ML032471632

Submittal of 10-Q Report

ML032471632
Person / Time
Site:	Brunswick, Robinson
Issue date:	08/22/2003
From:	Groblewski T Progress Energy Carolinas
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
-nr, PE&RAS-03-100
Download: ML032471632 (60)

Text

Mop% ,- .10 CFR 50.75(e)(lXiii)(B)

Qu Prgressnergy PO Box 1551 41 1 Fayetteville Street Mall Raleigh NC 27602 Serial: PE&RAS-03-100 August 22, 2003 United States Nuclear Regulatory Commission ATTENTION: Document Control Desk Washington, DC 20555 I B. ROBINSON STEAM ELECTRIC PLANT, UNIT NO. 2 DOCKET NO. 50-261 I 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 Carolinas, Inc. submits the enclosed quarterly 10-Q Report for Progress Energy, Inc. for the quarterly period ended June 30, 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)(Xiii)(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) 546-4579 ifyou need additional information concerning this report.

Sincerely, Tony Groblewski Supervisor - Regulatory Affairs HAS

Enclosure:

MO'QI

United States Nuclear Regulatory Commission PE&RAS-03-100 Page 2 C:

without enclosure:

L. A. Reyes, Regional Administrator - Region II USNRC Resident Inspector - BSEP, Unit Nos. 1 and 2 USNRC 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 M. A. Dusaniwskyj, USNRC NRR/DRIP/REXB-OWFN, 12 Di J. A. Sanford - North Carolina Utilities Commission

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q XI QUARTERLY REPORT PURSUANT TO SECI7ION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30. 2003 OR I1 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 I.R.S. Employer FileNumber 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 X 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 10-Q is filed separately by two registrants: Progress Energy, Inc. (Progress Energy) and Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC). Information contained herein relating to either individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other registrant.

Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of the latest practicable date. As of July 31, 2003, each registrant had the following shares of common stock outstanding:

Registrant Descdrtion Shya Progress Energy, Inc. Common Stock (Without Par Value) 243,437,696 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 tAROLIN ,S,INC.

FORM 10-Q - For the Quarter Ended June 30,2003 Glossary of Terns Safe Harbor For Forward-Looking Statements PART 1.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 Notes to Consolidated Interim Financial Statements Carolina Power & Light Company d/b/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. Managements 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 11. OTHER INFORMATION Item 1. Legal Proceedings Item 4. Submission of Matters to a Vote of Security Holders Item 6. Exhibits and Reports on Form 8-K Signatures 2

'-Jil

GLOSSARYOFTERMS The following abbreviations or acronyms used in the text of this combined Form IO-Q are defined below:

3IM PE1mrlQO AFUDC Allowance for funds used during construction the Agreement Stipulation and Settlement Agreement ARO Asset retirement obligations Bcf Billion cubic feet Cco Competitive Commercial Operations the Code Internal Revenue Service Code Colona Colona Synfuel Limited Partnership, L.L.L.P.

the Company Progress Energy, Inc. and subsidiaries CP&L Energy CP&L Energy, Inc., now known as Progress Energy, Inc.

CPI Consumer Price Index CR3 Progress Energy Florida's nuclear generating plant, Crystal River Unit No. 3 CVO Contingent value obligation 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 EITF Emerging Issues 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 Federal Circuit U.S. Circuit Court ofAppeals FERC Federal Energy Regulatory Commission FIN No. 46 FASB Interpretation No. 46, "Consolidation of Variable Interest Entities - An Interpretation of ARB No. 5I" FPC Florida Progress Corporation FPSC Florida Public Service Commission Funding Corp. Florida Progress Funding Corporation 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 NSP Northern States Power 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 PFA IRS Prefiling Agreement the Plan Revenue Sharing Incentive Plan PIRs Private Letter Rulings Preferred Securities FPC-obligated mandatorily redeemable preferred securities Progress Energy Progress Energy, Inc.

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Progress Rail Progress Rail Services Corporation Progress Telecom Progress Telecommunications Corporation 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'ehtity of Progress Ventures, Inc., formerly referred to as CPL Energy Ventures, Inc.

PWR Pressurized water reactor RAFT Railcar Asset Financing Trust Rail Rail Services 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 Section 42 Section 42 of the Internal Revenue Service Code

-Service Company Progress Energy Service Company, LLC SFAS No. 5 Statement of Financial Accounting Standards No. 5, "Accounting for Contingencies" SFAS No. 71 Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" SFAS No. 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" SPAS No. 150 Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial Instruments with Characteristics ofBoth Liabilities and Equity" SMD NOPR Notice of Proposed Rulemaking in Docket No. RMOI-12-000, 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 FOWARD-lOOKING STATEMET This combined report contains forward-looking statements within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, The matters discussed throughout this combined Form 10-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 we 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 environmental 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. (PEC) undertakes any obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made.

Examples of factors that you should consider with respect to any forward-looking statements made throughout this document include, but are not limited to, the following: the impact of fluid and complex government laws and regulations, including those relating to the environment; the impact of recent events in the energy markets that have increased the level of public and regulatory scrutiny in the energy industry and in the capital markets; deregulation or restructuring in the electric industry that may result in increased competition and unrecovered (stranded) costs; the uncertainty regarding the timing, creation and structure of regional transmission organizations; weather conditions that directly influence the demand for electricity 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 outcome of the IRS's audit and inquiry into the availability and use of Section 29 tax credits by synthetic fuel producers and the Company's continued ability to use Section 29 tax credits related to its coal and synthetic fuels businesses; the continued depressed state of the telecommunications industry and the Company's ability to realize future returns 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; the Company's ability to obtain an extension of the Securities and Exchange Commission's order requiring us to divest of Progress Rail Services Corporation by November 30, 2003; and unanticipated changes in operating expenses and capital expenditures. Most of these risks similarly impact the Company's subsidiaries including PEC.

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 were filed with the SEC on March 21, 2003. All such factors are difficultto predict, contain uncertainties that may materially affect actual results and may be beyond the control of Progress Energy and PEC.

New factors emerge from time to time, and it is not possible for management to predict all such factors, nor can it assess the effect of each such factor on Progress Energy and PEC.

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. i. F  : F PART I. FINANCLAL INFORMATION ItenI1I Financial Statements Progress Energy, Inc.

CONSOLIDATED INTERIM FINANCIAL STATEMENTS June 30, 2003 CONSOLIDATED STATEMENTS OF INCOME Three Months Ended WSkMonths Ended (Unaudited) June 30, June 30, (in thousands except per share data) '2003 2002 2003 2002 Operating Revenues Ulilly S 1,582,787 $ 1,600,581 S 3,236,674 $ 3,098,503 Diversified business 429,897 368,274 792,015 647.653 Total Operating Revenues 2,012,684 1,968,855 4,028,689 3,746,156 Operating Expenses Utilty Fuel used hI electric generation 393,331 366,757 804,954 736,809 Purchased power 209,825 224,685 412,S67 405,958 Operation and maintenance 364,766 346,358 699,079 675,332 Depredation and amortization 223,595 210,485 443,683 422,373 Taxes other than on income 94,445 93,306 197,278 189,227 Diversified business Cost of sales 379,710 347,438 686,651 647,963 Depredation and amortization 33,680 29,329 61,94A 56,664 Other 38,996 35,209 89,254 64,562 Total Operating Expenses 1,738,349 1,653,567 3,395,414 3,198,888 Operating Income 274,335 305,288 633,275 547,268 Other Income (Expense)

Interest income 3,531 6,153 6,297 8,106 Other, net (9,432) (2,340) (11,883) 3,718 Total Other Income (Expense) (5,001) 3.813 (5,586) 11,824 Income before Interest Charges and Income Taxes 268,434 309,101 627,689 559,092 Interest Charges Net interest charges 159,520 170,161 315,768 340,330 Allowance for borrowed funds used during construction (2,222) (3,353) (5,109) (6,906)

Total Interest Charges, Net 157,298 166,808 310,659 333,424 Income from Continuing Operations before Income 111,136 142,293 317,030 225,668 Tax Income Tax Expense (Benefit) (39,174) 20,360 p30,146) (20,326)

Income from Continuing Operations 150,310 121,933 347,176 245,994 Discontinued Operations, Net of Tax 2Z513 (1,313) 13,803 7,153 Net Income $ 152,823 $ 120,620 $ 360,979 $ 253,147 Average Common Shares Outstanding 236,057 215,007 234,755 213,999 Basic Earnings per Common Share Income from Corn ing Operations S 0.64 0.57 $ 1A48 $ 1.15 Discontinued Operations, Net of Tax S 0.01 S (0.01) $ 0.06 $ 0.03 Net income $ 0.65 $ 0.56 S 1.54 $ 1.18 Diluted Earnings per Common Share incomefromContinulngOperations $ 0.63 $ 0.56 $ 1.47 $ 1.15 Discontinued Operaftons, Net of Tax $ 0.01 $ 0.00 S 0.06 $ 003 Net income S 0.64 $ 0.56 S 1.53 $ 1.18 Dividends Declared per Common Share $ 0.560 S 0.545 S 1.120 S 1.090 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) June 30, December 31, Assets 2003 2002 Utility Plant Utility plant In service $ 20,991,295 $ 20,152,787 Accumulated depreciation (9,990,819) (10,480,880)

Utility plant In service, net 11,000,476 9,671,907 Held for future use 12,864 15,109 Construction work In progress 842,520 752,336 Nudear fuel, net of amortization 234,515 216,882 Total Utility Plant, Net 12,090,375 10,656,234 Current Assets Cash and cash equivalents 45,654 61,358 Accounts receivable 824,233 737,369 Unbilled accounts receivable 217,586 225,011 Inventory 546,928 875,485 Deferred fuel cost 277,480 183,518 Assets of discontinued operations 491,784 490,429 Prepayments and other current assets 213,209 260,804 Total Current Assets -2916,874 2,833,974 Deferred Debits and Other Assets Regulatory assets 640,891 393,215 Nuclear decommissioning trust funds 861,752 796,844 Diversified business property, net 2,213,623 1.884,271 Miscellaneous other property and Investments 443,428 463,776 Goodwill 3,719,327 3,719.327 Prepaid pension costs- 57,919 60,169 Other assets and deferred debits 684,764 517,182 Total Deferred Debits and Other Assets 8,621,704 7,834,784 Total Assets $ 23,628,953 S 21,324,992 Capitalization and Liabilities Common Stock Equity Common stock without par value, 500,000,000 shares authorized, 242,187,774 and 237,992,513 shares Issued and outstanding, respectively - $ 5,109,564 $ 4,929,104 Unearned ESOP common stock (88,734) (101,560)

Accumulated other comprehensive loss (240,508) (237,762)

Retained earnings 2,182,440 2,087,227 Total Common Stock Equity 6,962,762 6,677,009 Preferred Stock of Subskidaries-Not Subject to Mandatory Redemption 92,831 92,831 Long-Term Debt 9,223,632 9,747,293 Total Capitalization 16,279,225 16,517,133 i Current Uabilities Current portion of long-term debt 1,130,308 275,397 Accounts payable 606,658 756,287 Interest accrued 222,896 220,400 Dividends declared 135,280 132,232 Short-term obligations 858,991 694,850 Customer deposits 161,539 158,214 1.abllities of discontinued operations 119,058 124,767 Other current liabilities 478,419 350,132 Total Current Liabilities 3,713,149 2,712,279 Deferred Credits and Other Liabilitles Accumulated deferred Income taxes 824,961 932,813 Accumulated deferred investment tax credits 198,098 206,221 Regulatory lbiliies 542,210 119,766 Asset retrement obligations 1,225,605 Other liabilities and deferred credits 845,705 836,780 Total Deferred Credits and Other Liabilities 3,636,579 2,095,580 Commitments and Contingencies (Note 15)

Total Capitalization and Liabilities $ 23,628,953 $ 21,324,992 See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.

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I-W Progress Energy, Inc.

CONSOLIDATED STATEMENTS OF CASH FLOWS Six Months Ended (Unaudited) June 30.

(In thousands) 2003 2002 Operating Activities Net income $ 360,979 $ 253,147 Adjustments to reconcile net Income to net cash provided by operating activities:

Income from discontinued operations (13,803) (7,153)

Depredation and amortization 568,328 567,106 Deferred income taxes (118,442) (44,234)

Investment tax credit (8,123) (10,126)

Deferred fuel cost (credit) (93,962) 22,718 Net increase in accounts receivable (85,314) (35,229)

Net (Increase) decrease in Inventories 26,591 (38,637)

Net (ncrease) decrease in prepayments and other current assets 23,120 (14.993)

Net decrease hI accounts payable (15,332) (62,655)

Net Increase in income taxes, net 104,997 78,837 Net increase in other current liabilities 52,538 30,661 Other - 92,666 39,896 Net Cash Provided by Operating Activities 694,243 779,338 Investing Activities Gross utility property additions (541,205) (520,872)

Diversified business property additions and acquisitions (366,494) (627,042)

Nuclear fuel additions (84,050) (49,346)

Net contributions to nudear decommissioning tbust (17,959) (19,917)

Investments in non-utility activities (5,792) (10,301)

Acquisition of intangibles (190,168)

Net decrease (Increase) In restricted cash - 16,784 (105,721)

Other (1,136) 5,257 Net Cash Used In Investng Activities (1,190,020) (1,327,942)

Financing Actlestes issuance of common stock, net of issuance costs - 171,771 Purchase of restricted shares (6,560) (5,393)

Issuance of long-tenn debt net of issuance costs 654,824 1,013,633 Net increase hi short-term indebtedness 163,092 14,499 Net decrease In cash provided by checks drawn In excess of bank balances (43,707) (33,605)

Retrement of long-term debt (392,054) (108,381)

Dividends paid on common stock (267,608) (238.404)

Other 815 47,407 Net Cash Provided by Financing Activities 280,573 689,756 Cash Used in Discontinued Operations (500) (584)

Net Increase (Decrease) In Cash and Cash Equivalents (15.704) 140,568 Cash and Cash Equivalents at Beginning of the Period 61 358 53,708 Cash and Cash Equivalents at End of the Period $ 45,654 $ 194,276 Supplemental Disclosures of Cash Flow Information Cash paid during the year - interest (net of amount capitalized) $ 305,206 $ 324,234 Income taxes (net of refunds) $ 22,241 $ 15,977 Noncash Activities

• On April 26, 2002, Progress Fuels Corporation, a subsidiary of the Company, acquired 100% of Westchester Gas Company. In conjunction with the purchase, the Company issued approximately $129.0 million in common stock.

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

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Progress Energy, Inc.

NOTES TO CONSOLIDATED INTERIM iiACIAL STATEMENS-

. ORGANZATION AND BASIS OF PRESENTATION A. Organization Progress Energy, Inc. (Progress Energy or 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, Carolina Power & Light Company, Florida Power Corporation and Progress Ventures, Inc. (PVI) began doing business under the names Progress Energy Carolinas, Inc. (PEC), Progress Energy Florida, Inc. (PEF) and Progress Energy Ventures, Inc., respectively. The legal names of these entities have not changed, and there was no restructuring of any kind related to the name change. The current corporate and business unit structure remains unchanged.

Through its wholly owned subsidiaries, Progress Energy Carolinas, Inc. and Progress Energy Florida, Inc., 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 financial reporting of the Progress Ventures business unit. Whether, and when, the legal and functional structures will converge depends upon legislative and regulatory action, which cannot currently be anticipated.

B. Basis of Presentation 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 GAAP, 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 December31, 2002.

In accordance with the provisions of APB 28, GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. Income tax expense was increased by $4.8 million and $58.4 million for the second quarter of 2003 and 2002, respectively, in order to maintain an effective tax rate consistent with the estimated annual rate. Income tax expense was decreased by $5.4 million and increased $79.6 million for the first half of 2003 and 2002, respectively.

The amounts included in the consolidated interim financial statements are unaudited but, in the opinion of management, reflect all normal recurring 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 or future periods.

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. Certain amounts for 2002 have been reclassified to conform to the 2003 presentation.

2. ACQUISfITONS 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 (Bcf) 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 Gas, L.P., a wholly owned subsidiary of Progress Fuels Corporation. The cash purchase price for the transactions totaled $148 million.

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On May 31, 2003, PVI acquired fromi Williams Energy Marketing and Tradini; a subsidiary of the Williams Companies, Inc.,

a long-term full-requirements power supply agreement at fixed prices with Jackson Electric Membership Corp. (Jackson), for

$188.2 million. See Note 7 for additional information.

3. DIVESrJlTUES 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. By order issued June 26, 2003, the North Carolina Utilities Commission (NCUC) approved the Company's application to sell NCNG to Piedmont Natural Gas Company, Inc. The closing of the acquisition is subject to the approval of the Securities and Exchange Commission (SEC).

The sale is expected to close during the summer of 2003. Net proceeds from the sale will be used to pay down debt obligations.

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 has been allocated to discontinued operations based on the net assets of NCNG, assuming a uniform debt-o-equity ratio across the Company's operations. Interest expense allocated for the three months ended June 30, 2003 and 2002 was $3.3 million and $4.0 million, respectively. Amounts allocated for the six months ended June 30, 2003 and 2002 were $6.9 million and $8.0 million, respectively, The Company ceased recording depreciation upon classification of the assets as discontinued operations. After-tax depreciation expense recorded by NCNG during the second quarter of 2002 was $2.9 million and during the first half of 2002 was $5.8 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. The estimated loss is reviewed quarterly and will be finalized once the disposition is complete and the actual loss can be determined. Results of discontinued operations were as follows:

Three Months Ended Six Months Ended June 30, June 30, (in thousands) 2003 2002 2003 2002 Revenues _5S70,815 $ 64,510 $ 225,041 150,625 Earnings (loss) before income taxes 5 4,119 $ (5,514) S 22,602 S 8,522 Income tax expense (benefit) 1,606 (4,201) - ,799 1,369 Net earnings (loss) from discontinued operations S2,513 $ (1,313) S 13,803 S 7,153 The major balance sheet classes included in assets and liabilities of discontinued operations in the Consolidated Balance Sheets are as follows:

June 30, December 31, (in thousands) 2003 2002 Utility plant, net S 403,515 S 398,931 Current assets 69,743 72,821 Deferred debits and other assets 18,526 18,677 Assets of discontinued operations S 491,784 $ 490,429 Current liabilities $ 68,884 $ 76,372 Deferred credits and other liabilities 50,174 48,395 Liabilities of discontinued operations S 119,08 S 124,767 The Company's equity investment in ENCNG of $7.7 million as of June 30, 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 to write-down the assets to fair value less costs to sell.

The assets of Railcar Ltd. have been grouped as assets held for sale and are included in other current assets in the accompanying Consolidated Balance Sheets as of June 30,2003. The assets are recorded at $24.0 million and $23.6 million as of June 30,2003 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. IN L 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 reflect 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 PEC Electric and PEF segments are engaged in the generation, 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 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, which are located in the United States, include natural gas drilling and production, coal mining and terminals, and the production of synthetic fuels.

CCO operations, which are located in the United States, include nonregulated electric generation operations and limited trading activities. The increase in revenue and income from continuing operations for the six months ended June 30,2003 is primarily due to a tolling agreement termination payment from Dynegy.

Rail operations include railcar repair, rail parts reconditioning and sales, railcar leasing (primarily through Railcar Ltd.) and sales, and scrap metal recycling. These activities include maintenance and reconditioning of salvageable scrap components of railcars, locomotive repair and right-of-way maintenance. Rail's primary operations are located in the United States, with limited operation in Mexico and Canada.

/

Other primarily includes operations in the United States of Progress Telecommunications Corporation and Caronet, Inc.

(collectively referred to as Progress Telecom) and other nonregulated subsidiaries that do not meet the disclosure requirements of SFAS No. 131, "Disclosures about Segments ofan Enterprise and Related Information."

The Company's corporate operations include the operations of the holding company, Progress Energy Service Company, LLC 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 NCNG are not included as an operating segment.

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

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Income from Revenues Contlauln 3

Unaffiliate Operations (in thousands) d Intersegment Total Three Months Ended June 30. 2003 PEC Electric S 316,240 S 816,240 S 88,394 766,547 766,547 61,359 Fuels 166,918 89,361 256,779 53,807 CCO 33,2S3 33,283 2,383 Rail 213,740 213,740 2,192 Other 15,903 1,460 17,363 1,200 Corporate 53 (91,321) (91,268) (59,025)

Consolidated totals S 2,012,684 S _ S2,012,684 S 150,310 Three Months Ended lune 30. 2002 PEC Electric S 834,658 S _ S 834,658 S 131,690 PEF 765,923 765,923 76,753 Fuels 112,558 74,896 187,454 46,729 CCO 23,902 23,902 6,738 Rail 196,489 196,489 2,947 Other 25,325 1,454 26,779 (8,353)

Corporate (76,350) (76,350) (134,571)

Consolidated totals S 1,958,855 S - S 1,958,855 S 121,933 Income from Revenues Continuin Unafillte Operations (in thousands) d Interserment Total Assets Six Months Ended June 30. 2003 S 1,741,710 S S 1,741,710 S 223,264 S PEC Electric 9,568,769 PEF 1,494,964 1,494,964 132,116 5,912,152 Fuels 297,769 - 174,068 471,837 80,385 1,215,374 CCO ; 70,833 70,833 10,909 1,712,985 Rail 391,549 391,549 (1,204) 503,897 Other 31,753 2,957 34,715 1,869 305,53S Corporate 106 (177,025) (176.919) (100.163) 3.918.457 S4,028,689 S _ S 4,028,689 S 347,176 S Consolidated totals 23.137.169 S 1,646,139 S S 1,646,139 S 217,222 S PEC Electric 8,669,993 PEF 1,452,364 1,452,364 134,496 4,967,998 Fuels 215,824 150,003 365,827 88,324 963,109 CCO 32,949 32,949 4,627 1,277,824 Rail 351,456 351,456 2,246 607,617 Other 47,424 2,908 50,332 (13,202) 803,837 Corporate (152,911) (152,911) (187,719) 4,008,041 S 3,746,156 S S 3,746,156 S 245,994 S Consolidated totals 21,298,419

5. IMPCTOFNE ACONTNGSTNDRD SFASNo. 148. "Accounting for Stock-Based Compensoon" The Company measures comp ensation expense for stock options as the difference between the market price of its common stock and the exercise price of the option at the grant date. Accordingly, no compensation expense has been recognized for stock option grants.

For purposes of the pro forma disclosures required by SFAS No. 148, "Accounting for Stock-Based Compensation -

Transition and Disclosure - an Amendment of FASB Statement No. 123," the estimated fair value of the Company's stock 12

options is amortized to expense ovef the options' vesting period. The Company's information related to the pro forma impact on earnings and earnings pei share assuming stock options were exeiinsed for the three and six months ended June 30 is as follows:

(in thousands except per share data) Three Months Ended June 30, Six Months Ended June 30, 2003 2002 2003 2002 Net income, as reported $152,823 $ 120,620 $ 360,979 $ 253,147 Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects 1,697 1,320 4,276 3,112 Pro form net income $151,126 $ 119,300 $356,703 $250,035 Basic earnings per share As reported S 0.65 $ 0.56 S 154 $ 1.18 Pro forma S 0.64 $ 0.S5 S 1.52 $ 1.17 Fully diluted earnings per share As reported $ 0.64 S 0.56 S 1.53 S 1.18 Pro formna S 0.64 $ 0.55 S 1.51 $ 1.16 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 resolved by the FASB is the determination of the appropriate fair value measure. The FASB continues to deliberate additional- issues in this project; however, the FASB plans to issue an exposure draft in 2003 that could become effective in 2004.

DerivativeInstruments and Hedinr'Activities In April 2003, the FASE issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instrunients and Hedging Activities." The statement amends and clarifies SFAS No. 133 on accounting for derivative instrumnents, 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.

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 Derivative 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 late June 2003, the FASB issued final superseding guidance (DIG Issue C20) on this issue, which is significantly different from the tentative superseding guidance that was issued in April 2003. The new guidance is effective October 1,2003 for the Company. DIG Issue C20 specifies new pricing-related criteria for qualifying as a normal purchase or sale, and it requires a special transition adjustment as of October 1, 2003.

PEC has determined that it has one existing "normal contract that is affected by this revised guidance. PEC is in the process of evaluating the revised guidance and related contract to determine the transition adjustment that will be necessary and to determine if the contract will be required to be recorded at fair value subsequent to October 1,2003.

SFASNo. 150. "Accountingfor CertainFinancialInstruments with Characteristicsof Both Liabilitiesand Eguity" In May 2003, the FASB issued SWAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. The financial instruments within the scope of SEAS No. 150 include mandatorily redeemable stock, obligations to repurchase the issuer's equity shares by transferring assets, and certain obligations to issue a variable number of shares. SFAS No. 150 is effective immediately for such financial instruments entered into or modified after May 31,2003, and is effective for previously issued financial instruments within its scope on July 1,2003.

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Upon the Company's adoption of the fIN No.46, "Consolidation of Variableinteest Entities" (see below), the FPC Capital I Preferred Securities, as discussed mnNote 12, are anticipated to be deconsolidated from the Company's financial statements effective July 1, 2003. Therefore, the Company does not expect the adoption of SFAS No. 150 to have a material impact on its financial position or results of operations.

FIN No. 46. "Consolidationof Variable Interest Entiies" 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 six months 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 expected, the maximum cash obligations under these arrangements total approximately S54 million. However, management believes the maximum loss exposure would be significantly reduced based on the current fair values of the underlying assets related to these arrangements.

In addition, the Company is also evaluating certain other investments to determine if they require consolidation or disclosure upon adoption of FIN No. 46. These include investments in approximately 50 Affordable Housing properties eligible for Section 42 tax credits of the Internal Revenue Service Code (Section 42). The Company divested approximately 30 of these Affordable Housing investments in July 2003, and therefore the application of FIN No. 46 is not expected to have a material impact with respect to these 30 investments. It is reasonably possible that the Company will be required to consolidate some of the remaining 20 Affordable Housing entities that are currently accounted for under the equity method. The maximum exposure to loss as a result of the Company's total finding commitments for the remaining 20 Affordable Housing investments is approximately $23.9 million. However, management believes the total loss of its investments is unlikely given the nature of the investments and the utilization of certain Section 42 tax credits to date.

The implementation of FIN No.46 may require deconsolidation of certain previously consolidated entities. Upon adoption, the company anticipates deconsolidating the FPC Capital I Trust, which holds FPC-obligated mandatorily redeemable preferred securities. The Company will reflect it subordinate note obligation to the Trust as detailed in Note 12. Therefore, the deconsolidation is not expected to have a material effect.

The Company is in the final stages of completing the adoption of FIN No. 46, but having considered the facts described herein, does not expect the results to have a material impact on its consolidated financial position, results of operations or liquidity.

EITFIssueNo. 03-04. "Accounting for 'Cash Balance'PensionPlans" In May 2003, the EITF reached consensus in EITF Issue No. 03-04 to specifically address the accounting for certain cash balance pension plans. The consensus reached in EITF Issue No. 03-04 requires certain cash balance pension plans to be accounted for as defined benefit plans. For cash balance plans described in the consensus, the consensus also requires the use of the traditional unit credit method for purposes of measuring the benefit obligation and annual cost of benefits earned as opposed to the projected unit credit method. The Company has historically accounted for its cash balance plans as defined benefit plans; however, the Company is required to adopt the measurement provisions of EITF 03-04 at its cash balance plans' next measurement date of December 31, 2003. Any differences in the measurement of the obligations as a result of applying the consensus will be reported as a component of actuarial gain or loss. The Company is currently evaluating what effects EITF 03-04 will have on its results of operations and financial position.

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6. ASSET EIREMENTOBULGATIO 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 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 was recorded 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

$861.8 million at June 30,2003 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 impact on earnings related to accretion and depreciation was not significant for the three or six months ended June 30, 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 ARO liability is not estimable for such easements as the Company intends to utilize these properties indefinitely. In the event the Company decides to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time.

The utilities have previously recognized removal costs as a component of depreciation in accordance with regulatory treatment. As of June 30, 2003, the portions of such costs not representing AROs under SFAS No. 143 were $882.6 million for PEC, $940.1 million for PEF and $39.2 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 June 30, 2003 were $63.5 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 June 30, 2003, this amounted to $142.2 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.

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PEC filed a request with the NCUCrequesting deferral of the difference between expense pursuant to SFAS No. 143 and expense as previously dbtermin d by the NCUC. The NCUC granted the deferral of the January 1, 2003 cumulative adjustment. Because the clean air legislation discussed in Note 15 under "Air Quality" contained a prohibition against cost deferrals unless certain criteria are met, the NCUC denied the deferral of the ongoing effects. The Company has provided additional information to the NCUC that it believes will demonstrate that deferral of the ongoing effects should also be allowed. Since the NCUC order denied deferral of the ongoing effects, PEC ceased deferral of the ongoing effects during the second quarter for the six months ended June 30, 2003 related to its North Carolina retail jurisdiction. Pre tax income for the three and six months ended June 30, 2003 increased by approximately $13.6 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 SPAS No. 143 as regulatory assets or regulatory liabilities, which was accepted by all parties. The Commission approved the draft rule in June 2003, and a final order is expected in the third quarter of 2003.

7. GOODWILL AND OTHER INTANGIBLE ASSETS 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. The Company performed the annual goodwill impairment test for the CCO segment in the first quarter of 2003, and the annual goodwill impairment test for the PEC Electric and PEF segments in the second quarter of 2003, both of which indicated no impairment.

During 2002, the Company acquired Westchester GasCCompany (Westchester). The purchase-price was finalized during the first quarter 2003 with the purchase price being primarily allocated to fixed assets including oil and gas properties. No goodwill was recorded.

The carrying amounts of goodwill at June 30,2003, by reportable segment, are $19 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 June 30, 2003 and December 31, 2002 are as follows:

June 30, 2003 December 31, 2002 (in thousands) Gross Carrying Accumulated Gross Carrying Accumulated Amount Amortization Amount Amortization Synthetic fuel intangibles S 140,469 S(54,717) S 140,469 5(45,189)

Power agreements 221,192 (10,073) 33,000 (5,593)

Other 53,182 (9,453) 40,968 (7,792)

Total $ 414,843 $(74,243) S 214,437 S(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.

On May 31, 2003, PVI acquired from Williams Energy Marketing and Trading, a subsidiary of The Williams Companies, Inc., a long-term fiul-requirements power supply agreement at fixed prices with Jackson, located in Jefferson, Georgia for

$188.2 million. Assignment of Williams' responsibilities under the contract began in June 2003 and terminates in 2015, with a first refusal option to extend for five years. The agreement includes the use of 640 megawatts (MW) of contracted Georgia System generation comprised of nuclear, coal, gas and pumped-storage hydro resources. The intangible related to 16

this power agreement is being amortized based on the economic benefits of the contract. As part of the acquisition of generating assets from LG&E Energy Corp. on February 15, 2002, power agreements of $33 million were recorded and are amortized based on the economicbei6fits of the contracts through December 31, 2004, which approximates straight-line.

Other intangibles are primarily customer contracts and permits that are amortized over their respective lives. Of the increase in other intangible assets, $9.2 million relates to customer contracts acquired as part of the Westchester acquisition, which was identified as an intangible in the final purchase price allocation.

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 June 30, 2003 and 2002, respectively, was

$8.5 million and $8.1 million. Amortization expense recorded on intangible assets for the six months ended June 30, 2003 and 2002, respectively, was $15.7 million and $16.2 million. The estimated amortization expense for intangible assets for 2003 through 2007, in millions, is approximately $36.7, S41.3, $34.8, $35.9 and $36.1, respectively.

8. COMPREHENSIVEINCOME Comprehensive income for the three and six months ended June 30,2003 was $150.6 million and $358.2 million, respectively.

Comprehensive income for the three and six months ended June 30,2002 was $119.6 million and $256.4 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. FNANCING ACTIVIC 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, and to redeem the aggregate outstanding balance of its 8% First Mortgage Bonds Due 2022.

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.

In March 2003, Progress Genco Ventures, LLC. (Genco), a wholly owned subsidiary of PVI, terminated its $50 minion working capital credit facility. A related construction facility initially provided for Genco to draw up to $260 million. The amount outstanding under this facility is $241 million as of June 30, 2003. During the second quarter of 2003 Genco determined it did not need to make any additional draws under this facility. As a result of this decision, the drawn amount of$241 million will not increase.

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 maximumn total debt to total capital ratio of 65%; as of June 30,2003 the calculated ratio was 52.6%. 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 June 30,2003 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. On July 30, 2003, PEC renewed its $165 million 364-day credit agreement. PEC's

$285 minlion three-year credit agreement entered into in July 2002 remains in place, for total facilities of $450 million.

On May 27,2003, PEC redeemed $150 million of First Mortgage Bonds, 7.5% Series, Due March 1, 2023 at 103.22% of the principal amount of such bonds; PEC funded the redemption with commercial paper.

On July 14, 2003, PEC announced the redemption of $100 nillion of First Mortgage Bonds, 6.875% Series Due August 15, 2023 at 102.84%. The date of the redemption will be August 15,2003. PEC will fund the redemption with commercial paper.

For the three months ended June 30,2003, the Company issued approximately 2.4 million shares representing approximately

$98 million in proceeds from its Investor Plus Stock Purchase Plan and its employee benefit plans during the second quarter. For the six months ended June 30,2003, the Company has issued 42 million shares through these plans, resulting in approximately $172 million of cash proceeds.

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10. RISK MANAGEMENT ACIVETikS AND DERIVATIVE TRANSACTIM 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 bad been designated as cash flow hedges for accounting purposes.

Progress Energy currently has 850 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 pay a floating rate based on 3-month LIBOR. These agreements expire in March of2006, April 2007 and October 2008.

In March, April and June 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 $60 million.

Progress Fuels Corporation periodically enters into derivative instruments to hedge its exposure to price fluctuations on natural gas sales. As of June 30,2003, Progress Fuels Corporation had approximately 16.6 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 drawn 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 interest rate derivative agreements with banks with credit ratings of single A or better.

1.EARNINGS PER COMMON 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 June 30, Six Months Ended June 30, 2003 2002 2003 2002 Weighted-average common shams - basic 236,057 215,007 234,755 213,999 Restricted stock awards 1,004 734 967 690 Stock options 140 333 23 224 Weighted-average shares -- fully dilutive 237,201 216,074 235,745 214,913 18

12. FPC-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURMTES OF A SUBSIDIARY HOLDING SOLELY FPC GUARANTEEDNOTES  ;,f.

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 Interest Notes (subordinated notes) due 2039, for a principal amount of $309.3 million. The subordinated notes and the Notes Guarantee (as discussed below) are the sole assets of the Trust. Funding Corp.'s proceeds from the sale of the subordinated notes were advanced to Progress Capital and used for general corporate purposes including the repayment of a portion of certain outstanding short-term bank loans and commercial paper.

FPC has fully and unconditionally guaranteed the obligations of Funding Corp. under the subordinated notes (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 Conpany's Consolidated Balance Sheets. Upon adoption of FIN No. 46, the Company anticipates deconsolidating the FPC Capital I Trust which is not expected to have a material effect on the consolidated financial position, results of operations or liquidity (See Note 5).

13. REGULATORYMATTERSI 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. In September 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 (See Note 3A).

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 19

from the FPSC to enforce the Agreement. In this motion, the parties disputed PEF's calculation of retail revenue subject to refund and contended that the refund should be approximately $23 million.;. On July 9,2003, the FPSC ruled that PEF must provide an additional 18.4 million to its retail customers related to the 2002 revenue sharing calculation. PEF recorded this refund in the second quarter of 2003 as a charge against electric operating revenue and will refund this amount by no later than October 31, 2003. In the second quarter of 2003, PEF also recorded an additional accrual of $9.5 million related to estimated 2003 revenue sharing.

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 recent 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 (RTOs). This Order set minimum characteristics and functions that RTOs must meet, including independent transmission service. As a result 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. In July 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. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). If adopted as proposed, the rules set forth in the SMD NOPR would materially alter the manner in which transmission and generation services are provided and paid for. PEF and PEC, as subsidiaries of Progress Energy, filed comments on November 15,2002 and supplemental comments on January 10,2003. On April 28,2003, the FERC released a White Paper on the Wholesale Market Platform. The White Paper provides an overview of what the FERC currently intends to include in a final rule in the SMD NOPR docket. The White Paper retains the fundamental and most protested aspects of SMD NOPR, including mandatory RTOs and the FERC's assertion of jurisdiction over certain aspects of retail service. 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 a final rule after Congress votes this fall on the proposed House and Senate Energy Bills.

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 $31.2 million and an immaterial amount invested in GridSouth and GridFlorida, respectively, at June 30, 2003. It is unknown what impact the future proceedings will have on the Company's earnings, revenues or prices.

In October 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. On June 2,2003 the Florida Supreme Court dismissed the appeal without prejudice on the ground that certain portions of the Commission's order constituted non-final action. The dismissal is without prejudice to any party to challenge the Commission's order after all portions are final. A technical conference for the state of Florida to be conducted by the FERC is scheduled for September 15.-2003. 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 NCOME AND OTHER EN 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 are as follows:

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Three Months Ended June 30, Six Months Ended June 30, (in thousands) 2003 2002 2003 2002 Other income Net financial trading gain (loss) $ 67 $ 792 S (2,632) S (1,429)

Net energy brokered for resale (1,369) 124 157 (141)

Nonregulated energy and delivery services income 5,652 5,862 11,242 12,459 Contingent value obligation mark-to-market (1,677) 1,479 12,821 Investment gains 2,960 2,960 AFUDC equity 4,035 1,833 5,914 4,077 Other 5,299 7,905 10,937 13,049 Total other income S 12,007 $ 20,955 $ 25,618 S 43,796 Other expense Nonregulated energy and delivery services expenses 5,479 6,248 9,696 9,383 Donations 3,377 2,736 6,721 7,007 Investment losses 8,644 8,644 Other 3,939 14,311 12,440 23,688 Total other expense $ 21,439 S 23,295 S 37,501 S 40,078 Other, net S (,432) , (2,340) _S (11,883): $ 3,718 Net financial trading gains and losses represent non-asset-backed trades of electricity and gas. Net energy brokered 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. Investment losses represent losses on limited partnership investment funds.

15. CO£QMENNICMITINGENCIES Contingencies and significant changes to the commitmnents discussed in Note 24 of the financial statements included in the Company's 2002 Annual Report on Form 10-K are described below.

A. 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.

Guarantees as of June 30,2003, are summarized in the table below and discussed more fully in the subsequent paragraphs.

(in millions)

Guarantees of perfornance issued by or on behalf of affiliates Guarantees supporting nonregulated portfolio expansion and energy maketing and trading activities issued by Progress Energy S 290.5 Guarantees supporting energy marketing and trading activities issued by subsidiaries of Progress Energy 12.0 Guarantees supporting nuclear decommissioning 276.0 Guarantee supporting power supply agreements 285.0 Standby letters of credit 49.5 Surety bonds 104.3 Other guarantees 44.1 Guarantees issued on behalf of third parties Other guarantees 16A Total S 1,077.8 21

Guarantees Suoorting Nonregulated Portfolio Expansion and Energv Marketing and Trading Activities Progress Energy has issued approximately $290.5 million of guarantees on behalf of PVI and its subsidiaries for obligations under tolling agreements, transmission agreements, gas agreements, construction agreements and trading operations.

Approximately S26.9 million of these guarantees were issued during the year to support energy and trading activities. 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 June 30,2003, 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 S40.0 million for the benefit of the Company's counterparties.

Guarantees Sunnorting 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 parent company guarantees.

Guarantee Supporting Power SUgply Aereements On March 20, 2003, PVI entered into a definitive agreement with Williams Energy Marketing and Trading, a subsidiary of The Williams Companies, Inc., to acquire a long-term full-requirements power supply agreement at fixed prices with Jackson. The power supply agreement included a performance guarantee by Progress Energy. The transaction closed during the second quarter of 2003. The Company issued a payment and performance guarantee to Jackson related to the power supply agreement of $285.0 million. In the event that Progress Energy's credit ratings fall below investment grade, Progress Energy will be required to provide additional security for this guarantee in form and amount (not to exceed $285 million) acceptable to Jackson.

Standb 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 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.

Surely Bonds At June 30, 2003, the Company had $104.3 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.

As of June 30, 2003, management does not believe conditions are likely for performance under the agreements discussed in this Note 15.

B. Insurance Both PEC and PEF are insured against public liability for a nuclear incident. Under the current provisions of the Price Anderson Act, which limits liability for accidents at nuclear power plants, each company, as an owner of nuclear units, can be assessed a portion of any third-party liability claims arising from an accident at any commercial nuclear power plant in the United States. In the event that public liability claims from an insured nuclear incident exceed $300 million (currently available through commercial insurers), each company would be subject to pro rata assessments for each reactor owned 22

per occurrence. Effective August 20, 2003, the retroactive premium assessments will increase to $100.6 million per reactor from the current amount of $88.1 fifi~o'n. The total limit available to cover fi-ler liability losses will increase as well from

$9.6 billion to $10.6 billion. The annual retroactive premium limit of$ 10 million per reactor owned will not change.

C. 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.

Eff There are 12 former MGP sites and 14 other sites or groups of sites associated with PEC that have required or are anticipated to require investigation and/or remediation costs. PEC received insurance proceeds to address costs associated with environmental liabilities related to its involvement with some MGP sites. All eligible expenses related to these are charged against a specific fund containing these proceeds. As of June 30, 2003,- approximately $5.2 million remains in this centralized fund with a related accrual of $5.2 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. 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.

PEE There are two former MGP sites and II other active sites associated with PEF that have required or are anticipated to require investigation and/or remediation costs. As of June 30, 2003, PEF has accrued approximately $9.4 million, for probable and reasonably estimable costs at these sites. PEF does not believe that it can provide an estimate of the reasonably possible total remediation costs beyond what is currently accrued. In 2002, PEF filed a petition for annual recovery of aproximately $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.

SCNG 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 June 30, 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 23

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 finiincial 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. FPC estimates that its maximum contractual liability to AEP Resources, Inc., associated with Inland Marine Transportation is $60 million. The balance in this accrual is $9.9 million at June 30, 2003. 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. The Company cannot predict the outcome of this matter.

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. The Company cannot predict the outcome of this matter.

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. The Company cannot predict the outcome of this matter.

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 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 nationwide caps and emission rates over an extended period of time. This national multi-pollutant approach to air pollution control could involve significant capital costs which could be material to the Company's consolidated financial position or results of operations. Some companies may seek recovery of the related cost through rate adjustments or similar mechanisms. Control equipment that will be installed on North Carolina fossil generating facilities as Fart 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 responded to it in the second 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 $1A 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 ofthe companies may seek recovery of the related cost through rate adjustments or similar mechanisms.

The Company cannot predict the outcome of the EPA's initiative or its impact, if any, on the Company.

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.

24

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 Appeagfuled against the EPA with regard to tha 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 in the preceding paragraph. 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 coalfired 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, 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 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 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 carn 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 fiture regulatory interpretation, implementation or impact of this new law. PEC recorded $33.5 million in the second quarter of 2003 and approximately $54 million of clean air amortization to date in 2003. Clean air expenditures to date are $8.4 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 ofthis 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-25

fired power plants was appropriate. Putsuant to a Court Order, the EPA is developing a Maximum Available Control Technology (MACT) standard, Whicl 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.

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 (NSPE 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 bad 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. 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 v Subsequently, a number of utilities each filed an action for damages in the Federal Court of Claims. The U.S. Circuit Court of Appeals (Federal Circuit) has 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. Additionally, the ability to use tax credits currently being carried forward could be denied. Total Section 29 credits generated to date (including FPC prior to its acquisition by the Company) are approximately $1.028 billion, of which $445.6 million have been used and $582.4 million are being carried forward as of June 30,2003. The current Section 29 tax credit program expires in 2007.

26

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)hat-been allocated approximately $273.1 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 the Company'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.

In late June 2003, the Company was informed that IRS field auditors have raised questions regarding the chemical change associated with coal-based synthetic fuel manufactured at its Colona facility and the testing process by which the chemical change is verified. (The questions arose in connection with the Company's participation in the PFA program.) The chemical change and the associated testing process were described as part of the PLR request for Colona. Based on that application, the IRS ruled in Colona's PLR that the synthetic fuel produced at Colona undergoes a significant chemical change and thus qualifies for tax credits under Section 29 of the Internal Revenue Code. While the IRS has announced that they may revoke PLRs if test procedures and results do not demonstrate that a significant chemical change has occurred, based on the information received to date, the Company does not believe the issues warrant reversal by the IRS National Office of its prior position in the Colona PLR.

The information provided by the IRS field auditors addresses only Progress Energy's Colona facility. The Company, however, applies essentially the same chemical process and uses the same independent laboratories to confirm chemical change in the synthetic fuel manufactured at each of its four other facilities. The independent laboratories used by the Company to determine significant chemical change are the leading experts in their field and are used by many other industry participants. The Company believes that the laboratories' work and the chemical change process are consistent with the bases upon which the PLRs were issued.

The Company is working to resolve this matter as quickly as possible. At this time, the Company cannot predict how long the IRS process will take; however, the Company intends to continue working cooperatively with the IRS. The Company firmly believes that it is operating the Colona facility and its other plants in compliance with its PLRs and Section 29 of the Internal Revenue Code. Accordingly, the Company has no current plans to alter its synthetic fuel production schedules as a result of these matters.

In addition, the Company has retained an advisor to assist in selling an interest in one or more synthetic fuel entities. The Company is pursuing the sale of a portion of its synthetic fuel production capacity that is underutilized due to limits on the amount of credits that can be generated and utilized by the Company. The Company would expect to retain an ownership interest and to operate any sold facility for a management fee. However, the IRS has suspended issuance of PLRs relating to synthetic fuel production (typically a closing condition to the sale of an interest in a synthetic fuel entity). Unless that suspension on new PLRs is lifted, it will be difficult to consummate the successful sale of interests in the Company's synthetic fuel facilities. The Company cannot predict when or if the IRS will recommence issuing such PLRs. The final outcome and timing of the Company's efforts to sell interests in synthetic fuel facilities is uncertain and while the Company cannot predict the outcome of this matter, the outcome is not expected to have a material defect on the consolidated financial position, cash flows or results of operations.

d) In November of 2001, Strategic Resource Solutions Corp. (SRS) filed a claim against the San Francisco Unified School District ("the District") and other defendants claiming that SRS is entitled to approximately $10 million in unpaid contract payments and delay and impact damages related to the District's $30 million contract with SRS. On March 4, 2002, the District filed a counterclaim, seeking compensatory damages and liquidated damages in excess of $120 million, for various claims, including breach of contract and demand on a performance bond. SRS has asserted defenses to the District's claims.

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

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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 newpleadings on April 14, 2003. The Compqaniy has reviewed the new pleadings and the Company believes that the new claims are not meritorious. The Company has filed responsive pleadings denying the allegations, and the discovery process is underway. 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 both the District and the City.

e) 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 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 lOWER & LIGHT COMPANY dlb/a PROGRESS ENERGY CAROLINAS, INC.

CONSOLIDATED INTERIM FINANCIAL STATEMENTS June 30, 2003 CONSOLIDATED STATEMENTS OF INCONE Three Months Ended Six Months Ended (Unaudited) June 30, June 30, (In thousEnds) 2003 2002 2003 2002 Operating Revenues Electiic $ 816,240 $ 834,658 $ 1,741,710 $ 1,646,139 Diversified business 2,423 3,434 5,819 6,823 Total Operating Revenues 818,663 838.092 1,747,529 1.652,962 Operating Expenses Fuel used in electric generation 177,020 170,977 402562 342,703 Purchased power 68,977 90,918 142,157 164,228 Operation and maintenance 210,295 193,887 400,170 387,324 Depredation and amortization 141,848 133,459 280,644 274,844 Taxes other than on income 35,101 36,075 79,277 74,843 Diversified business 1,595 2,754 2,535 5,815 Total Operating Expenses 634,836 628,070 1,307,345 1,249,757 Operating Income 183,827 210,022 440,184 403,205 Other Income (Expense) interest Income 2,075 3,202 3,441 4,868 Other, net (8,380) 4,652 (10,931) 1,680 Total Other Income (Expense) (6,305) 7,854 (7,490) 6,548 Interest Charges interest charges 48,412 56,255 97,715 117,899 Allowance for borrowed funds used during (658) (2,779) (1,583) (5,873) construction Total Interest Charges, Net 47,754 53,476 96,132 112,026 Income before Income Taxes 129,768 164,400 336,562 297,727 Income Tax Expense 40,956 33,248 112,688 81,456 Net Income 88,812 131,152 223,874 216,271 Preferred Stock Dividend Requirement 741 741 1,482 1,482 Earnings for Common Stock S 88,071 $ 130,411 $ 222,392 $ 214,789 See Notes to Progress Energy Carolinas, Inc. Consolidated Interim Financial Statements.

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

CONSOLIDATED BALANCE SHEETS (Unaudited)

(In tousands) June 30, December31.

Assets 2003 2002 Utility Plant Utility plant In service $ 13,072,200 $ 12,675,761 Accumulated depredation (6,077,374) (6,356,933)

Utility plant in service, net 6,994,826 6,318,828 Held for future use 4,942 7,188 Construction work in progress 334,269 325,695 Nudear fuel, net of amortization 168,148 176,622 Total Utility Plant, Net 7,502,185 6,828,333 Current Assets Cash and cash equivalents 12,998 18,284 Accounts receivable 260,691 301,178 Unbilled accounts receivable 143,870 151,352 Receivables from affiliated companies 32,270 36,870 Notes receivable from affiliated companies 49.772 Taxes receivable - 55,006 Inventory 348,239 342,886 Deferred fuel cost 137,301 146,015 Prepayments and other current assets 35,459 45,542 Total Current Assets 970,828 1,146,905 Deferred Debits and Other Assets Regulatory assets 515,257 252,083 Nuclear decommissioning trust funds 465,043 423,293 Diversified business property, net 51,771 9,435 Miscellaneous other property and Investments 184,029 209,657 Other assets and deferred debits 98,947 104,978 Total Deferred Debits and Other Assets 1,315,047 999,446 Total Assets S 9,788,060 $ 8,974,684 Capitalization and Liabilities Capitalization Common stock $ 3,135,690 $ 3,089,115 Preferred stock - not subject to mandatory redemption 89,334 59,334 Long-term debt, net 2,516,941 3,048,466 Total Capitailzation 5,711,965 6,196,915 Current Liabilities Current portion of long-term debt 400,000 Accounts payable 176,387 259,217 Payables to affiliated companies 121,081 98,572 Notes payable to affiliated companies 49,359 Taxes accrued 4,031 Interest accrued 56,678 58,791 Short-term obligations 363,900 437,750 Oirrent portion of accumulated deferred Income taxes 44,197 66,088 Other current liabilities 92,016 93,171 Total Current Liabilities 1,307,649 1,013,589 Deferred Credits and Other LiabilitIes Accumulated deferred Income taxes 1,156,722 1,179,689 Accumulated deferred Investment tax credits 153,207 158,308 Regulatory Ilablties- 131,994 7,774 Asset retirement obligations 905,338 Other liabilities and deferred credits 421,185 418,409 Total Deferred Credits and Other Liabilities -2768,446 1,764,180 Commitments and Contingencies (Note 9)

Total Capitalization and Liabilities $ 9,788,060 $ 8,974,684 See Notes to Progress Energy Carolinas, Inc. Consolidated Interim Financial Statements.

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Carolina Power & Ught Company dib/a Progress Energy Carolinai, Iunc. IT, CONSOLIDATED STATEMENTS OF CASH FLOWS Six Months Ended (Unaudited) June 30, (in thousands) 2003 2002 Operating Activities Net income $ 223,874 $ 216.271 Adjustments to reconcile net Income to net cash provided by operating activities:

Depreciation and amortization 324,975 329,437 Deferred income taxes (38,115) (25,358)

Investment tax credit (5,100) (6,240)

Deferred feel cost 8,714 12,757 Net (increase) decrease In accounts receivable- - - - 20,169 (13,408)

Net decrease In affiliated accounts receivable 14,743 (38,213)

Net increase In Inventories (5,353) (1,229)

Net (Increase) decrease In prepayments and other current assets 8,315 (14,916)

Net decrease In accounts payable (14,632) (5,109)

Net Increase hi affiliated accounts payable 17,487 33,340 Net Increase hI other current liabilities 58,183 93,975 Other 50,783 21,921 Net Cash Provided by Operating Activities 664,043 603.228 Investing Activities Gross property additions (258,526) (333,308)

Proceeds from assets transferred to affiliate 243,719 Nuclear fuel additions (45,642) (49,380)

Contributions to nudear decommissioning trust (17,959) (17.915)

Diversified business property additions (262) (10,439)

Investments hi non-utility activities (2,258) (6,886)

Net Cash Used In Investing Activities (324,647) (174,209)

Financing Activities Proceeds from Issuance of long-term debt 46,505 Net decrease i short-term obligations (73,850) (207,535)

Net Increase (decrease) inIntercompany notes 99,131 (36,374)

Retirement of long-term debt (165,208) (49,754)

Dividends paid to parent (203,273) (190,599)

Dividends paid on preferred stock (1,482) (1,482)

Net Cash Used hI Fnancing Acivities (344,682) (439,239)

Net Decrease In Cash and Cash Equivalents (5,286) (10,220)

Cash and Cash Equivalents at Beginning of the Period 18,284 21,250 Cash and Cash Equivalents at End of the Period S 12,998 $ 11.030 Supplemental Disclosures of Cash Flow Information Cash paid during the year - interest (net of amount capitalized) $ 95,287 $ 103,911 income taxes (net of refunds) S 119,638 $ 61,163 Noncash Activities

• In February 2002, CP&L transferred the Rowan plant to Progress Ventures, Inc. and established an intercompany receivable. The property and inventory transferred totaled approximately $244 million. In April 2002, CP&L received cash proceeds in settlement of the intercompany receivable totaling approximately $244 million. This amount is reported in proceeds from assets transferred to affiliates in the investing activities section.

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

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

NOTES TO CONSOLIDATED INTERIM 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 primarily in portions of North Carolina and South Carolina. PEC is a wholly owned subsidiary of Progress Energy, Inc. (the Company or Progress Energy). The Company is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both the Company and its subsidiaries are subject to the regulatory provisions of PUHCA.

Effective January 1, 2003, Carolina Power & Light Company (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 GAAP, 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, as amended 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 or future periods.

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. 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.

2. FINANCIAL INFORMATION BY BUSINESSSEMN 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 and six months ended June 30, 2003 and 2002 is as follows:

(in thousands)

Three Months Ended June 30. Six Months Ended June 30.

2003 2002 2003 2002 Revenues S 816,240 S 834,658 S 1,741,710 S 1,646,139 Segment income S 88,394 S 131,690 S 223,264 S 217,222 Total segment assets 9,568,769 $8,669,993 S 9,568,769 S 8,669,993 The primary differences between the PEC Electric segment and PEC consolidated financial information relate to other non-electric operations and elimination entries.

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3. IMPACT OF NEW ACCOUIsnTKQ STANDARDS SFASNo. 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 fir 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 and six months ended June 30:

Three Months Ended June 30. Six Months Ended June 30.

(in thousands) , 2003 2002 2003 2002 Earnings for common stock, as reported $88,071 $130,411 $222,392 S214,789 Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects 706 535 1,779 1,294 Pro forma earnings for common stock S87,365 S 129,876 S 220,613 S213,495 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 resolved by the FASB is the determination of the appropriate fair value measure. The FASB continues to deliberate additional issues in this project; however, the FASB plans to issue an exposure draft in 2003 that could become effective in 2004.

Derivative Instruments andHedn,' Activities In April 2003, the FASB issued SWAS 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.

In connection with the January 2003 FASB Emerging Issues Task Force (EITF) meeting, the FASB was requested to reconsider an interpretation of SPAS No. 133. The interpretation, which is contained in the Derivatives Implementation Group's CII 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 late June 2003, the FASB issued final superseding guidance (DIG Issue C20) on this issue, which is significantly different from the tentative superseding guidance that was issued in April 2003. The new guidance is effective October 1, 2003 for PEC. DIG Issue C20 specifies new pricing-related criteria for qualifying as a normal purchase or sale, and it requires a special transition adjustment as of October 1, 2003.

PEC has determined that it has one existing "normal" contract that is affected by this revised guidance. PEC is in the process of evaluating the revised guidance and related contract to determine the transition adjustment that will be necessary and to determine if the contract will be required to be recorded at fair value subsequent to October 1, 2003.

SFAS No. 150, "Accountin' for CertainFinancialInstruments with Characteristicsof Both Liabilitiesand Equity" In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). The financial instruments within the scope of SPAS No. 150 include mandatorily redeemable stock, obligations to repurchase the issuer's equity shares by transferring assets, and certain obligations to issue a variable number of shares. SFAS No. 150 is effective immediately for such instruments entered into or modified after May 31, 2003, and is effective for previously issued financial instruments within its scope on July 1, 2003. PEC believes that the adoption of SFAS No. 150 will not have a material impact on its financial position or results of operations.

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FINNo. 46. "Consolidationof YartbleInteresLEntities" In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities - an Interpretation of ARB No. 51" (FIN No. 46). fhididInterpretation provides guidance reiat&i to identifying variable interest entities (previously know 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 six months 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. During this evaluation process, several arrangements have been identified to which this interpretation may apply. These arrangements include investments in approximately 50 Affordable Housing properties eligible for Section 42 tax credits. PEC divested approximately 30 of these Affordable Housing investments in July 2003, and therefore the application of FIN No. 46 is not expected to have a material impact with respect to those 30 investments. It is reasonably possible that the Company will be required to consolidate some of the remaining 20 Affordable Housing entities that are currently accounted for under the equity method. The maximum exposure to loss as a result of PEC's total funding commitments for the remaining 20 Affordable Housing investments is approximately $23.9 million. However, management believes the total loss of its investments is unlikely given the nature of the investments and the utilization of certain Section 42 tax credits to date.

PEC is in the final stages of completing the adoption of FIN No. 46, but having considered the facts described herein, does not expect the results to have a material impact on its consolidated financial position, results of operation or liquidity.

EITFLssue No. 03-04. "Accounting for 'Cash Balance PensionPlans" In May 2003, the EITF reached consensus in EITF Issue No. 03-04 to specifically address the accounting for certain cash balance pension plans. The consensus reached in EITF Issue No. 03-04 requires certain cash balance pension plans to be accounted for as defined benefit plans. For cash balance plans described in the consensus, the consensus also requires the'use of the traditional unit credit method for purposes of measuring the benefit obligation and annual cost of benefits earned as opposed to the projected unit credit method. -PEC has historically accounted for its cash balance plans as defined benefit plans; however, PEC is required to adopt the measurement provisions of EITF 03-04 at its cash balance plans' next measurement date of December 31, 2003. Any differences in the measurement of the obligations as a result of applying the consensus will be reported as a component of actuarial gain or loss. PEC is currently evaluating what effects EITF 03-04 will have on its results of operations and financial position.

4. ASSET REnIREMENT 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, PEC 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 totaling $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.

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Funds set aside in PEC's nuclear decomm issioning trust fund for the nuclear decommissioning liability totaled $465.0 million at June 30,2003 and $423.3 million at December 31,2002.

Pro forma net income has not beeftsented for prior years because the pro foima 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 June 30, 2003, the portion of such costs not representing AROs under SFAS No. 143 was $882.6 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 $63.5 million as of June 30, 2003, which is included in accumulated depreciation on the accompanying Consolidated Balance Sheets.

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. Because the clean air legislation discussed in Note 9 under "Air Quality" contained a prohibition against cost deferrals unless certain criteria are met, the NCUC denied the deferral of the ongoing effects. The Company has provided additional information to the NCUC that it believes will demonstrate that deferral of the ongoing effects should also be allowed. Since the NCUC order denied deferral of the ongoing effects, PEC ceased deferral of the ongoing effects during the second quarter for the six months ended June 30,2003 related to its North Carolina retail jurisdiction. Pre-tax income for the three and six months ended June 30,2003 increased by approximately $13.6 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.

5. COMPREHENSIVE INCOME Comprehensive income for the three and six months ended June 30,2003 was $88.0 million and $223.2 million, respectively.

Comprehensive income for the three and six months ended June 30,2002 was $129.6 million and $218.2 million, respectively.

Items of other comprehensive income for the periods consisted primarily of changes in fair value of derivatives used to hedge cash flows related to interest on long-term debt.

6.

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. On July 30, 2003, PEC renewed its $165 million 364-day credit agreement. PEC's

$285 million three-year credit agreement entered into in July 2002 remains in place, for total facilities of $450 million.

On May 27,2003, PEC redeemed $150 million of First Mortgage Bonds, 7.5% Series, Due March 1, 2023 at 103.22% of the principal amount of such bonds. PEC funded the redemption with commercial paper.

On July 14, 2003, PEC announced the redemption of $100 million of First Mortgage Bonds, 6.875% Series Due August 15, 2023 at 102.84%. The date of the redemption will be August 15,2003. PEC will fund the redemption with commercial paper.

7. RI M EMET ACTIVITIES AND DERIVATIVE TRANSACnlNS 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, April and June 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. These agreements have a total notional amount of $60 million.

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The notional amounts of the above cohtracts 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 replacifig the agreements at current market rates. PEC only enters into interest rate swap agreements with banks with credit ratings of single A or better.

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 and six months ended June 30, 2003 and 2002 are as follows:

Three Months Ended June 30. Six Months Ended June 30.

(in thousands) 2003 2002 2003 2002 Other income Net financial trading gain (loss) S 1,175 S 792 S (1,524) S (1,429)

Net energy brokered for resale (68) (89) 270 (446)

Nonregulated energy and delivery services income 2,052 3,016 - 4,338 5,567 AFUDC equity 774 1,602 1,364 3,662 Investment gains - 2,960 2,960 Other 2,767 4,711 5,523 5,981 Total other incorne S 6,700 S 12,992 S 10,471 S 16,295 Other ex"eDse Nonregulated energy and delivery services expenses S 2,022 S 3,632 S 3,995 S 5,267 Donations -1,339 1,178 2,645 2,548 Investmnent losses 3,643 8,643 Other 3,076 3,530 6,119 6,800 Total other expense - S 15,080 S 8,340 $ 21,402 S 14,615 Other, net S 4 652 _S (10,931) S 1,680 Net financial trading gains and losses represent non-asset-backed trades of electricity and gas. Net energy brokered 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. Investment losses represent losses on limited partnership investment funds.

9. CONM41WINT 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 I8 of the financial statements included in PEC's 2002 Annual Report on Form 10-K, as amended.

In 2003, PEC determined that its external funding levels did not fully meet the nuclear decommissioning financial assurance levels required by the NRC. Therefore, PEC obtained parent company guarantees of $276 million to meet the required levels. As of June 30, 2003, management does not believe conditions are likely for performance under the agreements discussed in this Note 9.

Insurance PEC is insured against public liability for a nuclear incident. Under the current provisions of the Price Anderson Act, which limits liability for accidents at nuclear plants, PEC, as an owner of nuclear units, can be assessed a portion of any third-party liability claims arising from an accident at any commercial nuclear power plant in the United States. In the event that public liability claims from an insured nuclear incident exceed $300 million (currently available through commercial insurers), each company would be subject to pro rata assessments for each reactor owned per occurrence. Effective August 20, 2003, the retroactive premium assessments will increase to $100.6 million per reactor from the current amount of

$88.1 million. The total limit available to cover nuclear liability losses will increase as well from $9.6 billion to S10.6 billion.

The annual retroactive premium limit of SI0 million per reactorowned will not change.

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Contingencies Claims and uncertainties e 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 or groups of sites associated with PEC that have required or are anticipated to require investigation and/or remediation costs. PEC received insurance proceeds to address costs associated with PEC environmental liabilities related to its involvement with some MGP sites. All eligible expenses related to these are charged against a specific fund containing these proceeds. As of June 30, 2003, approximately $5.2 million remains in this centralized fund with a related accrual of $5.2 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.

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 ofthis 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 the 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 37

for $300 million. These settlement agreements have generally called for expenditures to be nade 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 f thie EPA's initiative or its impact, if any, in i ie Company.

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. 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 in the preceding paragraph. 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 coalfired 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 aspart 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 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 coalfired generation in North Carolina that is affected by this legislation. The legislation requires the emissions reductions to be completed in phases by 2013, and applies to each utility's total system rather than setting requirements for individual power plants. The legislation also freezes the utilities' base rates for five years unless there are extraordinary events beyond the control of the utilities or unless the utilities persistently cam 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 recorded $33.5 million in the second quarter of 2003 and approximately $54 million of clean air amortization to date in 2003. Clean air expenditures to date are $8.4 million.

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Other Environmental Matters a) The Kyoto Protocol was ad&opat in 1997 by the United Nations td' address global climate change by reducing emissions of carbon dioxide aid 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 ofmercury 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 PEC's financial condition and results of operations.

However, PEC cannot predict the outcome ofthis 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. DOI 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 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 NSPDOE 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. D Subsequently, a number of utilities each filed an action for damages in the Federal Court of Claims. The U.S. Circuit Court of Appeals (Federal Circuit) ruled that utilities may sue the DOE for damages in the Federal Court of Claims instead of having to file an administrative claim with DOE. PEC is in the process of evaluating whether it should 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 cannot predict the outcome ofthis 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 December 2000.

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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 flatters. PEC believes the final disposhtibn 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. Mana ement'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.

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

This discussion should be read in conjunction with the accompanying financial statements found elsewhere in this report and in conjunction with the 2002 Form 10-K.

RESULTS OF OPERATIONS In this section, earnings and the factors affecting earnings for the three and six months ended June 30, 2003 as compared to the same periods in 2002 are discussed. The discussion begins with a general overview, then separately discusses earnings by business segment.

OVERVIEW The net income and basic earnings per share of Progress Energy, Inc. (Progress Energy or the Company) were $152.8 million or $0.65 per share and $120.6 million or S0.56 per share for the second quarter of 2003 and 2002, respectively. The Company's net income and basic earnings per share were $361.0 million or $1.54 per share and $253.1 million or $1.18 per share for the first half of 2003 and 2002, respectively.

The increase in net income for the second quarter of 2003, as compared to the second quarter of 2002, is primarily due to customer growth and usage at the utilities, increased sales of natural gas, a decrease in interest expense and the impact of levelizing the estimated effective tax rate throughout the year. These items were partially offset by the impact of unfavorable weather, PEF's retail revenue sharing and higher costs associated with a planned nuclear outage; The Company's operating segments impacted earnings for the quarter and first half ofthe year as follows:

(in millions) Three Months Ended June 30, Six Months Ended June 30, Business Segment 2003 2002 2003 2002 PEC Electric $88A $131.7 2233 217.2 PEF 61A 76.8 132.1 134.5 Fuels 53.8 46.7 80.4 88.3 CCO 2A 6.7 10.9 4.6 Rail 2.2 2.9 (1.2) 2.2 Other 1.2 (8.4) 1.9 (13.2)

Corporate (59.1) (134.5) (100.2) (187.6)

Total income from continuing operations 150.3 121.9 347.2 246.0 NCNG discontinued operations 2.5 (1.3) 13.8 7.1 Net income S152.8 $120.6 S361.0 S253.1 A detailed discussion of each of the Company's significant operating segments follows. The Company's significant operating 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 (differences between the PEC Electric segment and the PEC consolidated financial information relate to other non-electric operations and elimination entries);

• 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 limited trading activities;

• Progress Rail Services (Rail) - engaged in various rail and railcar related services; and 41

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

In prior years' 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 the operating segments listed above, the Company has other corporate activities that include holding company operations, service company operations and eliminations. These corporate activities have been included in the Other segment in the past. Additionally, earnings from wholesale customers on the regulated plants have previously been reported in both the regulated utilities' results and the results of Progress Ventures. 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 provided in the Discontinued Operations section that follows.

In March of 2003, the SEC completed an audit of Progress Energy Service Company, LLC (Service Company) and recommended that the Company change its cost allocation methodology for allocating Service Company costs. As part of the audit process, the Company was required to change the cost allocation methodology for 2003 and record retroactive reallocations between its affiliates in the first quarter of 2003 for allocations originally made in 2001 and 2002. This change in allocation methodology and the related retroactive adjustments have no impact on consolidated expense or earnings.

The impact on the affiliates is included in the segment discussion that follows. The new allocation methodology, as compared to the previous allocation methodology, generally decreases expenses in the regulated utilities and increases expenses in the nonregulated businesses. The regulated utilities' reallocations are within operation and maintenance expense, while the diversified businesses' reallocations are generally within diversified business expenses.

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. The allocation has no impact on the Company's consolidated tax expense or net income. The impacts on the business segments are included in the discussions below and generally decrease the income tax expense for the regulated utilities, while increasing income tax expense for the holding company. The second quarter 2002 reallocation included impacts from 2001 and the first two quarters of 2002, while the second quarter 2003 reallocation was for one quarter only.

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

Effective January 1,2003, the Company implemented SFAS No. 143, "Accounting for Asset Retirement Obligations," 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 recorded asset retirement obligations (AROs) in the first quarter of 2003. At June 30,2003, PEC Electric's AROs totaled $905.3 million and PEF's AROs totaled $310.9 million.

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. Because the clean air legislation enacted in North Carolina contained a prohibition against cost deferrals unless certain criteria are met, the NCUC denied the deferral of the ongoing effects. The Company has provided additional information to the NCUC that it believes will demonstrate that deferral of the ongoing effects should also be allowed.

Since the NCUC order denied deferral of the ongoing effects, PEC ceased deferral of the ongoing effects during the second quarter of 2003 for the six months ended June 30,2003 related to its North Carolina retail jurisdiction. Pre-tax income for the second quarter of 2003 increased by approximately $13.6 million, which represents a decrease in non-ARO cost of removal expense, partially offset by an increase in decommissioning expense. This earnings impact will be reversed if and when the NCUC issues an order granting deferral of the ongoing effects.

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On April 8, 2003, the SCPSC approved a joint request by PEC Electric, 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. Therefore, the adoption ofthe statement had no impact on the income of PEF due to the establishment of a regulatory liability pursuant to SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." The Commission approved the draft rule in June 2003, and a final order is expected in the third quarter of 2003.

PROGRESS ENERGY CAROLINAS ELECTRIC PEC Electric contributed net income of $S88A million and S131.7 million in the second quarter of 2003 and 2002, respectively, and $223.3 million and $217.2 million for the first half of 2003 and 2002, respectively. The decrease in the second quarter of 2003 compared to the second quarter of 2002 is primarily due to unfavorable weather conditions resulting in lower usage across all customer classes, the effect of the tax benefit reallocation and higher planned nuclear outage costs, partially offset by favorable retail customer growth and usage. The increase in the first half of 2003 compared to the first half of 2002 was primarily due to strong wholesale sales, retail growth and usage and lower interest charges, offset partially by the effect of the tax benefit reallocation, higher operation and maintenance costs related to planned nuclear outages and costs incurred for the February 2003 ice storm.

PEC's electric revenues for the second quarter and first half of 2003 are as follows:

(in millions of S) Three Months Ended June 30, Six Months Ended June 30, Customer Cass 2003 Change  % change 2002 2003 Change  % Change 2002 Residential - S 247.7 S (10.8) (4.2) S 258.5 S 604.7 $ 37.0 6.5 S 567.7 Commercial 198.8 (0.1) (0.1) 198.9 399.7 13.6 3.5 386.1 Industrial 155.9 (4.3) (2.7) 160.2 302.6 (3.3) (1.1) 305.9 Govenunental 17.8 (0.1) (0.6) 17.9 36.4 0.9 2.5 35.5 Total retail revenues 620.2 (15.3) (2.4) 635.5 1,343A 48.2 3.7 1,295.2 Wholesale 154.2 (2.5) (1.6) 156.7 363.6 64.3 21.5 299.3 Unbilled 23.5 (0.6) - 24.1 (7.5) (21.9) - 14.4 Miscellaneous 18.3 (0L.) (0.5) 18.4 42.2 5.0 13.4 37.2 Total electric revenues S 816.2 S(18.5) (2.2) S834.7 S 1,741.7 $ 95.6 5.8 S 1,646.1 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) Three Months Ended June 30, Six Months Ended June 30, Customer Class 2003 Change  % Change 2002 2003 Change  % Change 2002 Residential 3,052 (210) - (6.4) 3,262 7,639 -392 - 5.4 7,247 Cotmnercial 2,946 (81) (2.7) 3,027 5,930 112 1.9 5,818 Industrial 3,197 (164) (4.9) 3,361 6,202 (145) (2.3) 6,347 Governmental 317 (21) (6.2) 338 660 (3) (0.5) 663 Total retail energy sales 9,512 (476) (4.8) 9,988 20,431 356 1.8 20,075 Wholesale 3,301 (194) (5.6) 3,495 7,920 1,094 16.0 6,826 Unbilled 396 (35) - 431 (84) (329) - 245 Total mWh sales 13,209 (705) (5.1) 13,914 28,267 1,121 4.1 27,146 Second Quarter of 2003 Compared to Second Ouarter of 2002 Unfavorable weather accounted for a revenue decline of $34.1 million, with the average cooling degree days declining 37%

when comparing the second quarter of 2003 to the second quarter of 2002. Retail customer growth and usage, excluding the impact of weather, accounted for $18.1 million of additional revenue in the second quarter of 2003 as compared to the second quarter of 2002, with 22,364 additional retail customers during the second quarter of 2003 as compared to 2002.

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Operation and maintenance costs were $210.3 million for the second quarter of 2003, which represents a $16.4 million increase compared to the second quarter of 2002. A planned nuclear outage at the Harris plant during 2003 accounted for

$15.1 million of this increase.

Depreciation and amortization expense was $141.8 million for the second quarter of 2003, which represents an $8.3 million increase compared to the second quarter of 2002. This increase in depreciation and amortization expense results from $33.5 million in clean air amortization expensed during the second quarter of 2003 and a $7.0 million increase related to additional plant in service. These increases are partially offset by a $16.7 million reduction in accelerated nuclear amortization and the

$13.6 million decrease in depreciation expense related to the ongoing effects of SFAS No. 143 in the North Carolina retail jurisdiction, as previously discussed under "REGULATED ELECTRIC SEGMENTS." The clean air legislation allows flexibility in the recognition of the clean air amortization, with a maximum of $174 million per year. The Company currently plans to amortize approximately $100 million of clean air costs in 2003. An NCUC order allowed the reduction in the accelerated nuclear amortization and extended the recovery time.

Other income and expense was $6.9 million of expense for the second quarter of 2003 compared to $8.6 million of income during the second quarter of 2002. The primary driver of the unfavorability was $9.4 million of losses on limited partnership investment funds recorded during the second quarter of 2003.

Interest expense was $47.7 million for the second quarter of 2003, which represents a $5.8 million decrease compared to the same period in 2002. This decrease was due to both a decrease in average outstanding debt and a slightly lower interest rate.

Income tax expense was $40.0 million for the second quarter of 2003 as compared to $32.7 million for the second quarter of 2002. This variance is due to a $22.8 million lower tax benefit reallocation in the second quarter of 2003 compared to the same period in 2002, partially offset by the tax impact of changes in pre-tax income.

First Half of 2003 Comnared to First Half of 2002 Favorable wholesale revenues are the primary driver of the revenue increase for the first half of 2003 compared to 2002.

This favorability is attributable to weather-related sales of energy to the Northeastern United States markets during the first half of 2003. For its retail customers, mild weather in North and South Carolina during the second quarter of 2003 more than offset the favorable impact of cold weather experienced in the first quarter of 2003. Retail customer growth has increased during the first half of 2003 when compared to 2002, with residential and commercial customer growth of two percent.

Operation and maintenance costs increased $12.9 million compared to operation and maintenance costs of $387.3 million for the first half of 2002, primarily due to $10.4 million of storm costs in the first quarter of 2003 and $16.7 million of costs associated with a planned nuclear outage in the second quarter of 2003. These costs were partially offset by a decrease in operation and maintenance expense of $15.9 million related to the previously discussed reallocation of prior years' Service Company costs, as required by the SEC.

Depreciation and amortization expense increased $5.8 million compared to depreciation and amortization expense of $278.4 million for the first half of 2002. This increase results from $53.5 million of clean air amortization in 2003 and S10.4 million of depreciation on additional assets placed into service. These increases are partially offset by a $41.6 million reduction in accelerated nuclear amortization and the $13.6 million decrease in depreciation related to the ongoing effects of SFAS No.

143 in the North Carolina retail jurisdiction, all of which are discussed previously.

Other income and expense was $75 million of expense for the first half of 2003 compared to $6.9 million of income during the first half of 2002. The primary driver of the unfavorability was $9.4 million of losses on limited partnership investment funds recorded during the second quarter of 2003.

Interest expense was $96.1 million for the first half of 2003, which represents a decrease of$ 15.9 million. This decrease was due to both a decrease in average outstanding debt and a slightly lower interest rate.

Income tax expense was $110.1 million for the first half of 2003 as compared to $80.0 million for the first half of 2002. This variance is due to the tax impact of changes in pre-tax income and a $17.3 million lower tax benefit reallocation in the first half of 2003 conpared to the same period in 2002.

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PROGRESS ENERGY FLORIDA PEF contributed earnings for common stock of $61.4 million and $76.8 million in the second quarter of 2003 and 2002, respectively, and $132.1 million and $134.5 million in the first half of 2003 and 2002, respectively. These decreases are primarily attributed to impacts of the 2002 rate case and are partially offset by favorable retail customer growth and usage and the impact of the tax benefit reallocation, previously discussed.

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, provided for increases in certain service revenue rates and provided for revenue sharing with the retail customers if certain revenue thresholds were met.

The impacts of the settlement agreement are included below.

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

(in millions of S) Three Months Ended June 30, Six Months Ended June 30, Customer Class 2003 Chane  % Change 2002 2003 Change  % Change 2002 Residential S 413.5 S 17.9 4.5 S 395.6 S 798.5 $ 23.7 3.1 $ 774.8 Commercial 192.1 8.7 4.7 183A 342.5 (7.7) (2.2) 350.2 Industrial 56.1 1.0 1.8 55.1 103.5 (1.6) (1.5) 105.1 Governmental 45.8 2.3 5.3 43.5 93.8 0.3 0.4 83.5 Retroactive rate refimd . - 35.0. 100.0 (35.0)

Revenue sharinglrate refimd (28.1) .1) 1) - _ (28.1) (28.1) -

Total retail revenues 679.4 1.8 0.3 677.6 1,300.2 21.6 1.7 1,278.6 Wholesale 49.8 (6.0) (10.8) 55.8 121.1 12.8 11.8 108.3 Unbilled 7.3 1.9 - 5.4 6.6 (5.2) - 11.8 Miscellaneous 30.0 2.9 10.7 27.1 67.1 13.4 25.0 53.7 Total electric revenues S766.5 S 0.6 0.1 S 765.9 S 1,495.0 S 42.6 2.9 S 1,452A PEF's electric energy sales for the second quarter and first half of 2003 and 2002 and the amount and percentage change by quarter and by customer class are as follows:

(in thousands of mWh) Three Months Ended June 30, Six Months Ended June 30, Customer Class 2003 Change  % Cange 2002 2003 Change  % Change 2002 Residential 4,703 188 4.2 4,515 9,256 681 7.9 8,575 Conmercial 2,951 94 3.3 2,857 5,393 80 1.5 5,313 Industrial 1,008 14 1.A 994 1,924 48 2.6 1,876 Governmental 726 11 1.5 715 1,383 48 3.6 1,335 Total retail energy sales 9,388 307 3A 9,081 17,956 857 5.0 17,099 Wholesale 890 (86) (8.8) 976 2,166 210 10.7 1,956 Unbilled 498 55 - 443 553 79 - 474 Total mWh sales 10,776 276 2.6 10,500 20,675 1,146 5.9 19,529 Second Ouarter of 2003 Compared to Second Ouarter of 2002 Retail revenues, excluding fuel revenues of $286.3 million and $259.8 million for the second quarter of 2003 and 2002, respectively, decreased as a result of the impact of the final resolution of the revenue sharing provisions in the 2002 rate settlement agreement. Fuel revenues increased compared to the prior year primarily due to increased generation. On July 9,2003, the FPSC issued an order that required PEF to refund an additional $18.4 million related to 2002 revenue sharing. In the second quarter of 2003, PEF also recorded an additional accrual of $9.5 million related to estimated 2003 revenue sharing. This accrual will be reviewed and adjusted, if necessary, on a quarterly basis. Revenues were further reduced due to the impact of the 9.25% rate reduction that went into effect in May 2002, as part of the settlement agreement.

These decreases were partially offset by additional retail revenues of $l 1.4 million related to customer growth and usage.

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Operation and maintenance costs increased $0.6 million, compared to the $153.3 million incurred during the second quarter of 2002. A decrease in the pension credit of $5.4 million, due to continued weak market performance, is offset by lower spending by PEF's business units.-

Income tax expense was $28.0 million for the second quarter of 2003, compared to $45.6 million during the second quarter of 2002. Fluctuations in income tax expense result from the tax benefit reallocation, discussed previously, and changes in pre-tax income.

First Half of 2003 Compared to First Half of 2002 Retail revenues, excluding fuel revenues of $529.3 million and $498.1 million for the first half of 2003 and 2002, respectively, decreased due to the impact of the 9.25% rate reduction, 2002 revenue sharing resolution, and the 2003 revenue sharing accrual, all of which are discussed previously. Partially offsetting these items was the absence of the impact of the $35.0 million rate refund that was recognized in 2002 as part of the settlement agreement.

Strong customer growth and usage and favorable weather positively impacted revenues in 2003. The average number of customers during the first half of the year increased by approximately 34,000 or 2.3% in 2003 as compared to the same period in 2002.

Operation and maintenance costs increased $8.1 million, compared to the $286.6 million incurred during the first half of 2002. The higher operation and maintenance costs were primarily due to a $10.7 million decrease in the pension credit.

Income tax expense was $64.9 million for the first half of 2003, compared to $79.0 million during the first half of 2002.

Fluctuations in income tax expense result from the tax benefit reallocation, discussed previously, and changes in pre-tax income.

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

FUELS-The Fuels segment's operations include synthetic fuel operations, natural gas exploration and production, coal extraction and terminals operations. Fuels' results for the second quarter and first half of 2003 were impacted most significantly by the timin3 of synthetic fuel production and the increase in gas production.

The following summarizes the net income of the Fuels segment for the second quarter and first half of 2003 and 2002.

Three Months Ended June 30, Six Months Ended June 30, (in millions) 2003 2002 2003 2002 Synthetic fuel operations $41.7 $S44.3 $67.2 $83.1 Gas production and coal fiel operations 11.1 1.1 16.3 1.6 Other earnings (losses) 1.0 1.3 (3.1) 3.6 Income from continuing operations $53.8 $46.7 $80.4 $88.3 Synthetic Fuel Operations The synthetic fuels operations generated net income of $41.7 million and $44.3 million in the second quarter of 2003 and 2002, respectively, and $67.2 million and $83.1 million in the first half 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. In late June 2003, the IRS announced that field auditors have raised questions associated with synthetic fuel manufactured at the Colona facility regarding the scientific validity of test procedures and results used to verify a significant chemical change, which is a requirement of the synthetic fuel program. The impact of this review on the Company's synthetic fuel tax credits previously taken or expected to be taken in the future cannot be predicted at this time. See the "OTHER MATTERS" section for a further discussion of the IRS review. The following summarizes the synthetic fuel operations for the second quarter and first half of 2003 and 2002.

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Three Months Ended June 30, Six Months Ended June 30, (in millions) 2003 2002 2003 2002 Tons produced - 2.9 -3A4 c 4.9 6.4 Operating losses, excluding tax credits S(36.4) S(46.9) S(63.5) $(92.0)

Tax credits generated 78.1 91.2 130.7 175.1 Income from continuing operations $41.7 S44.3 S67.2 $83.1 Total 2003 synthetic fuel sales as compared to 2002 decreased $2.6 million and $9.4 million for the second quarter and first half, respectively, primarily due to a change in the synthetic fuel production pattern for 2003. The Company anticipates total synthetic fuel production of approximately 12 million tons for 2003, which is comparable to 2002 production levels.

Gas Production and Coal Fuel Operations Gas operations generated net income of $9.8 million and $0.9 million in the second quarter of 2003 and 2002, respectively, and of $14.7 million and $1.2 million in the first half of 2003 and 2002, respectively. The increase in production resulting from the acquisitions of Westchester Gas in 2002 and North Texas Gas in the first quarter of 2003 drove increased revenue and earnings. Although the Mesa operations continue to produce gas, no additional wells are being drilled at Mesa as various divestiture options are being explored. The following summarizes the gas revenues for the second quarter and first halfof 2003 and 2002 by production facility.

Three Months Ended June 30, Six Months Ended June 30, (in millions) 2003 2002 2003 2002 Mesa S4.0 $3.5 $8.7 $6.6 Westchester Gas 13.4 1.6 28.6 1.6 North Texas Gas 10.4 - 10A.

Other 2.7 0.8 2.6 0.8 Total gas sales $303 $5.9 $50.3 $9.0 Coal fuel operations and other operations within the Fuels segment have immaterial impacts on comparative earnings.

COMPETITIVE COMMERCIAL OPERATIONS CCO generates and sells electricity to the wholesale market through nonregulated plants. These operations also include limited financial trading activities. The following summarizes the net income, sales and generating capacity of the nonregulated plants for the second quarter and first half of 2003 and 2002.

Three Months Ended June 30, Six Months Ended June 30, (in millions except megawatts) 2003 2002 2003 2002 Operating revenue $333 $23.9 $70.8 $32.9 Income from continuing operations $2.4 $6.7 $10.9 S4.6 Generation capacity (MW) - June 30 2,620 1,239 2,620 1,239 The second quarter increase in revenue is primarily due to increased contracted capacity and energy sales from additional plants with tolling agreements. The increase during the first half of 2003 in revenue and earnings is also related to a tolling agreement termination payment from Dynegy. The revenue increases related to higher volumes were partially offset by lower prices in the wholesale energy market, higher depreciation cost of $2.4 million related to the additional facilities and by increases in costs allocated from the Service Company of $2.1 million in accordance with the SEC audit.

In the second quarter of 2003, PVI acquired from Williams Energy Marketing and Trading a full-requirements power supply agreement with Jackson Electric Membership Corp. (Jackson) in Georgia for $188 million.

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 segment to become impaired.

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The 466-megawatt Rowan combined cycle unit and the 600-megawatt Washington combustion turbine facilities were completed and placed into service in June 2003, The Washington plant has a tolling agreement with LG&E Power Trading

& Marketing through December 3i,-2004. The 480-megawatt Effingham ctifibined cycle facility is expected to be placed into service in August 2003 and will complete CCO's nonregulated build-out with a total capacity of 3,100 megawatts.

Including the Jackson contract and the impact of the Dynegy contract termination, mentioned previously, the Company has contracts for 68%, 74% and 50% 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.

RAL Rail's operations include railcar and locomotive repair, trackwork, rail parts reconditioning and sales, scrap metal recycling, railcar leasing and other rail related services. The Company intends to sell the assets of Railcar Ltd., a leasing subsidiary, in 2003 and has classified these assets as assets held for sale at June 30,2003.

Progress Rail contributed net income of $2.2 nillion and $2.9 million for the second quarter of 2003 and 2002, respectively, and a net loss of $1.2 million and net income of $2.2 million for the first half of 2003 and 2002, respectively. As a result of the SEC order, Rail incurred additional Service Company allocations of $1.2 and $6.9 million in the first quarter and first half of 2003, respectively. These increased costs were partially offset by improvements in the recycling business and reduced operating costs.

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 a three year extension from the SEC.

OTHER 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 have been removed and are being reported separately. The segment contributed income from continuing operations of $1.2 million and a loss from continuing operations of $8.4 million in the second quarter of 2003 and 2002, respectively, and income from continuing operations ofSl .9 million and a loss of $13.2 million in the first half of 2003 and 2002, respectively.

The improvement in both the quarter and the half 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. Additionally, SRS recognized a loss in the second quarter of 2002 related to the sale of certain portions of its operations.

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).

Three Months Ended June 30, Six Months Ended June 30, (in nillions) 2003 2002 2003 2002 Interest expense $733 $75.7 S144.3 $146.7 Contingent value obligations 1.7 (1.5) - (12.8)

Tax reallocation 93 30.0 18.6 30.0 Tax levelization 4.8 58.4 (5.4) 79.6 Other income taxes (313) (31.5) (62.4) (63.4)

Other expenses 1.2 3.5 5.1 7.6 Loss from continuing operations S59.0 S134.6 S100.2 $187.7 Progress Energy issued 98.6 million contingent value obligations (CVOs) in connection with the 2000 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 June 30, 2003 and 2002, the CVOs had fair market values of approximately $13.8 million and $29.1 million, respectively. Progress 48

Energy recorded an unrealized loss of S1.7.million and unrealized gain of $1.5 million for the second quarter of 2003 and 2002, respectively, to record the changes in fair value of the CVOs, which had average unit prices of $0.14 and $0.30 at June 30, 2003 and 2002, respectively. The CVO values at June 30, 2003 were unchanged from the January 1, 2003 values, thus requiring no recognition of an unr.lized gain or loss in the first half. A $12.8 inillion unrealized gain was recorded for the first half of 2002.

GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. Income tax expense was increased by $4.8 million and $58.4 million for the second quarter of 2003 and 2002, respectively, in order to maintain an effective tax rate consistent with the estimated annual rate. Income tax expense was decreased by $5.4 million and increased $79.6 million for the first half of 2003 and 2002, respectively. The tax credits associated with the Company's synthetic fuel operations primarily drive the required levelization amount.

Fluctuations in estimated annual earnings and tax credits can also cause large swings in the effective tax rate for interim periods. Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year.

DISCO1NT( D OPERATIONS In the fourth quarter of 2002, the Company's Board of Directors approved the sale of NCNG to Piedmont Natural Gas Company, Inc. As a result of this action, the operating results of NCNG were reclassified to discontinued operations for all reportable periods. Progress Energy expects the sale to close during the third quarter of 2003 for net proceeds of approximately $400 million. An estimated loss on the sale of NCNG of $29.4 million was recognized in the fourth quarter of 2002.

LIOUIDITY AND CAPITAL RESOURCES Progress Energy, Inc.

Statement of Cash Flows and FinancingA ctivities Cash provided by operating activities increased $114.9 million for the six months ended June 30, 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 cash flow at PVI and Progress Fuels, which offset lower cash from operations at the utility operations.

Net cash used in investing activities decreased $137.9 million for the six months ended June 30, 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 six months of 2003, $366.5 million was spent in diversified business property additions. This amount includes the acquisition ofthe natural gas reserves in February 2003 for $148 million. In addition to the $366.5 million spent on diversified business property additions, PVI also purchased a wholesale energy supply contract for approximately $190 million.

The increase in operating cash flow and lower capital expenditures resulted in an increase of $253 million of net cash flow before common dividend payments and other financing activity for the six nronth period ending June 30, 2003 compared with the corresponding period for the prior year.

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, which were retired on March 1,2003, and to redeem on March 24,2003, the $150 million aggregate outstanding balance of its 8% First Mortgage Bonds due 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 June 30,2003 the calculated ratio was 52.6%. 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 June 30,2003 the calculated ratio was 8.7 to 1.

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Also on April 1, 2003, PEC reduced the sizc'if its existing 364-day credit facility from $285 million to $165 million. The other terms of this facility were not changed. On July 30, 2003, PEC renewed its $165 million 364-day credit agreement PEC's

$285 million three-year credit agreement entered into in July 2002 remains in place, for total facilities of $450 million.

On May 27, 2003, PEC redeemed $150 million of First Mortgage Bonds, 7.5% Series, Due March 1, 2023 at 103.22% of the principal amount of such bonds. PEC funded the redemption with commercial paper.

In March 2003, Progress Genco Ventures, LLC (Genco), a wholly owned subsidiary of PVI, terminated its $50 million working capital credit facility. A rekted construction facility initially provided for Genco to draw up to $260 million. The amount outstanding under this facility is $241 million as of June 30, 2003. During the second quarter of 2003 Genco determined it did not need to make any additional draws under this facility. As a result of this decision, the drawn amount of $241 million will not increase.

On July 14, 2003, PEC announced the redemption of $100 million of First Mortgage Bonds, 6.875% Series Due August 15, 2023 at 102.84%. The date of the redemption will be August 15,2003. PEC will fund the redemption with commercial paper.

For the three months ended June 30,2003, the Company issued approximately 2.4 million shares representing approximately

$98 million in proceeds from its Investor Plus Stock Purchase Plan and its employee benefit plans during the second quarter ended June 30, 2003. For the six months ended June 30, 2003, the Company has issued 4.2 million shares through these plans, resulting in $172 million of cash proceeds.

Future Commitments The current portion of long-term debt of $1.1 billion includes $500 million of Progress Energy's 6.55% senior unsecured notes due March 1,2004. The Company expects to have sufficient commercial paper capacity to retire this issue due to the proceeds from the sale ofNorth Carolina Natural Gas (NCNG) in the summer of 2003. The proceeds from the sale of NCNG are expected to be approximately $400 million and will be used to reduce commercial paper. The current portion of long-term debt also includes $400 million of secured debt issued by PEC. These amounts are expected to be refinanced or retired through commercial paper, capital market transactions and with internal generation of funds.

As of June 30, 2003, Progress Energy's guarantees were approximately $1 billion, up from approximately $785 million as of March 31, 2003. The increase is due primarily to a $285 million performance guarantee associated with the purchase of a wholesale power supply contract, as discussed previously.

OTHERMATE .,S PEF Rate 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 to67.1% ofthe 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 order from the FPSC to enforce the Agreement. In this motion, the parties disputed PEF's calculation of retail revenue subject to refund and contended that the refund should have been approximately $23 million. On July 9, 2003, the FPSC ruled that PEF must provide an additional $18.4 million to its retail customers related to the 2002 revenue sharing calculation. PEF recorded this refund in the second quarter 2003 as a charge against electric operating revenue and will refund this amount by no later than October 31,2003. In the second quarter of 2003, PEF also recorded an additional accrual of $9.5 million related to estimated 2003 revenue sharing.

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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 facilitie 4tiaifies for tax credits under Section 29 6fthe 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. Additionally, the ability to use tax credits currently being carried forward could be denied. Total Section 29 credits generated to date (including FPC prior to its acquisition by the Company) are approximately S1.028 billion, of which $445.6 million have-been used and $582.4 million are being carried forward as of June 30, 2003.

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 $273.1 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 the Company'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, and issues not resolved through the program may proceed to the next level of the IRS exam process.

In late June 2003, the Company was informed that IRS field auditors have raised questions regarding the chemical change associated with coal-based synthetic fuel manufactured at its Colona facility and the testing process by which the chemical change is verified. (The questions arose in connection with the Company's participation in the PFA program.)

The chemical change and the associated testing process were described as part of the PLR request for Colona. Based upon that application, the IRS ruled in Colona's PLR that the synthetic fuel produced at Colona undergoes a significant chemical change and thus qualifies for tax credits under Section 29 of the Internal Revenue Code. While the IRS has announced that they may revoke PLRs if test procedures and results do not demonstrate that a significant chemical change has occurred, based on the information received to date, the Company does not believe the issues warrant reversal by the IRS National Office of its prior position in the Colona PLR.

The information provided by the IRS field auditors addresses only Progress Energy's Colona facility. The Company, however, applies essentially the same chemical process and uses the same independent laboratories to confirm chemical change in the synthetic fuel manufactured at each of its four other facilities. The independent laboratories used by the Company to determine significant chemical change are the leading experts in their field and are used by many other industry participants. The Company believes that the laboratories' work and the chemical change process are consistent with the bases upon which its PLRs were issued.

The Company is working to resolve this matter as quickly as possible. At this time, the Company cannot predict how long the IRS process will take; however, the Company intends to continue working cooperatively with the IRS. The Company firmly believes that it is operating the Colona facility and its other plants in compliance with its PLRs and Section 29 of the Internal Revenue Code. Accordingly, the Company has no current plans to alter its synthetic fuel production schedules as a result of these matters.

In addition, the Company has retained an advisor to assist in selling an interest in one or more synthetic fuel entities. The Company is pursuing the sale of a portion of its synthetic fuel production capacity that is underutilized due to limits on the amount of credits that can be generated and utilized by the Company. The Company would expect to retain an ownership interest and to operate any sold facility for a management fee. However, the IRS has suspended issuance of PLRs relating to synthetic fuel production (typically a closing condition to the sale of an interest in a synthetic fuel entity). Unless that suspension on new PLRs is lifted, it will be difficult to consummate the successful sale of interests in the Company's synthetic fuel facilities. The Company cannot predict when or if the IRS will recommence issuing such PLRs. The final outcome and timing of the Company's efforts to sell interests in synthetic fuel facilities is uncertain and while the Company cannot predict the outcome of this matter, the outcome is not expected to have a material effect on the consolidated financial position, cash flows or results of operations.

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Nuclear Matters The Shearon Harris Nuclear Plant in New Hill, North Carolina completed a successful refueling outage on May 18, 2003, when the unit was returned to service, l 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 the fall of 2003.

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 units. The Company is continuing to monitor this development for applicability to our plants and will take appropriate action if and when necessary.

In January 2003, the NRC issued a final order with regard to access control. This order requires the Company to enhance its current access control program by January 7,2004. The Company expects that it will be in full compliance with the order by the established deadline.

The NRC continues to issue additional orders designed to increase security at nuclear facilities. In April 2003, one of the orders issued by the NRC imposes revisions to the Design Basis Threat and requires power plants to implement additional protective actions to protect against sabotage by terrorists and other adversaries. The Company expects that it will be in full compliance with the order by the established deadline. 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 in Florida. As discussed below, two of the six cities, with a total of approximately 21,000 customers, have subsequently settled their lawsuits with PEF and signed new, 30-year franchise agreements. The lawsuits principally seek 1) a declaratory judgment that the cities have the right to purchase PEF's electric distribution system located within the municipal boundaries of the cities, 2) a declaratory judgment that the value of the distribution system must be determined through arbitration, and 3) injunctive relief requiring PEF to continue to collect from PEF's customers and remit to the cities, franchise fees during the pending litigation, and as long as PEF continues to occupy the cities' rights-of-way to provide electric service, notwithstanding the expiration of the franchise ordinances under which PEF had agreed to collect such fees. Five circuit courts have entered orders requiring arbitration to establish the purchase price of PEF's electric distribution system within five cities. Two appellate courts have upheld these circuit court decisions and authorized cities to determine the value of PEF'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's rate filing has been abated pending settlement discussions between the parties. On July 28, the City approved a settlement agreement and a new, 30-year franchise agreement with PEF. The settlement resolves all pending litigation with that city. A second arbitration (with the City of Winter Park) was completed in February 2003. That 52

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arbitration panel issued an award on May 29,2003 setting the value of PEF's distribution system within the City of Winter Park at approximately $31.5 million, not including separation and reintegration and construction work in progress, which could add several million dollars to the award. The panel also awarded PEF approximately $10.7 million in stranded costs.

The City of Winter Park has schlddilk a September 9, 2003 referendum whter 6itizens will decide whether to issue bonds of up to approximately $50 million to acquire PEF's electric distribution system. At this time, whether and when there will be further proceedings regarding the City of Winter Park cannot be determined. A third arbitration (with the Town of Belleair) was completed on June 16, 2003. A decision from the arbitration panel has not yet been issued in that case. A fourth arbitration (with the City of Apopka) has been scheduled for January 2004. On August 4, 2003, the City of Longwood approved a 30-year franchise and a settlement agreement with PEF, which will resolve all pending litigation with the City of Longwood. Arbitration in the remaining city's litigation (the City of Edgewood) has not yet been scheduled.

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 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 six months ended June 30, 2003 and 2002 are not material to PEC's consolidated financial statements.

LIQUIDITY AND CAPITAL RESOURCES Cash provided by operating activities increased $61 million for the six months ended June 30,2003, when compared to the corresponding period in the prior year. The increase was caused primarily by changes in working capital.

Cash used in investing activities increased approximately $150 million for the six months ended June 30, 2003, when compared to the corresponding period in the prior year. The increase was mostly due to $244 million in cash proceeds received during the second quarter of 2002 for the sale of generating assets to Progress Ventures during the first quarter of 2002. The sales proceeds were offset by a decrease in construction spending. During the first six months of 2003, $322 million was spent on PEC's construction program, nuclear fuel additions and contributions to its nuclear decommissioning fund. This amount was approximately $80 million less than the corresponding period last year. The decrease was due to lower construction expenditures associated with generation assets transferred to PVI during 2002.

As of June 30, 2003, PEC's liquidity, contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2002 Annual Report on Form 10-K, as amended.

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. On July 30,2003, PEC renewed its $165 million 364-day credit agreement PEC's $285 mnllion three-year credit agreement entered into in July 2002 remains in place, for total facilities of S450 million.

On May 27,2003, PEC redeemed $150 million of First Mortgage Bonds, 7.5% Series, Due March 1, 2023 at 103.22% of the principal amount of such bonds. PEC funded the redemption with commercial paper.

On July 14,2003, PEC announced the redemption of $100 million of First Mortgage Bonds, 6.875% Series Due August 15, 2023 at 102.84%. The date of the redemption will be August 15, 2003 and the redemption will be funded by PEC with commercial paper.

The current portion of long-term debt includes $400 million of secured debt issued by PEC. The current portion of long-term debt is expected to be refinanced or retired through commercial paper, capital market transactions and internal generation of funds.

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Item_4. Controls and Procedurm Progress Energy. Inc.

Pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934, Progress Energy carried out an evaluation, with the participation of Progress Energy's management, including Progress Energy's Chairman and Chief Executive Officer, and Chief Financial Officer, of the effectiveness of Progress Energy's disclosure controls and procedures (as defined under Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, Progress Energy's Chairman and Chief Executive Officer, and Chief Financial Officer concluded that Progress Energy's 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 Progress Energy's periodic SEC filings. There has been no change in Progress Energy's internal control over financial reporting during the quarter ended June 30, 2003 that has materially affected, or is reasonably likely to materially affect, Progress Energy's internal control over financial reporting.

Proress Energy Carolinas. Inc.

Pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934, PEC carried out an evaluation, with the participation of PEC's management, including PEC's Chairman and Chief Executive Officer, and Chief Financial Officer, of the effectiveness of PEC's disclosure controls and procedures (as defined under Rule 13a-l 5(c) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, PEC's Chairman and Chief Executive Officer, and Chief Financial Officer concluded that PEC's 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 PEC's periodic SEC filings. There has been no change in PEC's internal control over financial reporting during the quarter ended June 30, 2003 that has materially affected, or is reasonably likely to materially affect, PEC's internal control over financial reporting.

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-. APART II. OTHERINFORMATION ILtm.1. Legal Proceedings Legal aspects of certain matters are set forth in Part 1, 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 In November of 2001, SRS filed a claim against the San Francisco Unified School District ("the District") and other defendants claiming that SRS is entitled to approximately $10 million in unpaid contract payments and delay and impact damages related to the District's $30 million contract with SRS. On March 4, 2002, the District filed a counterclaim, seeking compensatory damages and liquidated damages in excess of $120 million, for various claims, including breach of contract and demand on a performance bond. SRS has asserted defenses to the District's claims.

On March 13, 2003, the City Attorney's office announced the filing of new claims by the City Attorney and the District in the form of a cross-complaint against SRS, Progress Energy, Inc., Progress Energy Solutions, Inc., and certain individuals, alleging fraud, false claims, violations of California statutes, and seeking compensatory damages, punitive damages, liquidated damages, treble damages, penalties, attorneys' fees and injunctive relief. The 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 has filed responsive pleadings denying the allegations, and the discovery process is underway. 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 both the District and the City.

Stem4. Submission of Matters to a Vote of Securitv Holders Progress Enern=. Inc.

(a) The Annual Meeting of the Shareholders of Progress Energy, Inc. was held on May 14,2003.

(b) The meeting involved the election of five Class II directors to serve for three-year terms. Proxies for the meeting were solicited pursuant to Regulation 14, there was no solicitation in opposition to management's nominees as listed below, and all nominees were elected.

(c) Results of matters voted on were as follows:

Election of Directors Class 11 Votes For Votes Withheld (Term Expiring in 2006)

Edwin B. Borden 193,007,893 4,613,431 James E. Bostic, Jr. 192,204,838 5,416,487 David L. Burner 192,182,065 5,439,259 Richard L. Daugherty 192,186,613 5,434,712 Richard A. Nunis 193,138,277 4,483,047 56

Shareholder Proposals The shareholder proposal requesting that the Board adopt a policy requiring that all stock option grants to senior executives be performance-based was presented, but was not approved by the shareholders.

The number of shares voted for the proposal was 32,819,916.

The number of shares voted againsft te proposal was 129,021,383.

The number of abstaining votes was 4,662,102.

The delivered not voted total was 31,157,923.

The shareholder proposal requesting that the Board establish a policy of expensing stock options on its annual income statement was presented, but was not approved by the shareholders.

The number of shares voted for the proposal was 72,431,261.

The number of shares voted against the proposal was 88,376,736 The number of abstaining votes was 5,655,400.

The delivered not voted total was 31,157,926.

Carolina Power & Lizht Comnanv. doing business as Progress Energy Carolinas. Inc.

(a) The Annual Meeting of the Shareholders ofCarolina Power & Light Company was held on May 14,2003.

(b) The meeting involved the election of five Class II directors to serve three-year terms. Proxies for the meeting were solicited pursuant to Regulation 14, there was no solicitation in opposition to management's nominees as listed below, and all nominees were elected.

(c) The total votes for the election of directors were as follows:

Class 11 Votes For Votes Withheld (Term Expiring in 2006)

Edwin B. Borden 159,941,669 1,470 James E. Bostic, Jr. 159,941,819 1,320 David L. Burner 159,941,802 1,339 Richard L. Daugherty 159,941,826 1,313 Richard A. Nunis 159,941,437 1,702 Item 6.Exhibits and Reports on Form 8-K (a) Exhibits Exhibit Progress Progress Energy Num Description Energy Inc, Carolinas, Inc, lo(i) Amended and Restated Progress Energy, Inc. Restoration X X Retirement Plan, effective as of July 10, 2002 10(iu) Progress Energy, Inc. Non-Employee Director Stock Unit X X Plan, amended and restated effective July 10, 2002 10(iii) Amended and Restated Supplemental Senior Executive X X Retirement Plan of Progress Energy, Inc., effective January 1, 1984 (As last amended effective July 10, 2002) l0(iv) Amended Management Incentive Compensation Plan of X X Progress Energy, Inc., as amended January 1, 2003 57

10(v) Amendment and Restatenentj dated as of July 30, 2003, to X the 364-Day Revolving Credit Agreement among Carolina Power & Light Company (dlb/a Progress Energy Carolinas, Inc.) and certain Lenders 31(a) Certifications pursuant to Section 302 of the Sarbanes- X X Oxley Act of2002 - Chairman and Chief Executive Officer 31(b) Certifications pursuant to Section 302 of the Sarbanes- X X Oxley Act of 2002 - Executive Vice President md Chief Financial Officer 32(a) Certifications pursuant to Section 906 of the Sarbanes- X X Oxley Act of2002 - Chairman and Chief Executive Officer 32(b) Certifications pursuant to Section 906 of the Sarbanes- X X Oxley Act of 2002 - Executive Vice President and Chief Financial Officer (b) Reports on Form 8-K since the beginning of the quarter:

Progress Energy. Inc.

Financial Item Statements Reoorted Included Date of Event 5 No April 1, 2003 April 1, 2003 9,12 Yes April 23,2003 April 23,2003 7,9 No April 30,2003 April 30,2003 9 No May 30,2003 May 30,2003 7,9 No May 30,2003 June 11,2003 5 No June 24,2003 June 24, 2003 9,12 Yes July 23,2003 July 23, 2003 Carolina Power & Light Company d/b/a Progress Enerrv Carolinas. Inc.

Financial Item Statements Rported Included Date of Event Date Filed 5 No April 1, 2003 April 1, 2003 9,12 Yes April 23,2003 April 23,2003 9,12 Yes July 23, 2003 July 23,2003 58

SIGNATURES 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.

PROGRESS ENERGY, INC, CAROLINA POWER & LIGHT COMPANY Date: August 11, 2003 (Registrants)

By: Isf Peter M. Scott 111 Peter M. Scott III Executive Vice President and Chief Financial Officer By: Isf Robert H. Bazemore. Jr.

Robert K Bazemore, Jr.

Vice President and Controller Chief Accounting Officer 59