to an amount equal to the equivalent actuarial value, to be determined in the sole discretion of the Committee, of such Vested Restoration Accrued Benefit under another plan, program or practice adopted by a Company. In the event the Plan is terminated, the Sponsor shall pay the Vested Restoration Accrued Benefits in accordance with the terms of the Plan as in effect prior to such termination except as otherwise provided in Section 6.4. 5.2 Source of Payments. Each Company will pay with respect to its own Eligible Employees all benefits arising under the Plan and all costs, charges and expenses relating thereto out of its general assets. 5.3 Non-Assignability of Benefits. Except as otherwise required by law, neither any benefit payable hereunder nor the right to receive any future benefit under the Plan may be anticipated, alienated, sold, transferred, assigned, pledged, encumbered, or subjected to any charge or legal process, and if any attempt is made to do so, or a person eligible for any benefits under the Plan becomes bankrupt, the interest under the Plan of the person affected may be terminated by the Plan Administrator which, in his or her sole discretion, may cause the same to be held or applied for the benefit of one or more of the dependents of such person or make any other disposition of such benefits that it deems appropriate. 5.4 Plan Unfunded. Nothing in the Plan shall be interpreted or construed to require a Company in any manner to fund any obligation to the Participants, terminated Participants, or beneficiaries hereunder. Nothing contained in the Plan nor any action taken hereunder shall create, or be construed to create, a trust of any kind, or a fiduciary relationship between a Company and the Participants, terminated Participants, beneficiaries, or any other persons. Any funds which may be accumulated by a Company in order to meet any obligations under the Plan shall for all purposes continue to be a part of the general assets of a Company; provided, however, that a Company may establish a trust to hold funds intended to provide benefits hereunder to the extent the assets of such trust become subject to the claims of the general creditors of such Company in the event of bankruptcy or insolvency of such Company. To the extent that any Participant, terminated Participant, or beneficiary acquires aright to receive payments from a Company under the Plan, such rights shall be no greater than the rights of any unsecured general creditor of such Company. 5.5 Applicable Law. All questions pertaining to the construction, validity and effect of the Plan shall be determined in accordance with the laws of the State of North Carolina to the extent not preempted by Federal law and shall be construed in a manner consistent with the requirements of Section 409A of the Code. 7 5.6 Limitation of Rights. The Plan is a voluntary undertaking on the part of the Sponsor and each Company. Neither the establishment of the Plan nor the payment of any benefits hereunder, nor any action of the Sponsor, a Company or the Plan Administrator shall be held or construed to be a contract of employment between the Sponsor, a Company and any Eligible Employee or to confer upon any person any legal right to be continued in the employ of the Sponsor or a Company. The Sponsor and each Company expressly reserves the right to discharge, discipline or otherwise terminate the employment of any Eligible Employee at any time. Participation in the Plan gives no right or claim to any benefits beyond those which are expressly provided herein and all rights and claims hereunder are limited as set forth in the Plan. 5.7 Severability. In the event any provision of the Plan shall be held illegal or invalid, or the inclusion of any Participant would serve to invalidate the Plan as an unfunded plan for a select group of management or highly compensated employees under ERISA, then the illegal or invalid provision shall be deemed to be null- and void, and the Plan shall be construed as if it did not contain that provision and in the case of the inclusion of any such Participant, a separate plan, with the same provisions as the Plan, shall be deemed to have been established for the Participant or Participants ultimately determined not to constitute a select group of management or highly compensated employees. 5.8 Headings. The headings to the Articles and Sections of the Plan are inserted for reference only, and are not to be taken as limiting or extending the provisions hereof. 5.9 Incapacity. If the Plan Administrator shall determine that a Participant, or any other person entitled to a benefit under the Plan (the "Recipient") is unable to care for his or her affairs because of illness, accident, or mental or physical incapacity, or because the Recipient is a minor, the Plan Administrator may direct that any benefit payment due the Recipient be paid to his or her duly appointed legal representative, or, if no such representative is appointed, to the Recipient's spouse, child, parent, or other blood relative, or to a person with whom the Recipient resides or who has incurred expense on behalf of the Recipient. Any such payment so made shall be a complete discharge of the liabilities of the Plan with respect to the Recipient. 5.10 Binding Effect and Release. Obligations incurred by the Sponsor or a Company pursuant to this Plan shall be binding upon the Sponsor or a Company, its successors and assigns, and inure to the benefit of the Participant or his Eligible Spouse. All persons accepting benefits under the Plan shall be deemed to have consented to the terms of the Plan. Any payment or distribution to any person entitled to benefits under the Plan shall be in full satisfaction of all claims against the Plan, the Committee, and the Sponsor and any Company arising by virtue of the Plan. 5.11 Acceleration of Payments. The acceleration of the time or schedule of any payment due under the Plan is prohibited except as provided in regulations and administrative guidance provided under Section 409A of the Code. It is not an acceleration of the time or schedule of payment if the Company waives or accelerates the vesting requirements applicable to a benefit under the Plan. 8 ARTICLE VI CHANGE IN CONTROL Upon the occurrence of a Change in Control, the following provisions shall become effective immediately: 6.1 Vesting. There shall be full Vesting of each Participant's Restoration Accrued Benefit, regardless of any termination of employment prior to eligibility for an Early Retirement Pension under the Retirement Plan, if he or she is otherwise vested under the Retirement Plan. 6.2 No Reduction Benefit. No amendment or termination of the Plan may reduce any Participant's Restoration Accrued Benefit as of the date of such amendment or termination. 6.3 Contributions to Trust. The Sponsor shall irrevocably set aside funds in one or more grantor trusts, subject to the provisions of Section 5.4, in an amount that is sufficient to pay each Participant (or Spouse) the benefits accrued under the Plan as of the date of the Change in Control. Any such trust shall be subject to the claims of the general creditors of the Sponsor in the event of the bankruptcy or insolvency of the Sponsor. 6.4 Termination of Plan. The Plan may be terminated and benefits distributed to Participants within twelve months of a "change in control" as defined for purposes of Section 409A of the Code. 9 APPENDIX A Progress Energy Florida, Inc. (non-bargaining employees) solely with respect to accrued benefits on or after January 1, 2002 so that no Restoration Accrued Benefit is calculated under the Plan with respect to employment prior to January 1, 2002. Progress Fuels Corporation (corporate employees) solely with respect to accrued benefits on or after January 1, 2002 so that no Restoration Accrued Benefit is calculated under the Plan with respect to employment prior to January 1, 2002. Progress Energy Carolinas, Inc. Progress Energy Service Company, LLC Progress Energy Ventures, Inc. 10 EX-10 7 pei_exhibit10c16-.txt EXHIBIT 10C(16) Exhibit 10c(16) AMENDED AND RESTATED SUPPLEMENTAL SENIOR EXECUTIVE RETIREMENT PLAN OF PROGRESS ENERGY, INC. Effective January 1, 1984 (As last amended effective January 1, 2005) TABLE OF CONTENTS Page ARTICLE I STATEMENT OF PURPOSE.......................................................1 ARTICLE II DEFINITIONS................................................................2 2.01 Terms........................................................2 2.02 Affiliated Company...........................................2 2.03 Assumed Deferred Vested Pension Benefit......................2 2.04 Assumed Early Retirement Pension Benefit.....................2 2.05 Assumed Normal Retirement Pension Benefit....................3 2.06 Board........................................................3 2.07 Change in Control............................................3 2.08 Committee....................................................5 2.09 Company......................................................5 2.10 Continuing Director..........................................5 2.11 Designated Beneficiary.......................................6 2.12 Early Retirement Date........................................6 2.13 Eligible Spouse..............................................6 2.14 Final Average Salary.........................................6 2.15 Normal Retirement Date.......................................7 2.16 Participant..................................................7 2.17 Pension......................................................7 2.18 Plan.........................................................7 2.19 Retirement Plan..............................................7 2.20 Salary.......................................................7 2.21 Separation from Service......................................8 2.22 Service......................................................8 2.23 Social Security Benefit......................................8 2.24 Spouse's Pension............................................10 2.25 Target Early Retirement Benefit.............................10 2.26 Target Normal Retirement Benefit............................10 2.27 Target Pre-Retirement Death Benefit.........................10 2.28 Target Severance Benefit....................................10 ARTICLE III ELIGIBILITY AND PARTICIPATION.............................................10 3.01 Eligibility.................................................10 3.02 Date of Participation.......................................11 3.03 Duration of Participation...................................11 ARTICLE IV RETIREMENT BENEFITS.......................................................11 4.01 Normal Retirement Benefit...................................11 4.02 Early Retirement Benefit....................................13 4.03 Surviving Spouse Benefit....................................15 4.04 Re-employment of Retired Participant........................15 ARTICLE V PRE-RETIREMENT DEATH BENEFITS.............................................15 5.01 Eligibility.................................................15 5.02 Amount......................................................15 5.03 Alternative Benefit.........................................16 5.04 Commencement and Duration...................................16 ARTICLE VI SEVERANCE BENEFITS........................................................16 6.01 Eligibility.................................................16 6.02 Amount......................................................17 6.03 Commencement and Duration...................................17 6.04 Surviving Spouse Benefit....................................18 ARTICLE VII ADMINISTRATION............................................................19 7.01 Committee...................................................19 7.02 Voting......................................................19 7.03 Records.....................................................19 7.04 Liability...................................................20 7.05 Expenses....................................................20 ARTICLE VIII AMENDMENT AND TERMINATION.................................................20 ARTICLE IX MISCELLANEOUS.............................................................21 9.01 Non-Alienation of Benefits..................................21 9.02 No Trust, Created...........................................21 9.03 No Employment Agreement.....................................22 9.04 Binding Effect..............................................22 9.05 Suicide.....................................................22 9.06 Claims for Benefits.........................................22 9.07 Entire Plan.................................................23 9.08 Change in Control...........................................23 9.09 Acceleration of Payment.....................................23 ARTICLE X CONSTRUCTION..............................................................24 10.01 Governing Law...............................................24 10.02 Gender......................................................24 10.03 Headings, etc...............................................24 10.04 Action......................................................24 ARTICLE I STATEMENT OF PURPOSE This Plan is designed and implemented for the purpose of enhancing the earnings and growth of Progress Energy, Inc. (the "Sponsor") by providing to the limited group of senior management employees largely responsible for such earnings and long-term growth deferred compensation in the form of supplemental retirement income benefits, thereby increasing the incentive of such key senior management employees to make the Sponsor and its Affiliated Companies more profitable. The benefits are normally payable to Participants upon retirement or death. The terms of the benefits operate in conjunction with the Participant's benefits payable under the Progress Energy Pension Plan and are designed to supplement such pension plan benefits and provide the Participant with additional financial security upon retirement or death. The Plan is intended to constitute a nonqualified deferred compensation plan that complies with the provisions of Section 409A of the Internal Revenue Code of 1986, as amended (the "Code") and an unfunded retirement plan for a select group of management or highly compensated employees within the meaning of Title I of the Employee Retirement Income Security Act of 1974, as amended. The Sponsor hereby restates and amends the Plan effective January 1, 2005. The terms of the amended and restated Plan shall govern the payment of any benefits commencing after January 1, 2005. ARTICLE II DEFINITIONS 2.01 Terms. Unless otherwise clearly required by the context, the terms used herein shall have the following meaning. Capitalized terms that are not defined below shall have the meaning ascribed to them in the Retirement Plan. 2.02 Affiliated Company. Shall mean any corporation or other entity that is required to be aggregated with the Sponsor pursuant to Section 414(b), (c), (m), or (o) of the Code, but only to the extent required. 2.03 Assumed Deferred Vested Pension Benefit. Shall mean the monthly benefit of the deferred vested Pension to commence on his Normal Retirement Date payable in the form of an annuity to which a separated Participant would be entitled under the Retirement Plan, calculated with the following assumptions based on such Participant's marital status at the time benefits hereunder commence: (a) In the case of a Participant with an Eligible Spouse, in the form of a 50% Qualified Joint and Survivor Annuity as provided in the Retirement Plan. (b) In the case of a Participant without an Eligible Spouse, in the form of a Single Life Annuity as provided in the Retirement Plan. (c) Without regard to any other benefit payment option under the Retirement Plan. 2.04 Assumed Early Retirement Pension Benefit. Shall mean the monthly benefit of the normal retirement Pension payable in the form of an annuity to which a Participant would be entitled under the Retirement Plan at his Normal Retirement Date, based upon his projected years of Service at his Normal Retirement Date and calculated with the following assumptions based upon his marital status at the time benefits hereunder commence: (a) In the case of a Participant with an Eligible Spouse, in the form of a 50% Qualified Joint and Survivor Annuity as provided in the Retirement Plan. (b) In the case of a Participant without an Eligible Spouse, in the form of a Single Life Annuity as provided in the Retirement Plan. (c) Without regard to any other benefit payment option under the Retirement Plan. 2.05 Assumed Normal Retirement Pension Benefit. Shall mean the monthly benefit of the normal retirement Pension payable in the form of an annuity to which a Participant would be entitled under the Retirement Plan if he retired at his Normal Retirement Date, calculated with the following assumptions based on his marital status at the time benefits hereunder commence: (a) In the case of a Participant with an Eligible Spouse, in the form of a 50% Qualified Joint and Survivor Annuity as provided in the Retirement Plan. (b) In the case of a Participant without an Eligible Spouse, in the form of a Single Life Annuity as provided in the Retirement Plan. (c) Without regard to any other benefit payment option under the Retirement Plan. 2.06 Board. Shall mean the Board of Directors of Sponsor. 2.07 Change in Control. Shall occur on the earliest of the following dates: (a) the date any person or group of persons (within the meaning of Section 13(d) or 14(d) of the Securities Exchange Act of 1934), excluding employee benefit plans of the Sponsor, becomes, directly or indirectly, the "beneficial owner" (as defined in Rule 13d-3 promulgated under the Securities Act of 1934) of securities of the Sponsor representing twenty-five percent (25%) or more of the combined voting power of the Sponsor's then outstanding securities (excluding the acquisition of securities of the Sponsor by an entity at least eighty percent (80%) of the outstanding voting securities of which are, directly or indirectly, beneficially owned by the Sponsor); or (b) the date of consummation of a tender offer for the ownership of more than fifty percent (50%) of the Sponsor's then outstanding voting securities; or (c) the date of consummation of a merger, share exchange or consolidation of the Sponsor with any other corporation or entity regardless of which entity is the survivor, other than a merger, share exchange or consolidation which would result in the voting securities of the Sponsor outstanding immediately prior thereto continuing to represent (either by remaining outstanding or being converted into voting securities of the surviving or acquiring entity) more than sixty percent (60%) of the combined voting power of the voting securities of the Sponsor or such surviving or acquiring entity outstanding immediately after such merger or consolidation; or (d) the date, when as a result of a tender offer or exchange offer for the purchase of securities of the Sponsor (other than such an offer by the Sponsor for its own securities), or as a result of a proxy contest, merger, share exchange, consolidation or sale of assets, or as a result of any combination of the foregoing, individuals who are Continuing Directors cease for any reason to constitute at least two-thirds (2/3) of the members of the Board; or (e) the date the shareholders of the Sponsor approve a plan of complete liquidation or winding-up of the Sponsor or an agreement for the sale or disposition by the Sponsor of all or substantially all of the Sponsor's assets; or (f) the date of any event which the Board determines should constitute a Change in Control. A Change in Control shall not be deemed to have occurred until a majority of the members of the Board receive written certification from the Committee that such event has occurred. Any determination that such an event has occurred shall, if made in good faith on the basis of information available at that time, be conclusive and binding on the Committee, the Sponsor, the Company, the Participants and their beneficiaries for all purposes of the Plan. 2.08 Committee. Shall mean the Committee on Organization and Compensation of the Board. 2.09 Company. Shall mean Progress Energy, Inc. or any successor to it in the ownership of substantially all of its assets, and each Affiliated Company that, with the consent of the Board adopts the Plan and is included in Appendix A, as in effect from time to time. Appendix A shall set forth any limitations imposed on employees of Affiliated Companies that adopt the Plan, including limitations on "Service," notwithstanding any provision of the Plan to the contrary. 2.10 Continuing Director. Shall mean the members of the Board as of July 10, 2002; provided, however, that any person becoming a Director subsequent to such date whose election or nomination for election was supported by seventy-five percent (75%) or more of the Directors who then comprised Continuing Directors shall be considered to be a Continuing Director. 2.11 Designated Beneficiary. Shall mean one or more beneficiaries as designated by a Participant in writing delivered to the Committee. In the event no such written designation is made by a Participant or if such beneficiary shall not be living or in existence at the time for commencement of payment to any Designated Beneficiary under the Plan, the Participant shall be deemed to have designated his estate as such beneficiary. 2.12 Early Retirement Date. Shall mean the date on which a Participant who qualifies for the early retirement benefit of Section 4.02 hereof retires from the employ of the Company and its affiliated entities. 2.13 Eligible Spouse. Shall mean the spouse of a Participant who, under the laws of the State where the marriage was contracted, is deemed married to that Participant on the date on which the payments from this Plan are to begin to the Participant, except that for purposes of Articles V and VI hereof, Eligible Spouse shall mean a person who is married to a Participant for a period of at least one year prior to his death. 2.14 Final Average Salary. Shall mean a Participant's average monthly Salary (as defined in Section 2.20 hereof) during the 36 completed calendar months of highest compensation within the 120-month period immediately preceding the earliest to occur of the Participant's death, Separation from Service, Early Retirement Date, or Normal Retirement Date, whichever is applicable. Provided, however, if a Participant becomes entitled to a benefit hereunder while under a period of long-term disability under the Sponsor's Group Insurance Plan, Final Average Salary shall be determined for the 12 calendar months immediately preceding the commencement of such period of long-term disability. Provided, further, in determining average monthly Salary (i) annual incentives and other similar payments shall be deemed received in twelve (12) equal payments beginning with the eleventh preceding month and ending with the month in which actual payment is made, and (ii) amounts of compensation deferred under any deferred compensation plan or arrangement shall be deemed received in the months such payments would have been received assuming no deferral had occurred. For years of Service granted under the terms of a written employment agreement as provided under Section 2.22, Salary during each such month is deemed to be zero dollars ($0.00) for purposes of calculating Final Average Salary. 2.15 Normal Retirement Date. Shall mean the first day of the calendar month coinciding with or next following the Participant's 65th birthday. 2.16 Participant. Shall mean an employee of the Company who is eligible and is participating in this Plan in accordance with Article III hereof. 2.17 Pension. Shall mean a level monthly annuity which is payable under the Retirement Plan as of the Benefit Commencement Date if the Participant elected an annuity form of benefit. 2.18 Plan. Shall mean the "Supplemental Senior Executive Retirement Plan of Progress Energy, Inc." as contained herein and as it may be amended from time to time hereafter. 2.19 Retirement Plan. Shall mean the "Progress Energy Pension Plan" (as amended effective January 1, 2002) as it may be amended from time to time thereafter. 2.20 Salary. Shall mean the sum of (1) The annual base compensation paid by the Company to a Participant, and (2) annual cash awards made under incentive compensation programs excluding, however, any payment made under the Sponsor's Long-Term Compensation Program or the Sponsor's 1997 and 2002 Equity Incentive Plans, and (3) amounts of annual compensation deferred under any deferred compensation plan or arrangement (including, without limitation, the "Executive Deferred Compensation Plan," the "Deferred Compensation Plan for Key Management Employees of Progress Energy, Inc.," the "Progress Energy, Inc. Management Deferred Compensation Plan" and the "Progress Energy 401(k) Savings and Stock Ownership Plan") and which, but for the deferral, would have been reflected in Internal Revenue Service Form W-2. 2.21 Separation from Service. Shall mean the date the Participant leaves the employ of the Company and all affiliated entities other than on account of his death, a period of long-term disability under the Company's long-term disability plan, or retirement at either his Early Retirement Date or upon or after his Normal Retirement Date. 2.22 Service. Shall have the same meaning as "Eligibility Service," determined as provided in Sections 2.02 and 3.01 of the Retirement Plan, plus any additional years of service that may be granted to the Participant in connection with this Plan under the terms of a written employment agreement (or any amendment thereto) entered into between the Company and the Participant. 2.23 Social Security Benefit. Means the monthly amount of benefit which a Participant is or would be entitled to receive at age 65 as a primary insurance amount under the federal Social Security Act, as amended, whether or not he applies for such benefit, and even though he may lose part or all of such benefit through delay in applying for it, by making application prior to age 65 for a reduced benefit, by entering into covered employment, or for any other reason. The amount of such Social Security Benefit to which the Participant is or would be entitled shall be estimated by the Committee for the purposes of this Plan as of the January 1 of the year in which his Separation from Service or retirement occurs on the following basis: (a) For a Participant entitled to a normal retirement benefit, on the basis of the federal Social Security Act as in effect on the January 1 coincident with or next preceding his Normal Retirement Date (regardless of any retroactive changes made by legislation enacted after said January 1); (b) For a Participant entitled to an early retirement benefit, on the basis of the federal Social Security Act as in effect on the January 1 coincident with or next preceding his Early Retirement Date (regardless of any retroactive change made by legislation enacted after said January 1), assuming that his employment, and Salary in effect at his Early Retirement Date, continued to age 65; or (c) For a Participant entitled to a severance benefit, on the basis of the federal Social Security Act as in effect on the January 1 coincident with or next preceding his Separation from Service (regardless of any retroactive change made by legislation enacted after said January 1), assuming that his employment, and Salary in effect at his Separation from Service, continued to age 65. For purposes of the calculations required under paragraphs (a) and (b) above, if a Participant is disabled under a period of long-term disability under the Company's Group Insurance Plan, said Social Security Benefit shall be calculated as if his Salary in effect at the commencement of such period of long-term disability continued to age 65. 2.24 Spouse's Pension. Shall mean the actual monthly benefit payable to an Eligible Spouse under the Retirement Plan, assuming the Eligible Spouse elected a 50% Joint and Survivor Annuity form of benefit. 2.25 Target Early Retirement Benefit. Shall mean an amount equal to a Participant's Final Average Salary determined at his Early Retirement Date multiplied by four percent (4%) for each projected year of Service at his Normal Retirement Date up to a maximum of sixty-two percent (62%). 2.26 Target Normal Retirement Benefit. Shall mean an amount equal to a Participant's Final Average Salary determined at his Normal Retirement Date multiplied by four percent (4%) for each projected year of Service at his Normal Retirement Date up to a maximum of sixty-two percent (62%). 2.27 Target Pre-Retirement Death Benefit. Shall mean an amount equal to a deceased Participant's Final Average Salary determined at his death multiplied by four percent (4%) for each year of Service at his death up to a maximum of sixty-two percent (62%). 2.28 Target Severance Benefit. Shall mean an amount equal to a Participant's Final Average Salary determined at his Separation from Service multiplied by four percent (4%) for each year of Service at his Separation from Service up to a maximum of sixty-two percent (62%). ARTICLE III ELIGIBILITY AND PARTICIPATION 3.01 Eligibility. Any executive employee of a Company who has served on the Senior Management Committee of the Sponsor and who has been a Senior Vice President or above for a minimum period of three (3) years and who has at least ten (10) years of Service shall be eligible to participate in this Plan. 3.02 Date of Participation. Each executive who is eligible to become a Participant under Section 3.01 shall become a Participant on the first day of the month following the month in which he is first eligible to participate. 3.03 Duration of Participation. Each executive who becomes a Participant shall continue to be a Participant until the termination of his employment with the Company or, if later, the date he is no longer entitled to benefits under this Plan. ARTICLE IV RETIREMENT BENEFITS 4.01 Normal Retirement Benefit. (a) Eligibility. A Participant whose employment with the Company or any Affiliated Company terminates on or after his Normal Retirement Date shall be eligible for the normal retirement benefit described in this Section 4.01. (b) Amount and Form. The monthly payment hereunder shall be in the form of a Single Life Annuity if the Participant has no Eligible Spouse and in the form of a 50% Qualified Joint and Survivor Annuity if the Participant has an Eligible Spouse. The eligible Participant's normal retirement benefit shall be a monthly amount equal to his Target Normal Retirement Benefit reduced by the sum of (1) his Assumed Normal Retirement Pension Benefit and (2) his Social Security Benefit. (c) Commencement and Duration. Monthly normal retirement benefit payments shall commence as of the first day of the calendar month next following the retirement of the Participant or as soon thereafter as practicable, and shall continue in monthly installments thereafter ending with a payment for the month in which such eligible Participant's death occurs, unless the benefit is being paid in the form of a Qualified Joint and Survivor Annuity, in which case the survivor benefit shall be paid to the Eligible Spouse, if living, for his or her life. If at the time of commencement of payment such eligible Participant does not have an Eligible Spouse the monthly benefit payments shall be guaranteed for one hundred twenty (120) monthly payments with any such guaranteed payments remaining at such Participant's death payable to his Designated Beneficiary. (d) Key Employees. Notwithstanding the foregoing, payments with respect to a Participant who is a key employee (as defined in Section 416(i) of the Code but determined without regard to the 50 employee limit on the number of officers treated as key employees) shall not begin earlier than six months after the date of termination of the Participant (or, if earlier, the date of death). In the event payments to the Participant under this Plan shall be delayed for six months following the termination of the Participant as provided in this paragraph (d), the Participant (if then living) shall receive a lump sum payment as of the first day of the seventh month following the termination of employment in an amount equal to six times the monthly payment due to the Participant under this Plan, plus the monthly payment then due to the Participant. If the Participant dies following termination of employment but prior to the commencement of payments under this paragraph (d), the Participant's surviving Eligible Spouse, if any, or Designated Beneficiary shall be entitled to receive the same death benefit payable in the event the Participant had commenced receiving benefit payments as of the first day of the month prior to his death. 4.02 Early Retirement Benefit. (a) Eligibility. A Participant whose employment with the Company or any Affiliated Company terminates upon or after his attainment of age fifty-five (55) with at least fifteen (15) years of Service (except for purposes of calculating benefits payable under Article V. PRE-RETIREMENT DEATH BENEFITS and Article VI. SEVERANCE BENEFITS, as applicable) but prior to his Normal Retirement Date, shall be eligible for the early retirement benefit described in this Section 4.02. (b) Amount and Form. The monthly payment hereunder shall be in the form of a Single Life Annuity if the Participant has no Eligible Spouse and in the form of a 50% Qualified Joint and Survivor Annuity if the Participant has an Eligible Spouse. The eligible Participant's early retirement benefit shall be a monthly amount equal to his Target Early Retirement Benefit reduced by the sum of (1) his Assumed Early Retirement Pension Benefit and (2) his Social Security Benefit; provided, however, such benefit will be reduced, where applicable, by the following: (i) The amount of 2.5% for each year that such benefit is received prior to his Normal Retirement Date, and (ii) If such eligible Participant's projected years of Service at his Normal Retirement Date are less than fifteen (15), his Target Early Retirement Benefit and his Assumed Early Retirement Pension Benefit shall be calculated based upon his actual years of Service at his Early Retirement Date rather than upon his projected years of Service at his Normal Retirement Date. (c) Commencement and Duration. Monthly early retirement benefit payments shall commence as of the first day of the calendar month next following the retirement of the Participant or as soon thereafter as practicable, and shall continue in monthly installments thereafter ending with a payment for the month in which such eligible Participant's death occurs, unless the benefit is being paid in the form of a Qualified Joint and Survivor Annuity, in which case the survivor benefit shall be paid to the Eligible Spouse, if living, for his or her life. If at the time of commencement of payment such eligible Participant does not have an Eligible Spouse, the monthly benefit payments shall be guaranteed for one hundred twenty (120) monthly payments with any such guaranteed payments remaining at such Participant's death payable to his Designated Beneficiary. (d) Key Employees. Notwithstanding the foregoing, payments with respect to a Participant who is a key employee (as defined in Section 416(i) of the Code but determined without regard to the 50 employee limit on the number of officers treated as key employees) shall not begin earlier than six months after the date of termination of the Participant (or, if earlier, the date of death). In the event payments to the Participant under this Plan shall be delayed for six months following the termination of the Participant as provided in this paragraph (d), the Participant (if then living) shall receive a lump sum payment as of the first day of the seventh month following the termination of employment in an amount equal to six times the monthly payment due to the Participant under this Plan, plus the monthly payment then due to the Participant. If the Participant dies following termination of employment but prior to the commencement of payments under this paragraph (d), the Participant's surviving Eligible Spouse, if any, or Designated Beneficiary shall be entitled to receive the same death benefit payable in the event the Participant had commenced receiving benefit payments as of the first day of the month prior to his death. 4.03 Surviving Spouse Benefit. The surviving Eligible Spouse of a Participant who is entitled to receive a Qualified Joint and Survivor Benefit as a normal retirement benefit or as an early retirement benefit shall be eligible for the surviving spouse benefit upon the death of the Participant for the duration of the Eligible Spouse's life. 4.04 Re-employment of Retired Participant. A retired Participant receiving or eligible to receive the retirement benefits described in Sections 4.01 and 4.02 hereof who is reemployed by the Company shall be ineligible to again participate in this Plan. ARTICLE V PRE-RETIREMENT DEATH BENEFITS 5.01 Eligibility. A Participant's surviving Eligible Spouse shall be eligible for the pre- retirement death benefit as described in this Article V if such Participant dies while in the employ of the Company with 10 or more years of Service. 5.02 Amount. Such surviving Eligible Spouse shall be entitled to a monthly pre-retirement death benefit payable in the form of an annuity in an amount equal to the difference, if any, between (a) forty percent (40%) of the Target Pre-Retirement Death Benefit and (b) the Spouse's Pension. 5.03 Alternative Benefit. If greater than the monthly benefit of Section 5.02 hereof, the surviving Eligible Spouse of a Participant who dies while in the employ of the Company after attaining age fifty-five (55) with fifteen (15) years of Service shall be entitled to a monthly pre-retirement death benefit equal to fifty percent (50%) of the early retirement benefit the Participant would have been entitled to receive under Section 4.02 hereof (calculated using both reductions, where applicable, in subsections 4.02(b)(i) and 4.02(b)(ii)) as if he had retired immediately prior to his death with the recommendation of the Chief Executive Officer and approval of the Committee. 5.04 Commencement and Duration. The surviving Eligible Spouse's monthly pre-retirement death benefit payments shall commence in the month following the Participant's death and shall be paid in monthly installments thereafter ending with a payment for the month in which such surviving Eligible Spouse's death occurs. ARTICLE VI SEVERANCE BENEFITS 6.01 Eligibility. Upon his Separation from Service from the Company or any Affiliated Company, a Participant who has completed ten (10) or more years of Service but is not eligible for a retirement benefit under Article IV shall be eligible for one of the severance benefits described in this Article VI. 6.02 Amount. (a) If at Separation from Service such eligible Participant is not entitled to a deferred vested Pension pursuant to Section 5.03 of the Retirement Plan or an early retirement Pension pursuant to Section 5.02 of the Retirement Plan, his severance benefit shall be a monthly amount equal to his Target Severance Benefit reduced by his Social Security Benefit. (b) If at Separation from Service such eligible Participant is entitled to a deferred vested Pension pursuant to Section 5.03 of the Retirement Plan, his severance benefit shall be a monthly amount equal to his Target Severance Benefit reduced by the sum of (1) his Assumed Deferred Vested Pension Benefit and (2) his Social Security Benefit. (c) If at his Separation from Service such eligible Participant is entitled to an early retirement Pension pursuant to Section 5.02 of the Retirement Plan, his severance benefit shall be a monthly amount equal to his Target Severance Benefit reduced by the sum of (1) his Assumed Early Retirement Pension Benefit and (2) his Social Security Benefit; provided, however, such Assumed Early Retirement Pension Benefit shall be calculated based upon his actual years of Service at his Separation from Service rather than upon his projected years of Service at his Normal Retirement Date. 6.03 Commencement and Duration. (a) General. Monthly severance benefit payments shall commence as of the eligible Participant's Normal Retirement Date and shall continue in monthly installments thereafter ending with a payment for the month in which such eligible Participant's death occurs. (b) Key Employees. Notwithstanding the foregoing, payments with respect to a Participant who is a key employee (as defined in Section 416(i) of the Code but determined without regard to the 50 employee limit on the number of officers treated as key employees) shall not begin earlier than six months after the date of termination of the Participant (or, if earlier, the date of death). In the event payments to the Participant under this Plan shall be delayed for six months following the termination of the Participant as provided in this paragraph (b), the Participant (if then living) shall receive a lump sum payment as of the first day of the seventh month following the termination of employment in an amount equal to six times the monthly payment due to the Participant under this Plan, in addition to the monthly payment then due to the Participant. If the Participant dies following termination of employment but prior to the commencement of payments under this paragraph (b), the Participant's surviving Eligible Spouse, if any, shall be eligible for the surviving spouse benefit provided in Section 6.04. 6.04 Surviving Spouse Benefit. (a) Eligibility. The surviving Eligible Spouse of a Participant who is receiving or who dies after attaining age fifty-five (55) entitled to receive a severance benefit hereunder shall be eligible for the surviving spouse benefit described in this Section 6.04. (b) Benefit Amount. Such surviving Eligible Spouse shall be entitled to a monthly surviving spouse benefit in an amount equal to fifty percent (50%) of the severance benefit which the deceased Participant was receiving or entitled to receive at his Normal Retirement Date under either Section 6.02(a) or 6.02(b) hereof on the day before his death. (c) Commencement and Duration. The monthly surviving spouse benefit payment shall commence in the month following the Participant's death and shall be paid in monthly installments thereafter ending with a payment for the month in which such surviving Eligible Spouse's death occurs. ARTICLE VII ADMINISTRATION 7.01 Committee. This Plan shall be administered by the Committee. The Committee shall have all powers necessary to enable it to carry out its duties in the administration of the Plan. Not in limitation, but in application of the foregoing, the Committee shall have the duty and power to determine all questions that may arise hereunder as to the status and rights of Participants in the Plan. 7.02 Voting. The Committee shall act by a majority of the number then constituting the Committee, and such action may be taken either by vote at a meeting or in writing, without a meeting. 7.03 Records. The Committee shall keep a complete record of all its proceedings and all data relating to the administration of the Plan. The Committee shall select one of its members as a Chairman. The Committee shall appoint a Secretary to keep minutes of its meetings and the Secretary may or may not be a member of the Committee. The Committee shall make such rules and regulations for the conduct of its business as it shall deem advisable. 7.04 Liability. To the extent permitted by law, no member of the Committee shall be liable to any person for any action taken or omitted in connection with the interpretation and administration of this Plan unless attributable to his own gross negligence or willful misconduct. The Sponsor shall indemnify the members of the Committee against any and all claims, losses, damages, expenses, including counsel fees, incurred by them, and any liability, including any amounts paid in settlement with their approval, arising from their action or failure to act, except when the same is judicially determined to be attributable to their gross negligence or willful misconduct. 7.05 Expenses. The cost of payments from this Plan and the expenses of administering the Plan shall borne by each Company with respect to its own employees. ARTICLE VIII AMENDMENT AND TERMINATION The Sponsor reserves the right, at any time or from time to time, by action of its Board, to modify or amend in whole or in part any or all provisions of the Plan. In addition, the Sponsor reserves the right by action of its Board to terminate the Plan in whole or in part. Provided, however, any such modification, amendment or termination shall not in any way affect a Participant's accrued benefit or the right to payment thereof under the provisions of the Plan as in effect immediately prior to such amendment or termination. Notwithstanding the foregoing, the Plan may be terminated and benefits distributed to Participants within twelve months of a "change in control" as defined for purposes of Section 409A of the Code. ARTICLE IX MISCELLANEOUS 9.01 Non-Alienation of Benefits. No right or benefit under the Plan shall be subject to anticipation, alienation, sale, assignment, pledge, encumbrance, or charge, and any attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge any right or benefit under the Plan shall be void. No right or benefit hereunder shall in any manner be liable for or subject to the debts, contracts, liabilities or torts of the person entitled to such benefits. If the Participant or Eligible Spouse shall become bankrupt, or attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge any right hereunder, then such right or benefit shall, in the discretion of the Committee, cease and terminate, and in such event, the Committee may hold or apply the same or any part thereof for the benefit of the Participant or his spouse, children, or other dependents, or any of them, in such manner and in such amounts and proportions as the Committee may deem proper. 9.02 No Trust, Created. The obligations of the Sponsor and each Company to make payments hereunder shall constitute a liability of the Sponsor and each Company, as the case may be, to a Participant. Such payments shall be made from the general funds of the Sponsor or a Company, and the Sponsor or a Company shall not be required to establish or maintain any special or separate fund, or purchase or acquire life insurance on a Participant's life, or otherwise to segregate assets to assure that such payment shall be made, and neither a Participant nor Eligible Spouse shall have any interest in any particular asset of the Sponsor or a Company by reason of its obligations hereunder. Nothing contained in the Plan shall create or be construed as creating a trust of any kind or any other fiduciary relationship between the Sponsor, a Company and a Participant or any other person. 9.03 No Employment Agreement. Neither the execution of this Plan nor any action taken by the Sponsor or a Company pursuant to this Plan shall be held or construed to confer on a Participant any legal right to be continued as an employee of the Sponsor or a Company in an executive position or in any other capacity whatsoever. This Plan shall not be deemed to constitute a contract of employment between the Sponsor or a Company and a Participant, nor shall any provision herein restrict the right of any Participant to terminate his employment with the Sponsor or a Company. 9.04 Binding Effect. Obligations incurred by the Sponsor or a Company pursuant to this Plan shall be binding upon and inure to the benefit of the Sponsor or a Company, its successors and assigns, and the Participant or his Eligible Spouse. 9.05 Suicide. No benefit shall be payable under the Plan to a Participant or Eligible Spouse where such Participant dies as a result of suicide within two (2) years of his commencement of participation herein. 9.06 Claims for Benefits. Each Participant or Eligible Spouse must claim any benefit to which he is entitled under this Plan by a written notification to the Committee. If a claim is denied, it must be denied within a reasonable period of time, and be contained in a written notice stating the following: A. The specific reason for the denial. B. Specific reference to the Plan provision on which the denial is based. C. Description of additional information necessary for the claimant to present his claim, if any, and an explanation of why such material is necessary. D. An explanation of the Plan's claims review procedure. The claimant will have 60 days to request a review of the denial by the Committee, which will provide a full and fair review. The request for review must be in writing delivered to the Committee. The claimant may review pertinent documents, and he may submit issues and comments in writing. The decision by the Committee with respect to the review must be given within 60 days after receipt of the request, unless special circumstances require an extension (such as for a hearing). In no event shall the decision be delayed beyond 120 days after receipt of the request for review. The decision shall be written in a manner calculated to be understood by the claimant, and it shall include specific reasons and refer to specific Plan provisions as to its effect. 9.07 Entire Plan. This document and any amendments contain all the terms and provisions of the Plan and shall constitute the entire Plan, any other alleged terms or provisions being of no effect. 9.08 Change in Control. In the event of a Change in Control, the Sponsor shall irrevocably set aside funds in one or more grantor trusts in an amount that is sufficient to pay each Participant (or Designated Beneficiary) the amount of benefits accrued under the Plan as of the date of the Change in Control. Any such trust shall be subject to the claims of the general creditors of the Company in the event of the bankruptcy or insolvency of the Company. 9.09 Acceleration of Payment. The acceleration of the time or schedule of any payment due under the Plan is prohibited except as provided in regulations and administrative guidance provided under Section 409A of the Code. It is not an acceleration of the time or schedule of payment if the Company waives or accelerates the vesting requirements applicable to a benefit under the Plan. ARTICLE X CONSTRUCTION 10.01Governing Law. This Plan shall be construed and governed in accordance with the laws of the State of North Carolina, to the extent not preempted by Federal Law. The Plan shall be construed in a manner that is consistent with the requirements of Section 409A of the Code and any regulations thereunder. 10.02Gender. The masculine gender, where appearing in the Plan, shall be deemed to include the feminine gender, and the singular may include the plural, unless the context clearly indicates to the contrary. 10.03Headings, etc. The cover page of this Plan, the Table of Contents and all headings used in this Plan are for convenience of reference only and are not part of the substance of this Plan. 10.04Action. Any action under this Plan required or permitted by the Sponsor shall be by action of its Board or its duly authorized designee. APPENDIX A Progress Energy Florida, Inc. (non-bargaining employees) ("PEF"); provided that for all purposes of the Plan, Service for an employee of PEF on December 31, 2001 (as defined in Section 2.21) shall include employment only with PEF (or another adopting Company) on or after January 1, 2002; and further provided that the accrued benefit calculated under Sections 2.03, 2.04 and 2.05 shall not include the "Accrued Benefit" under Supplement B, Paragraph B-2(a) of the Retirement Plan, attributable to the FPC Plan. Progress Fuels Corporation (corporate employees) ("PFC"); provided that for all purposes of the Plan, Service for an employee of PFC on December 31, 2001 (as defined in Section 2.21) shall include employment only with PFC (or another adopting Company) on or after January 1, 2002; and further provided that the accrued benefit calculated under Sections 2.03, 2.04 and 2.05 shall not include the "Accrued Benefit" under Supplement B, Paragraph B-2(a) of the Retirement Plan, attributable to the FPC Plan. Progress Energy Carolinas, Inc. Progress Energy Service Company, LLC Progress Energy Ventures, Inc. EX-10 8 pei_exhibit10c18-.txt EXHIBIT 10C(18) Exhibit 10c(18) Progress Energy, Inc. Restricted Stock Agreement This Agreement is made as of the ____ day of ______, _____, between Progress Energy, Inc., a North Carolina corporation (the "Company"), its affiliates, successors or assigns and ________________ (the "Employee"), an employee of [Insert name of affiliate employer], an Affiliate of the Company (the "Employer"). WHEREAS, the Board of Directors and shareholders of the Company have approved and adopted the Progress Energy, Inc. 2002 Equity Incentive Plan (the "Plan"); WHEREAS, pursuant to Section 9 of the Plan, the Organization and Compensation Committee of the Board (hereinafter the "Committee") is authorized to grant Restricted Stock to Key Employees of the Company, including its Affiliates; and WHEREAS, the Company desires to provide an incentive to the Employee so that he will exert his utmost efforts on behalf of the Employer, and for any other Affiliate of the Company for which the Employee performs services while holding the Restricted Stock, and thus enhance that employer's performance while aligning the Employee's interests with the interests of the Company's shareholders. NOW, THEREFORE, the parties hereto, intending to be legally bound hereby, agree as follows: 1. Grant of Shares Subject to Restrictions. The Employee is granted __________ shares of Company Common Stock (the "Restricted Stock"). The Restricted Stock is granted under the Plan, and is subject to the terms and conditions of the Plan and this Agreement. Capitalized terms not defined herein shall have the meanings ascribed thereto in the Plan. In accordance with Section 12 of the Plan, the Committee has determined that the grant of Restricted Stock under this Agreement is not intended to qualify for the exemption for performance-based compensation under Section 162(m) of the Code. The Restricted Stock granted hereunder is a matter of separate inducement and is not in lieu of salary or any other compensation for Employee's services. Both parties acknowledge that the "Grant Date" for the Restricted Stock shall be the date of this Agreement, which is first specified above. 2. Restrictions. Employee hereby agrees that until such restrictions are removed, as herein provided, he will not sell, assign, transfer, exchange, hypothecate, pledge, encumber or otherwise dispose of the Restricted Stock. Any attempt by the Employee to dispose of any shares of the Restricted Stock in any such manner shall result in the immediate forfeiture of such shares and any other shares then held by the Company or the designated escrow agent on the Employee's behalf. 3. Lapse of Restrictions. Subject to Paragraph 4 below and applicable provisions of the Plan, the shares of Restricted Stock shall be subject to restrictions on transferability. Said restrictions shall be removed from such shares of Restricted Stock based upon the vesting schedule set forth below: (a) ______ shares of Restricted Stock shall become and remain transferable on and after the _______ anniversary of the Date of Grant; (b) ______ shares of Restricted Stock shall become and remain transferable on and after the _______ anniversary of the Date of Grant; and (c) ______ shares of Restricted Stock shall become and remain transferable on and after the ________ anniversary of the Date of Grant. OR Lapse of Restrictions. Subject to Paragraph 4 below and applicable provisions of the Plan, the shares of Restricted Stock shall be subject to restrictions on transferability. Said restrictions shall be removed from such shares of Restricted Stock, and said shares shall become and remain transferable on and after ______________. 4. Termination of Employment. In the event the Employee's employment with the Employer or any other Affiliate by which the Employee may subsequently be employed, is terminated for any reason (except as specifically provided in Paragraph 7 below), then all shares of Restricted Stock that are still subject to restrictions under this Agreement shall be returned to the Company as of the date of such termination and all such shares of Restricted Stock shall be forfeited by the Employee as of the date of such termination. 5. Acquisition and Possession of Restricted Stock. The Restricted Stock granted hereunder shall be promptly acquired for the Employee and a certificate or certificates for such Restricted Stock shall be promptly provided in the Employee's name. Unless as otherwise provided in this Paragraph 5, the Company shall hold the certificate or certificates for the shares of Restricted Stock until the date the restrictions on transferability are removed in accordance with Paragraph 3 above. The Committee may, in its sole discretion and at any time prior to the date the restrictions on transferability are removed in accordance with Paragraph 3 above, require (i) that the stock certificate or certificates representing such shares shall be imprinted with a legend stating that the shares represented thereby are the restricted shares subject to the terms and conditions of this Agreement and, as such, may not be sold, exchanged, transferred, pledged, hypothecated or otherwise disposed of except in accordance with the terms of this Agreement, and if the Committee makes such requirement, then each transfer agent for the Common Stock shall be 2 instructed to like effect with respect to such shares, and/or (ii) that the Employee shall, upon receipt of the certificate or certificates therefor, deposit such instrument of transfer, appropriately endorsed in blank, with an escrow agent designated by the Committee, which may be the Company, under a deposit agreement containing such terms and conditions as the Committee shall approve, with the expenses of such escrow to be borne by the Company. 6. Rights to Dividends and Voting Rights. During the Period of Restriction and prior to the removal of restrictions as set forth in Paragraph 3 above, the Employee shall be the shareholder of all shares of Common Stock represented by the stock certificates, and shall be entitled to receive all voting rights and dividends associated with the Restricted Stock as with all other Company Common Stock shareholders; provided, however, that the shares shall be subject to the restrictions on transferability set forth in Paragraph 2 above. 7. Special Conditions. (a) Change in Control. The restrictions on all Restricted Stock granted pursuant to this Agreement shall be fully removed in the event the employment of the Employee is terminated by the Company, an Affiliate of the Company, or a successor to the Company, without Cause following a Change in Control, and the Employee shall take full and unrestricted ownership of such shares. (b) Death or Disability. In the event that, after the expiration of one year from the Grant Date, the Employee dies or experiences a Disability as defined in the Plan and becomes eligible to receive long-term disability benefits under the Company's Long-Term Disability Plan then in effect, then the restrictions on the Restricted Stock as set forth in Paragraph 3 of this Agreement shall be immediately and fully removed, and the Employee or his Designated Beneficiary (as applicable) shall take full and unrestricted ownership of such shares. (c) Retirement. In the event that the Employee terminates employment with the Employer, or any other Affiliate by which the Employee may subsequently be employed, at or following Early Retirement or Normal Retirement, as defined in the Plan, the Committee may, in its discretion, remove any time-based Period of Restriction on the Restricted Stock. 8. Capital Adjustments. If under Section 6.4 of the Plan the Employee, as the owner of the shares of the Restricted Stock, shall be entitled to new, additional or different shares of stock or securities, (i) the Committee may require that the certificate or certificates for, or other evidences of, such new, additional or different Stock or securities, together with a stock power or other instrument of transfer appropriately endorsed, shall be (x) imprinted with a legend as provided in Paragraph 5 above and/or (y) 3 deposited by the Employee under the deposit agreement provided for in Paragraph 5 above, and (ii) such certificate or certificates for, or other evidences of, such new additional or different Stock or securities, shall be subject to the restrictions on transferability as provided in Paragraph 3 above. 9. Taxes. By acceptance of this Agreement, the Employee agrees that the Committee may require the Employee to remit to or reimburse the Affiliate that employs the Employee as of the date of any scheduled lapse of restrictions as specified in Paragraph 3 above for the amount of any taxes required to be deducted or withheld with respect to the Restricted Stock, or in lieu thereof such Affiliate may withhold (or the Employee may be provided the opportunity to elect to tender) the number of shares of Restricted Stock equal in Fair Market Value to the amount of taxes required to be withheld. Additionally, the Employee agrees that the Affiliate that employs the Employee as of such date of lapse of restrictions shall have the right to deduct or withhold any taxes required by law to be withheld with respect to the Restricted Stock from any sums due or to become due from such Affiliate to the Employee. 10. Waiver of Election. By acceptance of this Agreement, the Employee agrees to irrevocably waive his right to make an election (as permitted under Section 83(b) of the Code) to include in gross income for the taxable year in which the Restricted Stock is granted an amount equal to the Fair Market Value of the Restricted Stock. 11. Compliance With Laws. If the Company, in its sole discretion, shall determine that it is necessary to comply with applicable securities laws, the certificate or certificates representing any shares of Common Stock delivered to the Employee under this Agreement shall bear an appropriate legend in form and substance, as determined by the Company, giving notice of applicable restrictions on transfer under or with respect to such laws. 12. Registration of Securities. The Employee covenants and agrees with the Company that if, with respect to any shares of Common Stock delivered to the Employee pursuant to this Agreement, there does not exist a Registration Statement on an appropriate form under the Securities Act of l933, as amended (the "Act"), which Registration Statement shall have become effective and shall include a prospectus that is current with respect to the shares subject to this Agreement, then the Employee shall execute a certificate to the Company indicating (i) that he takes the shares for his own account and not with a view to the resale or distribution thereof, (ii) that any subsequent offer for sale or sale of any such shares shall be made either pursuant to (x) a Registration Statement on an appropriate form under the Act, which Registration Statement shall have become effective and shall be current with respect to the shares being offered and sold, or (y) a specific exemption from the registration requirements of the Act and any rules or regulations thereunder and any applicable state securities laws and regulations, but in claiming such exemption, the Employee shall, prior to any offer for sale or 4 sale of such shares, obtain a favorable written opinion from counsel for or approved by the Company as to the applicability of such exemption and (iii) that the Employee agrees that the certificate or certificates evidencing such shares shall bear a legend to the effect of the foregoing. 13. Priority of Documents. This Agreement is subject to all terms, conditions, limitations and restrictions contained in the Plan, which shall be controlling in the event of any conflicting or inconsistent provisions. 14. No Employment Contract. This Agreement is not a contract of employment and the terms of the Employee's employment shall not be affected hereby or by any agreement referred to herein except to the extent specifically so provided herein or therein. Nothing herein shall be construed to impose any obligation on the Employer, or any other Affiliate for which the Employee may subsequently perform services, to continue the Employee's employment, and it shall not impose any obligation on the Employee's part to remain in the employ of any Affiliate. 15. Company Information. Employee acknowledges and agrees that neither the Company, its shareholders nor its directors and officers has any duty or obligation to disclose to the Employee any material information regarding the business of the Company or affecting the value of the Common Stock before or at the time of a termination of the employment of the Employee by the Employer, or any other Affiliate for which the Employee may subsequently perform services, including, without limitation, any information concerning plans for the Company to make a public offering of its securities or to be acquired by or merged with or into another firm or entity. IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the day and date set forth above. Progress Energy, Inc. By: --------------------------------------- (Name) (Title) ACCEPTED: - ------------------------------------------ (Name) Employee Date: ------------------------------------- EX-10 9 pei_exhibit10c28-.txt EXHIBIT 10C(28) Exhibit 10(c)28 March 31, 2004 Mr. William Cavanaugh III 1109 Tazwell Place Raleigh, NC 27612 Dear Bill: This letter will confirm the discussions we have recently had concerning your upcoming retirement as Chief Executive Officer on March 1, 2004, and as Chairman of the Board at the May 12 Annual Meeting of Shareholders. As agreed, you will be available to provide various services to the Company after May 12, 2004. These services will be as requested by, and performed under the general direction of, Progress Energy's Chief Executive Officer, as agreed to by you. The compensation for such services will be as approved by the Chief Executive Officer. The Company will continue to provide you with the following services and benefits: a home alarm and security service, a company network telephone and facsimile equipment at your residences, a personal computer, and a cellular telephone. The Company will provide you with financial planning for three years following your retirement and will provide financial planning for Mrs. Cavanaugh for one year after your death (if you predecease her). The Company will also continue to provide appropriate office and secretarial support. These services and appropriate office accommodations will be supplied until you attain the age of 75. After such time, if services or accommodations of any kind might be appropriate, the matter will be determined at that time by the Chief Executive Officer. In addition, the Company will reimburse you for your reasonable expenses in connection with your upcoming service for one term as Chairman of the World Association of Nuclear Operations (WANO). We understand that your term as Chairman of WANO will commence this year and will be a two-year commitment. Reasonable expenses will include the cost of a security detail in those places where security would be appropriate. The need for security will be determined after consultation with Progress Energy Corporate Security and the Chief Executive Officer or his designee. You should review your travel and other plans and expenditures concerning WANO in advance with the Chief Executive Officer. I look forward to our continued association. Sincerely, /s/ Robert B. McGehee Attachment Agreed: /s/ William Cavanaugh III Approved: /s/ Charles W. Coker ------------------------- -------------------- William Cavanaugh III Charles W. Coker EX-10 10 pei_exhibit10c29.txt EXHIBIT 10C(29) Exhibit 10c(29) EMPLOYMENT AGREEMENT BETWEEN PROGRESS ENERGY CAROLINAS, INC. AND WILLIAM D. JOHNSON January 1, 2005 EMPLOYMENT AGREEMENT This EMPLOYMENT AGREEMENT ("Agreement"), dated as of the ____________ day of January, 2005, is between Progress Energy Carolinas, Inc., a limited liability corporation headquartered in Raleigh, North Carolina and a wholly-owed subsidiary of Progress Energy, Inc., its successors or assigns, and William D. Johnson ("Johnson"). Progress Energy Carolinas, Inc. shall be referred to as "PEC" or "the Company" throughout. Progress Energy, Inc. shall be referred to as "Progress Energy" throughout. Preamble The Company and Johnson agree to enter into an employment relationship in which Johnson will serve as President and Chief Operating Officer of Progress Energy, 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. Johnson shall occupy the position of President and Chief Operating Officer at Progress Energy and shall undertake the general responsibilities and duties of such position as directed by Progress Energy's Chief Executive Officer. During the Term of the Agreement as defined in Section 2, below, Johnson shall perform faithfully the duties of Johnson's position, devote all of Johnson's working time and energies to the business and affairs of Progress Energy's regulated operating subsidiaries and shall use Johnson's best efforts, skills and abilities to promote Progress Energy's general business interests. PEC reserves the right to reassign Johnson to other positions within the controlled group of Progress Energy companies. 2. TERM OF THE AGREEMENT: (a) The Agreement becomes effective on January 1, 2005 ("the Effective Date"), and shall remain in effect until December 31, 2007. (b) On January 1, 2006 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"). (c) The Company may elect to not extend the Agreement and must notify Johnson 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 Johnson's normal retirement date unless Johnson 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, Johnson will be paid a Base Salary at the annual rate of ________________ ($_________) (less applicable withholdings) ("Base Salary") during 2005. Base Salary for each subsequent year of employment under the Agreement shall be subject to adjustment by PEC during the normal annual salary review process for similarly situated executives as determined by PEC in its discretion. Annual Base Salary shall be deemed earned proportionally as Johnson 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 PEC's standard payroll policies and procedures. 4. EMPLOYEE BENEFIT PLANS. During the Employment Term, Johnson 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 PEC employees. 5. EXECUTIVE INCENTIVES, BENEFITS AND PERQUISITES. Johnson 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. Johnson is eligible to participate in the Progress Energy sponsored Management Incentive Compensation Plan (MICP), subject to its terms. (b) Long Term Incentive Plans. Johnson 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) Restricted Stock. An award of restricted common stock vesting ratably on the 3rd, 4th and 5th anniversaries from the date of grant. These annual awards are generally made in March. 2 (c) Base Salary Deferral Plan. Johnson is eligible to participate in the Progress Energy sponsored Management Deferred Compensation Plan (MDCP), subject to its terms. (d) Incentive Deferral Plans. Johnson is eligible to defer up to 100% of his earned MICP and/or PSSP awards into deemed investments of Progress Energy common stock on an unfunded basis. (e) Supplemental Senior Executive Retirement Plan. Johnson shall be eligible for participation in Progress Energy's Supplemental Senior Executive Retirement Plan (SERP), subject to its terms. For purposes of the SERP only, Johnson has been credited with seven years of deemed service (vesting and benefits), including the three year Senior Management Committee requirement. (f) Split Dollar Insurance Plan. Johnson shall continue to participate in the Progress Energy sponsored Split Dollar Life Insurance Plan, subject to its terms and consistent with applicable laws and regulations. (g) Executive AD&D Life Insurance. Johnson shall be eligible to participate in Progress Energy's Executive AD&D Life Insurance Plan, subject to its terms. (h) Financial Planning. Johnson shall be eligible to participate in the Progress Energy sponsored financial planning program, subject to its terms. (i) Estate Planning. Johnson is eligible to receive reimbursement of up to $_________ annually for the preparation and periodic update of Johnson's estate plan. (j) Automobile Allowance. Johnson is eligible to receive an automobile allowance of ___________________ ($______) per month (less withholdings), subject to the terms of applicable Progress Energy policies. (k) Annual Physical. PEC will pay for an annual physical examination by a physician of Johnson's choice within the parameters of Progress Energy's executive physical program. (l) Luncheon Club. PEC will pay the monthly dues for a membership at a luncheon club approved by Progress Energy's Chief Executive Officer. Business related expenses will be reimbursed consistent with PEC's expense account guidelines. (m) Country Club Membership. PEC will pay an initiation fee and monthly dues for a membership for Johnson at a country club approved by Progress Energy's Chief Executive Officer. Business related expenses will be reimbursed consistent with PEC expense account guidelines. 3 (n) Health Club Membership. PEC will pay an initiation fee and monthly dues to a health club for Johnson's membership. (o) Home Security. PEC will provide a home security system at Johnson's residence and reimburse Johnson for applicable monitoring fees. (p) Air Travel. (i) PEC will provide an airline club membership in accordance with Company policy. (ii) PEC will reimburse Johnson's spouse's travel expenses when she accompanies Johnson to business meetings where spousal attendance is customary. (iii) PEC will provide chartered aircraft for Johnson's business related travel as needed. (iv) PEC will allow Johnson to travel first class at his discretion for business related travel. (q) Personal Computer. PEC will provide a personal computer to Johnson to be used at his personal residence. 6. COMPANY PLAN AND PROGRAM MAINTENANCE. Johnson's entitlement to the benefits described in Sections 4 and 5 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. 7. VACATION AND HOLIDAYS. Johnson will be entitled to four (4) 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. Johnson will be granted paid holidays per Company policy. 8. TERMINATION OF EMPLOYMENT. (a) Involuntary Termination. (i) For purposes of this Agreement, PEC shall be deemed to have terminated Johnson's employment if Johnson is displaced from an assignment within the controlled group of Progress Energy subsidiaries and affiliates, and (1) is not simultaneously reassigned to another position within the controlled 4 group of Progress Energy subsidiaries and affiliates; or (2) in the event that Progress Energy sells more than 50% of its interest in a Progress Energy subsidiary to which Johnson is assigned to a third party during the term of Johnson's assignment, the third party purchaser does not offer Johnson a position with comparable authority, duties, wages and benefits. (ii) Termination Without Cause. During the term of this Agreement, if Johnson's employment from the controlled group of Progress Energy companies is terminated without Cause as Cause is defined in paragraph 8(a)(iii), then Johnson 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, PEC will reimburse Johnson 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 Johnson 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 8(f), (g) and (h) of this Agreement. In addition, Johnson 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, PEC may elect at any time to terminate Johnson's employment immediately hereunder and remove Johnson from employment for Cause. For purposes of this paragraph 8(a)(iii), Cause for the termination of employment shall be defined as: (1) any act of Johnson's including, but not limited to, misconduct, negligence, unlawfulness, dishonesty or inattention to the business, which is detrimental to PEC's interests; or (2) Johnson's unsatisfactory job performance or failure to comply with PEC policies, rules or regulations. If Johnson 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, Johnson shall be entitled to any earned but unpaid Base Salary accrued to the date of termination. Any continued rights or benefits Johnson or his legal representatives may have under any PEC 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. (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 Johnson 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 defined in paragraph 8(a)(ii), will be the legal authority regarding any severance compensation and benefits. 5 (c) Voluntary Termination. If Johnson 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 Johnson's death during the Term of the Agreement, Johnson's employment hereunder shall terminate and the Company shall have no further obligation to Johnson under this Agreement except as specifically provided in this Agreement. Johnson's 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 Johnson's death occurs shall be calculated on a pro rata basis for the portion of the fiscal year prior to Johnson's death occurring and shall be paid at the regularly scheduled time for the payment of the short term incentive. Any rights and benefits Johnson, or Johnson's estate or other legal representatives, may have under employee benefit plans and programs of PEC or Progress Energy upon Johnson's 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) PEC may terminate Johnson's 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, Johnson 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, Johnson 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 Johnson applies for and is deemed qualified for benefits under the Progress Energy sponsored Long Term Disability Plan (LTD Benefits), Johnson shall receive such benefits and his employment will not be terminated as long as he is receiving LTD Benefits. (ii) Upon the termination of Johnson's employment due to medical condition or any period during which Johnson is qualified for LTD Benefits, PEC shall have no further obligation to Johnson under this Agreement except as specifically provided in this Agreement. Upon such termination or qualification for LTD Benefits, Johnson 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 Johnson 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 Johnson, or Johnson's legal representatives, may have under employee benefit plans and programs of PEC or Progress Energy upon Johnson's 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. 6 (f) Release of Claims. In order to receive continuation of salary under paragraph 8(a) or 8(b), Johnson agrees to execute a written release of all claims against PEC, and its employees, officers, directors, subsidiaries and affiliates, on a form acceptable to PEC. (g) Covenant Not to Compete. If PEC terminates Johnson's employment without Cause under paragraph 8(a), or if Johnson becomes eligible for the benefits available under paragraph 8(a) as the result of a Change in Control as set forth in paragraph 8(b), Johnson, 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 Johnson was involved at the time of his separation. (h) Non Interference. If PEC terminates Johnson's employment without Cause under paragraph 8(a) or if Johnson becomes eligible for the benefits available under paragraph 8(a) as the result of a Change in Control as set forth in paragraph 8(b), Johnson, 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. 9. ASSIGNABILITY. No rights or obligations of Johnson under this Agreement may be assigned or transferred by Johnson, except that (i) Johnson's rights to compensation and benefits hereunder may be transferred by will or laws of intestacy to the extent specified herein and (ii) Johnson's rights under employee benefit plans or programs described in Sections 4 and 5 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. 10. CONFIDENTIALITY. Johnson 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 PEC promptly upon receipt of such order or subpoena. 7 11. 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 Johnson and by an officer of PEC 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 PEC, 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): If to Johnson: William D. Johnson Progress Energy Carolinas, Inc. 410 S. Wilmington Street, PEB 1219 Raleigh, North Carolina 27601 If to PEC: Progress Energy Carolinas, Inc. c/o Progress Energy Service Company, LLC 410 S. Wilmington Street Raleigh, North Carolina 27601 Attn.: Vice President, Human Resources 8 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 Johnson's death or a judicial determination of Johnson's incompetence, reference in this Agreement to Johnson shall be deemed, where appropriate, to refer to Johnson's legal representative, or, where appropriate, to Johnson's 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: (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." 9 (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. WILLIAM D. JOHNSON Date: - ----------------------------------- -------------------- PROGRESS ENERGY CAROLINAS, INC. By: Date: -------------------------------- -------------------- ROBERT B. MCGEHEE CHAIRMAN EX-10 11 pei_exhibit10d1-.txt EXHIBIT 10D(1) Exhibit 10d(1) PURCHASE AGREEMENT BY AND BETWEEN WINCHESTER PRODUCTION COMPANY, LTD. TGG PIPELINE, LTD. PROGRESS FUELS CORPORATION AND ENCANA OIL & GAS (USA), INC. November 18, 2004 TABLE OF CONTENTS Page ARTICLE I DEFINITIONS.......................................................1 1.1. Action.........................................................1 1.2. Agreement......................................................1 1.3. Allocated Value................................................1 1.4. Assignment.....................................................1 1.5. Assumption Agreement...........................................2 1.6. Assets.........................................................2 1.7. Assumed Liabilities............................................2 1.8. Base Purchase Price............................................2 1.9. Basket.........................................................3 1.10. Beck Lease.....................................................3 1.11. Books and Records..............................................3 1.12. Burdened Leases................................................3 1.13. Business Day...................................................3 1.14. Buyer..........................................................3 1.15. Buyer Claim....................................................3 1.16. Buyer Indemnified Party........................................3 1.17. Buyer's Schedule of Allocated Values...........................3 1.18. Closing........................................................3 1.19. Closing Date...................................................3 1.20. Code...........................................................3 1.21. Easements......................................................4 1.22. Effective Time.................................................4 1.23. Environmental Laws.............................................4 1.24. Ewing Lease....................................................4 1.25. Excluded Assets................................................4 1.26. Governmental Authority.........................................4 1.27. Hazardous Substances...........................................4 1.28. Knowledge of Seller............................................5 1.29. Laws...........................................................5 1.30. Lease..........................................................5 1.31. Lease Burdens..................................................5 1.32. Losses.........................................................5 1.33. Material Adverse Effect........................................5 1.34. Maximum Indemnity Amount.......................................5 1.35. Net Revenue Interest...........................................5 1.36. Office Leases..................................................5 1.37. Permits........................................................5 1.38. Permitted Encumbrances.........................................6 1.39. Personal Property..............................................6 1.40. PFC............................................................6 1.41. Prime Rate.....................................................6 (i) 1.42. Production.....................................................6 1.43. Production Payment.............................................7 1.44. Production Payment Liquidation Amount..........................7 1.45. Properties.....................................................7 1.46. Property Agreements............................................7 1.47. Purchase Price.................................................7 1.48. Referral Firm..................................................7 1.49. REI............................................................7 1.50. Retained Liabilities...........................................7 1.51. Seller.........................................................7 1.52. Seller Claim...................................................7 1.53. Seller Indemnified Party.......................................7 1.54. Taxes..........................................................7 1.55. Tax Returns....................................................8 1.56. TGG Assets.....................................................8 1.57. Title Defect...................................................8 1.58. Title Defect Mechanism.........................................8 1.59. Wells..........................................................8 1.60. Working Interest...............................................8 ARTICLE II PURCHASE AND SALE................................................8 2.1. Purchase and Sale..............................................8 2.2. Purchase Price.................................................9 2.3. Adjustments to Base Purchase Price.............................9 2.4. Determination of Purchase Price...............................11 2.5. Allocation of Purchase Price..................................12 2.6. No Assumption of Retained Liabilities.........................12 2.7. Effective Time................................................12 ARTICLE III REPRESENTATIONS AND WARRANTIES OF SELLER.......................13 3.1. Organization..................................................13 3.2. Due Authorization.............................................13 3.3. No Violation or Conflict; Consents; Preferential Rights.......13 3.4. Title.........................................................13 3.5. Contracts.....................................................14 3.6. Lease Provisions..............................................15 3.7. Compliance with Law...........................................15 3.8. Litigation....................................................15 3.9. Taxes.........................................................15 3.10. Environmental Matters.........................................15 ARTICLE IV REPRESENTATIONS AND WARRANTIES OF THE BUYER.....................16 4.1. Organization..................................................16 4.2. Authorization.................................................16 (ii) 4.3. Noncontravention..............................................16 4.4. No Reliance...................................................16 4.5. Purchase for Investment.......................................17 4.6. Financing.....................................................17 ARTICLE V COVENANTS........................................................17 5.1. Conduct of Business...........................................17 5.2. Access to Information.........................................17 5.3. Further Assurances; Consents; Waiver of Notices...............17 5.4. Publicity.....................................................18 5.5. Environmental Investigation...................................18 5.6. Buyer's Schedule of Allocated Values..........................19 5.7. Amendment of Schedules........................................20 ARTICLE VI CONDITIONS PRECEDENT TO CONSUMMATION OF THE CLOSING; CLOSING....20 6.1. Conditions Precedent to Each Party's Obligations to Close.....20 6.2. Conditions Precedent to Obligations of the Buyer..............21 6.3. Conditions Precedent to Obligations of Seller.................21 6.4. The Closing...................................................22 ARTICLE VII ADDITIONAL COVENANTS...........................................23 7.1. Access to Books and Records...................................23 7.2. Tax Matters...................................................23 7.3. Surety Bonds..................................................24 7.4. Casualty......................................................24 7.5. Consents and Preferential Rights..............................24 7.6. Employee Matters..............................................25 7.7. Non-Solicitation..............................................25 7.8. Transition Services Agreement.................................25 7.9. Leased Equipment and Licensed Software........................25 7.10. Beck Lease....................................................25 7.11. Ewing Lease...................................................25 ARTICLE VIII SURVIVAL; INDEMNIFICATION.....................................26 8.1. Limitation on and Survival of Representations and Warranties..26 8.2. Indemnification by Seller.....................................26 8.3. Indemnification by Buyer......................................27 8.4. Limitation of Liability.......................................29 8.5. Exclusive Remedy..............................................29 8.6. Title Defects.................................................29 8.7. Disclaimer of Other Warranties................................29 (iii) ARTICLE IX TERMINATION.....................................................30 9.1. Termination...................................................30 9.2. Effect of Termination.........................................31 9.3. Amendment.....................................................31 9.4. Extension; Waiver.............................................31 ARTICLE X MISCELLANEOUS....................................................31 10.1. Entire Agreement..............................................31 10.2. Expenses......................................................31 10.3. Governing Law.................................................32 10.4. Assignment....................................................32 10.5. Notices.......................................................32 10.6. Counterparts; Headings........................................33 10.7. Specific Performance..........................................33 10.8. Interpretation................................................33 10.9. Severability..................................................33 10.10. No Third-Party Reliance.......................................33 SCHEDULES Exhibit A Procedure for Claiming Title Defects and Adjusting the Base Purchase Price Exhibit B Form of Assignment, Conveyance and Bill of Sale Exhibit C Form of Assumption Agreement Exhibit D Form of FIRPTA Affidavit Exhibit E TGG Asset Assignment Exhibit F Buyer's Initial Schedule of Allocated Values Schedule 1.25 Excluded Leases Schedule 2.1 TGG Assets Schedule 2.3(a)(v) Condensate in Stock as of October 31, 2004 Schedule 2.3(b) Accrued Suspense Funds Schedule 2.5 Allocation of Purchase Price (Tax) Schedule 3.3 Conflicts Schedule 3.4(a) Personal Property Schedule 3.4(b) Leases Schedule 3.4(c) Rights of Way and Surface Damage Agreements Schedule 3.5(a) Property Agreements Schedule 3.5(b) Exceptions to Contracts Schedule 3.6 Exceptions to Lease Provisions Schedule 3.7 Exceptions to Compliance with Law Schedule 3.8 Litigation (iv) Schedule 3.9 Tax Partnerships Schedule 3.10 Environmental Matters Schedule 5.1 Expected Capital Expenditures Schedule 5.5 Environmental Investigation Schedule 5.6 Buyer's Schedule of Allocated Values Schedule 7.3 Surety Bonds Schedule 7.5 Consents and Preferential Rights Schedule 7.6 Employees (v) PURCHASE AGREEMENT This Purchase Agreement ("Agreement") is made as of November 18, 2004, by and between WINCHESTER PRODUCTION COMPANY, LTD., a Texas limited partnership ("Winchester" or, alternatively the "Seller"), TGG PIPELINE LTD., a Texas limited partnership ("TGG"), solely for the purposes set forth below, Progress Fuels Corporation, a Florida corporation solely for the purposes set forth below ("PFC") and ENCANA OIL & GAS (USA), INC. a Delaware corporation (the "Buyer"). RECITALS A. Seller is the owner of certain oil and gas leases and wells located in the Denton, Tarrant, Wise and Hood Counties, Texas (all as further defined below, the "Assets"). B. Seller desires to sell and Buyer desires to acquire the Assets on the terms and under the conditions set forth in this Agreement. C. TGG is joining this Agreement solely for the purposes of conveying certain gathering lines and related easements. D. PFC is joining this Agreement solely for the purpose of supporting Seller's Indemnity Obligations set forth in Article VIII. AGREEMENT The parties, in consideration of the premises and of the mutual representations, warranties, covenants, conditions and agreements set forth herein and intending to be bound, agree as set forth below: ARTICLE I DEFINITIONS When used in this Agreement, the following terms shall have the meanings specified: 1.1. Action. "Action" means any action, claim, suit, litigation, arbitration or governmental investigation. 1.2. Agreement. "Agreement" means this Agreement, together with the Exhibits and Schedules attached hereto, as the same may be amended from time to time in accordance with the terms hereof. 1.3. Allocated Value. "Allocated Value" means the monetary amount, for each Lease, set forth on Exhibit F, as mutually agreed, for purposes of the Title Defect Mechanism set forth on Exhibit A. 1.4. Assignment. The term "Assignment" means the Assignment, Conveyance and Bill of Sale in the form of Exhibit B attached hereto. The Assignment may be executed in multiple counterparts for recording in the various jurisdictions 1 wherein the Assets are located. Interests in Leases that are federal leases will also be transferred by means of federal government forms 3000-3 and 3000-3a, as appropriate. 1.5. Assumption Agreement. The term "Assumption Agreement" means the Assumption Agreement concerning the Assumed Liabilities, in the form of Exhibit C attached hereto. 1.6. Assets. The term "Assets" means the following: (a) The Property Agreements, including, without limitation, the Leases; (b) The Personal Property; (c) The Production; and (d) The Books and Records. 1.7. Assumed Liabilities. "Assumed Liabilities" means: (a) any liability or obligation arising out of or resulting from performance due on or after the Effective Time under any Property Agreement, including but not limited to the Leases; (b) any liability or obligation for Taxes due after the Effective Time or assessed on the Assets from and after the Effective Time; (c) any liability or obligation for properly plugging and abandoning all of the Wells and restoring the surface areas associated with the Wells in accordance and compliance with the rules and regulations of Governmental Authorities having jurisdiction and the terms of the Leases; (d) any liability or obligation relating to the accrued suspense funds set forth on Schedule 2.3(b); (e) any liability or losses attributable to a Title Defect for which the Base Purchase Price is decreased pursuant to Section 2.3(b)(iv); (f) if transferred subject to Section 7.5, the Production Payment; (g) except as it may arise from a breach of the representation set forth in Section 3.10, any matter relating to the environmental condition of the Properties including, without limitation, any Environmental Defects for which the Base Purchase Price is adjusted at Closing; and (h) the Office Leases. 1.8. Base Purchase Price. "Base Purchase Price" has the meaning it is given in Section 2.2. 2 1.9. Basket. "Basket" has the meaning given in Section 8.4. 1.10. Beck Lease. "Beck Lease" means that certain oil, gas and mineral lease covering approximately 1000.30 acres in Denton County, Texas, dated June 30, 2003, by and between B Oil Investments, Ltd., as lessor, and Star of Texas Energy Services, Inc., as lessee, as the same may have been amended or supplemented from time to time, and a memorandum of which is recorded at Volume 365, Page 7465, of the Real Property Records of Denton County, Texas. 1.11. Books and Records. The term "Books and Records" means, in whatever form or media expressed, all books, records, files or copies thereof, in Seller's possession relating directly to the Assets, including, without limitation, geological, plats, surveys, maps, cross-sections, production records, electric logs, cuttings, cores, core data, pressure data, decline and production curves, well files and all related matters, division of interest records, division orders, lease files, title opinions, abstracts, lease operating statements and all other accounting information, marketing reports, statements, gas balancing information and all other marketing information, all geophysical and seismic records except to the extent that the transfer of such geophysical or seismic records would violate existing licensing or other contractual restrictions on such transfer, but excluding all Tax Returns. 1.12. Burdened Leases. "Burdened Leases" means those Leases that are subject to the Production Payment, as set forth on Exhibit A to the Production Payment. 1.13. Business Day. "Business Day" means any day other than (i) a Saturday or Sunday; or (ii) a day on which commercial banks in New York, New York or Dallas, Texas, are closed. 1.14. Buyer. "Buyer" is defined in the opening paragraph. 1.15. Buyer Claim. "Buyer Claim" means a claim for indemnification by Buyer pursuant to Section 8.2. 1.16. Buyer Indemnified Party. "Buyer Indemnified Party" is defined in Section 8.2(a). 1.17. Buyer's Schedule of Allocated Values. "Buyer's Schedule of Allocated Values" is defined in Section 5.6. 1.18. Closing. "Closing" means the conference held at 10:00 a.m., local time, on the Closing Date, at the offices of Hunton & Williams LLP, Energy Plaza, 30th Floor, 1601 Bryan Street, Dallas, Texas 75201-3402. 1.19. Closing Date. "Closing Date" means the latter of: (i) December 17, 2004, or (ii) the first Business Day following the date that the last of the conditions to Closing set forth in Section 6.1, 6.2 and 6.3 are fulfilled; or (iii) such other date as the parties may mutually agree in writing. 1.20. Code. "Code" means the Internal Revenue Code of 1986, as amended. 3 1.21. Easements. "Easements" means all rights of way, easements, surface leases and other rights of surface use held by Seller. 1.22. Effective Time. "Effective Time" is defined in Section 2.7. 1.23. Environmental Laws. "Environmental Laws" means any and all Laws, regulations, guidance, or other requirements relating to public health, or to pollution or protection of the environment (including, without limitation, ambient air, surface water, groundwater, land surface or subsurface strata) including, without limitation, the Clean Air Act, the Comprehensive Environmental Response Compensation and Liability Act ("CERCLA"), the Resource Conservation and Recovery Act of 1976 ("RCRA"), the Toxic Substances Control Act ("TSCA"), the Clean Water Act, the Safe Drinking Water Act, the Hazardous Materials Transportation Act ("HMTA"), the Oil Pollution Act of 1990, all as amended, and any state laws implementing or analogous to the foregoing federal laws, and all other laws relating to or regulating emissions, discharges, releases, or cleanup of pollutants, contaminants, chemicals, polychlorinated biphenyls ("PCBs"), oil and gas exploration and production wastes, brine, solid wastes, or toxic or Hazardous Substances or wastes. 1.24. Ewing Lease. "Ewing Lease" means that certain oil, gas and mineral lease, dated August 1, 2002, by and between Ewing Enterprises LP, as lessor, and Republic Energy, Inc., as lessee, as amended and extended from time to time, recorded at Volume 4935, Page 2741, of the Real Property Records of Denton County, Texas. 1.25. Excluded Assets. "Excluded Assets" means: (a) the oil and gas leases excluded due to title or other issues, as set forth on Schedule 1.25; (b) a copy of the Books and Records; and (c) any production hedges or other derivatives related to the Assets. 1.26. Governmental Authority. "Governmental Authority" means any federal, state, provincial, municipal, local or other governmental department, commission, board, bureau, agency or instrumentality, or any court, in each case whether of the United States, any of its possessions or territories, or of any foreign nation. 1.27. Hazardous Substances. "Hazardous Substances" means any substance or material which, if present in the environment would, under applicable law, require assessment, remediation, or corrective action including, without limitation, chemicals, pollutants, contaminants, wastes, toxic substances, petroleum and petroleum products which are classified as hazardous, toxic, radioactive, dangerous, or otherwise regulated by, or form the basis for liability under, any Environmental Laws including but not limited to any Polluting Substances, hazardous wastes under RCRA, hazardous substances under CERCLA, toxic substances under TSCA, hazardous materials under HMTA, or comparable materials or classification under any other of the Environmental Laws. 4 1.28. Knowledge of Seller. "Knowledge of Seller" means the actual knowledge of the following officers of Seller: (i) the Senior Vice President, Gas Operation; (ii) the Vice President of the North Texas business unit; (iii) the Operations Manager, Engineering Manager and Land Manager of the North Texas business unit. 1.29. Laws. "Laws" means any federal, state, local or other law or governmental requirement of any kind, and the rules, regulations and orders promulgated thereunder, all of the foregoing as in effect on the date hereof. 1.30. Lease. "Lease" (individually) and "Leases" (collectively) means the oil, gas, and/or mineral leases (including federal leases) owned by Winchester in Denton, Tarrant, Wise and Hood Counties, Texas, including, but not limited to leaseholds, record title and operating rights, royalty or overriding royalty interests owned by Winchester in such leases. Schedule 3.4(b) sets forth a list of the Leases, together with a description of Winchester's Net Revenue Interest and Working Interest therein and the Allocated Value associated therewith, and a list of the Wells associated with such Leases. 1.31. Lease Burdens. "Lease Burdens" means the royalties, overriding royalties, production payments (other than the Production Payment), net profit interests, and all similar interests burdening the Leases or production therefrom, that are legally binding and enforceable at law or in equity. 1.32. Losses. "Losses" is defined in Section 8.2(a). 1.33. Material Adverse Effect. "Material Adverse Effect" or "Material Adverse Change" means a material adverse effect on or change in (or any development that, insofar as reasonably can be foreseen, is reasonably likely to have a material adverse effect on or change in) the Assets, other than any change, circumstance or effect (i) relating to the economy or securities markets in general, (ii) affecting the oil and gas or energy industry generally, such as fluctuations in the price of oil or gas, or (iii) resulting from the execution or performance of this Agreement or the announcement thereof. 1.34. Maximum Indemnity Amount. "Maximum Indemnity Amount" is defined in Section 8.4. 1.35. Net Revenue Interest. "Net Revenue Interest" means the decimal ownership of the lessee in production from a Lease, after deducting all applicable Lease Burdens. 1.36. Office Leases. "Office Leases" means: (i) that certain lease agreement between PFC, as tenant, and TIAA Realty, Inc., as landlord, dated May 23, 2003, regarding the lease of Winchester's office space in Irving, Texas; and (ii) that certain lease agreement between Progress Fuels North Texas Gas, L.P., as tenant, and the Larry M. Grace Non-Exempt Trust, as successor in interest to the Estate of L.E. Grace, as landlord, dated September 1, 2003, regarding the lease of Winchester's office space in Bridgeport, Texas. 1.37. Permits. "Permits" means all written permits, licenses and governmental authorizations, registrations and approvals required, as of the date hereof, for the conduct of Seller's business. 5 1.38. Permitted Encumbrances. "Permitted Encumbrances" means: (A) liens, charges, encumbrances, contracts, agreements, instruments, obligations, defects and irregularities of title and restrictions of right or interest of any nature affecting any Lease that will be discharged at Closing; (B) lessors' royalties, overriding royalties, and similar burdens that do not operate to reduce the Net Revenue Interest of Winchester in any Lease; (C) division orders and sales contracts relating to hydrocarbons that are terminable, without material penalty, upon no more than 90 days notice to the purchaser under such division orders or sales contract (subject to applicable governmental regulations); (D) all rights to consent by, required notices to, and filings with or other actions by governmental authorities, if any, in connection with the change of ownership or control of an interest in any Lease; (E) any required third-party consent to change of ownership or control of the Leases or similar agreements; (F) materialmen's, mechanics', repairmen's, employees', contractors', operators', tax and other similar liens or charges arising pursuant to operations or in the ordinary course of business incidental to construction, maintenance, or operation of the Leases (i) if they have not been filed pursuant to law, or (ii) if filed, payment is being withheld as provided by law, or (iii) if their validity is being contested in good faith by appropriate action; or (iv) if due and payable, now or in the future, provision has been made by Winchester for the payment thereof; (G) easements in respect of surface operations, pipelines, or the like and easements on, over or in respect of the Leases that are not such as to interfere materially with the operation or use of the Leases; (H) all other inchoate liens, charges, encumbrances, contracts, agreements, instruments, obligations, defects and irregularities, including Title Defects, affecting any of the Leases that individually or in the aggregate are customary in the industry and are not such as to interfere materially with the operation, value or use of any of the Leases, and which do not reduce the Net Revenue Interest of the Leases to less than the applicable Net Revenue Interest set forth in Schedule 3.4(b) and do not obligate Winchester to bear costs and expenses relating to the maintenance, development and operation of any of the Leases in an amount greater than the applicable Working Interest set forth in Schedule 3.4(b); (I) all applicable Laws, rules and orders of any governmental authority; and (J) inchoate liens for Taxes not due and payable before the Closing Date. 1.39. Personal Property. The term "Personal Property" means all of Seller's interest in all of the tangible personal property, fixtures and improvements now and as of the Effective Time on, appurtenant to or used solely in connection with the Assets or with the production, treatment, storage, sale or disposal of hydrocarbons, water or other minerals or substances produced from the Leases, including, without limitation, all Wells, wellhead equipment, fixtures, casing and tubing, all production, storage, treating, compression, dehydration, delivering, salt water disposal and pipeline fixtures, and other facilities of every kind, character and description, used or usable solely in connection with the production, treatment, storage, delivery, sale or disposal of hydrocarbons, water or other minerals or substances produced from the Assets, including but not limited to those identified on Schedule 3.4(a). 1.40. PFC. The term "PFC" is defined in the introductory paragraph. 1.41. Prime Rate. "Prime Rate" means the prime rate as published from time to time in the Wall Street Journal. 6 1.42. Production. The term "Production" means all of Seller's right, title and interest in the oil, gas, casinghead gas, condensate, distillate and other liquid and gaseous hydrocarbons produced from the Leases, products refined and manufactured therefrom and the accounts and proceeds from the sale thereof to the extent the Production has been produced, or accrued, or is held on the Leases or in the tanks from and after the Effective Time. 1.43. Production Payment. "Production Payment" means the interest in production from the Burdened Leases that is attributable to the interest of REI, as set forth in that certain Memorandum of Production Payment between Progress Fuels North Texas Gas, L.P. and REI, dated February 24, 2003 and recorded in the Official Records of Denton, Tarrant and Wise Counties, Texas. 1.44. Production Payment Liquidation Amount. "Production Payment Liquidation Amount is defined in Section 7.5(b). 1.45. Properties. "Properties" means the lands associated with and subject to the Leases, to the extent, and only to the extent, that Seller has made use of such lands in connection with the exploration or drilling for, or production of, hydrocarbons under the terms of the Leases. 1.46. Property Agreements. The term "Property Agreements" means the Leases, pooling and unitization agreements, hydrocarbon purchase and sale contracts, leases, permits, rights-of-way, easements, servitudes, licenses, farmouts, options, surface leases, surface fee interests, orders and other contracts or agreements: (i) to the extent relating to any Well or to the other Assets; or (ii) to the extent relating to the production, storage, treatment, transportation, processing, sale or disposal of hydrocarbons, water or other minerals or substances produced therefrom or attributable thereto, including but not limited to those identified on Schedule 3.5(a). 1.47. Purchase Price. "Purchase Price" means the amount specified in Section 2.2 hereof. 1.48. Referral Firm. "Referral Firm" is defined in Section 2.4(d)(ii). 1.49. REI. "REI" means Republic Energy, Inc. 1.50. Retained Liabilities. "Retained Liabilities" means all liabilities and obligations of the Seller, whether such liabilities or obligations relate to payment, performance or otherwise, other than the Assumed Liabilities. 1.51. Seller. "Seller" means Winchester Production, Company, Ltd, a Texas limited partnership. 1.52. Seller Claim. "Seller Claim" means a claim to indemnification by Seller pursuant to Section 8.3. 1.53. Seller Indemnified Party. "Seller Indemnified Party" is defined in Section 8.3. 1.54. Taxes. "Taxes" means any and all taxes, levies, imposts, duties, assessments, charges and withholdings imposed or required to be collected by or paid over to any Governmental Authority, including any interest, penalties, fines, assessments or additions imposed with respect to the foregoing. 7 1.55. Tax Returns. "Tax Returns" means any report, return, information statement, payee statement or other information required to be provided to any Governmental Authority, with respect to Taxes, including any return of an affiliated, combined or unitary group, and any and all work papers relating to any Tax Return. 1.56. TGG Assets. "TGG Assets" is defined in Section 2.1(d). 1.57. Title Defect. "Title Defects" means any condition other than a Permitted Encumbrance that now or in the future: (A) reduces Seller's Net Revenue Interest in any of the Leases to less than the amount as shown on Schedule 3.4(b) for each Lease; (B) increases Seller's Working Interest as set forth on Schedule 3.4(b) for each Lease (other than increases that would result in the Net Revenue Interest in such Lease or Well being proportionately increased); or (C) imposes, on any of the Leases any lien, charge, encumbrance, claim, easement, servitude, right, burden or defect that is not a Permitted Encumbrance hereunder. It is expressly understood that Permitted Encumbrances and the Production Payment do not constitute Title Defects. 1.58. Title Defect Mechanism. "Title Defect Mechanism" means the procedure whereby the Purchase Price is adjusted to compensate for variations in the Allocated Values caused by Title Defects. The Title Defect Mechanism is set forth in Exhibit A. 1.59. Wells. "Wells" means any of the oil or gas wells specifically identified on Schedules 3.4(b). 1.60. Working Interest. "Working Interest" means that interest which bears a share of all costs and expenses proportionate to the interest owned, associated with the exploration, development and operation of a Lease and the Wells associated therewith, that the owner of a Lease is required to bear and pay by reason of such ownership, expressed as a decimal. ARTICLE II PURCHASE AND SALE 2.1. Purchase and Sale. (a) At the Closing, Seller shall sell, assign, convey, transfer and deliver to the Buyer, and Buyer shall purchase and accept from Seller, all of Seller's right, title and interest in and to the Assets; provided, however, the Excluded Assets will not be conveyed or purchased hereunder, but will be excluded from this transaction. (b) At the Closing, Buyer shall assume and become obligated to pay, perform, or otherwise discharge the Assumed Liabilities. (c) Notwithstanding anything herein to the contrary, Buyer shall not acquire any right or interest in any properties of Seller other than the Assets or in any proceeds of production produced and sold from the Assets prior to the Effective Time or in any payments due Seller for production from the Assets prior to the Effective Time. 8 (d) At Closing, TGG shall sell, assign, convey, transfer and deliver to Buyer, and Buyer shall purchase and accept from TGG, all of TGG's right, title and interest in and to the gathering lines and easements set forth in Schedule 2.1(d) (the "TGG Assets"). At the Closing, Buyer shall assume and become obligated to pay, perform, or otherwise discharge any liabilities or obligation arising from or related to the TGG Assets. 2.2. Purchase Price. The purchase price for the Assets, including the TGG assets, will be Two Hundred Fifty-Five Million United States Dollars ($255,000,000.00 US)(the "Base Purchase Price"), adjusted as provided in this Article II (the Base Purchase Price as so adjusted, being herein called the "Purchase Price"). At the Closing, Buyer shall pay Seller the Purchase Price in immediately available funds. 2.3. Adjustments to Base Purchase Price. (a) To determine the Purchase Price, the Base Purchase Price shall be increased by the following amounts: (i) the amount of all (1) ad valorem, property or similar Taxes paid by Seller and relating to the Assets for periods from and after the Effective Time, calculated in a similar fashion as set forth in Section 2.3(b)(i), and (2) any other expenses paid by Seller and relating to the Assets for periods from and after the Effective Time; (ii) the aggregate amount of any and all operating costs paid by Seller that relate to the Assets for periods from and after the Effective Time (excluding amounts for which the Base Purchase Price is increased pursuant to Section 2.3(a)(i) above), including, but not limited to, lease operating expenses, transportation and marketing expenses, lease payments, severance taxes and producing overhead rates; (iii) the aggregate amount of any and all capital expenditures actually made by Seller or on Seller's behalf that relate to the Assets for periods from and after the Effective Time; (iv) an amount of money equal to the sum of the daily salaries of all Winchester personnel directly employed in the operation and administration of the Wells, multiplied by the number of days between the Effective Time and the Closing Date, but not to exceed $200,000; (v) an amount of money equal to the value of oil or condensate held on the Leases in the tanks above the load line, as measured and recorded by Seller in the ordinary course of business as of October 31, 2004, (as set forth on Schedule 2.3(a)(v)) at a price per barrel of oil or condensate as established in that certain crude purchase contract between Seller and Sunoco for the month of October, 2004 (decreased by the amount of severance taxes attributable to such oil or condensate); (vi) an amount equal to interest on the Purchase Price paid at Closing from the date of execution of this Agreement until the Closing Date at the Prime Rate plus 2% (but in no event will this amount exceed $500,000); and 9 (vii) the value of any imbalances of natural gas owed by Seller to third parties and attributable to the Assets as of the Effective Time, such value to be $4.50 per MMBtu, less applicable royalties and taxes; and. (viii) any other amount agreed upon by the parties in writing. (b) To determine the Purchase Price, the Base Purchase Price shall be decreased by the following amounts: (i) the amount of all of Seller's unpaid ad valorem, production, severance, property or similar Taxes relating to the Assets, to the extent that such unpaid Taxes relate to periods of time before the Effective Time (to the extent that any such amount has not been finally determined by Closing or any other date of determination, such amount will be estimated based upon the amount paid for the previous year for the same asset or assets). Such Taxes with respect to a period which the Effective Time splits shall be prorated based on the number of days in such period which fall on each side of the Effective Time; provided however, to the extent that such Taxes are computed based on the production from the Assets, such Taxes shall be prorated between the parties based on the period in which such production which is the basis for such calculation occurs, in the same manner as the parties are entitled to receive (or be credited with) such production pursuant to the terms hereof; (ii) amounts equal to all revenues (net of royalty, overriding royalty payments and similar such payments) collected by Seller that are attributable to production of oil or gas from the Assets (but not taking into account any hedges) and relating to periods of time from and after the Effective Time; (iii) an amount equal to the amount of accrued suspense funds set forth on Schedule 2.3(b); (iv) an amount, calculated in accordance with the procedures of Exhibit A for Title Defects, equal to the agreed value of any Title Defect that is asserted prior to Closing, agreed to by Seller, and remains uncured by Seller at Closing; provided that Title Defects for which there is no agreement prior to Closing shall be addressed in accordance with procedures of Exhibit A; (v) an amount calculated pursuant to Section 5.5 for Environmental Defects; (vi) if the Production Payment is transferred pursuant to Section 7.5, the Production Payment Liquidation Amount; (vii) the value of any imbalances of natural gas owed by third parties to Seller and attributable to the Assets as of the Effective Time, such value to be $4.50 per MMBtu, less applicable royalties and taxes; (viii) any other amount agreed upon by the parties in writing; and 10 (ix) an amount of money equal to the Allocated Value of any Leases set forth on Schedule 7.5 that are removed from the purchase and sale under this Agreement by reason of the exercise of a preferential right to purchase by the holder of such right prior to Closing. 2.4. Determination of Purchase Price. (a) The amount to be paid by Buyer to Seller at Closing in consideration of the sale and delivery of the Assets to Buyer in accordance with this Agreement shall be determined by adding to or subtracting from the Base Purchase Price, as applicable, each adjustment to be made to the Base Purchase Price at Closing pursuant to Sections 2.3(a) and (b), as proposed by Seller and not disputed by Buyer in accordance with this Section 2.4. (b) Seller shall prepare and deliver to Buyer at least five (5) Business Days before the Closing Date a statement (the "Preliminary Settlement Statement") setting forth Seller's good faith estimate of each adjustment to be made in accordance with Sections 2.3(a) and (b). Buyer may dispute in good faith Seller's estimate of the amount of such adjustments by delivery to Seller by written notice thereof within three (3) Business Days after receipt of such estimate. Buyer and Seller shall use commercially reasonable efforts to resolve any such dispute prior to Closing; provided, that any and all amounts so disputed or other adjustments claimed by Seller and not resolved by mutual agreement of Buyer and Seller prior to Closing shall be resolved in accordance with Section 2.4(d) and the Closing shall occur with payment of the Base Purchase Price less the amount of the disputed items, notwithstanding any such dispute; provided, however Title Defects and Environmental Defects shall be addressed as set forth in Sections 2.3(b)(iv) and 2.3(b)(v). (c) After the Closing, the Purchase Price shall be subject to further adjustment pursuant to Section 2.4(d) of this Agreement, and neither Seller's delivery of an estimate of adjustments pursuant to this Section 2.4, the delivery of a dispute notice by Buyer pursuant to this Section 2.4, nor the failure to deliver any such dispute notice shall bar any such further adjustments. (d) (i) On or before the ninetieth (90th) day after the Closing, Seller shall prepare and deliver to Buyer in accordance with this Agreement, a statement (the "Final Settlement Statement") setting forth Seller's calculation of the final adjustments and showing the calculation of such adjustments. Within thirty (30) days after receipt of the Final Settlement Statement, Buyer shall deliver to Seller a written report containing any changes that Buyer proposes be made to the Final Settlement Statement and the reasons for those changes. The parties shall attempt to agree to the amounts due pursuant to such adjustments, including any amounts disputed under Section 2.4(b), no later than ninety (90) days after Buyer's receipt of the Final Settlement Statement. The date upon which such agreement is reached shall be herein called the "Final Settlement Date". Within five (5) Business Days from the Final Settlement Date, the party owing any amount for additional adjustments shall pay such amount, in immediately available funds. 11 (ii) If Seller and Buyer are unable to agree upon the Final Settlement Statement by the ninetieth (90th) day after Buyer's receipt of same, KPMG LLP (or, if such firm is unable or unwilling to act, such other nationally recognized independent public accounting firm as shall be agreed upon by Buyer and Seller in writing) (the "Referral Firm") shall review Seller's Final Settlement Statement and the records relating to the Leases and determine the final adjustments, other then adjustments determined under the mechanism regarding Title Defects set forth in Exhibit A. With respect to any matters under this Agreement to be resolved by the Referral Firm, neither the Referral Firm nor any person employed by the Referral Firm will interpret the provisions of this Agreement unless otherwise agreed by Seller and Buyer. With respect to any matters for which interpretation of this Agreement is required, and for which Buyer and Seller cannot agree on such interpretation, such matter shall be submitted to arbitration in a similar manner as set forth in Exhibit A, paragraph 6 regarding Title Defect disputes and the Referral Firm shall decide all other matters specified in this Section 2.4(d)(ii). The decision of the Referral Firm shall be binding on Buyer and Seller, and the fees and expenses of the Referral Firm shall be borne one-half each by Buyer and Seller. The Referral Firm shall deliver its final calculation of the Purchase Price in writing to Buyer and Seller as soon as is practicable, and the parties shall pay and receive the final adjustment amount, no later than the fifth (5th) business day following the paying person's receipt from the Referral Firm of the final Purchase Price determination. (e) The parties will, and will cause their representatives to, cooperate and assist in the preparation of the Final Settlement Statement and the conduct of the reviews and audits referred to in this Section 2.4, including but not limited to making available books, records and personnel as required. 2.5. Allocation of Purchase Price. The Purchase Price shall be allocated among the Assets as provided in Schedule 2.5, which shall be prepared by Buyer prior to Closing, and in a form that is acceptable to Seller. Schedule 2.5 will make an initial allocation based upon the Allocated Values and will provide for adjusting the allocation as necessary to reflect adjustments to the Base Purchase Price. Such allocation is intended to comply with the allocation method required by Section 1060 of the Code and the regulations thereunder, and the parties shall cooperate to comply with all procedural requirements of Section 1060 and such regulations. Buyer and Seller agree that they will not take nor will they permit any affiliated person to take any tax position inconsistent with the allocation made pursuant to Schedule 2.5; provided, however, that (i) Buyer's cost for the Assets may differ from the total amount allocated thereunder to reflect Buyer's capitalized transaction costs not included in the amount allocated, and (ii) Seller's amount realized on the sale of the Assets may differ from the total amount so allocated to reflect Seller's transaction costs that reduce the amount realized. 2.6. No Assumption of Retained Liabilities. Except as specifically set forth herein with respect to the Assumed Liabilities, the Buyer does not and will not assume any liability or obligation of Seller, or any obligation relating to the business or the use of the Assets or the performance under the Property Agreements whether absolute or contingent, asserted or unasserted, known or unknown, disclosed pursuant to this Agreement or otherwise. All of the Retained Liabilities shall remain the sole responsibility of and shall be retained, paid, performed and discharged solely by the Seller. 12 2.7. Effective Time. For all purposes of this Agreement, the "Effective Time" shall mean 12:01 a.m. Central Standard Time on November 1, 2004. ARTICLE III REPRESENTATIONS AND WARRANTIES OF SELLER Seller hereby represents and warrants to Buyer that: 3.1. Organization. Seller is duly organized, validly existing and in good standing under the laws of the State of Texas. Seller has full power and authority to conduct its business as it is now being conducted and to own the Assets (or to lease those Assets leased by it). Seller is duly qualified to do business as a limited partnership and is in good standing in each jurisdiction in which such qualification is necessary under applicable law as a result of the conduct of its business or the ownership of the Assets. 3.2. Due Authorization. The execution, delivery and performance of this Agreement have been authorized by all necessary action on the part of Seller, and no further actions on the part of Seller are necessary to authorize the execution, delivery and performance of this Agreement or the consummation of the transactions contemplated hereby. This Agreement, and all of the other documents or instruments required to be executed and delivered by Seller at Closing have been, or at Closing will be, duly executed and delivered by Seller and (assuming the due authorization, execution and delivery hereof and thereof by Buyer) are valid and binding obligations of Seller, enforceable against Seller in accordance with their terms (except to the extent that enforcement may be affected by applicable bankruptcy, reorganization, insolvency and similar laws affecting creditors' rights and remedies generally and by general principles of equity (regardless of whether enforcement is sought at law or in equity)). 3.3. No Violation or Conflict; Consents; Preferential Rights. Except as set forth on Schedule 3.3, the execution, delivery and performance of this Agreement and all of the other documents and instruments contemplated hereby to which Seller is a party does not and will not (a) conflict with, violate or breach any Laws, judgment, order or decree binding on Seller, the articles of organization or operating agreement of Seller, or any material contract to which Seller is a party or by which it is bound, or (b) give any party to any of the Property Agreements to which Seller is a party or by which they are bound any right of termination, breach, cancellation, acceleration or modification thereunder. 3.4. Title. (a) To the Knowledge of Seller, Schedule 3.4(a) contains a list of all the material items of Personal Property. Subject to ordinary wear and tear and to scheduled or necessary repairs in the ordinary course of business, all material items of Personal Property are in reasonably good and serviceable condition and repair and there are no necessary material repairs, improvements, restoration or other service work necessary to make any of such assets serviceable, except as specifically identified on Schedule 3.4(a). All leases covering any and all Personal Property are identified on Schedule 3.4(a). Except as set forth on Schedule 3.4(a), Seller owns the Personal Property free and clear of any claim, lien, right, or encumbrance, except for Permitted Encumbrances. 13 (b) Set forth on Schedule 3.4(b) is a true, correct and complete description of each of the Leases, together with a description of the Seller's Net Revenue Interest and Working Interest therein, and the Allocated Value associated therewith, and a list of the Wells located on the lands associated with and subject to the Leases. (c) Schedule 3.4(c) contains a list of all rights of way and surface damage agreements associated therewith that are held by Seller. (d) Exhibit A sets forth the procedure for adjustment of the Base Purchase Price to account for Title Defects. 3.5. Contracts. (a) Schedule 3.5(a) lists the material Property Agreements. Prior to the date hereof, Seller has provided Buyer with access to true and correct copies of all Property Agreements. Except as set forth on Schedule 3.5(b): (i) each Property Agreement is a valid and binding agreement of Seller, enforceable in accordance with its terms, except as may be limited by bankruptcy, insolvency, reorganization, or other laws affecting creditors' rights generally or equitable principles; (ii) Seller has performed, and to the Knowledge of Seller every other party has performed, each material term, covenant and condition of each of the Property Agreements to which Seller is a party that is to be performed by Seller or such other party at or before the date hereof; (iii) to the Knowledge of Seller no event has occurred that would, with the passage of time or compliance with any applicable notice requirements or both, constitute a default by Seller or any other party, under any of the Property Agreements to which Seller is a party, except for such defaults that individually or in the aggregate are not reasonably expected to have a Material Adverse Effect on any of the Property Agreements; and (iv) Seller does not intend, and Seller has not received notice that any other party to a Property Agreement intends, to cancel or terminate any of such Property Agreements on or before the Closing Date. (b) Except as set forth on Schedule 3.5(b) there are no on-going renegotiations of, or attempts to renegotiate, any amounts paid or payable to Seller under any of the Property Agreements and no party has made written demand for such renegotiations. Except as set forth on Schedule 3.5(b), there are no commissions due (or to become due) to any broker or other party as a result of the purchase or sale of hydrocarbons under any of the Property Agreements. Except as set forth on Schedule 3.5(b), Seller has not, with respect to the Property Agreements: (i) received any quantity of natural gas or liquids, condensate or crude oil to be paid for thereafter other than in the normal cycle of billing; or (ii) received prepayments, advance payments or loans which will require the performance of services or provision of natural gas or liquids, condensate or crude oil under such Property Agreements on or after the Effective Time without being currently paid therefore other than in the normal cycle of billing. Except as set forth on Schedule 3.5(b), Seller is not obligated, by virtue of prepayment arrangement, make up right under production sales contract containing a "take or pay" or similar provision, gas balancing agreement, production payment or any other arrangement to deliver hydrocarbons, or proceeds from the sale thereof, attributable to the Leases at some future time without then or thereafter receiving the full contract price therefore. Except as set forth on Schedule 3.5(b) or in any Property Agreement, there is no call upon, option to purchase or similar right to obtain hydrocarbons from the Leases in favor of any person or entity other than pursuant to renewal rights or automatic renewal provisions contained in existing contracts for the sale for hydrocarbons. 14 3.6. Lease Provisions. All Leases are in force and effect and are maintained by their terms. Accurate and timely payment of delay rentals have been made to maintain in force and effect all Leases within the primary term on which drilling operations were not timely commenced. All other Leases are validly preserved beyond the primary term by production in paying quantities or the accurate and timely payment of shut-in royalty payments or otherwise. Except as set forth on Schedule 3.6, all rentals, royalties, overriding royalty interests and other payments due under each of the Leases have been timely and accurately paid, except amounts that are being held in suspense as a result of title issues in circumstances that do not provide any third party a right to terminate any such Lease. Schedule 2.3(b) lists the accrued suspense funds by Well. 3.7. Compliance with Law. Except as set forth on Schedule 3.7: (a) All material filings and notices relating to the Leases, or the ownership or operation thereof, required to be made by Seller with all applicable state and federal agencies have been made by or on behalf of Seller. Seller is not in violation of any Law with respect to the Assets, except for such violations as are not, individually or in the aggregate, reasonably expected to have a Material Adverse Effect on the Leases as a whole. (b) Seller holds all of the Permits necessary for the operation of Seller's business as currently conducted, other than Permits for which the failure to hold is not, individually or in the aggregate, reasonably expected to have a Material Adverse Effect on Seller. There are no proceedings pending or, to the Knowledge of Seller, threatened that are reasonably expected to result in the revocation, cancellation, suspension or modification of the Permits. There are no proceedings pending or, to the Knowledge of Seller, threatened (x) with respect to any alleged failure to have all Permits required in connection with the operation of Seller's business as currently conducted, or (y) with respect to any valid requirement to plug or abandon any Well in which Seller owns an interest or that is located on any of the Leases. 3.8. Litigation. Except as set forth on Schedule 3.8 or Schedule 3.10, there is no claim, legal action, suit, litigation, arbitration, dispute or investigation, judicial, administrative or otherwise, or any order, decree or judgment, now pending or in effect, or, to the Knowledge of Seller, threatened or contemplated, that, if adversely determined, would have a Material Adverse Effect on the Assets or the transactions contemplated by this Agreement. 3.9. Taxes. There are no liens for Taxes on the Assets, except for Taxes not yet due, and (subject to Section 7.2(a)) there is no unpaid Tax payable by Seller for which Buyer would become liable by reason of purchasing the Assets hereunder. Seller has filed or will file all federal, state, local and other tax reports and returns required to be filed by Seller in connection with its ownership or operation of the Assets. Schedule 3.9 sets forth a list of joint operating agreements to which Seller is a party and for which there has not been made a valid election out of Subchapter K of the Code. Except as set forth on Schedule 3.9, to the Knowledge of Seller, none of the Assets is subject to any tax partnership as defined in Section 761 of the Code. 3.10. Environmental Matters. The Seller represents and warrants that as to the Properties, there are no pending or, to the Knowledge of Seller, threatened (1) lawsuits, (2) notices of violation or notices of deficiency, (3) civil or criminal penalties, or (4) other unresolved orders based on any noncompliance 15 with Environmental Laws. The Seller also represents and warrants that as to Seller's Knowledge, there are no material adverse environmental conditions existing on any of the Properties, except as disclosed in Schedule 3.10. SECTION 3.10 CONSTITUTES SELLER'S SOLE REPRESENTATION AND WARRANTY WITH RESPECT TO ENVIRONMENTAL LAWS. ARTICLE IV REPRESENTATIONS AND WARRANTIES OF THE BUYER The Buyer hereby represents and warrants to Seller: 4.1. Organization. The Buyer is a corporation, duly formed, validly existing and in good standing under the laws of Delaware. The Buyer is duly qualified as a foreign corporation in good standing in each jurisdiction in which the conduct of its business requires such qualification, except where the failure to be so qualified would not prevent, materially delay or affect consummation of the transactions contemplated hereby. 4.2. Authorization. The Buyer has full power and authority to execute, deliver and perform this Agreement and each agreement or instrument (to which it is a party) executed in connection herewith or delivered pursuant hereto and to consummate the transactions contemplated hereby. The Buyer's execution, delivery and performance of this Agreement and all agreements and instruments executed in connection herewith or delivered pursuant hereto and the transactions contemplated hereby have been duly authorized by all requisite action. This Agreement and all agreements or instruments executed by the Buyer in connection herewith or delivered by the Buyer pursuant hereto have been or will be duly executed and delivered by the Buyer, and this Agreement and all agreements and instruments executed by the Buyer in connection herewith or delivered by the Buyer pursuant hereto constitute and will constitute the legal, valid and binding obligations of the Buyer, enforceable in accordance with their respective terms. 4.3. Noncontravention. The execution, delivery and performance by the Buyer of this Agreement and each agreement or instrument executed in connection herewith or delivered pursuant hereto and the consummation of the transactions contemplated herein will not, with or without the giving of notice or the passage of time, or both, (i) conflict with, or result in a violation or breach of, or a default, right to accelerate or loss of rights under, or result in the creation of any Lien under or pursuant to, any provision of the Buyer's articles of incorporation or bylaws or any Laws, or any finding, order, judgment, writ, injunction or decree to which the Buyer is a party or by which the Buyer or its assets may be bound or affected; or (ii) require the approval, consent or authorization of, or prior notice to, filing with or registration with, any Governmental Authority, or any other person or entity. 4.4. No Reliance. With respect to the transactions contemplated herein, Buyer acknowledges that it (i) has been granted access to all the Books and Records and materials to conduct all necessary due diligence, and (ii) has been afforded the opportunity to ask questions of, and receive answers from, Seller. Buyer acknowledges that it has not relied on any oral or written statements, 16 representations, warranties, or assurances from Seller or its officers, directors, employees, agents, or consultants, except those in Article III hereof. Buyer is sophisticated in the evaluation, purchase, ownership and operation of oil and gas properties and related facilities. In making its decision to enter into this Agreement and to consummate the transaction contemplated herein, subject to the express representations of Seller set forth in this Agreement, Buyer (a) has relied or shall rely solely on its own independent investigation and evaluation of the assets and the express provisions of this Agreement and (b) has satisfied or shall satisfy itself as to the environmental and physical condition of and contractual arrangements affecting the assets. Buyer has no knowledge of any fact that results in the breach of any representation, warranty or covenant of Seller given hereunder. 4.5. Purchase for Investment. The Buyer is acquiring the Assets for its own account for the purpose of investment and not with a view to or for sale in connection with any distribution thereof. 4.6. Financing. (a) Buyer has, or will have by Closing, unencumbered cash or marketable securities sufficient to fully satisfy its obligations to pay the Purchase Price to Seller, as and when due. (b) Buyer has sufficient financial resources to fulfill the surety bonding requirements of the State of Texas and/or the United States Government in connection with the Leases. ARTICLE V COVENANTS 5.1. Conduct of Business. Except as provided in this Agreement, until the earlier of Closing or the termination of this Agreement in accordance with its terms, Seller will use commercially reasonable efforts to operate and maintain the Assets consistent with past practices. Other than capital expenditures for the various projects set forth on Schedule 5.1, Seller will not undertake any capital expenditures in excess of $20,000.00 or any contractual commitment in excess of thirty (30) days without the approval of the Buyer, except in cases of emergency which could, in the opinion of Seller, result in material damage or injury to persons, property or any of the Assets. 5.2. Access to Information. At Buyer's sole cost and expense, the Buyer and its authorized agents, officers and representatives shall have reasonable access to the Assets, including the Books and Records, in order to conduct such examinations and investigations of the Assets as the Buyer deems necessary; provided, however, that such examinations and investigations: (a) shall be conducted during the normal business hours of Seller, (b) shall not unreasonably interfere with the operations and activities of Seller, and (c) shall be subject to the prior approval of Seller. 5.3. Further Assurances; Consents; Waiver of Notices. Each of the parties hereto hereby agrees to use commercially reasonable efforts (a) to obtain, any and all approvals of Governmental Authorities and third party consents, approvals, notations and authorizations required in connection with the consummation of the transactions contemplated by this Agreement, (b) to comply 17 with all conditions and covenants applicable or related to it as contemplated by this Agreement, and (c) to take all such other commercially reasonable actions as are necessary or advisable in order to cause the consummation of the transactions contemplated hereby. 5.4. Publicity. All general notices, releases, statements and communications to suppliers, distributors and customers of Seller or Buyer and to the general public and the press relating to the transactions contemplated by this Agreement shall be made only at such times and in such manner as may be agreed upon in advance by Seller and Buyer; provided, however, that any party hereto or its affiliates shall be entitled to make a public announcement of the foregoing if, in the opinion of its legal counsel, such announcement is required to comply with Laws or any listing agreement with any national securities exchange or inter-dealer quotation system and if it first gives prior written notice to the other parties hereto of its intention to make such public announcement and provides the opportunity to review the content of such disclosure. 5.5. Environmental Investigation. (a) Upon execution of and pursuant to the terms of this Agreement, Buyer shall have the right, at reasonable times during normal business hours, to conduct its investigation into the status of the physical and environmental condition of the Properties. If, in the course of conducting such investigation, Buyer discovers that: (i) any Property or the ownership, record keeping, construction, maintenance, repair or operation thereof or with respect thereto is in violation of any statute, rule, regulation or order of any governmental agency having jurisdiction over the Assets or Seller and pertaining to health, safety or the environment such that the Asset could be subject to a Material Environmental Obligation or Liability; or (ii) any condition or circumstance exists with respect to any Property or the ownership, record keeping, construction, maintenance, repair or operation thereof or with respect thereto which has resulted in or given rise to, or could (with notice or the lapse of time or both) result in or give rise to, any Material Environmental Obligations or Liabilities, Buyer may raise such violation, condition or circumstance as an Environmental Defect in the manner set forth hereafter. For purposes of this Section 5.5 only, the term "Material Environmental Obligations or Liabilities" shall mean that, with respect to any individual Lease or pooled unit, the Environmental Obligations or Liabilities with respect to any single Environmental Defect exceeds $10,000 or that the aggregate Environmental Obligations or Liabilities with respect to all claimed Environmental Defects with respect to any individual Lease or pooled unit which have a value, cost or loss of less than $10,000 each, is $50,000. A series of related violations, conditions or circumstances arising out of similar facts and circumstances shall be considered a single Environmental Defect for purposes of applying this Section. No later than noon central standard time on December 13th (the "Environmental Defect Notice Date"), Buyer shall notify Seller in writing specifying such Environmental Defects, if any, the Lease or unit affected thereby, and Buyer's good faith estimate of the net reduction in value of the Lease or unit affected by such Environmental Defects. (b) If Buyer fails to notify Seller prior to or on the Environmental Defect Notice Date, of any Environmental Defect, such Environmental Defect will be deemed waived, Seller shall be released from any liability to Buyer therefore, the Parties shall proceed with Closing, and Seller shall be under no 18 obligation to Buyer to correct such Environmental Defects or to indemnify Seller with respect thereto. Seller may, but shall be under no obligation to, correct at its own cost and expense such waived Environmental Defects to Buyer's reasonable satisfaction on or before the Closing Date. (c) In the event that Buyer provides Seller with a timely Environmental Defect Notice with respect to an Environmental Defect, Seller shall either: (i) cure or remediate such Environmental Defect to Buyer's reasonable satisfaction; or (ii) the Base Purchase Price shall be reduced by an amount equal to the net reduction in value of the Assets affected by any uncured or unremediated Environmental Defects (the "Environmental Defect Value"), subject to Buyer's and Seller's right to terminate this Agreement as provided in Section 9.1 or elsewhere in this Agreement; or (iii) dispute the existence of the Environmental Defect or the Environmental Defect Value. If Buyer and Seller have not agreed upon the Environmental Defect Value attributable to any Environmental Defect by the Closing Date, then for purposes of Closing and determining any adjustment to the Base Purchase Price under this Section 5.5, the Environmental Defect Value shall be the amount identified by Buyer in its notice given pursuant to this Section 5.5. Any disputed reduction(s) in the Base Purchase Price pursuant to this Section 5.5 shall be paid by Buyer into a mutually acceptable escrow account at a national banking institution, and such escrowed amount shall be subsequently paid by the escrow agent to Buyer or Seller upon resolution of the dispute. (d) Buyer acknowledges that it has received the environmental reports listed in Schedule 5.5, has had full opportunity to examine the Assets and the information contained in those reports, and, as further stated in Article VIII, accepts the Assets with those conditions. 5.6. Buyer's Schedule of Allocated Values. (a) Buyer must prepare, and forward Schedule 5.6 "Buyer's Schedule of Allocated Values" to Seller not later than 16 Business Days prior to Closing. Buyer will use its best efforts to forward Schedule 5.6 to Seller no later than November 22, 2004. (b) Buyer's Schedule of Allocated Values must set forth: (i) a complete listing of the Burdened Leases; and (ii) the value allocated by Buyer to each Burdened Lease: 1. taking into account the effect of the Production Payment, but reduced by the amount of money attributable to production from the Burdened Leases after December 31, 2024; and 2. assuming that the Burdened Leases are acquired by Buyer free and clear of the Production Payment, but reduced by the amount of money attributable to production from the Burdened Leases after December 31, 2024. (c) Notwithstanding any other provisions of this Agreement, Seller shall fully indemnify and hold harmless Buyer from and against any and all Losses that may occur related to i) any dispute by the holders of the Production 19 Payment of the Allocated Values determined by Buyer for purposes of this Agreement; ii) any payment made by Seller to the holders of the Production Payment; or, iii) any other matter related to the Production Payment arising prior to the assumption of the Burdened Leases by Buyer. 5.7. Amendment of Schedules. Buyer and Seller will, promptly upon becoming aware of any fact, matter, circumstance or event, which fact, matter, circumstance or event arose either (i) on or prior to the date hereof or (ii) after the date hereof but prior to the Closing, in any case, requiring supplementation or amendment of the schedules provided by the parties attached hereto, supplement or amend such schedules to this Agreement to reflect any fact, matter, circumstance or event, which, if existing, occurring or known on the date of this Agreement, would have been required to be set forth or described in such schedules which were or have been rendered inaccurate thereby. If Closing occurs, all supplements and amendments to the schedules provided by the parties are effective for all purposes, including to (i) amend or supplement the representations and warranties (and corresponding schedules) made as of the date hereof, and (ii) for the purpose of determining (A) satisfaction of the conditions set forth in Sections 6.1, 6.2 or 6.3 hereof, and (B) compliance by the parties with their respective covenants and agreements set forth herein. Notwithstanding the above, in the opinion of the non-amending or supplementing party, should any such supplement or amendment result in a Material Adverse Change, then the parties shall agree to a reasonable extension of the Closing Date (which shall not be later than December 30, 2004) to investigate such Material Adverse Change or otherwise agree to an appropriate adjustment in the Purchase Price. ARTICLE VI CONDITIONS PRECEDENT TO CONSUMMATION OF THE CLOSING; CLOSING 6.1. Conditions Precedent to Each Party's Obligations to Close. The respective obligations of each party to consummate the transactions contemplated by this Agreement on the Closing Date are subject to the satisfaction or waiver at or prior to the Closing of the following conditions precedent: (a) no order, decree or injunction shall have been enacted, entered, promulgated or enforced by any United States court of competent jurisdiction or any United States governmental authority that prohibits the consummation of the transactions contemplated by this Agreement; provided, however, that the parties hereto shall use their commercially reasonable efforts to have any such order, decree or injunction vacated or reversed; and (b) all consents, authorizations, orders, permits and approvals for (or registrations, declarations or filings with) any Governmental Authority required in connection with the execution, delivery and performance of this Agreement and the transactions contemplated hereby shall have been obtained or made, and except where the failure to have obtained or made any such consent, authorization, order, approval, filing or registration may not reasonably be expected to have a Material Adverse Effect on Buyer or Seller following the Closing Date. 20 (c) Buyer has furnished Buyer's Schedule of Allocated Values and fifteen (15) Business Days have elapsed since Seller furnished Buyer's Schedule of Allocated Values to REI. 6.2. Conditions Precedent to Obligations of the Buyer. The obligation of the Buyer to consummate the transactions contemplated by this Agreement on the Closing Date is subject to the satisfaction or waiver at or prior to the Closing of the following conditions precedent: (a) the representations and warranties of Seller contained in Article III shall be true and correct in all material respects (when read without exception for materiality or Material Adverse Effect) at and as of the Closing Date with the same force and effect as if those representations and warranties had been made at and as of such time (with such exceptions, if any, necessary to give effect to events or transactions expressly permitted herein); (b) Seller shall have performed, in all material respects, all obligations and complied with all covenants contained herein that are necessary to be performed or complied with by it at or before Closing; (c) Seller shall have delivered, or caused to be delivered, to Buyer at Closing, all closing deliveries described in Section 6.4(a); and (d) all actions, corporate or other, to be taken by Seller in connection with the transactions contemplated by this Agreement, and all documents incident thereto, shall be reasonably satisfactory in form and substance to the Buyer and the Buyer's counsel. 6.3. Conditions Precedent to Obligations of Seller. The obligation of Seller to consummate the transactions contemplated by this Agreement on the Closing Date is subject to the satisfaction or waiver at or prior to the Closing of the following conditions precedent: (a) the representations and warranties of the Buyer contained in Article IV shall be true and correct in all material respects (when read without exception for materiality or Material Adverse Effect) at and as of the Closing Date with the same force and effect as if those representations and warranties had been made at and as of such time (with such exceptions, if any, necessary to give effect to events or transactions expressly permitted herein); (b) the Buyer shall have performed, in all material respects, all obligations and complied with all covenants contemplated herein that are necessary to be performed or complied with by it at or before Closing; (c) Buyer shall have delivered, or caused to be delivered, to Seller at Closing, the closing deliveries described in Section 6.4(b); (d) all actions, corporate or other, to be taken by the Buyer in connection with the transactions contemplated by this Agreement, and all documents incident thereto, shall be reasonably satisfactory in form and substance to Seller and its counsel; and 21 6.4. The Closing. The following provisions shall be applicable with respect to the Closing: (a) At Closing, Seller shall, as a condition precedent to Buyer's obligations hereunder: (i) execute and deliver the Assignment and the Assumption Agreements to Buyer; (ii) deliver a certificate of Seller, signed by an authorized officer of Seller, certifying that the conditions set forth in Section 6.2 have been satisfied; (iii) execute and deliver a FIRPTA Affidavit in the form attached as Exhibit D; (iv) execute and deliver to Buyer letters in lieu of transfer or division orders; (v) for Wells of which Seller is the designated operator, execute and deliver to Buyer: (1) a validly executed blanket transfer of P-4's designating Buyer as operator of the Wells with the Texas Railroad Commission; and (2) any other forms or documents required to designate Buyer as operator of Wells with the Bureau of Land Management, if necessary; (vi) execute and deliver to Buyer any other forms required by any Governmental Authority relating to the assignment of the Assets and relating to the assumption of operations by Buyer; (vii) execute and deliver to Buyer Assignments of Record Title and Transfers of Operating Rights on Bureau of Land Management forms 3003-3 and 3000-3a, as applicable; (viii) deliver to Buyer such of the Books and Records as Seller determines to be feasible and thereafter deliver the remainder of the Books and Records to Buyer as soon after Closing as is reasonably possible; and (ix) deliver possession of the Assets to Buyer. (b) At Closing, and as a condition precedent to Seller's obligations hereunder, Buyer shall: (i) pay and deliver to Seller the Purchase Price, as may be adjusted in accordance with the terms of this Agreement, by wire transfer to a bank to be designated by Seller at least two Business Days prior to Closing; (ii) execute and deliver the Assumption Agreement to Seller; 22 (iii) deliver a certificate of Buyer, signed by an authorized officer of Buyer, certifying that the conditions set forth in Section 6.3 have been satisfied; and (iv) execute and deliver to Seller any and all other instruments, documents and other items reasonably necessary to effectuate the terms of this Agreement, as may be reasonably requested by Seller. (c) At Closing, TGG shall execute and deliver and Buyer shall execute and accept, an instrument of conveyance and assumption of liabilities regarding the TGG Assets, in the form attached hereto as Exhibit E. ARTICLE VII ADDITIONAL COVENANTS 7.1. Access to Books and Records. At its expense, Seller and its affiliates and its and their authorized agents, officers and representatives shall have reasonable access after the Closing Date to the Books and Records for any reasonable business purpose, including, but not limited to, matters relating to Taxes; provided, however, that such access by Seller and its affiliates, and its and their authorized agents, officers and representatives (a) shall be conducted during the normal business hours of Buyer, and (b) shall not unreasonably interfere with the operations and activities of Buyer. The Buyer shall cooperate in all reasonable respects with Seller's review of such information, including, without limitation, retaining all such information until Seller has notified the Buyer in writing that all tax years (including any portion of a tax year) prior to and including the Closing Date have been closed or for seven (7) years, whichever is longer. 7.2. Tax Matters. (a) Buyer shall be responsible, and agrees to hold harmless and indemnify the Seller Indemnified Parties, for any and all sales, transfer, recordation, or similar Taxes payable by virtue of this transaction, excluding, however, Seller's income taxes. Buyer and Seller shall cooperate to timely prepare and file all Tax Returns for such Taxes. (b) Seller shall be responsible, and agrees to hold harmless and indemnify the Buyer Indemnified Parties, for all oil and gas production, severance, ad valorem and other similar Taxes with respect to the Assets for periods (or any portion thereof) or production prior to the Effective Time, in each case to the extent not taken into account under Section 2.3(b). Buyer shall be responsible, and agrees to hold harmless and indemnify the Seller Indemnified Parties, for all oil and gas production, severance, ad valorem and other similar Taxes with respect to the Assets for periods (or any portion thereof) or production after the Effective Time, in each case to the extent not taken into account under Section 2.3(a) but including the items described in Section 2.3(b). (c) The parties agree to cooperate with each other as reasonably required after the Closing Date in connection with audits and other proceedings with respect to any Taxes relating to the Assets. 23 (d) Notwithstanding any other provision of this Agreement, the covenants and obligations set forth in this Section 7.2 shall survive until, and any claim for indemnification with respect thereto must be made prior to, the expiration of the applicable statute of limitations with respect to the underlying Tax claim (including any valid extensions). 7.3. Surety Bonds. Buyer shall have surety bonds in place prior to or immediately following the Closing Date sufficient to replace Seller's surety bonds set forth on Schedule 7.3. Buyer shall release or cause Seller's surety bonds to be released as soon as reasonably practicable following the Closing Date. 7.4. Casualty. If any Asset shall be damaged or destroyed by fire or other casualty before the Closing, either party may, at its option, and upon written notice prior to Closing to the other party elect to exclude such Asset from this Agreement. In the event that the Asset to be excluded pursuant to this Section 7.4 is the entirety of a Lease, the Base Purchase Price shall be reduced by the Allocated Value of the Lease to be excluded. In the event that the Asset sought to be excluded is less than the entirety of a Lease, the Base Purchase Price shall be reduced by a mutually agreed upon amount. If neither party elects to delete such Asset from this Agreement as aforesaid, Seller shall pay the deductible due under any insurance policy or policies insuring the same and deliver to Buyer, at the Closing, any insurance proceeds actually received by it by reason of such casualty, and assign to Buyer all of its right, title and interest in any claim under any applicable insurance policies in respect of such casualty. 7.5. Consents and Preferential Rights. (a) Any consents other than consents customarily obtained after Closing, such as, for example, consents to assign federal leases, arising under any of the Property Agreements and unresolved at Closing (either by time constraints or by refusal to consent), shall be considered agreed-upon Title Defects under Exhibit A, until satisfied. If on the Closing Date, the holder of a preferential right has not indicated whether or not it will exercise its right and the time period within which it must timely respond has not lapsed, then the parties shall proceed to Closing on those Assets affected by the preferential right and Buyer shall assume responsibility for conveying the Assets to the holder of the preferential right should it timely exercise, in return for payment by the holder to Buyer of the Allocated Value of the affected Assets. (b) It is recognized that the Burdened Leases are subject to the Production Payment and that not later than 15 Business Days prior to Closing, Seller must notify REI of the impending sale, and furnish Buyer's Schedule of Allocated Values and certain other information to REI. It is also recognized that REI will have 10 Business Days in which to decide whether it will liquidate the Production Payment for an amount determined under a procedure set forth in the Production Payment (the "Production Payment Liquidation Amount"). If REI liquidates the Production Payment, then: (i) Seller will pay the Production Payment Liquidation Amount to REI at Closing; and (ii) Buyer will take the Burdened Leases free and clear of the Production Payment. If REI does not liquidate the Production Payment, the Production Payment will be an Assumed Liability and the Base Purchase Price will be reduced at Closing by the Production Payment Liquidation Amount. 24 7.6. Employee Matters. Attached hereto as Schedule 7.6 is a listing of field and office employees that Buyer may consider for employment. Buyer may, at is sole discretion, offer employment to any or all of such employees. Any such offers of employment shall be at a base salary or hourly wage, and come with such other benefits as are commensurate with similar positions with Buyer. 7.7. Non-Solicitation. For one (1) year from the date of this Agreement, Buyer may not solicit the employment of any employees of Seller that are assigned, temporarily or permanently, to Seller's Shreveport office. Solicitation for employment does not include general advertising for employment opportunities. 7.8. Transition Services Agreement. If requested by Buyer, Seller will provide administrative services with respect to the Assets for the period of time between the Closing Date and January 31, 2005. 7.9. Leased Equipment and Licensed Software. Seller will exercise commercially reasonable efforts to provide for the transfer of leased office equipment and licensed software that is used by Seller in its Irving, Texas and Bridgeport, Texas, offices, the leases and licenses with respect to which are not owned by Winchester. 7.10. Beck Lease. Until Closing, Seller will continue to use commercially reasonable efforts to negotiate with the lessors under the Beck Lease to allow for the expansion of the pad sites. 7.11. Ewing Lease. (a) Buyer and Seller acknowledge that the Ewing Lease expires on December 31, 2004. It is also recognized that Buyer and Seller have engaged in negotiations with the lessor under the Ewing Lease, Mr. Finley Ewing, with the objective of renewing or extending the Ewing Lease. Seller commits to continue to assist in such negotiations following Closing until December 31, 2005 or until the lease or other agreement is secured, whichever comes first. (b) At Closing, Buyer will pay Seller the entire value allocated by Buyer to the Ewing Lease, as set forth on Buyer's Schedule of Allocated Values. From the date this Agreement is executed through December 31, 2005, Buyer agrees to exercise commercially reasonable efforts to negotiate a new or revised lease on the lands covered by the Ewing Lease (a "Replacement Lease"). The term "Replacement Lease" means a new lease or an extension of the Ewing Lease or other agreement that allows Buyer to achieve the development program for the Ewing Lease set forth on Exhibit F. Seller will have the right to participate in all negotiations with Mr. Ewing. If the terms of the Replacement Lease require the payment of a bonus to Mr. Ewing, Seller will pay the first four hundred thousand dollars (US $400,000.00) of such bonus. (c) If Buyer, after the exercise of commercially reasonable efforts, exercised in good faith, does not, by December 31, 2005, acquire a lease or other agreement that qualifies as a Replacement Lease, Seller will refund to Buyer, upon the later of: (i) December 31, 2005; or (ii) the date that is the 25 end of the primary term or the end of any allowable period of drilling allowed by any lease or other agreement acquired by Buyer covering lands covered by the Ewing Lease, an amount of money equal to five million dollars (US $5,000,000.00) minus US $294,118 times the number of wells that Buyer has drilled or has the right to drill under the new agreement, if any. ARTICLE VIII SURVIVAL; INDEMNIFICATION 8.1. Limitation on and Survival of Representations and Warranties. (a) The Buyer and Seller acknowledge and agree that no representations or warranties have been made by Buyer or Seller in connection with the transactions contemplated by this Agreement, except for those representations and warranties made in Article III and Article IV hereof. (b) Subject to paragraph (a) of this Section 8.1, all representations and warranties contained in this Agreement, or in any agreements or instruments executed in connection herewith or delivered pursuant hereto, shall survive the Closing for a period of six months beginning on the Closing Date; provided, however, that the representations set forth in Section 3.10 shall survive the Closing for a period of one year. Such representations and warranties shall only be effective with respect to any breach or claim when notice of such breach or claim shall have been given in writing to the other party in breach or against whom indemnification is sought within such period. Any claim for indemnification for which notice has been given within the prescribed period may be prosecuted to conclusion notwithstanding the subsequent expiration of such period. No party to this Agreement shall be entitled to pursue any remedy for the breach of any representation or warranty: (i) to the extent such party was given written notice of such breach; or (ii) to the extent that such matter was set forth in any documents provided to Buyer prior to Closing and would reasonably give rise to the conclusion that such matter was a breach, prior to the Closing Date and such party proceeds with the Closing. 8.2. Indemnification by Seller. (a) Subject to the limitations set forth in Sections 8.1, 8.4, and 7.2, Seller and PFC (the "Seller Indemnifying Parties") hereby agree to indemnify and hold the Buyer and its employees, officers, directors and affiliates (each a "Buyer Indemnified Party") harmless from and against any and all claims, demands, suits, proceedings, judgments, losses, liabilities, damages, costs and expenses (including, but not limited to, reasonable attorneys' fees) (collectively, "Losses") imposed upon or incurred by any Buyer Indemnified Party as a result of or in connection with any of the following: (i) Any breach of a representation or warranty made by Seller in Article III of this Agreement; provided, that for purposes of this provision, a breach of a representation or warranty that is qualified by materiality or Material Adverse Effect shall be deemed to occur if there would have been a breach of such representation or warranty absent such qualification; or (ii) The breach of, or default in the performance by Seller of, any covenant, agreement or obligation to be performed by Seller pursuant to this Agreement or any agreement or instrument executed in connection herewith or pursuant hereto. 26 (b) Within thirty (30) days after receipt by a Buyer Indemnified Party of notice of an Action or other event giving rise to a buyer claim (a "Buyer Claim") with respect to which a Buyer Indemnified Party may be entitled to indemnification under this Section 8.2, the party receiving such notice shall notify (the "Buyer Claim Notice") the Seller Indemnifying Parties in writing of the commencement of such Action or the assertion of such Buyer Claim; provided, however, that failure to give such notice shall not affect the right to indemnification hereunder except to the extent of actual prejudice to the Seller Indemnifying Parties. The Seller Indemnifying Parties shall have the option, and shall notify the Buyer Indemnified Party in writing within ten (10) business days after the date of the Buyer Claim Notice of their election, either: (A) to participate (at the expense of the Seller Indemnifying Parties) in the defense of such Action or Buyer Claim (in which case the defense of such Action or Buyer Claim shall be controlled by the Buyer Indemnified Party) or (B) to take charge of and control the defense of such Action or Buyer Claim (at the expense of the Seller Indemnifying Parties). If the Seller Indemnifying Parties elect to control the defense, it will not compromise or settle the Action or Buyer Claim if (X) the amount to be paid in settlement exceeds the Maximum Indemnity Amount or (Y) the settlement does not include a provision releasing the Buyer Indemnified Party from all liabilities with respect thereto. If the Seller Indemnifying Parties fail to notify the Buyer Indemnified Party of their election within the applicable response period, then the Seller Indemnifying Parties shall be deemed to have elected not to control the defense of such Action or Buyer Claim. If the Seller Indemnifying Parties elect to control the defense of any Action or Buyer Claim, the Buyer Indemnified Party shall have the right to employ separate counsel and participate in the defense of such Action or Buyer Claim, but the fees and expenses of such counsel shall be at the expense of the Buyer Indemnified Party unless: (1) the named parties in such Action or Buyer Claim (including any impleaded parties) include both the Buyer Indemnified Party and an indemnifying party and the Buyer Indemnified Party shall have been advised by such counsel that there may be one or more legal defenses available to it that are different from or additional to those available to the indemnifying party, or (2) the Buyer Indemnified Party has reasonably determined that Losses that may be incurred may exceed either individually, or when aggregated with other Buyer Claims, the Maximum Indemnity Amount (in which case, the Seller Indemnifying Parties shall not have the right to control the defense of such Action or Buyer Claim on behalf of the Buyer Indemnified Party, it being understood, however, that the Seller Indemnifying Parties shall not, in connection with such Action or Buyer Claim, be liable for the fees and expenses of more than one separate firm of attorneys (in addition to any local counsel) and that all such fees and expenses shall be reimbursed as they are incurred). (c) If the Seller Indemnifying Parties do not control the defense of any Action or Buyer Claim, then the Buyer Indemnified Party may settle such Action or Buyer Claim with the prior written consent of Seller Indemnifying Party (not to be unreasonably withheld). 8.3. Indemnification by Buyer. (a) Subject to the limitations set forth in Section 8.4, the Buyer hereby agrees to indemnify and hold Seller and its employees, officers, managers, members, and affiliates (each a "Seller Indemnified Party") harmless from and against any and all Losses imposed upon or incurred by any Seller Indemnified Party (any of such Losses by Seller, a "Seller Claim") as a result of or in connection with any of the following: 27 (i) Any breach of a representation or warranty made by the Buyer in this Agreement or in any agreement or instrument executed in connection herewith or pursuant hereto; provided, that for purposes of this provision, a breach of a representation or warranty that is qualified by materiality or Material Adverse Effect shall be deemed to occur if there would have been a breach of such representation or warranty absent such qualification; (ii) The breach of or default in the performance by the Buyer of any covenant, agreement or obligation to be performed by the Buyer pursuant to this Agreement or any agreement or instrument executed in connection herewith or pursuant hereto; or (iii) The ownership or operation of the Assets from and after the Closing Date. (b) Within thirty (30) days after receipt by a Seller Indemnified Party of notice of the commencement of an Action or other event giving rise to a seller claim (a "Seller Claim") with respect to which a Seller Indemnified Party may be entitled to indemnification, the party receiving such notice shall notify (the "Seller Claim Notice") Buyer in writing of the commencement of such Action or the assertion of such Seller Claim; provided, however, that failure to give such notice shall not affect the right to indemnification hereunder except to the extent of actual prejudice to Buyer. Buyer shall have the option, and shall notify each indemnified party in writing within ten business days after the date of the Seller Claim of its election, either: (A) to participate (at its own expense) in the defense of the Action or Seller Claim (in which case the defense of such Action or Seller Claim shall be controlled by the Seller Indemnified Party) or (B) to take charge of and control defense of such Action or Seller Claim (at its own expense). If Buyer fails to notify the Seller Indemnified Party of its election within the applicable response period, then Buyer shall be deemed to have elected not to control the defense of such Action or Seller Claim. If Buyer elects to control the defense of any Action or Seller Claim, each Seller Indemnified Party shall have the right to employ separate counsel and participate in the defense of any such Action or Seller Claim, but the fees and expenses of such counsel shall be at the expense of the Seller Indemnified Party unless: (1) the named parties in such Action or Seller Claim (including any impleaded parties) include both the Seller Indemnified Party and Buyer and the Seller Indemnified Party shall have been advised by such counsel that there may be one or more legal defenses available to it that are different from or additional to those available to Buyer, or (2) Seller has reasonably determined that Losses that may be incurred may exceed either individually, or when aggregated with other Seller Claims, the Maximum Indemnity Amount (in which case, Buyer shall not have the right to assume the defense of such Action or Seller Claim on behalf of the Seller Indemnified Party, it being understood, however, that Buyer shall not, in connection with such Action or Seller Claim be liable for the fees and expenses of more than one separate firm of attorneys (in addition to any local counsel) and that such fees and expenses shall be reimbursed as they are incurred). (c) If Buyer does not control the defense of any Action or Seller Claim, then the Seller Indemnified Party or parties may settle such Action or Seller Claim with the prior written consent of Buyer (not to be unreasonably withheld). 28 8.4. Limitation of Liability. Notwithstanding the foregoing, (i) the Seller Indemnifying Parties shall not be obligated to indemnify the Buyer Indemnified Parties, and Buyer shall not be obligated to indemnify the Seller Indemnified Parties pursuant to this Article VIII unless and until the amount of all Losses incurred by Buyer, or by Seller, as the case may be, exceeds one million dollars ($1,000,000.00) in the aggregate (the "Basket"), in which event the party seeking indemnity may recover all Losses incurred in excess of the Basket from the first dollar above the Basket, and (ii) the Seller Indemnifying Parties maximum liability for Losses under Section 8.2 and Buyer's maximum liability for Losses under Section 8.3 shall be, in each case, fifteen percent (15%) of the Purchase Price (the "Maximum Indemnity Amount"). 8.5. Exclusive Remedy. Except as provided in Section 7.2 or Section 8.6, after the Closing, the parties' sole and exclusive recourse against each other for any Loss or claim of Losses arising out of or relating to this Agreement shall be expressly limited to the provisions of this Article VIII. 8.6. Title Defects. Buyer's sole and exclusive remedy with respect to Title Defects, or Losses arising thereunder, shall be as provided in Exhibit A. 8.7. Disclaimer of Other Warranties. (a) The express representations and warranties of Seller contained in this Agreement are exclusive and are in lieu of all other representations and warranties, express, implied, or statutory. SELLER HAS NOT MADE, AND SELLER HEREBY EXPRESSLY DISCLAIMS AND NEGATES, AND BUYER HEREBY EXPRESSLY WAIVES, ANY REPRESENTATION OR WARRANTY, EXPRESS, IMPLIED, AT COMMON LAW, BY STATUTE OR OTHERWISE RELATING TO (A) PRODUCTION RATES, RECOMPLETION OPPORTUNITIES, DECLINE RATES, GAS BALANCING INFORMATION OR THE QUALITY, QUANTITY, OR VOLUME OF THE RESERVES OF HYDROCARBONS, IF ANY, ATTRIBUTABLE TO THE ASSETS, (B) THE ACCURACY, COMPLETENESS OR MATERIALITY OF ANY INFORMATION, DATA OR OTHER MATERIALS (WRITTEN OR ORAL) NOW, HERETOFORE OR HEREAFTER FURNISHED TO BUYER BY OR ON BEHALF OF SELLER, (C) THE ENVIRONMENTAL CONDITION OF THE PROPERTIES, (D) ANY IMPLIED OR EXPRESS WARRANTY OF MERCHANTABILITY, (E) ANY IMPLIED OR EXPRESS WARRANTY OF FITNESS FOR A PARTICULAR PURPOSE, (F) ANY IMPLIED OR EXPRESS WARRANTY OF CONFORMITY TO MODELS OR SAMPLES OF MATERIALS, (G) ANY RIGHTS OF PURCHASERS UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION, AND (H) ANY AND ALL IMPLIED WARRANTIES EXISTING UNDER APPLICABLE LAW; IT BEING THE EXPRESS INTENTION OF BOTH BUYER AND SELLER THAT SUBJECT TO AND WITHOUT LIMITING SELLER'S EXPRESS REPRESENTATION AND WARRANTIES CONTAINED HEREIN, THE PERSONAL PROPERTY, EQUIPMENT AND FIXTURES INCLUDED WITHIN THE PROPERTIES ARE TO BE CONVEYED TO BUYER IN THEIR PRESENT CONDITION AND STATE OF REPAIR, AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS BUYER DEEMS APPROPRIATE. SELLER AND BUYER AGREE THAT, TO THE EXTENT REQUIRED BY APPLICABLE LAW TO BE EFFECTIVE, THE DISCLAIMERS OF CERTAIN WARRANTIES CONTAINED IN THIS SECTION ARE "CONSPICUOUS" DISCLAIMERS FOR THE PURPOSES OF ANY APPLICABLE LAW, RULE OR ORDER. 29 (b) Buyer is aware that the Properties have been used for exploration, development, production, handling, transporting and/or processing of oil and gas and that there may be petroleum, produced water, wastes, or other materials located on or under the Properties or associated with the premises. Some equipment and sites included in the Properties may contain asbestos, Hazardous Substances, or naturally occurring radioactive material ("NORM"). NORM may affix or attach itself to the inside of wells, materials, and equipment as scale, or in other forms; the wells, materials, and equipment located on the Properties or included in the Properties may contain NORM and other materials or Hazardous Substances; and NORM-containing material and other materials or Hazardous Substances may have been buried, come in contact with the soil or water, or otherwise been disposed of on the Properties. Special procedures may be required for the remediation, removal, transportation, or disposal of materials, asbestos, Hazardous Substances, and NORM from the Properties. Buyer will assume all liability for the assessment, remediation, removal, transportation, and disposal of these materials and associated activities and will conduct these activities in accordance with all applicable laws and regulations, including applicable environmental laws. (c) Buyer understands that operation of the Leases is subject to requirements of the governmental authorities having jurisdiction. It will be the obligation of Buyer to ensure that, as of the Closing, or as soon thereafter as reasonably practicable, Buyer will meet the qualifications of the governmental authorities having jurisdiction, in order to become record operator of the Leases. ARTICLE IX TERMINATION 9.1. Termination. This Agreement may be terminated and the transactions contemplated by this Agreement may be abandoned at any time, prior to the Closing only as follows: (a) by mutual written consent of the Buyer and Seller; (b) by the Buyer or Seller if the Closing shall not have occurred on or before December 30, 2004 (provided that the right to terminate this Agreement under this Section 9.1(b) shall not be available to any party whose failure to fulfill any obligation under this Agreement has been the cause of, or has resulted in, the failure of the Closing to occur on or before such date); or (c) by the Buyer or Seller, if any court of competent jurisdiction in the United States or other United States governmental body shall have issued an order, decree or ruling or taken any other action restraining, enjoining or otherwise prohibiting the transactions contemplated hereby and such order, decree, ruling or other action shall have become final and non-appealable. 30 (d) by the Buyer or Seller, if the aggregate of the Title Defect Values and Environmental Defect Values asserted by Buyer total more than ten percent (10%) of the Base Purchase Price. 9.2. Effect of Termination. If this Agreement is terminated pursuant to Section 9.1 and the transactions contemplated by this Agreement are not consummated, all further obligations of the parties under or pursuant to this Agreement shall terminate without further liability of either party to the other; provided, however, the obligations contained in this Section 9.2 and Section 10.2 of this Agreement shall survive any such termination. Nothing contained in this Section 9.2 shall relieve any party from liability for any breach of this Agreement. 9.3. Amendment. This Agreement may not be amended except by an instrument in writing signed by all of the parties. 9.4. Extension; Waiver. At any time prior to the Closing, the parties may (a) extend the time for the performance of any of the obligations or other acts of the other parties hereto, (b) waive any inaccuracies in the representations and warranties contained herein or in any document, certificate or writing delivered pursuant hereto, or (c) waive compliance with any of the covenants, agreements or conditions contained herein. Any agreement on the part of any party to any such extension or waiver shall be valid only if set forth in an instrument in writing signed on behalf of such party. ARTICLE X MISCELLANEOUS 10.1. Entire Agreement. This Agreement and the documents referred to herein and to be delivered pursuant hereto constitute the entire agreement between the parties pertaining to the subject matter hereof, and supersede all prior and contemporaneous agreements, understandings, negotiations and discussions of the parties, whether oral or written, and there are no warranties, representations or other agreements between the parties in connection with the subject matter hereof, except as specifically set forth herein or therein. 10.2. Expenses. (a) Whether or not the transactions contemplated by this Agreement are consummated, each of the parties hereto shall pay the fees and expenses of their respective counsel, investment bankers, financial advisors, accountants and other experts and the other expenses incident to the negotiation and preparation of this Agreement and consummation of the transactions contemplated hereby. (b) Buyer shall be solely responsible for all filings and recording of assignments and other documents which transfer any of the Assets to Buyer or which designate Buyer as the operator of the Assets and for all fees connected with such filing or recording. Upon request, Buyer shall advise Seller of the pertinent recording data. Seller shall not be responsible for any loss to Buyer because of Buyer's failure to file or record any such documents correctly or promptly 31 10.3. Governing Law. This Agreement shall be construed and interpreted according to the laws of the State of Texas without regard to the conflicts of law rules thereof. 10.4. Assignment. This Agreement and each party's respective rights hereunder may not be assigned at any time except as expressly set forth herein without the prior written consent of the other parties. 10.5. Notices. All communications, notices and disclosures required or permitted by this Agreement shall be in writing and shall be deemed to have been given when delivered personally or by messenger or by overnight delivery service, or when mailed by registered or certified United States mail, postage prepaid, return receipt requested, or when received via telecopy, telex or other electronic transmission, in all cases addressed to the person for whom it is intended at his address set forth below or to such other address as a party shall have designated by notice in writing to the other party in the manner provided by this Section 10.5: If to Seller, TGG or Progress Fuels Progress Fuels Corporation Corporation: P.O. Box 1551 Raleigh, North Carolina 27602 Attention: Robert M. Deacy Senior Vice President, Gas Operations Telecopy: 919-546-2990 With a copy to: Hunton & Williams LLP 421 Fayetteville Street Mall, Suite 1400 Raleigh, North Carolina 27601 Attention: Timothy S. Goettel Telecopy: 919-899-3160 And David B. Fountain Deputy General Counsel Progress Energy Service Company, LLC Mail Code PEB 17B2 Raleigh, North Carolina 27602 Telecopy: (919) 546-2920 32 If to the Buyer: EnCana Oil & Gas (USA), Inc. 950 17th Street, Suite 2600 Denver, CO 80202 Attention: Roger Biemans, President Telecopy: (303) 623-9178 With a copy to: Mr. John Sanchez 14001 N. Dallas Parkway, Suite 1000 Dallas, Texas 75240 Telecopy: (214) 691-1415 10.6. Counterparts; Headings. This Agreement may be executed in several counterparts, each of which shall be deemed an original, but such counterparts shall together constitute but one and the same Agreement. The Table of Contents and Article and Section headings in this Agreement are inserted for convenience of reference only and shall not constitute a part hereof. 10.7. Specific Performance. The parties hereto agree that irreparable damage would occur in the event any of the provisions of this Agreement were not performed in accordance with the terms hereof and that the parties shall be entitled to specific performance of the terms hereof, in addition to any other remedy at law or equity. 10.8. Interpretation. Unless the context requires otherwise, all words used in this Agreement in the singular number shall extend to and include the plural, all words in the plural number shall extend to and include the singular and all words in any gender shall extend to and include all genders. All references to contracts, agreements, leases, Employee Benefit Plans or other understandings or arrangements shall refer to oral as well as written matters. 10.9. Severability. If any provision, clause or part of this Agreement, or the application thereof under certain circumstances, is held invalid, the remainder of this Agreement, or the application of such provision, clause or part under other circumstances, shall not be affected thereby. 10.10. No Third-Party Reliance. No third party is entitled to rely on any of the representations, warranties and agreements contained in this Agreement, and Seller and the Buyer assume no liability to any third party because of any reliance on the representations, warranties and agreements of Seller and the Buyer contained in this Agreement. [SIGNATURE PAGE FOLLOWS] 33 IN WITNESS WHEREOF, the parties have caused this Purchase Agreement to be duly executed as of the day and year first above written. WINCHESTER PRODUCTION COMPANY, LTD. By: Vaughan Holding Company, LLC, its general partner By: /s/Robert M. Deacy ------------------------------- Name: Robert M. Deacy Title: Senior Vice President TGG PIPELINE, LTD., solely for the purpose of conveying the TGG Assets By: Vaughan Holding Company, LLC, its general partner By: /s/Robert M. Deacy ------------------------------- Name: Robert M. Deacy Title: Senior Vice President PROGRESS FUELS CORPORATION, solely for the purpose of supporting the obligations of Seller set forth in Article VIII By: /s/Bonnie V. Hancock ------------------------------- Name: Bonnie V. Hancock Title: President ENCANA OIL & GAS (USA) INC. By: /s/Roger Biemans ------------------------------- Name: Roger Biemans Title: President EX-31 12 pei_exhibit31-.txt EXHIBIT 31 Exhibit 31(a) CERTIFICATION 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)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) 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) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) 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 d) 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 (the registrant's fourth fiscal quarter in the case of this annual report) 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 ___, 2005 /s/ Robert B. McGehee ------------------------------------ Robert B. McGehee Chairman and Chief Executive Officer Exhibit 31(b) CERTIFICATION 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)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) 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) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) 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 d) 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 (the registrant's fourth fiscal quarter in the case of this annual report) 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 ___, 2005 /s/ Geoffrey S. Chatas ----------------------------- Geoffrey S. Chatas Executive Vice President and Chief Financial Officer Exhibit 31(a) CERTIFICATION 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 (the registrant's fourth fiscal quarter in the case of this annual report) 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 ___, 2005 /s/ Fred N. Day IV ------------------------------------- Fred N. Day IV President and Chief Executive Officer Exhibit 31(b) CERTIFICATION 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 (the registrant's fourth fiscal quarter in the case of this annual report) 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 ___, 2005 /s/ Geoffrey S. Chatas ------------------------------ Geoffrey S. Chatas Executive Vice President and Chief Financial Officer EX-32 13 pei_exhibit32-.txt EXHIBIT 32 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, 2004 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), as applicable, 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 Chairman and Chief Executive Officer March ___, 2005 This certification is being furnished and shall not be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or incorporated by reference in any filing under the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended. 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, 2004 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), as applicable, 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 ___, 2005 This certification is being furnished and shall not be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or incorporated by reference in any filing under the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended. 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, 2004 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), as applicable, 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 ___, 2005 This certification is being furnished and shall not be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or incorporated by reference in any filing under the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended. 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, 2004 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), as applicable, 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 ___, 2005 This certification is being furnished and shall not be deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or incorporated by reference in any filing under the Securities Exchange Act of 1934, as amended, or the Securities Act of 1933, as amended. -----END PRIVACY-ENHANCED MESSAGE-----