ML031700027

Submittal of 10-O Report

ML031700027
Person / Time
Site:	Brunswick, Robinson
Issue date:	06/06/2003
From:	Holt J Progress Energy Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
-nr, DG-1106, PE&RAS-03-064
Download: ML031700027 (68)

Text

- I -

progress Energy 10 CFR 50.75(e)(1)(iii)(B)

SSPMor Energy° PO Box 1551 41 1 Fayet¢vfle Street Mail 0 Raleigh NC 27602 Serial: PE&RAS-03-064 June 6, 2003 United States Nuclear Regulatory Commission ATTENTION: Document Control Desk Washington, DC 20555 HX B. ROBINSON STEAM ELECTRIC PLANT, UNIT NO. 2 DOCKET NO. 50-261 / LICENSE NO. DPR-23 BRUNSWICK STEAM ELECTRIC PLANT, UNIT NOS. 1 AND 2 DOCKET NOS. 50-325 AND 50-324 / LICENSE NOS. DPR-71 AND DPR-62 SUBMITTAL OF 10-0 REPORT Ladies and Gentlemen:

Progress Energy Carolins, Inc. (also known as Carolina Power & Light Company) submits the enclosed quarterly 10-Q Report for Progress Energy, Inc. for the quarterly period ended March 31, 2003.

Submittal to the NRC of financial reports filed with the U.S. Securities and Exchange Commission is required by the parent company guarantees used to provide financial assurance of decommissioning funds for H. B. Robinson Steam Electric Plant, Unit No. 2 and the Brunswick Steam Electric Plant, Unit Nos. 1 and 2, pursuant to 10 CFR 50.75(eX)(iii)(B). The parent company guarantees were written to require this submittal based on the guidance in Appendix B-6.5 of draft Regulatory Guide DG-1 106, "Assuring the Availability of Funds for Decommissioning Nuclear Reactors."

This document contains no new regulatory commitment.

Please contact me at (919) 546-6901 if you need additional information conceming this report.

Sincerely, 1'- . 4&

lames W. Holt Manager - Performance Evaluation & Regulatory Affairs HAS

Enclosure:

United States Nuclear Regulatory Commission PE&RAS-03-064 Page 2 c:

without enclosure:

L. A. Reyes, Regional Administrator - Region II USNRC Resident Inspector - BSEP, Unit Nos. 1 and 2 USNRC Senior Resident Inspector - HBRSEP, Unit No. 2 B. L. Mozafari, NRR Project Manager - BSEP, Unit Nos. 1 and 2 C. P. Patel, NRR Project Manager - HBRSEP, Unit No. 2 G. West, USNRC NSIRIDNS/LPSS-OWFN, A 4 D8 J. A. Sanford - North Carolina Utilities Commission

UN1TED STATES SECURlTIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q

[XI QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITES EXCHANGE ACT OF 1934 For the quarterly period ended March 31. 2003 OR I ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _ to Commission Exact name of registrants as specified in their charters, state of LR.S. Employer File Number incorporation, address of principal 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 (Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has 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 registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X. No_.

Indicate by check mark whether Progress Energy, Inc. is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes L No_

Indicate by check mark whether Carolina Power & Light Company is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes_. NoX.

This combined Form 0-Q is filed separately by two registrants: Progress Energy, Inc. (Progress Energy) and Carolina Power &

Light Company. Information contained herein relating to either individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to Information relating exclusively to the other registrant.

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

As of April 30, 2003, each registrant had the following shares of common stock outstanding:

Registrant Description Shares Progress Energy. Inc. Common Stock (Without Par Value) 240.800,322 Carolina Power & Light Company Common Stock (Without Par Value) 159,608,055 (all of which were held by Progress Energy, Inc.

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PROGRESS ENERGY, INC. AND PROGRESS ENERGY CAROLINAS, INC FORM 10-Q - For the QuarterEnded March 31, 2003 Glossary of Terms Safe Harbor For Forward-Looking Statements PART . FINANCIAL INFORMATION Item. 1. Financial Statements Consolidated Interim Financial Statements:

Progress Energy, Inc.

Consolidated Statements of Income Consolidated Balance Sheets Consolidated Statements of Cash Flows Supplemental Data Schedule Notes to Consolidated Interim Financial Statements Carolina Power & Light Company.

dtb/a Progress Energy Carolinas, Inc.

Consolidated Statements of Income Consolidated Balance Sheets Consolidated Statements of Cash Flows Notes to Consolidated Interim Financial Statements Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures PART ILOTHER INFORMATION Item 1. Legal Proceedings Item 2. Changes in Securities and Use of Proceeds Item 6. Exhibits and Reports on Form 8-K Signatures 2

GLOSSARY OF TERM The following abbreviations or acronyms used in the text of this combined Form 10-Q are defined below:

TERM DEFINIION AFUDC Allowance for funds used during construction the Agreement Stipulation and Settlement Agreement Bcf Billion cubic feet the Code Internal Revenue Service Code Colona Colona Synfuel Limited Partnership, L.L.L.P.

the Company Progress Energy, Inc. and subsidiaries CP'&L Carolina Power & Light Company, currently referred to as Progress Energy Carolinas or PEC CR3 Progress Energy Florida's nuclear generating plant, Crystal River Unit No. 3 CVO Contingent value obligation DEP Florida Department of Environment and Protection DIG Derivatives Implementation Group DOE United States Department of Energy Dt Dekatherm DWM North Carolina Department of Environment and Natural Resources, Division of Waste Management EBrIDA Earnings before interest, taxes, and depreciation and amortization EITF Emerging I*sues Task Force ENCNG Eastern North Carolina Natural Gas Company, formerly referred to as Eastern NC EPA United States Environmental Protection Agency FASB Financial Accounting Standards Board FDEP Florida Department of Environment and Protection FERC Federal Energy Regulatory Commission FIN No. 45 FASB Interpretation No. 45. Guarantor's Accounting and Disclosure Requirements' FIN No. 46 FASB Interpretation No. 46, Consolidation of Variable Interest Entities - An Interpretation of ARB No. 51 "

FPC Florida Progress Corporation FPSC Florida Public Service Commission GAAP Accounting principles generally accepted in the United States of America Genco Progress Genco Ventures, LLC IRS Internal Revenue Service Jackson Jackson Electric Membership Corp.

KWh Kilowatt-hour MACT Maximum Available Control Technology MGP Manufactured Gas Plant MW Megawatt NCNG North Carolina Natural Gas Corporation NCUC North Carolina Utilities Commission NOx SIP Call EPA rule which requires 23 jurisdictions including North and South Carolina and Georgia to further reduce nitrogen oxide emissions NRC United States Nuclear Regulatory Commission PCH Progress Capital Holdings, Inc.

PEC Progress Energy Carolinas, Inc.. formerly referred to as Carolina Power & Light Company PEF Progress Energy Florida, Inc., formerly referred to as Florida Power Corporation PES Progress Energy Solutions, formerly referred to as Strategic Resource Solutions Corp. or SRS PFA IRS Prefiling Agreement the Plan Revenue Sharing Incentive Plan PLRs Private Letter Rulings Progress Energy Progress Energy. Inc.

Progress Rail Progress Rail Services Corporation Progress Telecom Progress Telecommunications Corporation 3

A4.

Progress Ventures Business segment of Progress Energy primarily made up of nonregulated energy generation, gas, coal and synthetic fuel operations and energy marketing and trading PUHCA Public Utility Holding Company Act of 1935, as amended PVI Legal entity of Progress Ventures, Inc., formerly referred to as CPL Energy Ventures, Inc.

PWR Pressurized water reactor RAFT Railcar Asset Financing Trust RTO Regional Transmission Organization SCPSC Public Service Commission of South Carolina SEC United States Securities and Exchange Commission Section 29 Section 29 of the Internal Revenue Service Code Service Company Progress Energy Service Company, LLC.

SFAS No. 5 Statement of Financial Accounttng-StandardsNo. 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. 131 Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information' SFAS No. 133 Statement of Financial Accounting Standards No. 133. "Accounting for Derivative and Hedging Activities' 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. 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. 149 Statement of Financial Accounting Standards No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" SMD NOPR Notice of Proposed Rulemaking in Docket No. RMO1-12-OOO. Remedying Undue Discrimination through Open Access Transmission and Standard Market Design SRS Strategic Resource Solutions Corp.

the Trust FPC Capital I 4

SAFE HARBOR FOR FORWARD-LOOKING STATEMENS The matters discussed throughout this Form combined 0-Q 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, forward-looking statements are discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations' including, but not limited to, statements under the sub-heading Other Matters" about the effects of new enviromnental regulations, nuclear decommissioning costs and the effect of electric utility industry restructuring.

Any forward-looking statement speaks only as of the date on which such statement is made, and neither Progress Energy, Inc.

(Progress Energy) nor Progress. Energy Carolinas, Inc. (PEG) undertakes any obligation to update any Forward-looking statement r statements to reflect events or circumstances after the date on which such statement is made.

Examples of factors that you should consider with respect to any forward-looking statements made throughout this document include, but are not limited to, the following: the impact of fluid and complex government laws and regulations, including those relating to the environment; the impact of recent events in the energy markets that have increased the level of public and regulatory scrutiny in the energy industry and in the capital markets; deregulation or restructuring in the electric industry that may result in increased competition and unrecovered (stranded) costs; the uncertainty regarding the timing, creation and structure of regional transmission organizations; weather conditions that directly influence the demand for electricity and natural gas; recurring seasonal fluctuations in demand for electricity and natural gas; fluctuations in the price of energy commodities and purchased power; economic fluctuations and the corresponding Impact on the Company's commercial and industrial customers; the ability of the Company's subsidiaries to pay upstream dividends or distributions to it; the impact on the facilities and the businesses of the Company from a terrorist attack; the inherent risks associated with the operation of nuclear facilities, including environmental, health, regulatory and financial risks; the ability to successfully access capital markets on favorable terms; the impact that increases in leverage may have on the Company; the ability of the Company to maintain its current credit ratings; the impact of derivative contracts used in the normal course of business by the Company; the Company's continued ability to use Section 29 tax credits related to its coal and synthetic fuels businesses; the continued depressed state of the telecommunications Industry and the Company's ability to realize future retLrns from Progress Telecommunications Corporation and Caronet, Inc.; the Company's ability to successfully integrate newly acquired assets, properties or businesses into its operations as quickly or as profitably as expected; the Company's ability to successfully complete the sale of North Carolina Natural Gas and apply the proceeds therefrom to reduce outstanding indebtedness; the Company's ability to manage the risks involved with the construction and operation of its nonregulated plants, including construction delays, 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 and trading operations; and unanticipated changes in operating expenses and capital expenditures. Many of these risks similarly impact the Company's subsidiaries.

These and other risk factors are detailed from time to time in the Progress Energy and PEC SEC reports. Many, but not all of the factors that may impact actual results are discussed in the Risk Factors sections of Progress Energy's and PEC's annual report on Form 10-K for the year ended December 31, 2002, which was filed with the SEC on March 21, 2003. 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 t assess the effect of each such factor on Progress Energy and PEC.

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PART L FINANCIAL INFORMATION tmI. Financial Statements Progress Energy, Inc.

CONSOLIDAI'ED INTERIM FINANCIAL STATEMENTS March 31, 2003 CONSOLIDATED STATEMENTS OF NM IX CONSOLIDATED STATEMENTS OF INCOME Three Months Ended (Unaudited) March 31, (In thousands except per share data) 2003 2002 Operating Revenues Utility $ 1,653,897 $ 1,497,923 Diversified business 362,117 .289,379 Total Operating Revenues 201 6,004 1,787.302 Operating Expenses Utility Fuel used in electric generation 411,622 370,588 Purchased power 202,742 181,273 Operation and maintenance 334,313 328,438 Depreciation and amortization 220,088 211,888

- Taxes other than on income 102,832 95,922 Diversified business Cost of sales 306,941 300,525 Depreciation and amortization 28,268 27,335 Other 50,258 29,352

- Total Operating Expenses 1,657,064 1,545,321 Operating Income 358,940 241,981 Other Income (Expense)

Interest income 2,767 1,952 Other. net (2450) 6,058 Total Other Income 317 8,010 Income before Interest Charges and Income Taxes 359,257 249,991 Interest Charges Net interest charges 156,248 170,168 Allowance for borrowed funds used during construction (2,886) (3,553)

Total Interest Charges, Net 153,362 166,615 Income from Continuing Operations before Income Tax 205,895 83,376 Income Tax Expense (Benefit) 9,029 (40,686)

Income from Continuing Operations 196,866 124,062 Discontinued Operations, Net of Tax 11,290 8,465 Net Income $ 208,155 $ 132,527 Average Common Shares Outstanding 233,438 212.979 Basic and Fully Diluted Earnings per Common Share Income from Continuing Operations $ 0.84 $ 0.58 Discontinued Operatons, Net of Tax $ 0.05 $ 0.04 Net Income S 0.89 $ 0.62 Dividends Declared per Common Share $ 0.560 $ 0.545 See Notes to Progress Energy. Inc. Consolidated Interim Financial Statements.

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Progress Energy, Inc.

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands except share data) March 31, December 31, Assets 2003 2002 Utility Plant Utility plant in service $ 20,803,671 $ 20,152,787 Accumulated depreciation (9,866,4,34) (10,480,880)

Utility plant in service, net 10,937,237 9,671,907 Held for future use 15,109 15,109 Construction work in progress 826,674 752,336 Nuclear fuel, netof amortization 254,771 216,882

,j :TotalUtility Plant; Net - 12,033.791 10656,234 Current Assets Cash and -cash equivalents 35,487 61,358 Accounts receivable 780,655 737,369 Unbilled accounts receivable 187,451 225,011 Inventory - 844,919 875,485 Deferred fuel cost 229,522 183,518 Assets of discontinued operations 494,485 490,429 Prepayments and other current assets 255,233 283,036 Total Current Assets 2,827,752 2,856,206 Deferred Debits and Other Assets Regulatory assets 658,828 393,215 Nuclear decommissioning trust funds 788,766 796,844 Diversified business property, net . 2,074,373 1,884,271 Miscellaneous other property and investments 472,642 463,776 Goodwill 3,719,327 3,719,327 Prepaid pension costs 58,669 60,169 Other assets and deferred debits 538,744 522,662

-Total Deferred Debits and Other Assets 8,311,349 7,840,264 Totai Assets $ 23,172,892 $ 21.352,704 Capitalization and Liabilities Common Stock Equity Common stock without par value, 500,000,000 shares authorized, 239,816,121 and 237,992,513 shares issued and outstanding, respectively $ 5,007,203 $ 4,929,104 Unearned ESOP common stock (90,890) (101,560)

Accumulated other comprehensive loss (238,290) (237,762)

Retained eamings 2,163,431 2,087,227 Total Common Stock Equity 6,841.454 6.677,009 Preferred Stock of Subsidiaries-Not Subject to Mandatory Redemption 92,831 92,831 Long-Term Debt 9,597,948 9,747,293 Total Capitalization 16,532,233 16,517,133 Current Liabilities Current portion of long-term debt 880,164 275,397 Accounts payable 718,814 756,287 Interest accrued 162,817 220,400 Dividends declared 133,475 132,232 Short-term obligations 489,675 694,850 Customer deposits 159,780 158,214 Liabilities of discontinued operations 117,471 124,767 Other current liabilities 368,474 372,161 Total Current Liabilities 3,030,670 2,734.308 Deferred Credits and Other Liabilities Accumulated deferred income taxes 901,258 932,813 Accumulated deferred investment tax credits 202,160 206,221 Regulatory liabiities 451,769 119,766 Asset retirement obligations 1,209,587 Other liabilities and deferred credits 845,215 842,463 Total Deferred Credits and Other Liabilities 3,609,989 2,101,263 Commitments and Contingencies (Note 15)

Total Capitalization and Liabilities $ 23,172,892 $ 21.352.704 7

S See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.

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Progress Energy, Inc.

CONSOLIDATED STATEMENTS OF CASH FLOWS Three Months Ended (Unaudited) March 31, (in thousands) 2003 2002 Operating Activities Net income $ 208,156 $ 132,527 Adjustments to reconcile net income to net cash provided by operating activities:

.Income from discontinued operations (11,290) (8,466)

Depreciation and amortization 281,380 271,029 .

Deferred income taxes (2,608) 12,194 Investment tax credit - (4,.061) (5,435)

Peferred fuel cost (credit) * - 46,004) 49,442 Net increase inacco,uns receivable (14,982) (160. -)

Net increase) decrease in inventories *1 . 29,831 (33,766)

Net (increase) decreasein prepayments and other current assets 10,184 (10.137)

Net increase (decrease) in accounts payable 42,621 (71,494)

Net decrease in accrued interest (57.311) (64,004)

Net decrease in other current liabilities (16,776) (24,053)

Other 14,256 28,113 Net Cash Provided by Operating Activities 433,396 259,868 Investing Activities Gross utility property additions (291.318) (253,739)

Diversified business propeny additions and acquisitions, (222,626) (495,144)

Nuclear fuel additions (67,954) (33,386)

Net contributions to nuclear decommissioning trust (10,262) (12,226)

Investments in non-utility activities (3,383) (6,088)

Other 3,369 (100,313)

Net Cash Used in Investing Activities (592,174) (900,896)

Financing Activities Issuance of common stock, net 73,901 Purchase of restricted shares (6.560) (5,393)

Issuance of long-term debt, net 655,136 152,660 Net increase (decrease) in short-term indebtedness (205,175) 892,302 Net decrease in cash provided by checks drawn in excess of bank balances (36,847) (40,046)

Retirement of long-term debt (225,608) (104.533)

Dividends paid on common stock (133,286) (119,206)

Other 11,240 68,597 Net Cash Provided by Financing Activities 132,801 844,381 Cash Provided by (Used in) Discontinued Operations 106 (542)

Net Increase (Decrease) in Cash and Cash Equivalents (25,871) 202,811 Cash and Cash Equivalents at Beginning of the Period 61,358 53,708 Cash and Cash Equivalents at End of the Period $ 35,487 $ 256,519 Supplemental Disclosures of Cash Flow Information Cash paid during the year - interest (net of amount capitalized) $ 209,194 $ 231,067 income taxes (net of refunds) $ 3,345 $ 4,334 See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.

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Progress Energy, Inc.

SUPPLEMENTAL DATA SCHEDULE Three Months Ended March 31, (Unaudited) 2003 2002 Operating Revenues (in thousands)

Utility Retal $ 1,344,132 $ 1,260,810 Wholesale 280,723 194,945 Unbifled (31.673) (3,259)

Miscellaneous revenue 60,705 45,427 Total Utility 1,653,887 1.497,923 Diversified business 362,117 289.379 Total Operating Revenues $ 2,016,004 S 1,787.302 Energy Sales - Utility Utility (millions of kWh)

Retail Residential 9,140 8,045 Commercial 5,425 5,246 Industrial 3,921 3,869 Other retail 999 946 Total Retail 19,485 18,106 Wholesale 5,895 4,311 Unbilled (425) (156)

Total Utility 24,955 22,261 Energy Supply - Utility (millions of kWh)

Generated - Steam 12,982 11,414 Nuclear 7,612 7.228 Hydro 254 139 Combustion turbines 1.732 1,585 Purchased 3,446 2,993 Total Energy Supply - (Company Share) 26,026 23,359 Detail of Income Taxes (in thousands)

Income tax expense (credit) - Current S 15,698 $ (47.445)

Deferred (2,608) 12.194 Investment tax credit (4,061) (5,435)

Total Income Tax Expense (Benefit) $ 9.029 $ (40,686) 10

Progress Energy, Inc.

-NOITES TO CON50IDATED EVZTl FINANCIAL STIEMENI

1. ORGANIZATION AND BASIS OF PRESENTATION A. Organization

-- Progress Energyi nc. (Progress. Energy or the Company) is a registered holding company under the Public Utility-Holding Company Act o 135 (PUHC'A), as amended. Both the Company and its'subsidiaries are ubject to the

--regulatory provisions of PUHCA. Effective Januar-y 1 2003, Carolina Power & Light Company, Florida Power Corporation and Progress Ventures, Inc. (PVD began doing business under the names Progress Energy Carolirnas,

- ' ~Inc.,'Progress Energ .-Forida, Inc. and Progress Energy-Ventures, Ic. -resvectivwly. The legal names of these entities have not changed, and there:was no restructuring of any kind related to the name change.Te curret corporate and business unit tructure remains unchanged.

Through its wholly owned subsidiaries, Progress Energy Carolinas, Inc. (PEC) and Progress Energy Florida, Inc.

(PEF), the Company is engaged in the generation, purchase, transmission, distribution and sale of electricity primarily in portions of North Carolina, South Carolina and Florida. The Progress Ventures business unit consists of the Fuels and Competitive Commercial Operations (CCO) operating segments. The Fuels operating segment includes natural gas drilling and production. coal mining and synthetic fuels production. The CCO operating segment includes nonregulated generation and energy marketing and limited trading activities. Through other business units. the Company engages in other nonregulated business areas, including energy management and related services, rail services and telecommunications. Progress Energy's legal structure is not currently aligned with the functional management and fancial 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 These financial statements have been prepared in accordance ith accounting principles generally accepted in the Unfted States of Aerica (GAAP) for -interim fancial information and with the instructions to Form I0-Q and Regulation S-X. Accordingly, they do not include all of the 'information and footnotes required by GAAP for complete financial statements. Because the accompanying consolidated interim financial statements do not include all of the information and footnotes required by generally accepted accounting principles, they should be read in conjunction with the audited financial statements for the period ended December 31, 2002 and notes thereto included in Progress Energy's Form 10-K for the year ended December 3, 2002.

The amounts included in the consolidated interim financial statements are unaudited but. in the opinion of management, reflect all adjustments necessary to fairly present the Company's financial position and results of operations for the interim periods. Due to seasonal weather variations and the timing of outages of electric generating units, especially nuclear-fueled units, the results of operations for interim periods are not necessarily indicative of amounts expected for the entire year. Certain amounts for 2002 have been reclassified to conform to the 2003 presentation.

In preparing 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 financial statements and amounts of revenues and expenses reflected during the reporting period. Actual results could differ from those estimates.

2. ACOUIISMONS A. Acquisition of Natural Gas Reserves During the first quarter of 2003, Progress Fuels Corporation, a wholly owned subsidiary of Progress Energy, entered into three independent transactions to acquire approximately 162 natural gas-producing wells with proven reserves of approximately 195 billion cubic feet cl from Republic Energy, Inc. and two other privately-owned companies, all headquartered in Texas. The primary assets in the acquisition have been contributed to Progress Fuels North Texas 11

Gas, LP., a wholly owned subsidiary of Progress Fuels Corporation. The total cash purchase price for the transactions was $148 million.

B. Wholesale Energy Contract Acquisition On March 20, 2003. PVI entered into a definitive agreement with Williams Energy Marketing and Trading, a subsidiary of The Williams Companies, Inc., to acquire a long-terr fll-requirements power supply agreement at fixed prices with Jackson Electric Membership Corp. (Jackson), located in Jefterson. Georgia. The agreement calls for a $188 million cash payment to Williams Energy Marketing and'Trading iiexchange for assignment of the Jackson supply agreement. The power supply agreement terminates in 2015, vwith a first refusal option to extend for five years. The agreement includes the use of 640 negawatts (MW) of cpntracted Georgia System generation comprised of nuclear, coal, gas and pumped-storage hydro resources. PVI expects to supplement the acquired resources with its own intermediate and peaking assets in Georgia to serve Jackson'-s forecasted 1,100 MW peak demand in 2005 growing to a forecasted 1.700 MW demand by 2015. The transaction is eXpected to close iri the second quarter of 2003, subject to customary closing conditions.

3. DVESTUS A. NCNG Divestiture On October 16, 2002, the Company announced the Board of Directors' approval to sell 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., for approximately $400 million in net proceeds. The sale is expected to close during the summer of 2003 and must be approved by the NCUC and federal regulatory agencies.

The accompanying consolidated interim 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 $3.7 million and $4.0 million for the three months ended March 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 upon classification of the assets as discontinted operations. After-tax depreciation expense recorded by NCNG during the first quarter of 2bO2 was $2.9 million. The'asset group, including goodwill, has been recorded at fair value less cost to sell, resulting in an estimated loss on disposal of approximately $29.4 million, which was recorded in the fourth quarter of 2002 until the disposition is complete and the actual loss can be determined. Results of discontinued operations for the three months ended March 3 1, were as follows:

(in thousands) 2003 2002 Revenues $ 154,226 $ 86,115 Earnings before income taxes S 18,483 $ 14,035 Income tax expense 7,193 5,570 Net earnings from discontinued operations $ 11,290 $ 8.465 The major balance sheet classes included in assets and liabilities of discontinued operations in the Consolidated Balance Sheets are as follows:

March 31, December 31, (in thousands) 2003 2002 Utility plant, net $ 401,035 $ 398,931 Current assets 75,338 72,821 Deferred debits and other assets 18,112 18,677 Assets of discontinued operations $ 494,485 $ 490,429 Current liabUities $ 68,185 $ 76,372 Deferred credits and other liabilities 49,286 48,395 Liabilities of discontinued operations $ 117,471 S 124,767 12

The Company's equity investment in ENCNG of $7:7 million as of March 31, 2003 and December 31, 2002 is included in miscellaneous other property and investments in the 'Consolidated Balance Sheets.

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B. Railcar Ltd. Divestiture In December 2002, the Progress Energy Board of Directors adopted a resolution to sell the assets of Railcar Ltd., a leasing subsidiary included in the Rail Services segment. A series of sales transactions is expected to take place throughout 2003. An estimated impairment on assets held for sale was recognized in December 2002 for the write-down of the assets to be sold to fair value less the costs to sell.

The assets of Railcar Ltd. have been grouped as assets held for sale and are included in other current assets on the Consolidated Balance Sheets as of March 31, 2003. The assets are recorded at $23.8 million and $23.6 million as of March 31, 2003 and December 31, 2002, respectively.

On March 12, 2003, the Company signed. a letter of intent to sell the majority of Railcar Ltd. assets to The Andersons, Inc. The majority of the proceeds from the sale will be used by the Company to pay off certain Railcar Ltd. off balance sheet lease obligations for railcars that will be transferred to The Andersons, Inc. as part of the sales transaction. The transaction is subject to various closing conditions including financing, due diligence and the completion of a definitive purchase agreement.

4. FINANCLL INFORMATION BY BUSINESS SEGMENT The Company currently has the following business segments: Progress Energy Carolinas Electric (PEC Electric),

Progress Energy Florida (PEF). Fuels. Competitive Commercial Operations (CCO), Rail Services (Rail) and Other Businesses (Other). Prior to 2003, Fuels and CCO were reported together as the Progress Ventures business segment and corporate costs were included in the Other segment. These reportable segment changes eflect the current management structure. Additionally, earnings from wholesale customers of the regulated plants have previously been reported in both the regulated utilities' results and the results of Progress Ventures. With the realignment of the reportable business segments, these results are now included in each of the respective regulated utilities' results only. The prior period has been restated to reflect these changes.

The PEC Electric and PEF segments are engaged in the generation, purchase, transmission, distribution and sale of electric energy primarily in portions of North Carolina, South Carolina and Florida. These electric operations are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC). the North Carolina Utility Commission (NCUC), the Public Service Commission of South Carolina (SCPSC), the Florida Public Service Commission (FPSC) and the U.S. Nuclear Regulatory Commission (NRC).

Fuels' operations include natural gas drilling and production, coal mining and terminals and the production of synthetic fuels.

CCO operations include nonregulated electric generation operations and energy marketing and limited trading activities on behalf of its nonregulated plants. The increase in revenue and income from continuing operations in 2003 is primarily due to a tolling agreement termination payment from Dynegy.

Rail segment 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.

The Other segment primarily includes the operations of Progress Telecommunications Corporation (Progress Telecom) and nonregulated subsidiaries that do not meet the disclosure requirements of SFAS No. 131. Disclosures about Segments of an Enterprise and Related Information.'

The Company's corporate operations include the operations of the holding company, the Progress Energy Service Company, LLC (Service Company) and intercompany elimination transactions. The operating business segments combined with the corporate operations represent the total continuing operations of the Company. In prior periods, Corporate was reported as a component of the Other segment.

The discontinued operations related to the sale of NCNG are not included as an operating segment.

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The following summarizes the revenues, income from continuing operations and assets for the business segments, corporate and total Progress Energy. The 2002 information has been restated to align with the 2003 segment structure.

Revenues Income from Continuin

.g Unaffiliate Operation (in thousands) d Intersegment Total s Assets FOR THE THREE MONTHS ENDED MARCH 31. 2003

-$ 925.470 S 134.577 S 9,616,357 PEC Electric 925,470 PEF - 728,417 728,417 70,757 5.716,828 Fuels 129,874 117,396 247,270 26,565 1,151,361 cCO 37,152 37,152 8,526 1,504,197 Rafl 177.687 122 177.809 (3.396) 504,533 Other 17.352 17.352 335 50.091 Corporate 52 (117,518) (117,466) (40,498) 4,135.040 S 0 S 2,016,004 S 196.866 S Consolidated totals 2,016,004 22.678.407 FOR THE THREE MONTHS ENDED MARCH 31. 2002 S S S 811,482 S 85,533 PEC Electric 811,482 9,092,069 PEF 686,441 - 686,441 57,743 5,039,094 Fuels 102,312 133.976 236,288 41,596 743,686 ccO 9,046 - 9,046 (2,112) 1,157,066 Rail 154,469 496 154,965 (701) 596,765 Other 23,552 - 23,552 (4,938) 618,796 Corporate (134,472) (134.472) (53,059) 3,858,691 S 0 $ 1,787,302 S 124,062 S Consolidated totals 1,787,302 21,106,167

5. IMPACT OF NEW ACCOUNTING STANDARDS SFAS No. 148. "Accounting for Stock-Based Compensation -

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." the estimated fair value of the Company's stock options is amortized to expense over the options' vesting period. The Company's information related to the pro forma impact on earnings and earnings per share assuming stock options were expensed for the three months ended March 31 is as follows:

(in thousands except per share data) 2003 2002 Net income, as reported $ 208,156 $ 132,527 Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects 2,579 1,792 Pro forma net income $ 205,577 $ 130,735 Basic and fully diluted earnings per share As reported $0.89 $0.62 Pro forma $0.88 $0.61 In April 2003, the Financial Accounting Standards Board (FASB) approved certain decisions on its stock-based compensation project. Some of the key decisions reached by the FASB were that stock-based compensation should be recognized in the income statement as an expense and that the expense should be measured as of the grant date at fair value. A significant issue yet to be addressed by the FASB is the determination of the appropriate fair value 15

measure. The FASB has not yet scheduled when it will deliberate additional issues in this project; however, the FASB plans to issue an exposure draft in 2003 that could become effective in 2004.

SFAS No. 149. Amendment of Statement 133 on Denvative Instruments and HedgingActivities" In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities.' The statement amends and clarifies SFAS No. 133 on accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. The new guidance incorporates decisions made as part of the Derivatives Implementation Group (DIG) process, as well as decisions regarding implementation issues raised in relation to the application of the definition of a derivative. SFAS No. 149 is generally effective for contracts entered into or modified after June 30, 2003. The Company is currently evaluating what effects, if any, this statement will have on its results of operations and financial position.

FIN No. 45. Guarantor'sAccounting and DisclosureRequirements for Guarantees. IncludingIndirect Guarantees of Indebtedness of Others' In November 2002, the FASB issued Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an Interpretation of FASB Statements No. 5, 57 and 107 and Rescission of FASB Interpretation No. 34" (FIN No. 45). This interpretation clarifies the disclosures to be made by a guarantor in its interim and annual financial statements about obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize. at the inception of certain guarantees, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The applicable disclosures required by FIN No. 45 have been made in Notes 12 and 15. The adoption of FIN No. 45 did not have a material effect on the Company's results of operations or financial condition.

FIN No. 46. Consolidationof Variable Interest Entities" In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities - an Interpretation of ARB No. 51" (FIN No. 46). This interpretation provides guidance related to identifying variable interest entities (previously known as special purpose entities or SPEs) and determining whether such entities should be consolidated. Certain disclosures are required if it is reasonably possible that a company will consolidate or disclose information about a variable interest entity when it initially applies FIN No. 46. This interpretation must be applied immediately to variable interest entities created or obtained after January 31, 2003. During the first quarter of 2003, the Company did not participate in the creation of, or obtain a new variable interest in, any variable interest entity. For those variable interest entities created or obtained on or before January 31, 2003, the Company must apply the provisions of FIN No. 46 in the third quarter of 2003.

The Company is currently evaluating what effects, if any, this interpretation will have on its results of operations and financial position. During this evaluation process, several arrangements through its Railcar Ltd. subsidiary have been identified to which this interpretation may apply. These arrangements include an agreement with Railcar Asset Financing Trust (RAFT), a receivables securitization trust, and seven synthetic leases. Because the Company expects to sell the majority of Railcar Ltd. during 2003 (See Note 3B) and divest of its interests in these arrangements, the application of FIN No. 46 is not expected to have a material impact with respect to these arrangements. If these interests are not divested as currently planned, the maximum cash obligations under these arrangements total approximately $54.3 million. However, management believes the maximum cash obligations would be significantly reduced based on the current fair values of the underlying assets related to these arrangements.

6. ASSET RETIREMENT OBLIGATIONS SFAS No. 143, "Accounting for Asset Retirement Obligations," provides accounting and disclosure requirements for retirement obligations associated with long-lived assets and was adopted by the Company effective January 1, 2003.

This statement requires that the present value of retirement costs for which the Company has a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period.

The liability is then accreted over time by applying an interest method of allocation to the liability. Cumulative accretion and accumulated depreciation were recognized for the time period from the date the liability would have been recognized had the provisions of this statement been in effect, to the date of adoption of this statement. For assets acquired through acquisition, the cumulative effect was based on the acquisition date.

Upon adoption of SFAS No. 143, the Company recorded asset retirement obligations (AROs) totaling $1,182.5 million for nuclear decommissioning of radiated plant at PEC and PEF. The Company used an expected cash flow approach 16

to measure these obligations. This amount includes accruals recorded prior to adoption totaling $775.2 million, which were previously recorded in accumulated depreciation. The related asset retirement costs, net of accumulated depreciation, recorded upon adoption totaled $367.5 million for regulated operations. The adoption of this statement had no impact on the income of the regulated entities, as the effects were offset by the establishment of a regulatory asset and a regulatory liability pursuant to SFAS No. 71, Accounting for the Effects of Certain Types of Regulation." A regulatory asset was recorded related to PEC in the amount of $271.1 million, representing the cumulative accretion and accumulated depreciation for the time period from the date the liability would have been recognized had the provisions of this statement been in effect to the date of adoption, less amounts previously recorded. A regulatory.liability wastecorded related-to PEF in the amount of $231.3 million, representing the amount by which previously recorded accruals-exceeded the cumulative accretion and accumulated depreciation for the time-period from the date the liability would have been recognized had the provisions of this statement been in effect at the date of the acquisition of the assets by Progress Energy to the date of adoption.

Funds set aside in the Company's nuclear decommissioning trust fund for the nuclear decommissioning liability totaled $788.8 million at March 31, 2003 and $796.8 million at December 31, 2002.

The Company also recorded AROs totaling $10.3 million for synthetic fuel operations of PVI and coal mine operations, synthetic fuel operations and gas production of Progress Fuels Corporation. The Company used an expected cash flow approach to measure these obligations. This amount includes accruals recorded prior to adoption totaling $4.6 million, which was previously recorded in other liabilities and deferred credits. The related asset retirement costs, net of accumulated depreciation, recorded upon adoption totaled $7.0 million for nonregulated operations. The cumulative effect of initial adoption of this statement related to nonregulated operations was $1.3 million of pre-tax income. The ongoing ipact on earnings related to accretion and depreciation was not significant for the three months ended March 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.

-The Company has identified but not recognized AROs related to electric transmission and distribution, gas distribution and telecommunications assets as the result of easements over property not owned by the Company.

These easements are generally perpetual and only require retirement action upon abandonment or cessation of use of the property for the specified purpose. The AROG liability is not estimable for such easements as the Company intends to utilize these properties indefinitely. In the event the Company decides to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time.

The utilities have previously recognized removal costs as a component of depreciation in accordance with regulatory treatment. As of March 31, 2003, the portion of such costs not representing AROs under SFAS No. 143 was $893.2 million for PEC, $931.4 million for PEF and $38.3 million for NCNG. The amounts for PEC and PEF are included in accumulated depreciation on the accompanying Consolidated Balance Sheets. The amount for NCNG is included as an offset to assets of discontinued operations on the accompanying Consolidated Balance Sheets. PEC and PEF have collected amounts for non-radiated areas at nuclear facilities, which do not represent asset retirement obligations. The amounts at March 31, 2003 were $63.8 million for PEC and $61.5 million for PEF, which are included in accumulated depreciation on the accompanying Consolidated Balance Sheets. PEF previously collected amounts for dismantlement of its fossil generation plants. As of March 31, 2003. this amounted to $142.0 million, which is included in accumulated depreciation on the accompanying Consolidated Balance Sheets. This collection was suspended pursuant to the rate case settlement discussed in Note 13A.

PEC filed a request with the NCUC requesting deferral of the difference between expense pursuant to SFAS No. 143 and expense as previously determined by the NCUC. The NCUC granted the deferral of the January 1, 2003 cumulative adjustment, but denied the deferral of the ongoing effects, citing a lack of information concerning the ongoing effects that would support the granting of such a deferral. The Company is in the process of providing additional information to the NCUC that it believes will demonstrate that deferral of the ongoing effects should also be allowed. Accordingly. for the quarter ended March 31, 2003, PEC deferred the ongoing effects. If PEC had not deferred the ongoing effects, pre-tax income for the quarter would have increased by approximately $5.7 million, which represents a decrease in non-ARO cost of removal expense, partially offset by an increase in decommissioning expense.

17

On April 8, 2003, the SCPSC approved a joint request by PEC, Duke Energy and South Carolina Electric and Gas Company for an accounting order to authorize the deferral of all cumulative and prospective effects related to the adoption of SFAS No. 143.

On January 23, 2003, the Staff of the FPSC issued a notice of proposed rule development to adopt provisions relating to accounting for asset retirement obligations under SFAS No. 143. Accompanying the notice was a draft rule presented by the Staff which adopts the provisions of SFAS No. 143 along with the requirement to record the difference between amounts-prescribed by the FPSC and those used in the application of SFAS No. 143 as regulatory assets or regulatory liabilities, which was accepted by all parties. 'The adoption and acceptance of this draft rule is subject to FPSC approval.

7. GOODWILL AND OTHER-INTANGIBLE ASSES SFAS No. 142, Goodwill and Other Intangible Assets." requires that goodwill be tested for impairment at least annually and more frequently when indicators of impairment exist. SFAS No. 142 requires a two-step fair value-based test. The first step, used to identify potential impairment, compares the fair value of the reporting unit with its carrying amount, including goodwill. The second step, used to measure the amount of the impairment loss if step one indicates a potential impairment, compares the implied fair value of the reporting unit goodwill with the carrying amount of the goodwill. This assessment could result in periodic impairment charges.

During 2002, the Company completed the acquisition of two electric generating projects, Walton County Power, LLC and Washington County Power, LLC. The acquisition resulted in goodwill of $64.1 million. The Company performed the annual goodwill impairment test in the first quarter of 2003. which indicated no impairment.

During 2002, the Company. also acquired Westchester Gas Company. The purchase price was finalized during the first quarter 2003 with all of the purchase price allocated to fixed assets including oil and gas properties. No goodwill was recorded.

The carrying amounts of goodwill at March 31, 2003, by reportable segment, are $1.9 billion, $1.7 billion, and $64.1 million for PEC Electric, PEF and CCO, respectively.

The gross carrying amount and accumulated amortization of the Company's intangible assets as of March 31. 2003 and December 31, 2002 are as follows:

March 31, 2003 December 31, 2002 (in thousands) Gross Carrying Accumulated Gross Carrying Accumulated Amount Amortization Amount Amortization Synthetic fuel intangibles $ 140,469 S(49.953) $ 140,469 $(45,189)

Power sale agreements 33,000 (7,265) 33,000 (5,593)

Other 42,005 (8,531) 40,968 (7,792)

Total S 215,474 $(65.749) S 214,437 $(58,574)

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 Service Code (the Code) in December 2007. The power sale agreements were recorded as part of the acquisition of generating assets from LG&E Energy Corp. and are amortized on a straight-line basis beginning with the in-service date of these plants through December 31, 2004. Other intangibles are primarily customer contracts and permits that are amortized over their respective lives.

Net intangible assets are included in other assets and deferred debits in the accompanying Consolidated Balance Sheets. Amortization expense recorded on intangible assets for the three months ended March 31, 2003 and 2002.

respectively, was $7.2 million and $8.1 million. The estimated amortization expense for intangible assets for 2003 through 2007, in millions, is approximately $33.5, $36.5, $20.3, $19.8 and $19.8. respectively.

8. COMPREHENSIVE INCOME 18

Comprehensive income for the three months ended March 31. 2003 and 2002 was $207.6 million and $136.8 million, respectively. Items of other comprehensive income for the three month periods consisted primarily of changes in the fair value of derivatives used to hedge cash flows related to interest on long-term debt and gas sales.

9. FINANCING ACTIVITIES On February 21, 2003, PEF 'issued $425 million of First Mortgage Bonds, 4.80% Series, Due March 1, 2013 and $225 million of First Mortgage Bonds, 5.90% Series, Due March 1, 2033.

On March 1. 2003, $70 million of PEF First Mortgage Bonds, 6.125% Series, matured and were retired.

On March 24, 2003, PEF redeemed $150 million of First Mortgage Bonds, 8% Series, Due December 1, 2022 at 103.75%

of the principal amount of such bonds.'

On April 1, 2003, PEF entered into a new $200 million 364-day credit agreement and a new $200 million three-year credit agreement, replacing its prior credit facilities (which had been a $90 million 364-day facility and a $200 million five-year facility). The new PEF credit facilities contain a defined maximum total debt to total capital ratio of 65%; as of March 31, 2003 the calculated ratio was 50.9%. The new credit facilities also contain a requirement that the ratio of EBITDA, as defined in the facilities, to interest expense to be at least 3 to 1; as of March 31, 2003 the calculated ratio was 8.7 to 1.

Also on April , 2003, PEC reduced the size of its existing 364-day credit facility from $285 million to $165 million. The other terms of this facility were not changed. PEC's $285 million three-year credit agreement entered into in July 2002 remains in place, for total facilities of $450 million.

On April 25, 2003, PEC announced the redemption of $150 million of First Mortgage Bonds, 7.5% Series, Due March 1, 2023 at 103.22% of the principal amount of such bonds. The date of the redemption will be May 27, 2003; PEC will fund the redemption through commercial paper.

In March 2003, Progress Genco Ventures, LLC (Genco) a wholly owned subsidiary of PVI, terminated its $50 million working capital credit facility. The remaining $260 million of Genco's credit facility was not changed.

The Company issued approximately 1.8 million shares representing approximately $74 million in proceeds from its Dividend Reinvestment and Stock Purchase Plan and its employee benefit plans during the three months ended March 31, 2003.

10. RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS Progress Energy and its subsidiaries are exposed to various risks related to changes in market conditions. The Company has a risk management committee that is chaired by the Chief Financial Officer and includes senior executives from various business groups. The risk management committee is responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries.

The Company manages its market risk in accordance with its established risk management policies, which may include entering into various derivative transactions.

Progress Energy uses interest rate derivative instruments to adjust the fixed and variable rate debt components of its debt portfolio and to hedge interest rates with regard to future fixed rate debt issuances. Treasury rate lock agreements were terminated in conjunction with the pricing of the PEF First Mortgage Bonds in February 2003. The loss on the agreements was deferred and is being amortized over the life of the bonds as these agreements had been designated as cash flow hedges for accounting purposes.

Progress Energy currently has $950 million of fixed rate debt swapped to floating rate debt by executing interest rate derivative agreements. Under terms of these swap rate agreements, Progress Energy will receive a fixed rate and will pay a floating rate based on 3-month LIBOR. These agreements expire in March of 2006, April 2007 and October 2008.

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In March and April of 2003, PEC entered into treasury rate locks to hedge its exposure to interest rates with regard to a future issuance of debt. These agreements have a computational period of ten years and are designated as cash flow hedges for accounting purposes. The agreements have a total notional amount of $35 million.

Progress Fuels Corporation periodically enters into derivative instruments to hedge its exposure to price fluctuations on natural gas sales. As of March 31, 2003, Progress Fuels Corporation had approximately 22.6 Bcf of cash flow hedges in place for its natural gas production. These positions span the remainder of 2003 and extend through December 2004. These instruments did not have a material impact on the Company's consolidated financial position or results of operations.

Genco has a series of interest rate. collars to hedge floating rate exposure associated with the construction credit facility. These collars hedge 75% of the 4rawn facility balance through March of 2007.

The notional amounts of the above contracts are not exchanged and do not represent exposure to credit loss. In the event of default by a counterparty, the risk in the transaction is the cost of replacing the agreements at current market rates. Progress Energy only enters into derivative agreements with banks with credit ratings of single A or better.

In connection with the January 2003 FASB Emerging Issues Task Force (EITF) meeting, the FASB was requested to reconsider an interpretation of SFAS No. 133. The interpretation, which is contained in the Derivatives Implementation Group's C II guidance, relates to the pricing of contracts that include broad market indices (e.g., CP).

In particular, that guidance discusses 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 in a defined accounting term, and may not, in all cases, indicate whether the contract would be normal' from an operating entity viewpoint). In April 2003, the FASB issued tentative superceding guidance (DIG Issue C20) on this issue that is expected to be finalized in the second or third quarter of 2003.

PEC has determined that it has one existing normal' contract that could be affected by this revised guidance, and PEC is in the process of evaluating the revised guidance to determine if that contract will be required to be recorded at fair value if the revised guidance is approved in its present form.

11. EARNINGS PER COMMON SHARE Restricted stock awards and stock options did not have a significant dilutive effect on earnings per share.

A reconciliation of the weighted-average number of common shares outstanding for basic and dilutive earnings per share purposes is as follows (in thousands):

Three Months Ended March 31, March 31, 2003 2002 Weighted-average common shares - basic 233,438 212,979 Restricted stock awards 931 646 Stock options - 119 Weighted-average shares - fully dilutive 234,369 213,744

12. FPC-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURMES OF A SUBSIDIARY HOLDING SOLELY FPC GUARANTEED NOTES In April 1999, FPC Capital I (the Trust), an indirect wholly owned subsidiary of FPC, issued 12 million shares of $25 par cumulative FPC-obligated mandatorily redeemable preferred securities (Preferred Securities) due 2039, with an aggregate liquidation value of $300 million and an annual distribution rate of 7.10%. Currently, all 12 million shares of the Preferred Securities that were issued are outstanding. Concurrent with the issuance of the Preferred Securities, the Trust issued to Florida Progress Funding Corporation (Funding Corp.) all of the common securities of the Trust (371,135 shares) for $9.3 million. Funding Corp. is a direct wholly owned subsidiary of FPC.

The existence of the Trust is for the sole purpose of issuing the Preferred Securities and the common securities and using the proceeds thereof to purchase from Funding Corp. its 7.10% Junior Subordinated Deferrable nterest Notes (subordinated notes) due 2039, for a principal amount of $309.3 million. The subordinated notes and the Notes 20

Guarantee (as discussed below) are the sole assets of the Trust. Funding Corp.'s proceeds from the sale of the subordinated notes were advanced to Progress Capital and used for general corporate purposes including the repayment of a portion of certain outstanding short-term bank loans and commercial paper.

FPC has fully and unconditionally guaranteed the obligations of Funding Corp. under the subordinated notes (the Notes Guarantee). In addition, FPC has guaranteed the payment of all distributions required to be made by the Trust, but only to the extent that the Trust has funds available for such distributions (Preferred Securities Guarantee). The Preferred Securities Guarantee, considered together with the Notes Guarantee, constitutes a full and unconditional guarantee by FPC of the Trust's obligations under the Preferred Securities.

The subordinated notes may be. redeemed at the option of Funding Corp. beginning in 2004 at par value plus accrued interest through the redemption date. The proceeds of any redemption of the subordinated notes will be used by the Trust to redeem proportional amounts of the Preferred Securities and common securities in accordance with their terms. Upon liquidation or dissolution of Funding Corp., holders of the Preferred Securities-would be entitled to the liquidation preference of $25 per share plus all accrued and unpaid dividends thereon to the date of payment.

These Preferred Securities are classified as long-term debt on the Company's Consolidated Balance Sheets.

13. REGULATORY MATTERS A. Retail Rate Matters In conjunction with the acquisition of NCNG, PEC agreed to cap base retail electric rates in North Carolina and South Carolina through December 2004. The cap on base retail electric rates in South Carolina was extended to December 2005 in conjunction with regulatory approval to form a holding company. NCNG also agreed to cap its North Carolina margin rates for gas sales and transportation services, with limited exceptions, through November 1, 2003. On May 16, 2002, NCNG filed a request to increase its margin rates and rebalance its rates with the NCUC, requesting an annual rate increase of $4.1 million to recover costs associated with specific system improvements. On September 23, 2002, the NCUC issued its order approving the $4.1 million rate increase. The rate increase was effective October 1, 2002. NCNG filed a general rate case with the NCUC on March 31, 2003. NCNG anticipates that new rates, if approved, will go into effect in November 2003, after the terms of the joint stipulation agreement expire.

On March 27, 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 on April 23, 2002. The Agreement provides that PEF will operate under a Revenue Sharing Incentive Plan (the Plan) through 2005 and thereafter until terminated by the FPSC.

The Plan establishes annual revenue caps and sharing thresholds. The Plan provides that all retail base revenues between an established threshold and cap will be shared - a 2/3 share to be refunded to PEF's retail customers, and a 1/3 share to be received by PEF's shareholders. All retail base rate revenues above the retail base rate revenue caps established for each year will be refunded 100% 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 rate revenue sharing threshold amounts for 2003 are $ 1.333 billion and will increase $37 million each year thereafter. The retail base revenue cap for 2003 is $1.393 billion and will increase $37 million each year thereafter. As of December 31, 2002, $4.7 million was accrued and was refunded to customers in March 2003. On February 24, 2003, the parties to the Agreement filed a motion seeking an order from the FPSC to enforce the Agreement. In this motion, the parties dispute PEF's calculation of retail revenue subject to refund and contend that the refund should be approximately $23 million. This issue will be addressed by the FPSC in the near future. PEF cannot predict the outcome of this matter.

On March 4, 2003, the FPSC approved PEF's petition to increase its fuel factors due to continuing increases in oil and natural gas commodity prices. The crisis in the Middle East along with the Venezuelan oil workers' strike have put upward pressure on commodity prices that was not anticipated by PEF when fuel factors for 2003 were approved by the FPSC in November 2002. New rates became effective on March 28, 2003.

B. Regional Transmission Organizations In early 2000, the FERC issued Order 2000 regarding regional transmission organizations fZTOs). This Order set minimum characteristics and functions that RTOs must meet, including independent transmission service. As a result 21

of Order 2000, PEF, along with Florida Power & Light Company and Tampa Electric Company, filed with the FERC, in October 2000, an application for approval of a GridFlorida RTO. In March 2001, the FERC issued an order provisionally approving GridFlorida. PEC, along with Duke Energy Corporation and South Carolina Electric & Gas Company, filed with the FERC. for approval of a GridSouth RTO. On July 12, 2001, the FERC issued an order provisionally approving GridSouth. However, in July 2001, FERC issued orders recommending that companies in the Southeast engage in a mediation to develop a plan for a single RTO for the Southeast. PEF and PEC participated in the mediation. The FERC has not issued an order specifically on this mediation. In July 2002, the FERC issued its Notice of Proposed Rulemaking in Docket No. RMOI-12-000, Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). If adopted as proposed, the rules set forth in the SMD NOPR would materially alter the manner in which transmission and generation services are provided and paid for. PEF and PEC, as subsidiaries of Progress Energy, filed comments on November 15, 2002 and supplement comments-on January- 0, .2003. On;Aprir 28, 2003, the FERC released a White Paper on the Wholesale-Market Platform. The White Paper provides an overview ofwhat the FERC currently intends to include in a final rule in the SMD NOPR docket. The White Paper retains the fundamental and most protested aspects of SMD NOPR.

including mandatory RTOs and the FERC's assertion of jurisdiction over certain aspects of retail service. PEF and PEC, as subsidiaries of Progress Energy, plan to file comments on the White Paper. The FERC has also indicated that it expects to issue final rules during the summer 2003. The Company cannot predict the outcome of these matters or the effect that they may have on the GridFlorida and GridSouth proceedings currently ongoing before the FERC. The Company has $29.4 million and an insignificant amount invested in GridSouth and GridFlorida. respectively, at March 31, 2003. It is unknown what impact the future proceedings will have on the Company's earnings, revenues or prices.

On October 15, 2002, the FPSC abated its proceedings regarding its review of the proposed GridFlorida RTO. The FPSC action to abate the proceedings came in response to the Florida Office at Public Counsel's appeal before the State Supreme Court requesting review of the FPSC's order approving the transfer of operational control of electric transmission assets to an RTO under the jurisdiction of the FERC. Oral argument before the Florida Supreme Court occurred on May 6. 2003. It is unknown what the outcome of this appeal will be at this time. 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 prices.

14. OTHER INCOME AND OTHER EXPENSE Other income and expense includes interest income, gain on the sale of investments, impairment of investments and other income and expense items as discussed below. The components of other, net as shown on the Consolidated Statements of Income for the three months ended March 31, 2003 and 2002 are as follows:

(in thousands) 2003 2002 Other income Net financial trading loss $ (2,698) $ (2,541)

Net energy purchased for resale 1,525 62 Nonregulated energy and delivery services income 5,590 6,598 Contingent value obligation unrealized gain 1,677 11.342 Investment gains 370 969 AFUDC equity 1,879 2,244 Other 4.576 597 Total other income $ 12,919 $ 19.271 Other expense Nonregulated energy and delivery services expenses 4,217 3,138 Donations 3,490 5,343 Other 7,662 4,732 Total other expense $ 15,369 $ 13,213 Other, net $ (2,450) $ 6,058 Net financial trading loss represents non-asset-backed trades of electricity and gas. Net energy purchased for resale represents electricity purchased for sale to a third party. 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.

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15. COMMITMENTS AND CONTINGENCIES Contingencies and significant changes to the commitments discussed in Note 24 of the financial statements included in the Company's 2002 Annual Report on Form 10-K are described below.

Commitments Guarantees As a part of normal business, Progress Energy and certain subsidiaries enter into various agreements providing financial or performance assessments to third parties. Such agreements include guarantees, standby letters of credit and surety bonds. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended commercial purposes.

At March 31, 2003, outstanding guarantees are summarized as follows:

(inmillions)

Guarantees supporting nonregulated portfolio expansion and energy marketing and trading activities $ 331.6 Guarantees supporting nuclear decommissioning 276.0 Standby letters of credit 48.2 Surety bonds 104.7 Other guarantees 23.4 Total $ 783.9 Each of these guarantees is discussed more fully below.

Guarantees Supporting Nonregulated Portfolio Expansion and Energy Marketing and Trading Activities Progress Energy has issued approximately $319.6 million of guarantees on behalf of PVI and its subsidiaries for obligations under power purchase agreements, tolling agreements, gas agreements, construction agreements and trading operations. In addition, PVI issued a $12.0 million guarantee related to expansion of its nonregulated generation portfolio, which ensures performance under generation construction and operating agreements.

Approximately $74.4 million of the $319.6 million of guarantees issued by Progress Energy relate to certain guarantee agreements issued to support obligations related to PVI's expansion of its nonregulated generation portfolio. No new guarantees of this type were issued during the quarter. The remaining $245.2 million of these commitments issued by Progress Energy are guarantees issued to support PVI's energy marketing and trading functions.

Approximately $23.0 million of these guarantees were issued during the quarter. The majority of the marketing and trading contracts supported by the guarantees contain language regarding downgrade events, ratings triggers, monthly netting of exposure and/or payments and offset provisions in the event of a default. Based upon the amount of trading positions outstanding at March 31, 2003, if the Company's ratings were to decline below investment grade, the Company would have to deposit cash or provide letters of credit or other cash collateral of approximately $14.7 million for the benefit of the Company's counterparties.

Guarantees Supporting Nuclear Decommissioning In 2003, PEC determined that its external funding levels did not fully meet the nuclear decommissioning financial assurance levels required by the NRC. Therefore, PEC met the financial assurance requirements by obtaining a parent company guarantee.

Standby Letters of Credit The Company has issued standby letters of credit to financial institutions for the benefit of third parties that have extended credit to the Company and certain subsidiaries. These letters of credit have been issued primarily for the 23

purpose of supporting payments of trade payables, securing performance under contracts and lease obligations and self-insurance for workers' compensation. If a subsidiary does not pay amounts when due under a covered contract, the counterparty may present its claim for payment to the financial institution, which will in turn request payment from the Company. Any amounts owed by the Company's subsidiaries are reflected in the accompanying Consolidated Balance Sheets.

Surety Bonds At March 31. 2003, the Company had $104.7 million in surety bonds purchased primarily for purposes such as providing workers' compensation coverage, obtaining licenses, permits and rights-of-way and project performance.

To the extent liabilities are incurred as a result of the activities covered by the surety bonds, such liabilities are included in the accompanying Consolidated Balance-Sheets.

Other Guarantees The Company has other guarantees outstanding related primarily to prompt performance payments, lease obligations and other payments subject to contingencies.

On March 20, 2003, PVI entered into a definitive agreement with Williams Energy Marketing and Trading, a subsidiary of The Williams Companies, Inc., to acquire a long-term full-requirements power supply agreement at fixed prices with Jackson. The power supply agreement includes a performance guarantee by Progress Energy. 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 (not to exceed $285 million) acceptable to Jackson. Because this transaction has not closed, the amount of this guarantee is not included in the table above.

As of March 31, 2003, management does not believe conditions are likely for performance under these agreements.

Contingencies Claims and uncertainties a) The Company is subject to federal, state and local regulations addressing hazardous and solid waste management, air and water quality and other environmental matters.

Hazardous and Solid Waste Management Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. The principal regulatory agency that is responsible for a specific former manufactured gas plant (MGP) site depends largely upon the state in which the site is located. There are several MGP sites to which both electric utilities and the gas utility have some connection. In this regard, both electric utilities and the gas utility and other potentially responsible parties are participating in investigating and, if necessary, remediating former MGP sites with several regulatory agencies, including, but not limited to, the U.S.

Environmental Protection Agency (EPA), the Florida Department of Environmental Protection (FDEP) and the North Carolina Department of Environment and Natural Resources, Division of Waste Management (DWM). In addition, the Company and its subsidiaries are periodically notified by regulators such as the EPA and various state agencies of their involvement or potential involvement in sites, other than MGP sites, that may require investigation and/or remediation. A discussion of these sites by legal entity follows.

PE There are 12 former MGP sites and 14 other sites associated with PEC that have required or are anticipated to require investigation and/or remediation costs. PEC received insurance proceeds to address costs associated with environmental liabilities related to its involvement with MGP sites. All eligible expenses related to these are charged against a specific fund containing these proceeds. As of March 31, 2003, approximately $5.7 million remains in this centralized fund with a related accrual of $5.7 million recorded for the associated expenses of environmental issues.

As PEC's share of costs for investigating and remediating these sites becomes known, the fund is assessed to determine if additional accruals will be required. PEC does not believe that it can provide an. estimate of the reasonably possible total remediation costs beyond what remains in the environmental insurance recovery fund.

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This is due to the fact that the sites are at different stages: investigation has not begun at 15 sites, investigation has begun but remediation cannot be estimated at seven sites and four sites have begun remediation. 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 potentially responsible parties. Once the environmental insurance recovery fund is depleted, PEC will accrue costs for the sites to the extent its liability is probable and the costs can be reasonably estimated. Presently, PEC cannot determine the total costs that may be incurred in connection with the remediation of all sites. According to current information, these future costs at the PEC sites are not expected to be material to the Company's financial condition or results of operations.

PEF There are two former MGP sites and 11 other active sites associated with PEF that have required or are anticipated to require investigation and/or remediation costs. As of March 31, 2003, P-EF has accrued approximately

$10.8 million, for probable and'reasonably estimable costs at these sites. PEF does not believe tat itcan provide an estimate of the reasonably possible total remediation costs beyond what is currently .accrued. In 2002, PEF filed a petition for annual recovery of approximately $4.0 million in environmental costs through the Environmental Cost Recovery Clause with the FPSC. PEF was successful with this filing and will recover costs through rates for investigation and remediation associated with transmission and distribution substations and transformers. As more activity occurs at these sites, PEF will assess the need to adjust the accruals. These accruals have been recorded on an undiscounted basis. PEF measures its liability for these sites based on available evidence including its experience in investigating and remediating environmentally impaired sites. This process often includes assessing and developing cost-sharing arrangements with other potentially responsible parties. Presently, PEF cannot determine the total costs that may be incurred in connection with the remediation of all sites. According to current information, these future costs at the PEF sites are not expected to be material to the Company's financial condition or results of operations.

NCNG There are five former MGP sites associated with NCNG that have or are anticipated to have investigation or remediation costs associated with them. As of March 31, 2003, NCNG has accrued approximately $2.3 million for probable and reasonably estimable remediation costs at these sites. These accruals have been recorded on an undiscounted basis. NCNG measures its liability for these sites based on available evidence including its experience in investigating and remediating environmentally impaired sites. This process often involves assessing and developing cost-sharing arrangements with other potentially responsible parties. NCNG does not believe it can provide an estimate of the reasonably possible total remediation costs beyond the accrual because two of the five sites associated with NCNG have not begun investigation activities. Therefore, NCNG cannot currently determine the total costs that may be incurred in connection with the investigation and/or remediation of all sites. Based upon current information, the Company does not expect the future costs at the NCNG sites to be material to the Company's financial condition or results of operations. In October 2002, the Company announced plans to sell NCNG to Piedmont Natural Gas Company, Inc. The Company will retain the environmental liability associated with the five former MGP sites.

Florida Progress Corporation In 2001, FPC sold its Inland Marine Transportation business operated by MEMCO Barge Line, Inc. to AEP Resources, Inc. FPC established an accrual to address indemnities and retained an environmental liability associated with the transaction. The balance in this accrual is $9.9 million at March 31, 2003.

FPC estimates that its maximum contractual liability to AEP Resources, Inc., associated with Inland Marine Transportation is $60 million. This accrual has been determined on an undiscounted basis. FPC measures its liability for this site based on estimable and probable remediation scenarios. The Company believes that it is reasonably probable that additional costs, which cannot be currently estimated, may be incurred related to the environmental indemnification provision beyond the amount accrued. The Company cannot predict the outcome of this matter.

Certain historical waste sites exist that are being addressed voluntarily by Fuels. The Company cannot determine the total costs that may be incurred in connection with these sites. According to current information, these future costs are not expected to be material to the Company's financial condition or results of operations.

Rail Services is voluntarily addressing certain historical waste sites. The Company cannot determine the total costs that may be incurred in connection with these sites. According to current information, these future costs are not expected to be material to the Company's financial condition or results of operations.

PEC, PEF, Fuels and NCNG have filed claims with the Company's general liability insurance carriers to recover costs arising out of actual or potential environmental liabilities. Some claims have been settled and others are still pending.

25

While the Company cannot predict the outcome of these matters, the outcome is not expected to have a material effect on the consolidated financial position or results of operations.

The Company is also currently in the process of assessing potential costs and exposures at other environmentally impaired sites. As the assessments are developed and analyzed, the Company will accrue costs for the sites to the extent the costs are probable and can be reasonably estimated.

Air and Water Quality There has been and may be further proposed federal legislation requiring reductions in air emissions for nitrogen oxides, sulfur dioxide, carbon dioxide and mercury. Some of these proposals establish rationwide caps and emission rates over an extended period of time. This national multi-pollutant approach to air pollution control could in'volve significant capital costs which could be material to the Company's consolidated financial position or results of operations. Some companies may seek recovery of the related cost through rate adjustments or similar mechanisms.

Control equipment that will be installed on North Carolina fossil generating facilities as part of the North Carolina legislation discussed below may address some of the issues outlined above. However, the Company cannot predict the outcome of this matter.

The EPA is conducting an enforcement initiative related to a number of coal-fired utility power plants in an effort to determine whether modifications at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. Both PEC and PEF were asked to provide information to the EPA as part of this initiative and cooperated in providing the requested information. During the first quarter of 2003, PEC responded to a supplemental information request from the EPA. PEF has received a similar supplemental information request, and will respond to it in the setond quarter. 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, ranging from $1.0 billion to $1.4 billion. A utility that was not subject to a civil enforcement action settled its New Source Review issues with the EPA for $300 million. These settlement agreements have generally called for expenditures to be made over extended time periods, and some of the companies may seek recovery of the related cost through rate adjustments or similar mechanisms. The Company cannot predict the outcome of this matter.

In 1998, the EPA published a final rule addressing the regional transport of ozone. This rule is commonly known as the NOx SIP Call. The EPA's rule requires 23 jurisdictions, including North Carolina, South Carolina and Georgia, but not Florida, to further reduce nitrogen oxide emissions in order to attain pre-set state NOx emission levels by May 31.

2004. PEC is currently installing controls necessary to comply with the rule. Capital expenditures needed to meet these measures in North and South Carolina could reach approximately $370 million, which has not been adjusted for inflation. Increased operation and maintenance costs relating to the NOx SIP Call are not expected to be material to the Company's results of operations. Further controls are anticipated as electricity demand increases. The Company cannot predict the outcome of this matter.

In July 1997, the EPA issued final regulations establishing a new eight-hour ozone standard. In October 1999, the District of Columbia Circuit Court of Appeals ruled against the EPA with regard to the federal eight-hour ozone standard. The U.S. Supreme Court has upheld, in part, the District of Columbia Circuit Court of Appeals' decision.

Designation of areas that do not attain the standard is proceeding, and further litigation and rulemaking on this and other aspects of the standard are anticipated. North Carolina adopted the federal eight-hour ozone standard and Is proceeding with the implementation process. North Carolina has promulgated final regulations, which will require PEC to install nitrogen oxide controls under the state's eight-hour standard. The costs of those controls are included in the $370 million cost estimate set forth above. However, further technical analysis and rulemaking may result in a requirement for additional controls at some units. The Company cannot predict the outcome of this matter.

The EPA published a final rule approving petitions under Section 126 of the Clean Air Act. This rule, as originally promulgated, required certain sources to make reductions in nitrogen oxide emissions by May 1, 2003. The final rule also includes a set of regulations that affect nitrogen oxide emissions from sources included in the petitions. The North Carolina coal-fired electric generating plants are included in these petitions. Acceptable state plans under the NOx SIP Call can be approved in lieu of the final rules the EPA approved as part of the Section 126 petitions. PEC.

other utilities, trade organizations and other states participated in litigation challenging the EPA's action. On May 15, 2001, the District of Columbia Circuit Court of Appeals ruled in favor of the EPA, which will require North Carolina to make reductions in nitrogen oxide emissions by May 1, 2003. However, the Court. in its May 15th decision, 26

rejected the EPA's methodology for estimating the future growth factors the EPA used in calculating the emissions limits for utilities. In August 2001, the Court granted a request by PEC and other utilities to delay the implementation of the Section 126 rule for electric generating units pending resolution by the EPA of the growth factor issue. The Court's order tolls the three-year compliance period (originally set to end on May 1, 2003) for electric generating units as of May 15, 2001. On April 30, 2002. the EPA published a final rule harmonizing the dates for the Section 126 rule and the NOx SIP Call. In addition, the EPA determined in this rule that the future growth factor estimation methodology was appropriate. The new compliance date for all affected sources is now May 31, 2004, rather than May 1, 2003. The EPA has approved North Carolina's NOx SIP Call rule and has formally proposed to rescind the Section 126 rule. This rulemaking is expected to become final during the summer of 2003. The Company expects a favorable outcome of this matter.

On June 20, 2002, legislation was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of nitrogen oxide and sulfur dioxide from coal-fired power plants. Progress Energy expects itscapital costs to meet these emission iargets will be approximately $813 million by 2013. PEC currently has approximately 5,100 MW of coal-fired generation capacity in North Carolina that is affected by this legislation. The legislation requires the emissions reductions to be completed in phases by 2013, and applies to each utility's total system rather than setting requirements for individual power plants. The legislation also freezes the utilities' base rates for five years unless there are extraordinary events beyond the control of the utilities or unless the utilities persistently earn a return substantially in excess of the rate of return established and found reasonable by the NCUC in the utilities' last general rate case. Further, the legislation allows the utilities to recover from their retail customers the projected capital costs during the first seven years of the ten-year compliance period beginning on January 1 2003. The utilities must recover at least 70% of their projected capital costs during the five-year rate freeze period. Pursuant to the new law, PEC entered into an agreement with the state of North Carolina to transfer to the state any future emissions allowances acquired as a result of compliance with the new law. The new law also requires the state to undertake a study of mercury and carbon dioxide emissions in North Carolina. Progress Energy cannot predict the future regulatory interpretation, implementation or impact of this new law. PEC has recorded $20 million of clean air amortization to date and clean air expenditures to date are $2.5 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. The United States has not adopted the Kyoto Protocol; however, a number of carbon dioxide emissions control proposals have been advanced in Congress and by the Bush administration. The Bush administration favors voluntary programs. Reductions in carbon dioxide emissions to the levels specified by the Kyoto Protocol and some legislative proposals could be materially adverse to Company financials and operations if associated costs cannot be recovered from customers. The Company favors the voluntary program approach recommended by the administration, and is evaluating options for the reduction, avoidance and sequestration of greenhouse gases. However, the Company cannot predict the outcome of this matter.

In 1997, the EPA's Mercury Study Report and Utility Report to Congress conveyed that mercury is not a risk to the average American and expressed uncertainty about whether reductions in mercury emissions from coal-fired power plants would reduce human exposure. Nevertheless, the EPA determined in 2000 that regulation of mercury emissions from coal-fired power plants was appropriate. Pursuant to a Court Order, the EPA is developing a Maximum Available Control Technology (MACT) standard, which is expected to become final in December 2004, with compliance in 2008. Achieving compliance with the MACT standard could be materially adverse to the Company's financial condition and results of operations. However, the Company cannot predict the outcome of this matter.

b) As required under the Nuclear Waste Policy Act of 1982, PEC and PEF each entered into a contract with the U.S.

Department of Energy (DOE) under which the DOE agreed to begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract.

In April 1995, the DOE issued a final interpretation that it did not have an unconditional obligation to take spent nuclear fuel by January 31, 1998. In Indiana & Michigan Power v. DOE, the Court of Appeals vacated the DOE's final interpretation and ruled that the DOE had an unconditional obligation to begin taking spent nuclear fuel. The Court did not specify a remedy because the DOE was not yet in default.

27

After the DOE failed to comply with the decision in Indiana & Michigan Power v. DOE a group of utilities petitioned the Court of Appeals in Northern States Power (NSP) v. DOE seeking an order requiring the DOE to begin taking spent nuclear fuel by January 31. 1998. The DOE took the position that their delay was unavoidable, and the DOE was excused from performance under the terms and conditions of the contract. The Court of Appeals found that the delay was not unavoidable, but did not order the DOE to begin taking spent nuclear fuel, stating that the utilities had a potentially adequate remedy by filing a claim for damages under the contract After the DOE failed to begin taking spent nuclear fuel by January 31, 1998, a group of utilities filed a motion with the Court of Appeals to enforce the mandate in NSP v. DOF Specifically, this group of utilities asked the Court to permit the utilities to escrow their waste fee payments, to order the DOE not to use the waste fund to pay damages to the utilities, and to order the DOE to establish a schedule for disposal of spent nuclear fuel. The Court denied this motion based primarily on the grounds that a review of the matter was premature, and that some of the requested remedies fell outside of the mandate in NSP v. DOE Subsequently, a number of utilities each filed an action for damages in the Federal Court of Claims. In a recent decision, the U.S. Circuit Court of Appeals (Federal Circuit) ruled that utilities may sue the DOE for damages in the Federal Court of Claims instead of having to file an administrative claim with the DOE. PEC and PEF are in the process of evaluating whether they should each file a similar action for damages.

On July 9, 2002, Congress passed an override resolution to Nevada's veto of DOE's proposal to locate a permanent underground nuclear waste storage facility at Yucca Mountain, Nevada. DOE plans to submit a license application for the Yucca Mountain facility by the end of 2004. PEC and PEF cannot predict the outcome of this matter.

With certain modifications, and additional approval by the NRC, PEC's spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on PEC's system through the expiration of the current operating licenses for all of PEC's nuclear generating units. Subsequent or prior to the expiration of these licenses, or any renewal of these licenses, dry storage or acquisition of new shipping casks may be necessary. PEC obtained approval from the NRC to use additional storage space at the Harris Plant in December 2000. PEF currently is storing spent nuclear fuel onsite in spent fuel pools. If PEF does not seek renewal of the Crystal River Nuclear Plant (CR3) operating license, CR3. will have sufficient storage capacity in place for fuel consumed through the end of the expiration of the license in 2016. If PEF extends the CR3 operating license, dry storage may be necessary.

c) Progress Energy, through its subsidiaries, produces synthetic fuel from coal fines. The production and sale of the synthetic fuel from these facilities qualifies for tax credits under Section 29 of the Code (Section 29) if certain requirements are satisfied, including a requirement that the synthetic fuel differs significantly in chemical composition from the coal used to produce such synthetic fuel. Any synthetic fuel tax credit amounts not utilized are carried forward indefinitely. All of Progress Energy's synthetic fuel facilities have received private letter rulings (PLRs) from the Internal Revenue Service (IRS) with respect to their synthetic fuel operations. These tax credits are subject to review by the IRS, 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.

One synthetic fuel entity, Colona Synfuel Limited Partnership, L.L.L.P. (Colona), from which the Company (and FPC prior to its acquisition by the Company) has been allocated approximately $258 million in tax credits to date, is being audited by the IRS. The audit of Colona was expected. The Company is audited regularly in the normal course of business, as are most similarly situated companies. In September 2002. all of Progress Energy's majority-owned synthetic fuel entities, including Colona, were accepted into the IRS Prefiling Agreement (PFA) program. The PFA program allows taxpayers to voluntarily accelerate the IRS exam process in order to seek resolution of specific issues. Either the Company or the IRS can withdraw from the program at any time, and issues not resolved through the program may proceed to the next level of the IRS exam process. While the ultimate outcome is uncertain, the Company believes that participation in the PFA program will likely shorten the tax exam process. In management's opinion, Progress Energy is complying with all the necessary requirements to be allowed such credits under Section 29 and believes it is likely, although it cannot provide certainty, that it will prevail if challenged by the IRS on any credits taken. The current Section 29 tax credit program expires in 2007.

d) The Company and its subsidiaries are involved in various litigation matters in the ordinary course of business, some of which involve claims for substantial amounts. Where appropriate, accruals have been made in accordance 28

with SFAS No. 5. Accounting for Contingencies,' to provide for such matters. The Company believes the final disposition of pending litigation would not have a material adverse effect on the Company's consolidated results of operations or financial position.

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CAROLINA POWER & LIGHT COMPANY d/b/a PROGRESS ENERGY CAROLINAS, INC.

CONSOLIDATED INTERIM FINANCIAL STATEMENTS March 31, 2003 CONSOLIDATED STATEMENTS OF INCOME Three Months Ended (Unaudited) March 31, (In thousands) 2003 - 2002 Operating Revenues Electric $ 925,470 $ 811,482 Diversified business 3,397 3,389 Total Operating Revenues 928,867 814,871 Operating Expenses Fuel used in electric generation 225,542 171,726 Purchased power 73,180 73,309 Operation and maintenance 189,875 193,436 Depreciation and amortization 138,797 141,386 Taxes other than on income 44,176 38,768 Diversified business 939 3,061 Total Operating Expenses 672,509 621,686 Operating Income 256,358 193,185 Other Income (Expense)

Interest income 1,367 1.666 Other, net (2,553) (2,973)

Total Other Expense (1,186) (1,307)

Interest Charges Interest charges 49,303 61,645 Allowance for borrowed funds used during construction (925) (3,094)

Total Interest Charges, Net 48,378 58,551 Income before Income Taxes 206,794 133,327 Income Tax Expense 71,733 48,208 Net Income $ 135,061 $ 8,119 Preferred Stock Dividend Requirement 741 741 Earnings for Common Stock $ 134,320 $ 84,378 See Notes to Progress Energy Carolinas, Inc. Consolidated Interim Financial Statements.

30

Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.

CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands) March 31, December 31, A---.- 'fnn onno Utility Plant Utility plant in service $ 12,954,849 $ 12,675,761 Accumulated depreciation (5,999,260) (6,356,933)

Utility plant in service, net 6,955,589 6,318,828 Held for future use 7,188 7,188 Construction work in progress 374,031 325,695 Nuclearfuel,netofamortization 182,253 176,622 Total Utility Plant, Not 7,519,061 6,828,333 Current Assets Cash and cash equivalents 13,454 18,284 Accounts receivable 322,638 301,178 Unbilled accounts receivable 120,417 151,352 Receivables from affiliated companies 26,527 36,870 Notes receivable from affiliated companies - 49,772 Taxes receivable - 5,890 Inventory 326,562 342,886 Deferred fuel cost 138,273 146,015 Prepayments and other current assets 84,654 94.658 Total Current Assets 1,032,525 1,146,905 Deferred Debits and Other Assets Regulatory assets 518,747 252,083 Nuclear decommissioning trust funds 421,159 423,293 Diversified business property, net 9,763 9,435 Miscellaneous other property and investments 213,123 209,657 Other assets and deferred debits 100,471 104,978 Total Deferred Debits and Other Assets 1,263,263 999.446 Total Assets $ 9,814,849 $ 8,974,684 Capitalization and Liabilities Capitalization Comrmon stock $ 3,122,281 S 3,089,115 Preferred stock - not subject to mandatory redemption 59,334 59,334 Long-term debt, net 2,898,985 3,048,466 Total Capitalization 6,080,600 6,196,915 Current Liabilities Current portion of long-term debt 150,000 Accounts payable 242,622 259,217 Payables to affiliated companies 101,615 98.572 Notes payable to affiliated companies 39,679 Taxes accrued 86,465 Interest accrued 47,385 58,791 Short-term obligations 221,975 437,750 Current portion of accumulated deferred income taxes 67,562 66,088 Other current liabilities 73,672 93,171 Total Current Liabilities 1,030,975 1,013,589 Deferred Credits and Other Liabilities Accumulated deferred income taxes 1,164,952 1,179,689 Accumulated deferred investment tax credits 155,757 158,308 Regulatory liabilities 67,536 7,774 Asset retirement obligations 892,422 Other liabilities and deferred credits 422.607 418.409 Total Deferred Credits and Other Liabilities 2,703,274 1,764.180 Commitments and Contingencies (Note 9)

Total Capitalization and Liabilities $ 9,814,849 S 8,974,684 See Notes to Progress Energy Carolinas, Inc. Consolidated Interim Financial Statements.

31

Carolina Power & Light Company d/bla Progress Energy Carolinas, Inc.

CONSOLIDATED STATEMENTS OF CASH FLOWS Three Months Ended (Unaudited) March 31, (in thousands) .

2003 2002 Operating Activities Net income $ 135,061 $ 85,119 Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization 164,008 167,980 Deferred income taxes (10,377) (12,891)

Investment tax credit (2,550) (3.496)

Deferred fuel credit 7,742 .112,063 Net (increase) decrease in accounts.receivable 19,818 (126,306)

Net (increase) decrease ininventories 16,324 (14,452)

Net (increase) decrease in prepayments and other current assets 5.469 (13,622)

Net increase (decrease) inaccounts payable 14,239 (78,351)

Net increase in other current liabilities 61,616 62,332 Other 28,124 32,962 Net Cash Provided by Operating Activities 439,474 111,338 Investing Activities Gross property additions (149,938) (176.230)

Nuclear fuel additions (29,592) (33.406)

Contributions to nuclear decommissioning trust (10,262) (10,225)

Diversified business property additions (181) (8,350)

Investments innon-utility activities (4,000) (4,480)

Net Cash Used in Investing Activities (193,973) (232,691)

Financing Activities Proceeds from issuance of long-term debt 46.507 Net increase (decrease) in short-term obligations (215,775) 243,930 Net increase in intercompany notes 89,450 107,507 Retirement of long-term debt (153) (49.697)

Dividends paid to parent (123,112) (131,000)

Dividends paid on preferred stock (741) (741)

Net Cash Provided by (Used in) Financing Activities (250,331) 216,506 Net Increase (Decrease) inCash and Cash Equivalents (4,830) 95,153 Cash and Cash Equivalents at Beginning of the Period 18,284 21,250 Cash and Cash Equivalents at End of the Period $ 13,454 $ 116.403 Supplemental Disclosures of Cash Flow Information Cash paid during the year - interest (net of amount capitalized) $ 58,305 $ 58,410 income taxes (net of refunds) $ 3,382 $ 31,307 Non-cash investing and financing activity

• In February 2002, Progress Energy Carolinas, Inc. transferred the Rowan Plant to Progress Ventures, Inc. The property and inventory transferred totaled approximately $245 million.

See Notes to Progress Energy Carolinas, Inc. Consolidated Interim Financial Statements.

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Carolina Power & Light Company db/a Progress Energy Carolinas, Inc.

NOTES TO CONSOLIDATED INTERN FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION A. Organization.

Progress Energy Carolinas, Inc. (PEC) is a public service corporation primarily engaged in the generation.

transmission, distribution and sale of electricity prinarily in portions of North Carolina and South Carolina. PEC is a wholly owned subsidiary of Progress Energy, Inc. (the Company or Progress Energy), which was formed as a result

-'of the rerganiatio ofCarolina PoWer &Light Company (CP&LYint6 a holding.company structure on June'19, 2000...'

All shares of common stock of CP&L were exchanged for an equal number of shares of CP&L Energy, Inc. On December 4, 2000, the Company changed its name from CP&L Energy, Inc. to Progress Energy, Inc. The Company is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA), as amended. Both the Company and its subsidiaries are subject to the regulatory provisions of PUHCA.

Effective January 1. 2003, CP&L began doing business under the assumed name Progress Energy Carolinas, Inc. The legal name has not changed and there was no restructuring of any kind related to the name change. The current corporate and business unit structure remains unchanged.

B. Basis of Presentation.

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q and Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. Because the accompanying consolidated interim financial statements do not include all of the information and footnotes required by generally accepted accounting principles, they should be read in conjunction with the audited financial statements for the period ended December 31, 2002 and notes thereto included in PEC's Form 10-K for the year ended December 31, 2002.

The amounts included in the consolidated interim financial statements are' unaudited but, in the opinion of management, reflect all adjustments necessary to fairly present PEC's financial position and results of operations for the interim periods. Due to seasonal weather variations and the timing of outages of electric generating units, especially nuclear-fueled units, the results of operations for interim periods are not necessarily indicative of amounts expected for the entire year. Certain amounts for 2002 have been reclassified to conform to the 2003 presentation, with no effect on previously reported net income or common stock equity.

In preparing 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 financial statements and amounts of revenues and expenses reflected during the reporting period. Actual results could differ from those estimates.

2. FINANCIAL INFORMATION BY BUSINESS SEGMENT PEC's operations consist primarily of the PEC Electric segment with no other material segments.

The financial information for the PEC Electric segment for the three months ended March 31, 2003 and 2002 is as follows:

Three Months Ended (in thousands) March 31, 2003 March 31, 2002 Revenues $ 925,470 $ 811,482 Segment income $ 134,577 $ 85,533 Total segment assets $ 9,616,357 $ 9,092,069

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The primary differences between the PEC Electric segment and PEC consolidated financial information relate to other non-electric operations and elimination entries.

3. IMPACT OF NEW ACCOUNTING STANDARDS SFAS No. 148. "Accounting for Stock-Based Compensation 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," the estimated fair value of the Company's stock options is amortized to expense over the options' vesting period. PEC's information related to the pro forma impact on earnings assuming stock options were expensed for the three months ended March 31 is as follows:

(in thousands) 2003 2002 Earnings for common stock, as reported $ 134,320 $ 84,378 Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects 1,073 759 Pro forma earnings for common stock $ 133,247 $ 83,619 In April 2003. the Financial Accounting Standards Board (FASB) approved certain decisions on its stock-based compensation project. Some of the key decisions reached by the FASB were that stock-based compensation should be recognized in the income statement as an expense and that the expense should be measured as of the grant date at fair value. A significant issue yet to be addressed by the FASB is the determination of the appropriate fair value measure. The FASB has not yet scheduled when it will deliberate additional issues in this project; however, the FASB plans to issue an exposure draft in 2Q03 that could become effective in 2004.

SFAS No. 149. Amendment of Statement 133 on Derivative Instruments and Hedging Activities" In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities.' The statement amends and clarifies SFAS No. 133 on accounting for derivative instruments. including certain derivative instruments embedded in other contracts, and for hedging activities. The new guidance incorporates decisions made as part of the Derivatives Implementation Group (DIG) process, as well as decisions regarding implementation issues raised in relation to the application of the definition of a derivative. SFAS No. 149 is generally effective for contracts entered into or modified after June 30, 2003. PEC is currently evaluating what effects, if any, this statement will have on its results of operations and financial position.

FINNo. 45. "Guarantor'sAccounting and DisclosureRequirements for Guarantees.Including Indirect Guarantees of Indebtedness of Others" In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an Interpretation of FASB Statements No. 5, 57 and 107 and Rescission of FASB Interpretation No. 34" (FIN No. 45). This interpretation clarifies the disclosures to be made by a guarantor in its interim and annual financial statements about obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of certain guarantees, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. See Note 9 for disclosures of current guarantees. The adoption of FIN No. 45 did not have a material effect on PEC's results of operations or financial position.

FIN No. 46. "Consolidationof Variable Interest Entities-In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities - an Interpretation of ARB No. 51" (FIN No. 46). This interpretation provides guidance related to identifying variable interest entities (previously known as special purpose entities or SPEs) and determining whether such entities should be consolidated. Certain disclosures are required when FIN No. 46 becomes effective if it is reasonably possible that a company will consolidate or disclose information about a variable interest entity when it initially applies FIN No. 46.

This interpretation must be applied immediately to variable interest entities created or obtained after January 31, 2003.

During the first quarter of 2003, PEC did not participate in the creation of, or obtain a new variable interest in, any variable interest entity. For those variable interest entities created or obtained on or before January 31, 2003, PEC must apply the provisions of FIN No. 46 in the third quarter of 2003. PEC is currently evaluating what effects, if any, this interpretation will have on its results of operations and financial position.

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4. ASSET RETIREMENT OBLIGATIONS SFAS No. 143, 'Accounting for Asset Retirement Obligations," provides accounting and disclosure requirements for retirement obligations associated with long-lived assets and was adopted by the Company effective January 1, 2003.

This statement requires that the present value of retirement costs for which PEC has a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The liability is then accreted over time by applying an interest method of allocation to the liability. Cumulative accretion and accumulated depreciation were recognized for the time period from the date the liability would have been recognized had the provisions of this statement been in effect, to the date of adoption of this statement.

Upon adoption of SFAS No. 143 PEG recorded asset retirement obligations (AROs) for nuclear decommissioning of radiated plant totaling $879.7 million. PEC used an expected cash-flow approach to measure these obligations. This amount includes accruals recorded prior to adoption toialing $491.3-million, which were previously recorded in accumulated depreciation. The related asset retirement costs, net of accumulated depreciation, recorded upon adoption totaled $117.3 million. The cumulative effect of adoption of this statement had no impact on the net income of PEC, as the effects were offset by the establishment of a regulatory asset in the amount of $271.1 million, pursuant to SFAS No. 71, 'Accounting for the Effects of Certain Types of Regulation." The regulatory asset represents the cumulative accretion and accumulated depreciation for the time period from the date the liability would have been recognized had the provisions of this statement been in effect to the date of adoption, less the amount previously recorded.

Funds set aside in PEC's nuclear decommissioning trust fund for the nuclear decommissioning liability totaled $421.2 million at March 31, 2003 and $423.3 million at December 31, 2002.

Pro forma net income has not been presented for prior years because the pro forma application of SFAS No. 143 to prior years would result in pro forma net income not materially different from the actual amounts reported.

PEC has identified but not recognized AROs related to electric transmission and distribution and telecommunications assets as the result of easements over property not owned by PEC. These easements are generally perpetual and only require retirement action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements as PEC intends to utilize these properties indefinitely. In the event PEC decides to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time, PEC has previously recognized removal costs as a component of depreciation in accordance with regulatory treatment. As of March 31, 2003, the portion of such costs not representing AROs under SFAS No. 143 was $893.2 million. This amount is included in accumulated depreciation on the accompanying Consolidated Balance Sheets.

PEC has collected amounts for non-radiated areas at nuclear facilities, which do not represent asset retirement obligations. These amounts totaled $63.8 million as of March 31, 2003, which is included in accumulated depreciation on the accompanying Consolidated Balance Sheets.

PEC filed a request with the North Carolina Utility Commission (NCUC) requesting deferral of the difference between expense pursuant to SFAS No. 143 and expense as previously determined by the NCUC. The NCUC granted the deferral of the January 1, 2003 cumulative adjustment, but denied the deferral of the ongoing effects, citing a lack of information concerning the ongoing effects that would support the granting of such a deferral. PEC is in the process of providing additional information to the NCUC that it believes will demonstrate that deferral of the ongoing effects should be allowed. Accordingly, for the quarter ended March 31, 2003, PEC deferred the ongoing effects. If PEC had not deferred the ongoing effects, pre-tax income for the quarter would have increased by approximately $5.7 million, which represents a decrease in non-ARO cost of removal expense, partially offset by an increase in decommissioning expense.

On April 8, 2003, the Public Service Commission of South Carolina (SCPSC) approved a joint request by PEC, Duke Energy and South Carolina Electric and Gas Company for an accounting order to authorize the deferral of all cumulative and prospective effects related to the adoption of SFAS No. 143.

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5. COMPREHENSIVE INCOME Comprehensive income for the three months ended March 31, 2003 and 2002 was $135.2 million and $88.5 million, respectively. Items of other comprehensive income for the three month periods consisted primarily of changes in fair value of derivatives used to hedge cash flows related to interest on long-term debt.

6. FINANCING ACTIVITIES On April 1 2003, PEC reduced the size of its existing 364-day credit facility from $285 million to $165 million. The other terms of this facility were not changed. PEC's $285 million three-year credit agreement entered into in July 2002 termains in place, for total facilities of $450 million.

On April 25, 2003, PEC announced the redemption of $150 million of First Mortgage Bonds, 7.5% Series, Due March 1, 2023 at 103.22% of the principal amount of such bonds. The date of the redemption will be May 27, 2003. PEC will fund the redemption through commercial paper.

7. RISK MANAGEMENT ACTITIES AND DERIVATIVE TRANSACTIONS PEC uses interest rate derivative instruments to adjust the fixed and variable rate debt components of its debt portfolio and to hedge interest rates with regard to future fixed rate debt issuances. In March and April of 2003, PEC entered into treasury rate locks to hedge its exposure to interest rates with regard to a future issuance of debt. These agreements have a computational period of ten years and are designated as cash flow hedges for accounting purposes.

The notional amounts of the above contracts are not exchanged and do not represent exposure to credit loss. In the event of default by a counter party, the risk in the transaction is the cost of replacing the agreements at current market rates. PEC only enters into swap agreements with banks with credit ratings of single A or better.

In connection with the January 2003 FASB Emerging Issues Task Force (EITF) meeting, the FASB was requested to reconsider an interpretation of SFAS No. 133. The interpretation, which is contained in the Derivatives Implementation Group's ClI guidance, relates to the pricing of contracts that include broad market indices (e.g., CPI).

In particular, that guidance discusses whether the pricing in a contract that contains broad market indices could qualify as a normal purchase or sale (the normal purchase or sale term is a defined accounting term, and may not, in all cases, indicate whether the contract would be normal" from an operating entity viewpoint). In April 2003, the FASB issued tentative superceding guidance (DIG Issue C20) on this issue and is expected to be finalized in the second or third quarter of 2003.

The Company has determined that it has one existing "normal" contract that could be affected by this revised guidance, and the Company is in the process of evaluating the revised guidance to determine if that contract will be required to be recorded at fair value if the revised guidance is approved in its present form.

8. OTHER INCOME AND OTHER EXPENSE Other income and expense includes interest income, gain on the sale of investments, impairment of investments and other income and expense items as discussed below. The components of other, net as shown on the Consolidated Statements of Income for the three months ended March 31, 2003 and 2002 are as follows:

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(in thousands) 2003 2002 Other income Net financial trading loss $ (2,698) $ (2,541)

Net energy purchased for resale 338 (36)

Nonregulated energy and delivery services income 2,286 2,551 AFUDC equity 1,090 2,059 Other 2,703 Total other income - $ 3,719 $ 2,033 Other expense Nonregulated energy and delivery services expenses $ 1,973 $ .1,635 Donations 1,306 1,370 Other 2,993 I  : - 2,001 Total other expense $ 6,272 $ 5,006 Other, net $ (2,553) S (2,973)

Net financial trading loss represents non-asset-backed trades of electricity and gas. Net energy purchased for resale represents electricity purchased externally for sale to a third party. 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.

9. COMMITMENTS AND CONTINGENCIES' Contingencies existing as of the date of these statements are described below. No significant changes have occurred since December 31, 2002, with respect to the commitments discussed in Note 18 of the financial statements included in PEC's 2002 Annual Report on Form 10-K.

Other In 2003, PEC determined that its external funding levels did not fully meet the nuclear decommissioning financial assurance levels required by the NRC. Therefore, PEC obtained a parent company guarantee to meet the required levels.

As of March 31, 2003, management does not believe conditions are likely for performance under these agreements.

Contingencies

1) Claims and uncertainties a) 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 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 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, are participating in investigating and, if necessary, remediating former MGP sites with several regulatory agencies, including, but not limited to, the EPA and the North Carolina Department of Environment and Natural Resources, Division of Waste Management (DWM). In addition, PEC is periodically notified by regulators such as the EPA and various state agencies of their involvement or potential involvement in sites, other than MGP sites, that may require investigation and/or remediation.

There are 12 former MGP sites and 14 other sites associated with PEC that have required or are anticipated to require investigation and/or remediation costs. PEC received insurance proceeds to address costs associated with PEC environmental liabilities related to its involvement with MGP sites. All eligible expenses related to these are charged 37

against a specific fund containing these proceeds. As of March 31, 2003, approximately $5.7 million remains in this centralized fund with a related accrual of $5.7 million recorded for the associated expenses of environmental issues.

As PEC's share of costs for investigating and remediating these sites become known, the fund is assessed to determine if additional accruals will be required. PEC does not believe that it can provide an estimate of the reasonably possible total remediation costs beyond what remains in the environmental insurance recovery fund.

This is due to the fact that the sites are at different stages: investigation has not begun at 15 sites, investigation has begun but remediation cannot be estimated at seven sites and four sites have begun remediation. 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 potentially responsible parties. Once the environmental insurance recovery fund is depleted, PEC will accrue costs for the sites to the extent its liability is probable and the costs can be reasonably estimated. Presently, PEC cannot -determine the total costs that may be incurred in connection with the remediation of all sites. According to current information, these future costs at the PEC sites are not expected to be material to PEC's financial condition or results of operations.

PEC has filed claims with its general liability insurance carriers to recover costs arising out of actual or potential environmental liabilities. Some claims have settled and others are still pending. While management cannot predict the outcome of these matters, the outcome is not expected to have a material effect on the consolidated financial position or results of operations.

PEC is also currently in the process of assessing potential costs and exposures at other environmentally impaired sites. As the assessments are developed and analyzed, PEC will accrue costs for the sites to the extent the costs are probable and can be reasonably estimated.

Air Quality There has been and may be further proposed federal legislation requiring reductions in air emissions for nitrogen oxides, sulfur dioxide, carbon dioxide and mercury. Some of these proposals establish nation-wide caps and emission rates over an extended period of time. This national multi-pollutant approach to air pollution control could involve significant capital costs which could be material to- PEC's consolidated financial position or results of operations. Some companies may seek recovery of the related cost through rate adjustments or similar mechanisms.

Control equipment that will be installed on North Carolina fossil generating facilities as part of the North Carolina legislation discussed below may address some of the issues outlined above. However, PEC cannot predict the outcome of this matter.

The EPA is conducting an enforcement initiative related to a number of coal-fired utility power plants in an effort to determine whether modifications at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. PEC was asked to provide information to the EPA as part of this initiative and cooperated in providing the requested information. During the first quarter of 2003, PEC responded to a supplemental information request from EPA. 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, ranging from $1.0 billion to $1.4 billion. A utility that was not subject to a civil enforcement action settled its New Source Review issues with the EPA for $300 million. These settlement agreements have generally called for expenditures to be made over extended time periods, and some of the companies may seek recovery of the related' cost through rate adjustments or similar mechanisms. PEC cannot predict the outcome of this matter.

In 1998, the EPA published a final rule addressing the regional transport of ozone. This rule is commonly known as the NOx SIP Call. The EPA's rule requires 23 jurisdictions. including North Carolina, South Carolina and Georgia, to further reduce nitrogen oxide emissions in order to attain a pre-set state NOx emission levels by May 31, 2004. PEC is currently installing controls necessary to comply with the rule. Capital expenditures needed to meet these measures in North and South Carolina could reach approximately $370 million, which has not been adjusted for inflation.

Increased operation and maintenance costs relating to the NOx SIP Call are not expected to be material to PEC's results of operations. Further controls are anticipated as electricity demand increases. PEC cannot predict the outcome of this matter.

In July 1997, the EPA issued final regulations establishing a new eight-hour ozone standard. In October 1999, the District of Columbia Circuit Court of Appeals ruled against the EPA with regard to the federal eight-hour ozone standard. The U.S. Supreme Court has upheld, in part, the District of Columbia Circuit Court of Appeals decision.

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Designation of areas that do not attain the standard is proceeding, and further litigation and rulemaking on this and other aspects of the standard are anticipated. North Carolina adopted the federal eight-hour ozone standard and is proceeding with the implementation process. North Carolina has promulgated final regulations, which will require PEC to install nitrogen oxide controls under the State's eight-hour standard. The costs of those controls are included in the $370 million cost estimate set forth above. However, further technical analysis and rulemaking may result in a requirement for additional controls at some units. PEC cannot predict the outcome of this matter.

The EPA published a final rule approving petitions under Section 126 of the Clean Air Act. This rule as originally promulgated required certain sources to make reductions in nitrogen oxide emissions by May 1, 2003. The final rule also includes a set of regulations that affect nitrogen oxide emissions from sources included in the petitions. The North Carolina coal-fired electric generating plants are included in these petitions. Acceptable state plans under the NOx SIP Call can be approved in lieu of the final rules the EPA approved as part of the 126 petitions. PEC, other utilities, trade organizations and other-states participated in litigation challenging the EPA's action. On May 15, 2001, the District of Columbia Circuit Court of Appeals ruled in favor of the EPA, which will require North Carolina to make reductions in nitrogen oxide emissions by May 1, 2003. However, the Court in its May 15th decision rejected the EPA's methodology for estimating the future growth factors the EPA used in calculating the emissions limits for utilities. In August 2001, the Court granted a request by PEC and other utilities to delay the implementation of the 126 Rule for electric generating units pending resolution by the EPA of the growth factor issue. The Court's order tolls the three-year compliance period (originally -set to end on May 1, 2003) for electric generating units as of May 15, 2001. On April 30. 2002, the EPA published a final rule harmonizing the dates for the Section 126 Rule and the NOx SIP Call. In addition, the EPA determined in this rule that the future growth factor estimation methodology was appropriate. The new compliance date for all affected sources is now May 31, 2004, rather than May 1, 2003. The EPA has approved North Carolina's NOx SIP Call rule and has formally proposed to rescind the Section 126 rule.

This rulemaking is expected to become final during the summer of 2003. PEC expects a favorable outcome of this matter.

On June 20, 2002, legislation was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of nitrogen oxide and sulfur dioxide from -coal-fired power plants. PEC expects its capital costs to meet these emission targets will be approximately $813 million by 2013. PEC currently has approximately 5,100 MW of coal-fired generation in North Carolina that is affected by this legislation. The legislation requires the emissions reductions to be completed in phases by 2013, and applies to each utility's total system rather than setting requirements for individual power plants. The legislation- also freezes thP utilities' base rates for five years unless there are extraordinary events beyond the control of the utilities or unless the utilities persistently earn a return substantially in excess of the rate of return established and found reasonable by the NCUC in the utilities' last general rate case. Further, the legislation allows the utilities to recover from their retail customers the projected capital costs during the first seven years of the 10-year compliance period beginning on January 1, 2003. The utilities must recover at least 70% of their projected capital costs during the five-year rate freeze period. Pursuant to the new law, PEC entered into an agreement with the state of North Carolina to transfer to the state any future emissions allowances acquired as a result of compliance with the new law. The new law also requires the state to undertake a study of mercury and carbon dioxide emissions in North Carolina. PEC cannot predict the future regulatory interpretation, implementation or impact of this new law. PEC has recorded $20 million of clean air amortization to date and clean air expenditures to date are $2.5 million.

Other Envirounental Matters The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of carbon dioxide and other greenhouse gases. The United States has not adopted the Kyoto Protocol;.

however, a number of carbon dioxide emissions control proposals have been advanced in Congress and by the Bush administration. The Bush administration favors voluntary programs. Reductions in carbon dioxide emissions to the levels specified by the Kyoto Protocol and some legislative proposals could be materially adverse to PEC's financials and operations if associated costs cannot be recovered from customers. PEC favors the voluntary program approach recommended by the administration, and is evaluating options for the reduction, avoidance, and sequestration of greenhouse gases. However, PEC cannot predict the outcome of this matter.

In 1997, the EPA's Mercury Study Report and Utility Report to Congress conveyed that mercury is not a risk to the average American and expressed uncertainty about whether reductions in mercury emissions from coal-fired power plants would reduce human exposure. Nevertheless, EPA determined in 2000 that regulation of mercury emissions from coal-fired power plants was appropriate. Pursuant to a Court Order, the EPA is developing a Maximum 39

Available Control Technology (MACT) standard, which is expected to become final in December 2004, with compliance in 2008. Achieving compliance with the MACT standard could be materially adverse to PEC's financial condition and results of operations. However, PEC cannot predict the outcome of this matter.

b) As required under the Nuclear Waste Policy Act of 1982, PEC entered into a contract with the DOE under which the DOE agreed to begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract.

In April 1995, the DOE issued a final interpretation that it did not have an unconditional obligation to take spent nuclear fuel by January 31, 1998. In Indiana & Michigan Power v. DOE, the Court of Appeals vacated the DOE's final interpretation and ruled that the DOE had an unconditional obligation to begin taking spent nuclear fuel. The Court did not specify a remedy because the DOE was not yet in default.

After the DOE failed to comply with the decision in Indiana & Michigan Power v. DOE, a group of utilities petitioned the Court of Appeals in Northern States Power (NSP) v. DOE, seeking an order requiring the DOE to begin taking spent nuclear fuel by January 31, 1998. The DOE took the position that its delay was unavoidable, and the DOE was excused from performance under the terms and conditions of the contract. The Court of Appeals did not order the DOE to begin taking spent nuclear fuel, stating that the utilities had a potentially adequate remedy by filing a claim for damages under the contract.

After the DOE failed to begin taking spent nuclear fuel by January 31, 1998, a group of utilities filed a motion with the Court of Appeals to enforce the mandate in NSP v. DOE Specifically, this group of utilities asked the Court to permit the utilities to escrow their waste fee payments, to order the DOE not to use the waste fund to pay damages to the utilities, and to order the DOE to establish a schedule for disposal of spent nuclear fuel. The Court denied this motion based primarily on the grounds that a review of the matter was premature, and that some of the requested remedies fell outside of the mandate in NSP v. DOE Subsequently, a number of utilities eacl filed an action for damages in the Federal Court of Claims. In a recent decision, the U.S. Circuit Court of Appeals (Federal Circuit) ruled that utilities may sue the DOE for damages in the Federal Court of Claims instead of having to file an administrative claim with DOE. PEC is in the process of evaluating whether it should file a similac action for damages.

On July 9, 2002, Congress passed an override resolution to Nevada's veto of DOE's proposal to locate a permanent underground nuclear waste storage facility at Yucca Mountain, Nevada. DOE plans to submit a license application for the Yucca Mountain facility by the end of 2004. PEC and PEF cannot predict the outcome of this matter.

With certain modifications and additional approval by the NRC. PEC's spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on its system through the expiration of the current operating licenses for all of its nuclear generating units. Subsequent or prior to the expiration of these licenses, or any renewal of these licenses, dry storage or acquisition of new shipping casks may be necessary. PEC obtained NRC approval to use additional storage space at the Harris Plant in 2000.

c) PEC is involved in various litigation matters in the ordinary course of business, some of which involve claims for substantial amounts. Where appropriate, accruals have been made in accordance with SFAS No.

5, "Accounting for Contingencies,' to provide for such matters. PEC believes the final disposition of pending litigation would not have a material adverse effect on PEC's consolidated results of operations or financial position.

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Item 2. 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 "SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS" for a discussion of the factors that may impact any such forward-looking statements made herein.

RESULTS OF OPERATIONS In this section, earnings and the factors affecting earnings for the three months ended March 31, 2003 as compared to the same period in 2002 are discussed. The discussion begins with a general overview, then separately discusses earnings by business segment.

Amounts reported in the interim Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption and the timing of maintenance on electric generating units, among other factors.

OVERVIEW The net income and basic earnings per share of Progress Energy, Inc. (Progress Energy or the Company) was $208.2 million or $0.89 per share and $132.5 million or $0.62 per share for the quarters ended March 31, 2003 and 2002, respectively. Income from continuing operations was $196.9 million and $124.1 million, respectively, with the operations of North Carolina Natural Gas Corporation (NCNG) being classified as discontinued operations. The increase in net income in 2003 is primarily due to:

• the favorable impact of weather and customer growth on retail sales,

.. strong, weather-related wholesale sales,

• lower interest expense,

• positive impact of the Westchester Gas acquisition and

• a wholesale contract termination agreement.

Partially offsetting these items were:

• higher operation and maintenance costs primarily due to ice storm costs in the Carolinas and a decreased pension credit and

• lower planned synthetic fuel production.

Effective January 1, 2003, Carolina Power and Light Company (CP&L), Florida Power Corporation and Progress Ventures, Inc. began doing business under the names Progress Energy Carolinas, Inc., Progress Energy Florida, Inc.,

and Progress Energy Ventures, Inc., respectively. The legal names of these entities have not changed and there is no restructuring of any kind related to the name change. The corporate and business unit structure remains unchanged.

The Company's business segments and their primary operations are:

• PEC Electric - engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina;

• PEF - engaged in the generation, transmission, distribution and sale of electricity in portions of Florida;

• Fuels - engaged in natural gas drilling and production, coal mining and the production of synthetic fuels;

• Competitive Commercial Operations (CCO) - engaged in nonregulated generation operations and energy marketing and limited trading activities;

• Progress Rail Services (Rail) - engaged in various rail and railcar related services; and

• Other Businesses (Other) - engaged in other nonregulated business areas including telecommunications and energy services operations.

In prior reporting, CCO and Fuels were components of the Progress Ventures segment. With the expansion of the nonregulated energy generation facilities and the current management structure, CCO is now a distinct operating segment. In addition to these operating segments, the Company has other corporate activities that include holding company operations, service company operations and eliminations. These corporate activities have been included in the Other segment in the past. Additionally, earnings from wholesale customers on the regulated plants have 41

previously been reported in both the regulated utilities' results and the results of Progress Ventures. With the realignment of the reportable business segments, this activity is now included in the regulated utilities' results only.

For comparative purposes, the 2002 results have been restated to align with the new business segments.

In 2002, the operations of NCNG, previously reported in the Other segment, were reclassified to discontinued operations and therefore were not included in the results from continuing operations during the periods reported. A discussion of the planned divestiture of NCNG is in the Discontinued Operations section.

In March 2003, the SEC completed an audit of the 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 20Ul and 200?. This change in allocation methodology and the related retroactive adjustments have no impact on consolidated expense or earnings. The impact on the affiliates is included in the segment discussion that follows.

ELECTRIC SEGMEWIS The operating results of both electric utilities are primarily influenced by customer demand for electricity, the ability to control costs and regulatory return on equity. Annual demand for electricity is based on the number of customers and their annual usage, with usage largely impacted by weather. In addition, the current economic conditions in the service territories may impact the annual demand for electricity.

Effective January 1 2003, the Company implemented SFAS No. 143 which requires that the present value of retirement costs for which the Company has a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The liability is then accreted over time by applying an interest method of allocation to the liability. Both electric utilities recognized asset retirement obligations (AROs) in the first quarter of 2003. The adoption of the statement had no impact on the income of tht. electric segments, due to the establishment of regulatory assets and liabilities pursuant to SFAS No. 71. At March 31, 2003.

the utilities have recorded AROs of $892.4 million and $306.8 million for PEC and PEF, respectively.

PEC filed a request with the NCUC requesting deferral of the difference between expense pursuant to SFAS No. 143 and expense as previously determined by the NCUC. The NCUC granted the deferral of the January 1, 2003, cumulative adjustment, but denied the deferral of the ongoing effects, citing a lack of information concerning the ongoing effects that would support the granting of such a deferral. The Company is in the process of providing additional information to the NCUC that it believes will demonstrate that deferral of the ongoing effects should also be allowed. Accordingly, for the quarter ended March 31, 2003, PEC deferred the ongoing effects. If PEC had not deferred the ongoing effects, expense for the quarter would have decreased by approximately $5.7 million, which represents a decrease in non-ARO cost of removal expense, partially offset by an increase in decommissioning expense.

On April 8 2003, the SCPSC approved a joint request by PEC, Duke Energy and South Carolina Electric and Gas Company for an accounting order to authorize the deferral of all cumulative and prospective effects related to the adoption of SFAS No. 143.

On January 23, 2003, the Staff of the FPSC issued a notice of proposed rule development to adopt provisions relating to accounting for asset retirement obligations under SFAS No. 143. Accompanying the notice was a draft rule presented by the staff which adopts the provisions of SFAS No. 143 along with the requirement to record the difference between amounts prescribed by the FPSC and those used in the application of SFAS No. 143 as regulatory assets or regulatory liabilities, which was accepted by all parties. The adoption and acceptance of this draft rule is subject to FPSC approval.

PROGRESS ENERGY CAROLINAS ELECTRIC PEC Electric contributed income from continuing operations of $134.6 million and $85.5 million in the first quarter of 2003 and 2002, respectively. The increase is primarily attributed to favorable weather conditions in the first quarter of 2003, as compared to the first quarter of 2002, which impacted both the retail and wholesale markets, strong customer growth and lower interest charges.

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Revenues PEC's electric revenues for the first quarter of 2003 and 2002 and the amount and percentage change by quarter and by customer class are as follows:

(in millions)

Customer Class 2003 Amount Change  % Change 2002 Residential $356.9 - $47.6- 15.4% $309.3 Commercial 200.9 13.6 7.3 187.3 Industrial 146.7 1.0 0.7 145.7 Governmental 18.7 1.2 - 6.9 17.5 Total retail revenues ; 723.2 - 63.4 9.6 659.8 Wholesale 209.4 66.8 46.8 142.6 Unbilled (30.9) (21.2) - (9.7)

Miscellaneous 23.8 5.0 26.6 18.8 Total electric revenues $925.5 $114.0 14.0% $811.5 PEC's electric energy sales for 2003 and 2002 and the amount and percentage change by quarter and by customer class are as follows:

(in thousands of mWh)

Customer Class 2003 Amount Change  % Change 2002 Residential 4,587 602 15.1% 3,985 Commercial 2,984 194 7.0 2,790 Industrial 3,005 18 0.6 2,987 Governmental 343 18 5.5 325 Total retail energy sales 10,919 832 8.2 10,087 Wholesale 4,619 1,288 38.7 3,331 Unbilled (480) (293) - (187)

Total mWh sales 15,058 1,827 13.8% 13,231 Favorable weather in the first quarter of 2003 as compared to the first quarter of 2002 was the primary driver of the increased retail and wholesale energy sales and revenue. Wholesale revenue growth is also attributed to increased weather driven sales of energy to the Northeastern United States markets during the first quarter of 2003. The residential and commercial customer classes' customer base increased two percent.

Expenses The following summarizes PEC Electric's expenses for the first quarter of 2003 and 2002.

(in millions)

Expense Category 2003 Amount Change  % Change 2002 Fuel and purchased power $298.7 $51.5 20.8% $247.2 Operations and maintenance 189.9 (1.4) (0.7) 191.3 Depreciation and amortization 138.8 (2.6) (1.8) 141.4 Taxes other than on income 44.2 5.4 13.9 38.8 Net interest charges 48.4 (10.1) (17.3) 58.5 Income taxes 70.0 22.6 47.7 47.4 Other expenses 0.9 (0.5) (35.7) 1.4 Total expenses $790.9 $64.9 8.9% $726.0 The increase in fuel and purchased power expense is due to an 11.8% increase in generation, higher fuel prices and changes in generation mix. Fuel expenses are recovered primarily through cost recovery clauses and, as such, have no material impact on operating results.

43

The decrease in operations and maintenance expense is primarily the result of the revised Service Company cost allocation methodology. Operations and maintenance costs decreased $15.9 million related to the reallocation of prior years' costs and $2.5 million related to current year costs. These cost reductions were partially offset by costs incurred for the February ice storms of $10.4 million.

The decrease in depreciation and amortization expense results from a $25.0 million reduction in accelerated nuclear amortization, partially offset by a $20.0 million increase in clean air amortization. An NCUC order allowed the reduction in the accelerated nuclear amortization and extended the recovery time.

Interest expense decreased due to both a decrease in average nutstanding debt and a slightly lower interest rate.

In accordance with an SEC order under-PUHCA, effective in the second quarter of 2002, tax berefits nct related to acquisition interest expense that were previously held unallocated at the holding company must be allocated to the profitable subsidiaries. As a result, $5.5 million of the tax benefit that was previously held at the holding company was allocated to PEC in the first quarter of 2003. The allocation has no impact on the Company's consolidated tax expense or net income. Other fluctuations in income taxes are primarily due to changes in pre-tax income.

PROGRESS ENERGY FLORIDA PEF contributed income from continuing operations of $70.8 million and $57.7 million in the first quarter of 2003 and 2002, respectively. This increase is primarily attributed to favorable weather, retail growth/usage and the absence of the impact of the retroactive rate refund in 2002. Partially offsetting these improvements was the impact of the reduced rates in 2003 resulting from the May 2002 rate case settlement.

In March 2002, PEF settled a rate case which provided for a one-time retroactive rate refund, decreased future retail rates by 9.25% (effective May 1. 2002), provided for lower depreciation and amortization and provided for increases in certain service revenue rates.

Revenues PEF's electric revenues for the first quarter of 2003 and 2002 nd the amount and percentage change by quarter and by customer class are as follows:

(in millions)

Customer Class 2003 Amount Change  % Change 2002 Residential $385.0 $5.8 1.5% $379.2 Commercial 150.4 (16.4) (9.8) 166.8 Industrial 47.5 (2.5) (5.0) 50.0 Covernmental 38.0 (1.9) (4.8) 39.9 Revenue Sharing/Rate Refund - 35.0 100.0 (35.0)

Total retail revenues 620.9 20.0 3.3 600.9 Wholesale 71.3 18.9 36.1 52.4 Unbilled (0.7) (7.2) - 6.5 Miscellaneous 36.9 10.3 38.7 26.6 Total electric revenues $728.4 $42.0 6.1% $686.4 PEF's electric energy sales for the first quarter of 2003 and 2002 and the amount and percentage change by quarter and by customer class are as follows:

(in thousands of mWh)

Customer Class 2003 Amount Change  % Change 2002 Residential 4,553 493 12.1% 4,060 Commercial 2,442 (14) (0.6) 2,456 Industrial 916 34 3.9 882 Governmental 657 36 5.8 621 44

Total Retail Energy Sales 8,568 549 6.8 8,019 Wholesale 1,277 298 30.4 979 Unbilled 54 22 - 32 Total mWh Sales 9,899 869 9.6% 9.030 The first quarter 2002 rate refund of $35.0 million was virtually offset by the 2003 first quarter rate reduction, both of which resulted from the 2002 rate case settlement. Excluding these impacts, revenue increased due to favorable weather in the first quarter of 2003, as compared to the first quarter of 2002 (heating degree days increased 25.6%)

and continued retail customer growth (retail customer base increased 1.25%/). Increased demand 1om other utilities drove the wholesale revenue increase. Higher service charges allowed in the rate case settlement contributed to the higher miscellaneous revenues.

Expenses The following summarizes PEF's expenses for the first quarter of 2003 and 2002.

(in millions)

Expense Category 2003 Amount Change  % Change 2002 Fuel and purchased power $315.6 $8.8 2.9% $306.8 Operations and maintenance 139.8 7.0 5.3 132.8 Depreciation and amortization 79.4 10.1 14.6 69.3 Taxes other than on income 58.6 1.5 2.6 57.1 Net interest charges 26.5 (1.8) (6.4) 28.3 Income taxes 37.0 3.6 10.8 33.4 Other expenses 0.7 (0.3) (30.0) 1.0 Total expenses $657.6 $28.9 4.6% $628.7 Fuel and purchased power expenses are recovered primarily- through cost recovery clauses and, as such, havt rio material impact on operating results.

The increase in operations and maintenance expense results from a $5.3 million lower pension credit.

The increase in depreciation and amortization expense relates primarily to an increase in amortization of the Tiger Bay regulatory asset. The amortization is recovered through a cost recovery clause and has no impact on earnings. The regulatory asset was created as a result of the early termination of certain long-term cogeneration contracts and is amortized according to a plan approved by the Florida Public Service Commission.

In accordance with an SEC order under PUHCA. effective in the second quarter of 2002, tax benefits not related to acquisition interest expense that were previously held unallocated at the holding company must be allocated to the profitable subsidiaries. As a result, $3.4 million of the tax benefit that was previously held at the holding company was allocated to PEF in the first quarter of 2003. The allocation has no impact on the Company's consolidated tax expense or net income. Other fluctuations in income taxes are primarily due to changes in pre-tax income.

DIVERSIFEED BUSINESSES The Company's diversified businesses consist primarily of the Fuels segment, the CCO segment, the Rail segment and Progress Telecom and SRS, which are in the Other segment. These businesses are explained in more detail below.

FUELS The Fuels segment's operations includes synthetic fuel operations, natural gas exploration and production and coal extraction. Fuels' results for the first quarter of 2003 were impacted most significantly by the timing of synthetic fuel production and the increase in gas production.

The following summarizes the income from continuing operations of the Fuels segment for the first quarter 2003 and 2002.

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(in millions) 2003 Change 2002 Synthetic fuel operations $25.4 $(13.4) $38.8 Gas production and coal fuel operations 5.2 4.7 0.5 Other (losses) earnings (4.0) (6.3) 2.3 Income from continuing operations $26.6 $(15.0) $41.6 46

Synthetic Fuel Operations The synthetic fuels operations generated income from continuing operations of $25.4 million and $38.8 million in the first quarter of 2003 and 2002, respectively. 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. The following summarizes the synthetic fuel operations for the first quarter of 2003 and 2002.

(inmillions) 2003 2002 Tons produced 2.0 3.0 Operating losses, excluding tax credits $(27.3) $(45.0' Tax credits generated 52.7 83.8 I Income from contiidihgoperations  : " -; $ 25.4 $ 38.8 -

Total synthetic fuel sales decreased in the current year primarily due to a change in the synthetic fuel oroduction pattern for 2003. The Company anticipates total synthetic fuel production of 12 to 13 million t ns for the yuir, which is comparable to 2002 production levels.

Gas production and coal fuel operations Gas operations generated income from continuing operations of $4.9 million and $0.3 million in the first quarter of 2003 and 2002, respectively. The increase in production drove the increased revenue and earnings with the addition of the Westchester operations accounting for 64% of the gas production in the first quarter of 2003. Income from operations related to coal fuel operations was immaterial for both periods presented.

During the first quarter of 2003, Progress Fuels Corporation, a wholly owned subsidiary of Progress Energy, entered into three independent transactions to acquire approximately 162 natural gas-producing wells with proven resel ves cf

.95 billion cubic feet for $148 million. The primary assets in the acquisition have been transfermrl. to Progress Fuels North Texas Gas, L.P., a wholly owned subsidiary of Progress Fuels Corporation.

Fuels' operations also include terminals, coal production and transportation operations and other untilocated segment costs. The 2003 unallocated segment costs include $4.7 million after tax of addstic1si Senulce Co-pany allocations related to the SEC audit.

COMPETITIVE COMMERCLAL OPERATIONS CCO generates and sells (on a wholesale basis) electricity through nonregulated plants. These operations also include limited financial trading activities. The following summarizes the income from continuing operations, sales and generating capacity of the nonregulated plants for the first quarters of 2003 and 2002.

(inmillions except megawatts) 2003 Change 2002 Income/loss from continuing operations $ 8.5 $ 10.6 $ (2.1)

Operating revenue $ 37.2 $ 28.2 $ 9.0 Generation capacity (MW) 1,554 1,239 315 On March 21, 2003, PVI announced entering into a definitive agreement with Williams Energy Marketing and Trading to acquire a full-requirements power supply agreement with Jackson in Georgia for $188 million. This transaction is expected to close in the second quarter.

The increase in revenue and earnings is primarily due to a tolling agreement termination payment from Dynegy. Also contributing slightly to the increase was the increased production capacity from the addition of generating capacity.

The earnings and revenue increases related to the increased capacity was partially offset by lower prices in the wholesale energy market. Including the Jackson contract and the impact of the Dynegy contract termination, mentioned above, the Company has contracts for 68%, 74% and 49% of planned production capacity for 2003 through 2005, respectively. The 2005 decline results from the expiration of four contracts. The Company continues to pursue opportunities with both current customers and other potential customers.

47

The first quarter 2003 results include $2.8 million after tax of additional Service Company allocations related to the SEC order.

During 2002. the Company completed the acquisition of two electric generation projects, Walton County Power, LLC and Washington County Power, LLC. The acquisition resulted in goodwill of $64.1 million. The Company performed the annual goodwill impairment test in the first quarter of 2003 which indicated no impairment. However, modest changes in either assumptions or market conditions could cause some or all of the $64 million of goodwill related to the CCO operating segrnent to become impaired.

RAIL SERVICES (RAIL)

Rail- operations include railcar and ocomotive repair,. trac&,vkw<k, rail part:, re%unditioniing and .:aies, crap meto' recycling, railcai leasing and other rail related services. The Corhpany intends t: sell the assets of Railcar Ltd. a leasing subsidiary, in 2003 and has reported these assets as assets held for sale at March 31, 2003.

Progress Rail contributed losses from continuing operations of $3.4 million and $0.7 million for the first quarters of 2003 and 2002, respectively. As a result of the SEC order, Rail incurred additional Service Company allocations of

$3.4 million after tax in the first quarter of 2003. Rail's results for both quarters were affected by the downturn in the overall economy. Rail experienced revenue growth in the first quarter of 2003 with stronger wheel set sales and recycling sales. Aggressive cost management programs were identified throughout 2002 and in the first quarter of 2003.

An SEC order approving the merger of FPC requires the Company to divest Rail by November 30, 2003. The Company is pursuing alternatives, but does not expect to find the right divestiture opportunity by that date.

Therefore, the Company has sought an extension from the SEC.

OTBER BUSINESSES SEGMENT Progress Energy's Other segment primarily includes the operations of SRS, Progress Telecom and small nonregulated subsidiaries of PEC. Holding company operations and other corporate functions that have previously been included in the Other segment hava been removed and are being reported separately. The segment contributed earnings of

$0.3 million and a loss of $4.9 million in the first quarter of 2003 and 2002, respectively.

The improvement is related to Progress Telecom's lower depreciation charges resulting from the impairment of a significant portion of its assets in the third quarter of 2002.

CORPORATE SERVICES Corporate Services includes the operations of the Holding Company, the Service Company, and consolidation entities, as summarized below (expenses are indicated by positive numbers).

(in millions) 2003 Amount Change 2002 Interest expense $71.0 $ - $71.0 Contingent value obligations (1.7) 9.6 (11.3)

Tax reallocation 9.1 9.1 Tax levelization (10.3) (31.5) 21.2 Other income taxes (30.9) 1.0 (31.9)

Other expenses 3.3 (0.8) 4.1 Loss from continuing operations $40.5 $(12.6) $53.1 Progress Energy issued 98.6 million contingent value obligations rVOs) in connection with the FPC acquisition.

Each CVO represents the right to receive contingent payments based on the performance of four synthetic fuel facilities owned by Progress Energy. The payments, if any, are based on the net after-tax cash flows the facilities generate. At March 31, 2003 and 2002, the CVOs had fair market values of approximately $12.1 million and $30.6 million, respectively. Progress Energy recorded an unrealized gain of $1.7 million and $11.3 million for the first quarter of 2003 and 2002. respectively, to record the changes in fair value of the CVOs, which had average unit prices of $0.12 and $0.31 at March 31, 2003 and 2002, respectively.

48

According to an SEC order under PUHCA, Progress Energy's tax benefit not related to acquisition interest expense is to be allocated to profitable subsidiaries. Therefore, the tax benefit that was previously held in the Holding Company was allocated to the profitable subsidiaries effective with the second quarter of 2002. The allocation has no impact on consolidated tax expense or earnings. However, in the first quarter of 2003, the allocation increased the Corporate Services tax expense $9.1 million with offsetting decreases in other segments (primarily PEC and PEF).

GAAP requires companies t apply a levelized effective tax rate to interimr periods that is consistent with the estimated aRLnual effective tax rate. Income tax expense was increased by $10.3 rn'lion and de-.m;sed $21.2 million for the first quarter of 2003 and 2002, respectively, in order to maintain an effective tax rate consistent witn the estimated annual rate. The tax credits associated with the Company's synthetic-fuel operations primarily drive the required levelization amount. In the first quarter of 2003, a benefit was realized hecanFe synthetic fel l-oducii was -hifted

.-out of the first quarter and weather condii:ons hindered thedelivery oi-sy;th.i fuels t -*: ; i ' 2. l the fi 4 quartef nf 2002, a-tax expense-was recogniied because of higher synthetc fiel production ad Saie.s. luccuations in estimated annual earnings and tax credits can also cause large swings in the effective tax rate tor interim periods.

Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year.

Other fluctuations in income taxes are primarily due to changes in pre-tax income.

DISCONTINUED OPERATIONS In the fourth quarter of 2002, the Company's Board of Directors approved the sale of North Carolina Natural Gas Corporation (NCNG) to Piedmont Natural Gas Company, Inc. As a result of this action, the operating results of NCNG were reclassified to discontinueli operations for all reportable periods. With its classification as a discontinued operation, the assets of NCNG are no longer depreciated, resulting in $2.9 million less after-tax depreciation expense, when compared to the first quarter 2002. Progress Energy expects to sell NCNG in the summer of 2003 for net proceeds of approximately $400 million. The company expects to use the proceeds to reduce outstanding debt.

UOUID1TY AND CAPITAL RESOURCES Progress Energy, Inc.

Statement of Cash Flows and FinancingActivities Cash provided by operating activities increased $174 million for the three months ended March 31, 2003, when compared to the corresponding period in the prior year. The increase in cash from operating activities for the 2003 period is due to improved operating results at both electric utilities. In addition, changes in the balances of certain current assets and liabilities due to operational fluctuations provided cash by operating activities.

Net cash used in investing activities decreased $309 million for the three months ended March 31, 2003, when compared to the corresponding period in the prior year. The decrease in cash used in investing activities is primarily due to lower capital spending at PVI, which acquired generating assets from LG&E in February 2002 for approximately

$350 million. During the first three months of 2003, $222.6 million was spent in diversified business property additions. The acquisition of the natural gas reserves resulted in a cash outflow of $148 million, which is included in the $222.6 million in diversified property additions.

Net cash provided by financing activities decreased $712 million for the three months ended March 31, 2003, when compared to the corresponding period in the prior year. The decrease in financing requirements was primarily due to the improved operating cash flow and lower capital expenditures for the quarter.

On February 7, 2003, Moody's Investors Service (Moody's) announced that it was lowering Progress Energy, Inc.'s senior unsecured debt rating from Baal to Baa2, and changing the outlook of the rating from negative to stable.

Moody's cited the slower than planned pace of the Company's efforts to pay down debt from its acquisition of Florida Progress as the primary reason for the ratings change. Moody's also changed the outlook of Progress Energy Florida, Inc. (Al senior secured) and Progress Capital Holdings, Inc. (A3 senior unsecured) from stable to negative and lowered the trust preferred rating of FPC Capital I from A3 to Baa 1 with a negative outlook.

49

The change in outlook by the rating agency has not materially affected Progress Energy's access to liquidity or the cost of its short-term borrowings.

On February 21, 2003, PEF issued $425 million of First Mortgage Bonds, 4.80% Series, Due March 1, 2013 and $225 million of First Mortgage Bonds, 5.90% Series, Due March 1, 2033. Proceeds from this issuance were used to repay the balance of its outstanding commercial paper, to refinance its secured and unsecured indebtedness, including PEF's First Mortgage Bonds 6.125% Series Due March 1, 2003 ad to redeem the aggregate outstanding balance of its 8% First Mortgage Bonds due 2022.

On March 1,2003, $70 million of PEF First Mortgage Bnrls, 6.125% Series, rnatred and wera reti;ed.

-Effectve March24, 2003, PEF redeemed $150 million of First MV-rtg.'gc EoX!us, 8% Snfi..., d;,-e December 1. i2S2 ai-1-03.75% of the principal amount of such bonds.

On April 1, 2003, PEF entered into a new $200 million 364-day credit agreement and a new $200 million three-year credit agreement, replacing its prior credit facilities (which had been a $90 million 364-day facility and a $200 million five-year facility). The new PEF credit facilities contain a defined maximum total debt to total capital ratio of 65%; as of March 31, 2003 the calculated ratio was 50.9%. The new credit facilities also contain a requirement that the ratio of EDITDA, as defined in the facilities, to interest expense to be at least 3 to 1; as of March 31, 2003 the calculated ratio was 8.7 to 1.

Also on April 1, 2003, PEC reduced the size of its existing 364-day credit facility from $285 million to $165 million. The other terms of this facility were not changed. Progress Energy Carolinas' $285 million three-year credit agreement entered into inJuly 2002 remains in place, for total facilities of $450 million.

On April 25, 2003, PEC announced the redemption of $150 million of First Mortgage Bonds, 7.5% Series, Due March 1.

2023 at 103.22% of the principal amount of such bonds. The date of the redemption will be May 27, 2003, and PEC will fund the redemption through commercial paper.

In March 2003. Progress Genco Ventures, LLC (Genco), a wholly owned subsidiary of PVI, terminated its $50 million wo;orking capital credit facility. The remaining $260 million of Genco's credit facility was not changed.

The Company issued approximately 1.8 million shares representing approximately $74 million in proceeds from its Dividend Reinvestment and Stock Purchase Plan and its employee benefit plans during the three months ended March 31, 2003.

Future Commitment, As of March 31, 2003, Progress Energy's contractual cash obligations and other commercial commitments has not changed materially from what was reported in the 2002 Annual Report on Form 10-K. The only changes in Progress Energy's future commitments involve the additional first quarter 2003 long-term debt issuances that are detailed above.

OTHER MATFERS PEFRate Case Settlement On March 27, 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 on April 23, 2002. The Agreement provides that PEF will operate under a Revenue Sharing Incentive Plan (the Plan) through 2005 and thereafter until terminated by the FPSC.

The Plan provides that all retail base revenues between the established threshold and cap will be shared on a 2/3 -

1/3, customer/shareholder basis. All retail base rate revenues above the retail base rate revenue caps established for each year will be refunded 100% to retail customers on an annual basis. For 2002, the refund to customers was limited to 67.1% of the retail base rate revenues that exceeded the 2002 cap. The retail base revenue cap for 2003 is $1.393 billion and will increase $37 million each year thereafter. As of December 31, 2002, $4.7 million was accrued and was refunded to customers in March 2003. On February 24, 2003, the parties to the Agreement filed a motion seeking an 50

order from the FPSC to enforce the Agreement. In this motion, the parties dispute PEF's calculation of retail revenue subject to refund and contend that the refund should be approximately $23 million. This issue will be addressed by the FPSC in the near future. The Company cannot predict the outcome of this matter.

Synthetic Fuels Tax Credits Progress Energy, through its subsidiaries, produces synthetic fuel from coal fines. The production and sale of the synthetic. fuel from these facilities qualifies for tax credits under Section 29 of the Code (Section 29) if certain requirempnts are satisfied, including a requirerhlent that the synthetic fuel differs -signifteantly i .mrcai composition from the coal used to produce such synthetic fuel. Any synthetic fuel tax credit amounts not utilized are carried forward indefinitely. All of Progress Srtf gy's synthetic fuel facilities have received private letnc rulings (PL-Rs) from the Internal RevenivŽ Service (IRS) wli respect t their synthetic fuel 6perations. These tax cr:edi- art:

subject to e-vr6w by the IRS. arid if Progr:Žss E_eFy fals ib frstl di: mgh the adr.iniP ;i . or lej,ai proreS.

there could be significant ta x liability owed for previously taken ection'29 cdits -withi :;igniilcar himpact o ..

earnings and cash flows. Total Section 29 credits generated to date (including FPC prio t its acquisition by the Company) are approximately $949.9 million.

One synthetic fuel entity, Colona Synfuel Limited Partnership, L.L.L.P. (Colona), from which the Company (and FPC prior to its acquisition by the Company) has been allocated approximately $258 million in tax credits to date, is being audited by the IRS. The audit of Colona was expected. The Company is audited regularly in the normal course of business, as are most similarly situated companies. In September 2002, all of Progress Energy's majority-owned synthetic fuel entities, including Colona, were accepted into the IRS Prefiling Agreement (PFA) program. The PFA program allows taxpayers to voluntarily accelerate the IRS exam process in order to seek resolution of specific issues. Either the Company or the IRS can withdraw from the program at any time, and issues not resolved through the program may proceed to the next level of the IRS exam process. While the ultimate outcome is unceitain, the Company believes that participation in the PFA program will likely shorten the tax exam process. In management's opinion, Progress Energy is complying with all the necessary requirements to be allowed sucl credits under Section 29 and believes it is likely, although it cannot provide certainty, that it will prevail if challenged by the IRS on.any.

-redits taken. 1 e current Section 29 tax credit prograrn expires in 2007.

The Company has retained an advisor to assist in selling an interest in one or more synthetic fuel entities. The Company is pursuing. the sale of a portion of its syntiietic fuel production capacity that is urder .Aili7'd due to liaits on the amount of credits that can be generated and utilized by the Company. The Company would expect to retain an ownership interest and to operate any sold facility for a management fee. The final outcome and timing of these discussions is uncertain and the Company cannot predict the outcome of this matter.

Nuclear Matters Progress Energy's Brunswick Nuclear Plant Unit 2 completed a successful refueling outage on April 6, 2003, when the unit was returned to service. During the outage, the first of two phases of an extended power uprate project for that unit was completed, which added approximately 70 additional megawatts of electricity at the plant.

On August 9, 2002. the NRC issued an additional bulletin dealing with head leakage due to cracks near the control rod nozzles. The NRC has asked 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 October 2002. The Company completed a series of examinations in October 2002 of the entire reactor pressure vessel head and found no indications of control rod drive mechanism penetration leakage and no corrosion of the head itself. During the outage, a boric acid leakage walkdown of the reactor coolant pressure boundary was also completed and no corrosion was found.

The Company currently plans to re-inspect the Robinson Plant reactor head during its next refueling outage in the spring of 2004 and replace the head in the fall of 2005. The Harris Plant is ranked in the lowest susceptibility classification. During the Harris Plant's Spring 2003 outage, the Company completed a series of examinations of the entire reactor pressure vessel head and found no degradation or indication of leakage.

In October 2001 at the Crystal River Plant (CR3). one nozzle was found to have a crack and was repaired: however, no degradation of the reactor vessel head was identified. Current plans are to replace the vessel head at CR3 during its next regularly scheduled refueling outage in 2003.

51

In February 2003, the NRC issued Order EA-03-009, requiring specific inspections of the reactor pressure vessel head and associated penetration nozzles at pressurized water reactors (PWRs). The Company has responded to the Order, stating that the Company intends to comply with the provisions of the Order. No adverse impact is anticipated.

In April 2003, the STP Nuclear Operating Company, an unaffiliated entity, notified the NRC of a potential leak indication on the bottom head of the reactor vessel of one of its inits. The Company is continuing to monitor this development for applicability to our plants arid will take appropriate :ati-ul if and whe-: necessary.

In January 2003, the NRC issued a final order with regard to acess control This oider requires tl:.e Company to enhance its cULrrent access control-ptogram by January 7, 2004. The Company expeczs that it will be in ful -ompliarce wi{h the order by the established deadline.

The NRC contfnues to issue additional orders designed to increase security at nuclea- facilities. In At i1 2003. one of the orders issued by the NRC imposes revisions to the Design Basis Threat and requires power planis o implement additional protective actions to protect against sabotage by terrorists and other- adversaries. fhe Company is currently in the process of reviewing this order and cannot currently predict the potential impact to the Company's financial condition or results of operations. 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.

FranchiseLitigation Six cities, with a total of approximately 49,000 customers, have sued PEF in various circuit courts ir. Florida. 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 io continue to collect from PEF's customers and rernit to the cities, franchise fees during the pending litigation, a.;d as long as PEI continues to occupy the citiesrights-of-way-to provide electric service, notwithstanding the expiatiori oi the franchise ordinances under which PEF had agreed to collect such fees. Five circuit courts have entered orders requiring arbitration to establish the purchase price of PEF's electric distribution system within five cities. Two appellate courts have upheld  :;3e circuit court decisions and authorized cities to etermine the :.alue of PPF's electric distribution system within the cities through arbitration. To date, no city has attempted to actually exercise the option to purchase any portion of PEF's electric distribution system. Arbitration in one of the cases (the City of Casselberry) was held in August 2002 and an award was issued in October 2002 setting the value of PEF's distribution system within that city at approximately $22 million. On April 2, 2003, PEF filed a rate filing with the FERC to recover $10.6 million in stranded costs from the City of Casselberry in the event the City ultimately chooses and is allowed to form a municipal electric utility. PEF has made a settlement proposal. which is scheduled to be voted on by the City Commission on May 12, 2003. At this time, whether and when there will be further proceedings regarding the City cannot be determined. A second arbitration (with the City of Winter Park) was completed in February 2003.

A decision from the arbitration panel has not yet been issued in that case. Two additional arbitrations have been scheduled to occur in the second quarter of 2003 and the first quarter of 2004.

As part of the above litigation, two appellate courts have also reached opposite conclusions regarding whether PEF must continue to collect from its customers and remit to the cities franchise fees" under the expired franchise ordinances. PEF has filed an appeal with the Florida Supreme Court to resolve the conflict between the two appellate courts. The Florida Supreme Court has set oral argument for August 27, 2003. The Company cannot predict the outcome of these matters at this time.

Progress Energy Carolinas, Inc.

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 and OTHER MATTERS.

RESULTS OF OPERATIONS 52

The results of operations for the PEC Electric segment are identical between PEC and Progress Energy. The results of operations for PEC's non-utility subsidiaries for the three months ended March 31, 2003 and 2002 are not material to PEC's consolidated financial statements.

ULUIDITY AND CAPITAL RESOURCES During e first three months of 2003, $15Q rillion was spent on PEC's construcioh prograrri Žcd' T0.? r2nllion was spent on diversified business property additions.

As of Maich 3i, 003, PEC's liquidity, conitractual cash obligatiost and other comrruw 'I .ow aiitm:-s have not changdr-n eaii1yfF..hi 9 isc'prte-l $i e'O0A :u0iAala 2epo; on rcl-K On Apiil I, 2003, PEC reduced the size of its existing 364-day credit facility from $285 million io $165 million. The other terms of this facili,y were not changed. PEC's $285 million three-year credit-agreement entered into in lily 2002 remains in place, for total facilities of $450 million.

On April 25, 2003, PEC announced the redemption of $150 million of First Mortgage Bonds, 7 5% Series, Due March 1, 2023 at 103.22% of the principal amount of such bonds. The date of the redemption will be May 27, 2003, and PEC will fund the redemption through commercial paper.

Item 3. Ouantitative and Oualitative 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 ito in the normal course of business. The Company'. primary expos-ures are changes in interest rates with rc.pect 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 varipus derivative transactions. -

The Company's exposure to return on marketable securities for the decommissioning trust funds has not changed materially since December 31, 2002. The Company's exposure to market value risk with respect to the CVOs has also not changed materially since December 31, 2002.

On February 21, 2003. PEF issued $425 million of First Mortgage Bonds, 4.80% Series, Due March 1, 2013 and $225 million of First Mortgage Bonds, 5.90% Series, Due March 1, 2033.

On March 1, 2003, $70 million of PEF First Mortgage Bonds, 6.125% Series, matured and were retired.

Effective March 24, 2003, PEF redeemed $150 million of First Mortgage Bonds, 8% Series, Due December 1, 2022 at 103.75% of the principle amount of such bonds.

The exposure to changes in interest rates from the Company's fixed rate and variable rate long-term debt at March 31, 2003 has changed from December 31, 2002. The total fixed rate long-term debt at March 31, 2003 was $9.1 billion, with an average interest rate of 6.7% and fair market value of $10 billion. The total variable rate long-term debt at March 31, 2003, was $1.1 billion, with an average interest rate of 1.44% and fair market value of $1.1 billion.

The exposure to changes in interest rates from the Company's commercial paper and FPC mandatorily redeemable securities of trust at March 31, 2003, was not materially different than at December 31, 2002.

Progress Energy Carolinas, Inc.

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 53

trust funds. PEC's exposure to return on marketable securities for the decommission trust funds has not changed materially since December 31, 2002.

In March and April of 2003, PEC entered into treasury rate locks to hedge its exposure to interest rates with regard to a future issuance of debt. These agreements have a computational period of ten years and are designated as cash flow hedges for accounting purposes.

The exposure to changes ir interest rates rom the PEC' fiat rate long-ern debt, variable rate long-term debt and commercial paper at March 31, 2003 was not materially different than at December 31, 2002. In addition, PEC's exposure on the notional amount of interest rate swap arp.eTnentsiused t hedge its exposure on variable rate debt positions at March 31, 2003 was not matei .ally diffei o th.* . ecember 31. OI) .

Item 4 Controls and Procedures Progress Energy. Inc.

Within the 90 days prior to the filing date of this report, Progress Energy carried out an evaluation, under the supervision and with the participation of its management, including Progress Energy's Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation. of Progress Energy's disclosure controls and procedures pursuant to Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934. Based upon that evaluation, Progress Energy's Chief Executive Officer and Chief Financial Officer concluded that its disclosure controls and procedures are effective in timely alerting them to material information relating to Progress Energy (including its consolidated subsidiaries) required to be included in the periodic SEC filings.

Since the date of the evaluation, there have been no significant changes in Progress Energy's internal controls or in other factors that could significantly affect these controls.

Progiess Energy Carolinas. Inc.

Within the 90 days prior to the filing date of this report, PEC carried out an evaluation, under the supervision and with the participation of its management, including PEC's FO and C' ? of the effectiveness of th design ad operation of PEC's disclosure controls and procedures pursuant to Rules 3a-14 and 15d-14 under the Securities Exchange Act of 1934. Based upon that evaluation, PEC's CEO and CFO concluded that its disclosure controls and procedures are effective in timely alerting them to material information relating to PEC (including its consolidated subsidiaries) required to be included in its periodic SEC filings.

Since the date of the evaluation, there have been no significant changes in PEC's internal controls or in other factors that could significantly affect these controls.

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PART II. OTHER INFORMATION Item 1. Legal Proceedings Legal aspects of certain matters are set forth in Part I, Item 1. See Note 15 to the Progress Energy, Inc. Consolidated Interim Financial Statements and Note 9 to the PEC's Consolidated Interim Financial Statements.

-1. Strategic Resource Solutions Corp. ("SRS") v.San.Francisco Unified School District, et al., Sacramento Superior Court, Case No. 02AS033114 -- -

Ir-November of 2001, SRS 'filed a clir against the Sari Francisoo Unified School District Cthe District" and ot1/2r

-defendants claimirig that SRS is entitled' to approximately $10' nillion in unpaid contract paymerts and 1elay n'd.

- Lnpa.t -amages c!atid t' the Digtri'is $30 millio iinttact *it SS. On-March 4, 2002 the S. -iis.rifd - -

counterclaim, seeking compensatory damages and liquidated damages in excess of $120 n:iiihn, or vari3Aus claims,-

including breach of contract and demand on a performance bond. SRS has asserted defenses to the District's claims.

On March 13, 2003, the City Attorney's office announced the filing of-new claims by the City Attorney nd the District in the form of a cross-complaint against SRS, Progress Energy, Inc., Progress Energy Solutions, lc., and certain individuals, alleging fraud, false claims, violations of California statutes, and seeking compensatory damages, punitive damages, liquidated damages, treble damages, penalties, attorneys' fees and injunctive relief. The City Attorney's announcement states that the City and the District seek more than $300 million in damages and penalties.'

The Company has reviewed the District:s earlier pleadings against SRS and believes that those claims are not meritorious. SRS filed its answer to the new pleadings on April 14, 2003. The Company has reviewed the new pleadings and the Company believes that the new claims are not meritorious. The Company will file appropriate responsive pleadings in due course. SRS, the Company and Progress Energy Solutions, Inc. will vigorously defend and litigate all of these claims. The Company cannot predict the outcome of this matter, but the Company believes that it and its subsidiaries have good defenses to all claims asserted by Loth the District and the City.

Item 2. Changes in Securities and Use of Proceeds RESTRICTED STOCK AWARDS:

(a) Securities Delivered. On March 18, 2003, 167,400 restricted shares of the Company's Common Shares were granted to certain key employees pursuant to the terms of the Company's 2002 Equity Incentive Plan (Equity Incentive Plan), which was approved by the Company's shareholders on May 8, 2002. Section 9 of the Plan provides for the granting of Restricted Stock by the Organization and Compensation Committee of the Company's Board of Directors, (the Committee) to key employees of the Company, including its Affiliates or any successor, and to outside directors of the Company. The Common Shares delivered pursuant to the Plan were acquired in market transactions directly for the accounts of the recipients and do not represent newly issued shares of the Company.

(b) Underwriters and Other Purchasers. No underwriters were used in connection with the delivery of Common Shares described above. The common Shares were delivered to certain key employees of the Company. The Plan defines "key employee" as an officer or other employee of the Company who is selected for participation in the Plan.

(c) Consideration. The Common Shares were delivered to provide an incentive to the employee recipients to exert their utmost efforts on the Company's behalf and thus enhance the Company's performance while aligning the employee's interest with those of the Company's shareholders.

(d) Exemption from Registration Claimed. The Common Shares described in this Item were delivered on the basis of an exemption from registration under Section 4(2) of the Securities Act of 1933. Receipt of the Common shares required no investment decision on the part of the recipients. All award decisions were made by the Committee, which consists entirely of non-employee directors.

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Item 6. Exhibits and Reports on Form 8-K (a) Exhibits Exhibit Progress Progress Energy Number DescrPf- .n CaroliLnaLnc.

• 10(i) Progress Energy, Inc. Amended and Restated x x Management Defetred Corlpen ation Plan Adopted as of January 1, 2U00, Revised and Re.,iaed effeictivp January 1 2003 (filed as Exhibit 4.3 to '-'ro Energy Form S -8on May 2, 2003, File No. 333 lt952j.

0(i) Notice, dated March 25, 2003, to the Agent for the lenders x x named in the Carolina Power & Light Company 364-day Revolving Credit Agreement, dated July 31, 2002, of a commitment reduction in the amount of $120,000

• 0(iii) Florida Power Corporation d/b/a Progress Energy Florida, x Inc. 364-Day $200,000,000 Credit Agreement, dated as of April 1, 2003 (filed as Exhibit 10(ii) to Florida Power Corporation Form 10-Q for the quarter ended March 31.

2003).

• l0(iv) Florida Power Corporation d/b/a Progress Energy Florida, x Inc. 3-Year 200,000.000 Credit Agreement, dated as of April 1, 2003 (filed as Exhibit 10('ii) to Florida Power Coiporatioii Forni O-Q for tt,e quiarter ended Mai ch 31, 2003).

99 Certifications pursuant to Section 906 of the Sarbanes- x x Oxley Act of 2002

• Incorporated herein by reference as indicated.

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(b) Reports on Form 8-K with respect to the quarter:

Progress Energv. Inc.

Financial Item Statements Reported Included - Date of Event Date Filed

. 5 No :  :.February 7, 2003 Febiua/U, I?G3 7 Yes- February 18, 2003 February 18. 2003

5. No. April 1; 2003 Aprifl 1OO3 9., Yes -Apr-d 3,2003 -Apri3r-2O(' f Carolina Power & Light Company d/b/a Progress Energy Carolinas. Inc.

Financial Item Statements Reported Included Date of Event Date Filed 5 No January 1, 2003 January 3, 2003 7 Yes February 18, 2003 February 18, 2003 5 No April 1 2003 April 1,2003 9, 12 Yes April 23, 2003 April 23, 2003 57

SIGNATIJRES Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PROQRESS ENERGY INC.

CAROLINA POWER & LIGHT COMPANY Date: May 9, 2003 (Registrants)

By 1s/ Peter M. Scott lIt Peter M. Scott Il Executive Vice President and Chief Financial Officer By: /sl Robert H. Bazemore. Tr Robert H. Bazemore, Jr.

Vice President and Controller Chief Accounting Officer 58

CERTIFICATION PURSUANr TO 18 U.S.C. SECTION 1350, AS ADOPrED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, William Cavanaugh IIL, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Progress Energy, Inc.,

2. Based on my knowledge, this quarterly ieport does not contain any untrue statement of a material fact or oint to state a material fact necessary-to make the statements made, in light of the circumstances imddr which such L`atements were made. not misleading witlh respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included mn this quarterly 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 quarterly 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-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures 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 quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors:

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 9, 2003 /s/ William Cavanaugh III William Cavanaugh III Chairman and Chief Executive Officer 59

CERTICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Peter M. Scott III, certify that:

I I have reviewed this quarterly report on Form 0-Q of Progress Energy, Inc.;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material t

fact necessary to make the statements made, in light of the circumstarcxs under which such statemen s were made, not misleadh11g with respect to the period covefed by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly 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 quarterly 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-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures 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 quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on ouI evaluation as of the Evaluation Date;

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors:

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 9. 2003 /sf Peter M. Scott III Peter M. Scott 111 Executive Vice President and Chief Financial Officer 60

CERTIFICAION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, William Cavanaugh III, certify that:

I I have reviewed this quarterly report on Form 10-Q of Carolina Power & Light Company

.2. Based on my.kn,owledge, this quarterly repoi 'does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements rade, in light of the circdmstances unlder which such statemhents were made, iot misleading.

with respect to the period covered by this quarterly report;-

3. Based on my knowledge, the financial statements, and other-financial information included in this quarterly 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 quarterly 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- 14 and 15d- 14) for the registrant and we have:

a) designed such disclosure controls and procedures 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 quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors:

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 9, 2003 /s/ William Cavanaugh III William Cavanaugh III Chairman and Chief Executive Officer 61

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 1,Peter M. Scott 111, certify that:

I have reviewed this quarterly report on Form 10-Q of Carolina Power & Light Company;

2. Based on my knowledge, this quarterly report does not contain any ntrue statemk fit o f a material fact or omit to state a material -;

fact necessary to make the statements .made, in light of the circumstances under whL;ich stuch statemernts wet e made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information icluded in this quarterly 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 quarterly 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-l 4 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures 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 quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officer and I have disclosed, based-on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors:

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 9. 2003 ls/ Peter M. Scott II Peter M. Scott III Executive Vice President and Chief Financial Officer 62

Exhibit 99 CERTIFICATION FURNISHED PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report on Form 10-Q of Progress Energy, Inc. (the Company") for the period ending March 31, 2003 as filed with the Se ' rities and Exchange Commission on the date hereof (the Report"), I, William Cavanaugh UI. Chairman and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) . the Report fully complieswith the re-idrements of Sertion 13(a) or 5(d) of the Securities Exchange Act of 1934, as amended; and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/sl William Cavanaugh III William Cavanaugh III Chairman and Chief Executive Officer May 9, 2003 A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchlange Commission or its staff upon request.

63

CERTIFICATION FURNISHED PURSUANT TO 13 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report on Form 10-Q of Progress Energy, Inc. (the Company") for the period ending March 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the 'Report"), I, Peter M. Scott II!, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully cornplies with the -equiremepts of Secto.; 13(e x-l5(i) of the Securities Fxchaiige 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/ Peter M. Scott III Peter M. Scott III Executive Vice President and Chief Financial Officer May 9. 2003 A signed original of this written staiment required by Sictijn 906 has ben pyovided to the Company and will be ret'ined by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

64

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 Quarterly Report on Form 10-Q of Carolina Power & Light Company (the "Company') for the period ending March 31. 2003 as filed with the Securities and Exchange Commission on the date hereof (the Report'), I, William Cavanaugh III, Chairman and Chief Executive Officer of the Company, certify. pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 20G2, that:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as .

amendul ; n.d (2.) t}.e information contained i the Report fairly presents, n all material respects, th£ financial condition and rcsult of .

operations of the Company.

Is! William Cavanaugh III William Cavanaugh III Chairman and Chief Executive Officer May 9, 2003 A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

65

CERTIFICATION FURNISHED PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 a rnnectiol witli the Quarterly Report on Form 10-Q of Carolina Potv: ' Light C (the "Corrpany") ft- the p -i.t euiding iraich 31, 2003 as filed vith the Securities waio Exchange 'om mission oilti at:heret (the Rcpo. ;, 1, ter t Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to § 906 of the Saibaries-Oxley Act of 2002, that:

'<epoft ful cornpes witl te Secou1rtineats o1 ŽirŽ i- Vtot nnende:'mld (2') the information contained in the Report fairly presents, in all material respet , financial condition and result of operations ef the Company.

/s/ Peter M. Scott III Peter M. Scott Il Executive Vice President and Chief Financial Officer May 9, 2003 A signed riginal of this written statement required by Section 306 has been pr(ci Ind to the Ci,ryipany and will e retainer' h!\ the uompany dnd uriiished to the Securities and Exchange Commission o its stfI pull eqieAt.

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