ML051590333

Submittal of 10-Q Report

ML051590333
Person / Time
Site:	Brunswick
Issue date:	05/31/2005
From:	Burton C Progress Energy Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
PE&RAS-05-040
Download: ML051590333 (72)

Text

10 CFR 50.75(e)(1)(iii)(B) gTProgress Energy PO Box 1551 411 Fayetteville Street Mall Raleigh NC 27602 Serial: PE&RAS-05-040 May 31, 2005 United States Nuclear Regulatory Commission ATTENTION: Document Control Desk Washington, DC 20555-0001 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:

Carolina Power & Light Company, now doing business as Progress Energy Carolinas, Inc., submits the enclosed quarterly 10-Q Report for Progress Energy, Inc. for the quarterly period ended March 31, 2005.

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 the Brunswick Steam Electric Plant, Unit Nos. 1 and 2, pursuant to 10 CFR 50.75(e)(1)(iii)(B). This requirement was written into the parent company guarantees pursuant to the guidance in Appendix B-6.5 of Regulatory Guide 1.159, "Assuring the Availability of Funds for Decommissioning Nuclear Reactors."

This document contains no new regulatory commitment.

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

Sincerely, Chris Burton Manager - Performance Evaluation & Regulatory Affairs HAS

Enclosure:

0 OM

United States Nuclear Regulatory Commission PE&RAS-05-040 Page 2 c:

without enclosure:

W. D. Travers, Regional Administrator- Region II USNRC Resident Inspector - BSEP, Unit Nos. 1 and 2 B. L. Mozafari, NRR Project Manager - BSEP, Unit Nos. 1 and 2 M. A. Dusaniwskyj, USNRC NRR/DR1P/RPRP J. A. Sanford, Chair- North Carolina Utilities Commission Sam Watson, Attorney - North Carolina Utilities Commission Geneva Thigpen, Chief Clerk - North Carolina Utilities Commission

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

$' ;tli Washington, D.C:20549 FORM 10-Q

[X I QUARTERLY REPORT PURSUANT TO SEC7ION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31. 2005 OR I ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to I.R.S. Employer Commission Exact name of registrants as specified in their charters, state of Identification File Number incorporation, address of principal executive offices, and telephone number 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 dlbla Progress Energy Carolinas, Inc.

410 South Wilmington Street Raleigh, North Carolina 27601-1748 Telephone: (919) 546-6111 State of Incorporation: North Carolina NONE (Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark whether Progress Energy, Inc. (Progress Energy) 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 - No X This combined Form 10-Q is filed separately by two registrants: 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 April 30,2005, each registrant had the following shares of common stock outstanding:

Registrant Descrintion Shares Progress Energy Common Stock (Without Par Value) 248,680,504 PEC Common Stock (Without Par Value) 159,608,055 (all of which were held by Progress Energy, Inc.)

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PROGRESS ENERGY, INC. AND PROGRESS ENERGY CAROLINAS, INC.

FORM 10-Q - For the Quarter Ended Marc_. 31, 2005 Glossary of Terms Safe Harbor For Forward-Looking Statements PART I. 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. Management's Discussion and Analysis of Financial Condition and Results of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures PART II. OTHER INFORMATION Item 1. Legal Proceedings Item 2. Unregistered Sales of Equity Securities and Use of Proceeds Item 6. Exhibits Signatures 2

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

TERM DEFINMON 401(k) Progress Energy 401 (k) Savings and Stock Ownership Plan AFUDC Allowance for funds used during construction the Agreement Stipulation and Settlement Agreement related to retail rate matters ARO Asset retirement obligation Bcf Billion cubic feet Btu British thermal unit CAIR Clean Air Interstate Rule CAMR Clean Air Mercury Rule CCO Competitive Commercial Operations business segment CERCLA or Superfund Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended Code Internal Revenue Code Colona Colona Synfuel Limited Partnership, LLLP the Company Progress Energy, Inc. and subsidiaries CP&L Carolina Power & Light Company, d/b/a Progress Energy Carolinas, Inc.

CR3 Crystal River Unit No.3 CVO Contingent value obligation DOE United States Department of Energy DWM North Carolina Department of Environment and Natural Resources, Division of Waste Management ECRC Environmental Cost Recovery Clause EITF Emerging Issues Task Force EMCs Electric Membership Cooperatives EPA of 1992 Energy Policy Act of 1992 FASB Financial Accounting Standards Board FDEP Florida Department of Environment and Protection FERC Federal Energy Regulatory Commission FIN No. 45 Financial Accounting Standards Board (FASB) Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" FIN No. 46R FASB Interpretation No. 46R, "Consolidation of Variable Interest Entities -

an Interpretation of ARB No. 51" Florida Progress or FPC Florida Progress Corporation FPSC Florida Public Service Commission Fuels Fuels business segment GAAP Accounting Principles Generally Accepted in the United States of America Global U.S. Global LLC the holding company Progress Energy Corporate IRS Internal Revenue Service Jackson Jackson Electric Membership Corporation LIBOR London Inter Bank Offering Rate MACT Maximum Achievable Control Technology Medicare Act Medicare Prescription Drug, Improvement and Modernization Act of 2003 MGP Manufactured Gas Plant MW Megawatt MWh Megawatt-hour NCUC North Carolina Utilities Commission NOx Nitrogen Oxide NOx SIP Call EPA rule which requires 22 states including North and South Carolina to further reduce nitrogen oxide emissions.

NRC United States Nuclear Regulatory Commission Nuclear Waste Act Nuclear Waste Policy Act of 1982 O&M Operations & Maintenance Expense 3

OPEB Postretirement benefits other than pensions PEC Progress Energy Carolinas, Inc., formerly referred to as Carolina Power &

Light Company _, ,, ;l PEC Electric PEC Electric business segmert made up of the utility operations and excludes operations of nonregulated subsidiaries PEF Progress Energy Florida, formerly referred to as Florida Fower Corporation PFA IRS Prefiling Agreement PLR Private Letter Ruling Progress Energy Progress Energy, Inc.

Progress Fuels Progress Fuels Corporation, formerly Electric Fuels Corporation Progress Rail Progress Rail Services Corporation Progress Ventures Business unit of Progress Energy primarily made up of nonregulated energy generation and marketing activities, as well as gas, coal and synthetic fuel operations PRP Potentially responsible party, as defined in CERCLA PTC Progress Telecommunications Corporation PT LLC Progress Telecom, LLC PUHCA Public Utility Holding Company Act of 1935, as amended PV1 Progress Energy Ventures, Inc. (formerly referred to as CPL Energy Ventures, Inc.)

Rail Services Rail Services business segment RCA Revolving credit agreement ROE Return on Equity SCPSC Public Service Commission of South Carolina SEC United States Securities and Exchange Commission Section 29 Section 29 of the Internal Revenue Service Code Service Company Progress Energy Service Company, LLC SFAS Statement of Financial Accounting Standards SFAS No. 5 Statement of Financial Accounting Standards No. 5, "Accounting for Contingencies" SFAS No. 71 Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" SFAS No. 123R Statement of Financial Accounting Standards No. 123R, "Accounting for Stock-Based Compensation" SFAS No. 133 Statement of Financial Accounting Standards No. 133, "Accounting for Derivative and Hedging Activities" SFAS No. 138 Statement of Financial Accounting Standards No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - An Amendment of FASB Statement No. 133" SFAS No. 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" Smokestacks Act North Carolina Clean Smokestacks Act enacted in June 2002 SO 2 Sulfur dioxide SRS Strategic Resource Solutions Corp.

the Trust FPC Capital I 4

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS This combined report contains forwaid-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 are discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" including, but not limited to, statements under the sub-heading "Results of Operations" about trends and uncertainties, "Liquidity and Capital Resources" about future liquidity requirements and "Other Matters" about the Company's synthetic fuel facilities.

Any forward-looking statement is based on information current as of the date of this report and speaks only as of the date on which such statement is made, and neither Progress Energy, Inc. (Progress Energy or the Company) 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; 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; the Company's ability to recover through the regulatory process, and the timing of such recovery of, the costs associated with the four hurricanes that impacted our service territory in 2004 or other future significant weather events; recurring seasonal fluctuations in demand for electricity; fluctuations in the price of energy commodities and purchased power; economic fluctuations and the corresponding impact on the Company and its subsidiaries' commercial and industrial customers; the ability of the Company's subsidiaries to pay upstream dividends or distributions to it; the impact on the facilities and the businesses of the Company from a terrorist attack; the inherent risks associated with the operation of nuclear facilities, including environmental, health, regulatory and financial risks; the ability to successfully access capital markets on favorable terms; the ability of the Company to maintain its current credit ratings and the impact on the Company's financial condition and ability to meet its cash and other financial obligations in the event its credit ratings are downgraded below investment grade; the impact that increases in leverage may have on the Company; the impact of derivative contracts used in the normal course of business by the Company; investment performance of pension and benefit plans; the Company's ability to control costs, including pension and benefit expense, and achieve its cost management targets for 2007; the availability and use of Internal Revenue Code Section 29 (Section 29) tax credits by synthetic fuel producers and the Company's continued ability to use Section 29 tax credits related to its coal and synthetic fuel businesses; the impact to the Company's financial condition and performance in the event it is determined the Company is not entitled to previously taken Section 29 tax credits; the impact of future accounting pronouncements regarding uncertain tax positions; the outcome of Progress Energy Florida's (PEF) rate proceeding in 2005 regarding its future base rates; the Company's ability to manage the risks involved with the operation of its nonregulated plants, including dependence on third parties and related counter-party risks, and a lack of operating history; the Company's ability to manage the risks associated with its energy marketing operations; the outcome of any ongoing or future litigation or similar disputes and the impact of any such outcome or related settlements; and unanticipated changes in operating expenses and capital expenditures. Many of these risks similarly impact the Company's subsidiaries.

These and other risk factors are detailed from time to time in the Company's and PEC's filings with the United States Securities and Exchange Commission (SEC). Many, but not all, of the factors that may impact actual results are discussed in the Risk Factors sections of Progress Energy's and PEC's annual reports on Form 10-K for the year ended December 31, 2004, which were filed with the SEC on March 16, 2005. All such factors are difficult to predict, contain uncertainties that may materially affect actual results and may be beyond the control of Progress Energy and PEC. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor can it assess the effect of each such factor on Progress Energy and PEC.

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PART I. FINANCIAL INFORMATION Item 1. Financial Statements I PROGRESS ENERGY, INC.

CONSOLIDATED INTERIM FINANCIAL STATEMENTS March 31, 2005 UNAUDITED CONSOLIDATED STATEMENTS of INCOME (inmillions except per share data)

Three months ended March 31, 2005 2004 Operating revenues Utility S 1,783 S 1,685 Diversified business 415 321 Total operating revenues 2,198 2,006 Operating expenses Utility Fuel used in electric generation 550 493 Purchased power 198 183 Operation and maintenance 406 363 Depreciation and amortization 208 202 Taxes other than on income 117 105 Diversified business Cost of sales 395 311 Depreciation and amortization 39 41 Other 32 30 Total operating expenses 1,945 1.728 Operating Income 253 278 Other Income (expense)

Interest income 4 2 Other, net 2 (22)

Total other income (expense) 6 (20)

Interest charges Net interest charges 166 161 Allowance for borrowed funds used during construction (3) (1)

Total interest charges, net 163 160 Income from continuing operations before Income tax and minority Interest 96 98 Income tax benefit 1 2 Income from continuing operations before minority interest 97 100 Minority interest in subsidiaries' loss (income), net of tax 8 (1)

Income from continuing operations 105 99 Discontinued operations, net of tax (12) 9 Net Income S 93 S 108 Average common shares outstanding 244 241 Basic earnings per common share Income from continuing operations S OA3 S 0.41 Discontinued operations, net of tax (0.05) 0.04 Net income S 0.38 S 0.45 Diluted earnings per common share Income from continuing operations S 0.43 S 0.41 Discontinued operations, net of tax (0.05) 0.04 Net income S 0.38 S 0.45 Dividends declared per common share S 0.590 SO.575 See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.

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PROGRESS ENERGY, INC. v TWNATMTTVFD fNVQlT TnATFtn ftAT.ANNr. QTWVT4  :. I '

(in millions) March 31, December 31, 2005 2004 ASSETS Utility plant Utility plant in service S 22,117 S 22,103 Accumulated depreciation (9,231) (8,783)

Utility plant in service, net 12,886 13,320 Held for future use 13 13 Construction work in progress 972 799 Nuclear fuel, net of amortization 251 231 Total utility plant, net 14,122 14,363 Current assets Cash and cash equivalents 280 56 Short-term investments 229 82 Receivables 931 911 Inventory 772 805 Deferred fuel cost 235 229 Deferred income taxes 65 111 Assets of discontinued operations - 574 Prepayments and other current assets 291 174 Total current assets 2,803 2,942 Deferred debits and other assets Regulatory assets 1,021 1,064 Nuclear decommissioning trust funds 1,078 1,044 Diversified business property, net 1,861 1,838 Miscellaneous other property and investments 480 444 Goodwill 3,719 3,719 Intangibles, net 330 337 Other assets and deferred debits 282 265 Total deferred debits and other assets 8,771 8,711 Total assets S 25,696 S 26,016 CAPITALIZATION AND LIABILITIES Common stock equity Common stock without par value, 500 million shares authorized, 249 and 247 million shares issued and outstanding, respectively S 5,428 $ 5,360 Unearned restricted shares (I and I million shares, respectively) (16) (13)

Unearned ESOP shares (3 and 3 million shares, respectively (65) (76)

Accumulated other comprehensive loss (159) (164)

Retained earnings 2,475 2,526 Total common stock equity 7,663 7.633 Preferred stock of subsidiaries-not subject to mandatory redemption 93 93 Minority Interest 38 36 Long-term debt, affiliate 270 270 Long-term debt, net 8,728 9,251 Total capitalization 16,792 17,283 Current liabilities Current portion of long-term debt 1,148 349 Accounts payable 582 630 Interest accrued 165 219 Dividends declared 146 145 Short-term obligations 691 684 Customer deposits 186 180 Liabilities of discontinued operations _ 149 Other current liabilities 620 703 Total current liabilities 3,538 3,059 Deferred credits and other liabilities Noncurrent income tax liabilities 603 625 Accumulated deferred investment tax credits 173 176 Regulatory liabilities 2,402 2,654 Asset retirement obligations 1,211 1,282 Other liabilities and deferred credits 977 937 Total deferred credits and other liabilities 5,366 5,674 Commitments and contingencies (Note 14)

Total capitalization and liabilities S 25,696 S 26,016 See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.

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PROGRESS ENERGY, INC.

UNAUDITED CONSOLIDATED STATEMENTS of CASH FLOWS (in millions)

Three Months Ended March 31, 2005 2004 Operating activities Net income S 93 S 108 Adjustments to reconcile net income to net cash provided by operating activities:

Discontinued operations, net of tax 12 (9)

Depreciation and amortization 276 271 Deferred income taxes 13 (7)

Investment tax credit (3) (4)

Deferred fuel cost 19 63 Other adjustments to net income 42 16 Cash provided (used) by changes in operating assets and liabilities:

Receivables 4 50 Inventory (23) 6 Prepayments and other current assets (10) (20)

Accounts payable 38 (35)

Other current liabilities (156) (131)

Regulatory assets and liabilities (55) (7)

Other 29 66 Net cash provided by operating activities 279 367 Investing activities Gross utility property additions (263) (242)

Diversified business property additions (49) (45)

Nuclear fuel additions (64) (39)

Proceeds from sales of subsidiaries and other investments 406 84 Purchases of short-term investments (1,840) (601)

Proceeds from sales of short-term investments 1,693 828 Other (49) (9)

Net cash used In Investing activities (166) (24)

Financing activities Issuance of common stock 60 29 Issuance of long-term debt 495 Net increase in short-term indebtedness 7 503 Retirement of long-term debt (216) (675)

Dividends paid on common stock (145) (141)

Other (48) (62)

Net cash provided by (used In) financing activities 153 (346)

Cash (used) provided by discontinued operations (42) 6 Net Increase In cash and cash equivalents 224 3 Cash and cash equivalents at beginning of period 56 34 Cash and cash equivalents at end of period S280 S 37 See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.

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PROGRESS ENERGY, INC.

NOTES TO CONSOLIDATED INTERIM FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION A. 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 annual 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, 2004, and notes thereto included in Progress Energy's Form 10-K for the year ended December 31, 2004.

In accordance with the provisions of Accounting Principles Board Opinion (APB) No. 28, "Interim Financial Reporting," 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 $3 million and $39 million for the three months ended March 31, 2005 and 2004, respectively, in order to maintain an effective tax rate consistent with the estimated annual rate. The income tax provisions for the Company differ from amounts computed by applying the Federal statutory tax rate to income before income taxes, primarily due to the recognition of synthetic fuel tax credits.

PEC and PEF collect from customers certain excise taxes levied by the state or local government upon the customers. PEC and PEF account for excise taxes on a gross basis. For the three months ended March 31, 2005 and 2004, gross receipts tax, franchise taxes and other excise taxes of approximately

$57 million and $53 million, respectively, are included in utility revenues and taxes other than on income in the Consolidated Statements of Income.

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 2004 have been reclassified to conform to the 2005 presentation.

B. Stock-Based Compensation The Company measures compensation expense for stock options as the difference between the market price of its common stock and the exercise price of the option at the grant date. The exercise price at which options are granted by the Company equals the market price at the grant date, and accordingly, no compensation expense has been recognized for stock option grants. For purposes of the pro forma disclosures required by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - an Amendment of FASB Statement No. 123" (SFAS No. 148), the estimated fair value of the Company's stock options is amortized to expense over the options' vesting period. The following table illustrates the effect on net income and earnings per share if the fair value method had been applied to all outstanding and unvested awards in each period:

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(in millions except per share data) Three Months Ended March 31, 2005 2004 Net income, as reported $ 93 S 108 Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects 1 3 Pro forma net income $ 92 $105 Basic earnings per share As reported S.3C SO.45 Pro forma $0.38 SO.44 Fully diluted earnings per share As reported $0.38 $0.45 Pro forma $0.38 $0.43 The Company expects to begin expensing stock options on July 1, 2005 (See Note 2).

C. Consolidation of Variable Interest Entities The Company consolidates all voting interest entities in which it owns a majority voting interest and all variable interest entities for which it is. the primary beneficiary in accordance with FASB Interpretation No. 46R, "Consolidation of Variable Interest Entities - An Interpretation of ARB No.

51" (FIN No. 46R). The Company is the primary beneficiary of and consolidates two limited partnerships that qualify for federal affordable housing and historic tax credits under Section 42 of the Internal Revenue Code (Code). As of March 31, 2005, the total assets of the two entities were $37 million, the majority of which are collateral for the entities' obligations and are included in other current assets and miscellaneous other property and investments in the Consolidated Balance Sheets.

The Company has an interest in a limited partnership that invests in 17 low-income housing partnerships that qualify for federal and state tax credits. The Company also has interests in two power plants resulting from long-term power purchase contracts. The Company has requested the necessary information to deternine if the 17 partnerships and the two power plant owners are variable interest entities or to identify the primary beneficiaries; all three entities declined to provide the Company with the necessary financial information. Therefore, the Company has applied the information scope exception in FIN No. 46R, paragraph 4(g) to the 17 partnerships and the two power plants. The Company believes that if it is determined to be the primary beneficiary of any of these entities, the effect of consolidating the entities would result in increases to total assets, long-term debt and other liabilities, but would have an insignificant or no impact on the Company's common stock equity, net earnings or cash flows.

The Company also has interests in several other variable interest entities for which the Company is not the primary beneficiary. These arrangements include investments in approximately 28 limited partnerships, limited liability corporations and venture capital funds and two building leases with special-purpose entities. The aggregate maximum loss exposure at March 31, 2005, that the Company could be required to record in its income statement as a result of these arrangements totals approximately $38 million. The creditors of these variable interest entities do not have recourse to the general credit of the Company in excess of the aggregate maximum loss exposure.

2. IMPACT OF NEW ACCOUNTING STANDARDS PROPOSEDFASB INTERPRETATIONOFSFASNO. 109, "ACCOUNT1NG FORINCOME TAXES" In July 2004, the Financial Accounting Standards Board (FASB) stated that it plans to issue an exposure draft of a proposed interpretation of SFAS No. 109, "Accounting for Income Taxes" (SFAS No. 109), that would address the accounting for uncertain tax positions. The FASB has indicated that the interpretation would require that uncertain tax benefits be probable of being sustained in order to record such benefits in the consolidated financial statements. The exposure draft is expected to be issued in the second quarter of 2005. The Company cannot predict what actions the FASB will take or 10

how any such actions might ultimately affect the Company's financial position or results of operations, but such changes could have a material impact on the Company's evaluation and recognition of Section 29 tax credits (See Note 14). Go*'S; SFAS NO. 123 (REVISED 2004), "SHARE-BASED PA YMENT" (SEAS NO. 123R)

In December 2004, the FASB issued SFAS No. 123R, which revises SFAS No. 123, "Accounting for Stock-Based Compensation," and supersedes Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees." The key requirement of SFAS No. 123R is that the cost of share-based awards to employees will be measured based on an award's fair value at the grant date, with such cost to be amortized over the appropriate service period. Previously, entities could elect to continue accounting for such awards at their grant date intrinsic value under APB Opinion No. 25, and the Company made that election. The intrinsic value method resulted in the Company recording no compensation expense for stock options granted to employees (See Note IB).

As written, SEAS No. 123R had an original effective date of July 1, 2005 for the Company. In April 2005, the SEC delayed the effective date for public companies, which resulted in a required effective date of January 1, 2006 for the Company. The SEC delayed the effective date due to concerns that implementation in mid-year could make compliance more difficult and make comparisons of quarterly reports more difficult. The Company currently intends to implement SEAS No. 123R on the original effective date of July 1, 2005. The Company intends to implement the standard using the required modified prospective method. Under that method and with a July 1, 2005 implementation, the Company will record compensation expense under SFAS No. 123R for all awards it grants after July 1, 2005, and it will record compensation expense (as previous awards continue to vest) for the unvested portion of previously granted awards that remain outstanding at July 1, 2005. In 2004, the Company made the decision to cease granting stock options and replaced that compensation with alternative forms of compensation. Therefore, the amount of stock option expense expected to be recorded in 2005 is below the amount that would have been recorded if the stock option program had continued. The Company expects to record approximately $3 million of pre-tax expense for stock options in 2005.

FASB INTERPRETATION NO. 47, "ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT OBLIGATIONS" On March 30, 2005, the FASB issued Interpretation No. 47, "Accounting 'for Conditional Asset Retirement Obligations," an interpretation of SFAS No. 143, "Accounting for Asset Retirement Obligations" (SEAS No. 143). The interpretation clarifies that a legal obligation to perform an asset retirement activity that is conditional on a future event is within the scope of SFAS No. 143.

Accordingly, an entity is required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability's fair value can be reasonably estimated.

The interpretation also provides additional guidance for evaluating whether sufficient information is available to make a reasonable estimate of the fair value. The interpretation is effective for the Company no later than December 31, 2005. The Company has not yet determined the impact of the interpretation on its financial position, results of operations or liquidity.

3. DIVESTITURES Progress Rail Divestiture On March 24, 2005, the Company completed the sale of Progress Rail to One Equity Partners LLC, a private equity firm unit of J.P. Morgan Chase & Co. Gross cash proceeds from the sale are estimated to be S433 million, consisting of $405 million base proceeds plus an estimated working capital adjustment. Proceeds from the sale were used to reduce debt.

Based on the estimated gross proceeds associated with the sale of $433 million, the Company recorded an estimated after-tax loss on disposal of $17 million during the first quarter of 2005. The Company anticipates adjustments to the loss on the divestiture during the second quarter of 2005 related to employee benefit settlements and the finalization of the working capital adjustment and other operating estimates.

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The accompanying consolidated interim financial Etatements have been restated for all periods presented to reflect the operations of Progress Rail as discontinued operations in the Consolidated Statements of Income. Interest expense has been allocated to discontinued operations based on the net assets of Progress Rail, assuming a uniform debt-to-equity ratio across the Company's operations.

Interest expense allocated for the three months ended March 31, 2005 and 2004 was $4 million each period. The Company ceased recording depreciation upon classification of the assets as discontinued operations in February 2005. After-tax depreciation expense recorded by Progress Rail during the three months ended March 31, 2005 and 2004 was $3 million and S2 million, respectively. Results of discontinued operations were as follows:

Three Months Ended March 31, (in millions) 2005 2004 Revenues S 358 $ 239 Earnings before income taxes $ 8 $ 12 Income tax expense 3 3.

Net earnings from discontinued operations 5 9 Estimated loss on disposal of discontinued operations, including income tax benefit of $14 (17)

Earnings (loss) from discontinued operations S (12) $ 9 Prior to the sale of Progress Rail, the results of operations of Progress Rail were reported one month in arrears. Accordingly, the net loss from discontinued operations for the first quarter of 2005 includes four months of Progress Rail's operations.

In connection with the sale, Progress; Fuels and Progress Energy provided guarantees and indemnifications of certain legal, tax and environmental matters to One Equity Partners, LLC. See discussion of the Company's guarantees at Note 14A.

The major balance sheet classes included in assets and liabilities of discontinued operations in the Consolidated Balance Sheets as of December 31, 2004 are as follows:

(in millions)

Accounts receivable $ 172 Inventory 177 Other current assets 18 Total property, plant and equipment, net 174 Total other assets 33 Assets of discontinued operations S 574 Accounts payable S 112 Accrued expenses 37 Liabilities of discontinued operations S 149 In February 2004, the Company sold the majority of the assets of Railcar Ltd., a subsidiary of Progress Rail, to The Andersons, Inc. for proceeds of approximately S82 million.

4. REGULATORY MATTERS PEF Retail Rate Matters Hearings on PEF's petition for recovery of $252 million of storm costs filed with the Florida Public Service Commission (FPSC) were held from March 30, 2005 to April 1, 2005. The FPSC is scheduled to vote on the Company's petition on June 14, 2005, with an order expected on July 5, 2005. The Company cannot predict the outcome of this matter.

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Or. May 4, 2005, a bill was approved by the Florida Legislature that would authorize the FPSC to consider allowing the state's investor-owned utilities to issue bonds that are secured by surcharges on utility customer bills. These bonds would be issued for recovery of storm damage costs and potentially to restore depleted storm reserves. The amount of funds established for recovery is subject to the review and approval of the FPSC. The bill will now be sent to Governor Bush for his consideration.

The Governor has indicated that he supports the bill. The Company cannot predict the outcome of this matter.

On April 29, 2005, PEF submitted minimum filing requirements, based on a 2006 projected test year, to initiate a base rate proceeding regarding its future base rates. In its filing, PEF has requested a $206 million annual increase in base rates effective January 1, 2006. PEF's request for an increase in base rates reflects an increase in operational costs with (i) the addition of Hines 2 generation facility into base rates rather than the Fuel Clause as was permitted under the terms of existing Stipulation and Settlement Agreement (the Agreement), (ii) completion of the Hines 3 generation facility, (iii) the need to replenish PEF's depleted storm reserve by adjusting the annual accrual in light of recent history on a going-forward basis, (iv) the expected infrastructure investment necessary to meet high customer expectations, coupled with the demands placed on PEF's strong customer growth, (v) significant additional costs including increased depreciation and fossil dismantlement expenses and (vi) general inflationary pressures.

Hearings on the base rate proceeding are expected during the third quarter of 2005 and a final decision is expected by the end of 2005. The Company cannot predict the outcome of this matter.

The FPSC requires that PEF perform a depreciation study no less than every four years. PEF filed a depreciation study with the FPSC on April 29, 2005, as part of the Company's base rate filing, which will increase depreciation expense in 2006 by $14 million and forward if approved by the FPSC. The Company cannot predict the outcome or impact of this matter. PEF reduced its estimated removal costs to take into account the estimates used in the depreciation study. This resulted in a downward revision in the PEF estimated removal costs and equal increase in accumulated depreciation of approximately S379 million.

The FPSC requires that PEF update its cost estimate for fossil dismantlement every four years. PEF filed an updated fossil dismantlement study with the FPSC on April 29, 2005, as part of the Company's base rate filing, which will increase the accrual by $10 million and what PEF collects in base rates for fossil dismantlement in 2006 and forward if approved by the FPSC. PEF's retail reserve for fossil plant dismantlement was approximately $133 million at March 31, 2005. Retail accruals on PEF's reserves for fossil dismantlement were previously suspended through December 2005 under the terms of PEF's existing Agreement. The Company cannot predict the outcome or impact of this matter.

The FPSC requires that PEF update its cost estimate for nuclear decommissioning every five years.

PEF filed a new site-specific estimate of decommissioning costs for the Crystal River Nuclear Plant (CR3) with the FPSC on April 29, 2005 as part of the Company's base rate filing. PEF's estimate was based on prompt decommissioning. The estimate, in 2005 dollars, is $614 million and is subject to change based on a variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning and changes in federal, state or local regulations.

The cost estimate excludes the portion attributable to other co-owners of CR3. The NRC operating license held by PEF for Crystal River Unit No. 3 (CR3) currently expires in December 2016. An application to extend this license 20 years is expected to be submitted in the first quarter of 2009. As part of this new estimate and assumed license extension, PEF reduced its ARO liability by approximately S88 million at March 31, 2005. Retail accruals on PEF's reserves for nuclear decommissioning were previously suspended through December 2005 under the terms of the Agreement and the new study supports a continuation of that suspension. The Company cannot predict the outcome or impact of this matter.

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-. , >' e.6-;  ;,...

PEC Retail Rate Matters On April 27, 2005, PEC filed for an increase in the fuel rate charged to its South Carolina customers with the Public Service Commission of South Carolina (SCPSC). PEC is asking the SCPSC to approve a $97 million, or 21 percent, increase in rates. PEC requested the increase for underrecovered fuel costs for the previous 15 months and to meet future expected fuel costs. This request reflects increases in the prices of coal ana niiitiral gas. If approved, the increase wouid take effect July 1, 2005. The Company cannot predict the outcome of this matter.

5. GOODWILL AND OTHER INTANGIBLE ASSETS The Company performed the annual goodwill impairment test in accordance with SFAS No. 142, "Goodwill and Other Intangible Assets," for the CCO segment in the first quarter of 2005, which indicated no impairment was necessary. The annual impairment tests for the PEC Electric and PEF segments will be performed in the second quarter of 2005.

The changes in the carrying amount of goodwill for the periods ended March 31, 2005 and December 31, 2004, by reportable segment, are as follows:

(in millions) PEC Electric PEF CCO Other Total Balance as of January 1, 2004 S 1,922 S 1,733 S 64 $ 7 S 3,726 Purchase accounting adiustment - - - (7) (7)

Balance as of December 31, 2004 $ 1,922 S 1,733 $ 64 $ - $ 3,719 Balance as of March 31,2005 S 1,922 S 1,733 S 64 -S - $ 3,719 The gross carrying amount and accumulated amortization of the Company's intangible assets at March 31, 2005 and December 31, 2004, are as follows:

March 31, 2005 December 31, 2004 Gross Gross Carrying Accumulated Carrying Accumulated (in millions) Amount Amortization Amount Amortization Synthetic fuel intangibles S 134 $ (84) S 134 S (80)

Power agreements acquired 188 (8) 188 (6)

Other 119 (19) 119 (18)

Total S441 . (111) S 441 S (104)

Amortization expense recorded on intangible assets for the three months ended March 31, 2005 and 2004, was $7 million and SlO million, respectively. The estimated annual amortization expense for intangible assets for 2005 through 2009, in millions, is approximately $35, $36, $36, $18 and S18, respectively.

6. EQUITY AND COMPREHENSIVE INCOME A. 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:

Three Months Ended March 31, (in millions) 2005 2004 Weighted-average common shares -basic 244 241 Restricted stock awards 1 1 Weighted-average shares - fully dilutive 245 242 14

B. Comprehensive Income Three Months Ended March 31, (in millions) 2005 2004 Net income $ 93 $108 Other comprehensive income (loss):

Reclassification adjustments included in net income:

Change in cash flow hedges (net of tax expense of SI and S2, respectively) 2 4 Foreign currency translation adjustments included in discontinued operations (6)

Minimum pension liability adjustment included in discontinued operations (net of tax expense of $1) 1 Changes in net unrealized gains (losses) on cash flow hedges (net of tax expense (benefit) of $5 and ($8), respectively) 6 (17)

Foreign currency translation adjustment and other 2 2 Other comprehensive income (loss) $ 5 S (1 '

Comprehensive income $ 98 S 97 C. Common Stock At December 31, 2004, the Company had approximately 63 million shares of common stock authorized by the Board of Directors that remained unissued and reserved. In 2002, the Board of Directors authorized meeting the requirements of the Progress Energy 401(k) Savings and Stock Ownership Plan and the Investor Plus Stock Purchase Plan with original issue shares. For the three months ended March 31, 2005, the Company issued approximately 1.3 million shares under these plans for net proceeds of approximately $58 million.

7. DEBT AND CREDIT FACILITIES AND FINANCING ACTIVITIES Changes to the Company's debt and credit facilities since December 31, 2004, discussed in Note 13 of the Company's 2004 Annual Report on Form 10-K, are described below.

In January 2005, the Company used proceeds from the issuance of commercial paper to pay off $260 million of revolving credit agreement (RCA) loans, which included S90 million at PEC and $170 million at PEF.

On January 31, 2005, Progress Energy, Inc. entered into a new S600 million RCA, which expires December 30, 2005. This facility was added to provide additional liquidity during 2005 due in part to the uncertainty of the timing of storm restoration cost recovery from the hurricanes in Florida during 2004. The RCA includes a defined maximum total debt to total capital ratio of 68% and a minimum interest coverage ratio of 2.5 to 1. The RCA also contains various cross-default and other acceleration provisions. On February 4, 2005, $300 million was drawn under the new facility to reduce commercial paper and pay off the remaining amount of loans outstanding under other RCA facilities, which consisted of $160 million at Progress Energy and $55 million at PEF. As discussed below, the maximum size of this RCA was reduced to $300 million on March 22, 2005.

On March 22, 2005, PEC issued $300 million of First Mortgage Bonds, 5.15% Series due 2015, and

$200 million of First Mortgage Bonds, 5.70% Series due 2035. The net proceeds from the sale of the bonds were used to pay off $300 million of its 7.50% Senior Notes on April 1, 2005, and reduce the outstanding balance of commercial paper. Pursuant to the terms of the Progress Energy $600 million RCA, commitments were reduced to $300 million, effective March 22, 2005.

In March 2005, Progress Energy, Inc.'s five-year credit facility was amended to increase the maximum total debt to total capital ratio from 65% to 68% due to the potential impacts of proposed accounting rules for uncertain tax positions (See Note 2).

15

, .,1~,; ' rp On March 28, 2005, PEF entered into a new $450 million RCA with a syndication of financial institutions. The RCA will be used to provide liquidity support foryPEF's issuances of commercial paper and other short-term obligations. The RCA will expire on' March 28, 2010. The new $450 million RCA replaced PEF's $200 million three-year RCA and $200 million 364-day RCA, which were each terminated effective March 28, 2005. Fees and interest rates under the $450 million RCA are to be determined based upon the credit rating of PEF's long-term unsecured senior non-credit enhanced debt, currently rated as A3 by Moody's Investor Services (Moody's) and BBB by Standard and Poor's (S&P). The RCA includes a defined maximum total debt to capital ratio of 65%. The RCA also contains various cross-default and other acceleration provisions, including a cross-default provision for defaults of indebtedness in excess of $35 million. The RCA does not include a material adverse change representation for borrowings or a financial covenant for interest coverage, which had been provisions in the terminated agreements.

On March 28, 2005, PEC entered into a new $450 million RCA with a syndication of financial institutions. The RCA will be used to provide liquidity support for PEC's issuances of commercial paper and other short-term obligations. The RCA will expire on June 28, 2010. The new $450 million RCA replaced PEC's S285 million three-year RCA and $165 million 364-day RCA, which were each terminated effective March 28, 2005. Fees and interest rates under the $450 million RCA are to be determined based upon the credit rating of PEC's long-term unsecured senior non-credit enhanced debt, currently rated as Baal by Moody's and BBB by S&P. The RCA includes a defined maximum total debt to capital ratio of 65%. The RCA also contains various cross-default and other acceleration provisions, including a cross-default provision for defaults of indebtedness in excess of $35 million.

The RCA does not include a material adverse change representation for borrowings, which had been a provision in the terminated agreements.

8. BENEFIT PLANS The Company and some of its subsidiaries have a noncontributory defined benefit retirement (pension) plan for substantially all full-time employees. The Company also has supplementary defined benefit pension plans that provide benefits to higher-level employees. In addition to pension benefits, the Company and some of its subsidiaries provide contributory other postretirement benefits (OPEB),

including certain health care and life insurance benefits, for retired employees who meet specified criteria. The components of the net periodic benefit cost for the three months ended March 31 are:

Other Postretirement Pension Benefits Benefits (in millions) 2005 2004 2005 2004 Service cost $ 15 S 13 $ 3 $ 4 Interest cost 29 28 8 8 Expected return on plan assets (37) (37) (1) (1)

Amortization of actuarial loss 6 5 1 1 Other amortization, net 1 - - 1 Net periodic cost $ 14 $ 9 $ 11 $ 13 Additional cost / (benefit) recognition (a) (4) (4) 1 1 Net periodic cost recognized S 10 $ 5 $ 12 $ 14 (a) Relates to the acquisition of FPC. See Note 17B of Progress Energy's Form 10-K for year ended December 31, 2004.

9. RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS Progress Energy and its subsidiaries are exposed to various risks related to changes in market conditions. The Company has a risk management committee that 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. Under its risk policy, the Company may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk if the counterparty fails to perform under the contract. The Company minimizes such risk by performing credit reviews using, among other things, publicly available credit ratings of such 16

counterparties. See Note 18 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004.

A. Commodity Derivatives .:l General Most of the Company's commodity contracts are not derivatives pursuant to SFAS No. 133 or qualify as normal purchases or sales pursuant to SFAS No. 133. Therefore, such contracts are not recorded at fair value.

In 2003, PEC recorded a $38 million pre-tax ($23 million after-tax) fair value loss transition adjustment pursuant to the provisions of DIG Issue C20, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature." The related liability is being amortized to earnings over the term of the related contract (See Note 12). At March 31, 2005 and December 31, 2004, the remaining liability was $25 million and $26 million, respectively.

Economic Derivatives Derivative products, primarily electricity and natural gas contracts, may be entered into from time to time for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions. The Company manages open positions with strict policies that limit its exposure to market risk and require daily reporting to management of potential financial exposures. The Company recorded a $2 million pre-tax gain and a

$12 million pre-tax loss on such contracts for the three months ended March 31, 2005 and 2004, respectively. The Company did not have material outstanding positions in such contracts at March 31, 2005 and December 31, 2004.

PEF has derivative instruments related to its exposure to price fluctuations on fuel oil purchases. At March 31, 2005, the fair values of these instruments were a $34 million short-term derivative asset position included in other current assets and a $23 million long-term derivative asset position included in other assets and deferred debits. At December 31, 2004, the fair values of these instruments were a

$2 million long-term derivative asset position included in other assets and deferred debits and a $5 million short-term derivative liability position included in other current liabilities. These instruments receive regulatory accounting treatment. Unrealized gains and losses are recorded in regulatory liabilities and regulatory assets, respectively.

Cash Flow Hedges Progress Energy's subsidiaries designate a portion of commodity derivative instruments as cash flow hedges under SFAS No. 133. The objective for holding these instruments is to hedge exposure to market risk associated with fluctuations in the price of natural gas for the Company's forecasted purchases and sales. Realized gains and losses are recorded net in operating revenues or operating expenses, as appropriate. The ineffective portion of commodity cash flow hedges for the three months ending March 31, 2005 and 2004 was not material to the Company's results of operations.

The fair values of commodity cash flow hedges at March 31, 2005 and December 31, 2004 were as follows:

(in millions) March 31, December 31, 2005 2004 Fair value of assets $ 19 $ -

Fair value of liabilities (26) (15)

Fair value, net $ (7) $ (15) 17

The following table presents selected information related to the Company's commodity cash flow hedges at March 31, 2005:

Accumulated Other e Portion Expected to Comprehensive ' be Reclassified to (term in years/ Maximum Income/(Loss), net of Earnings during the millions of dollars) Term() tax Next 12 Months(b)

Commodity cash flow hedges 10 $ (5) S (16)

(a) Hedges in fair value liability positions have a maximum term of less than two years and hedges in fair value asset positions have a maximum term of 10 years.

( Due to the volatility of the commodities markets, the value in accumulated other comprehensive incomel(loss) (OCI) is subject to change prior to its reclassification into earnings.

B. Interest Rate Derivatives - Fair Value or Cash Flow Hedges The Company uses cash flow hedging strategies to hedge variable interest rates on long-term and short-term debt and to hedge interest rates with regard to future fixed-rate debt issuances. The Company uses fair value hedging strategies to manage its exposure to fixed interest rates on long-term debt. The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss. In the event of default by the counterparty, the risk in these transactions is the cost of replacing the agreements at current market rates.

The fair values of interest rate hedges at March 31, 2005 and December 31, 2004 were as follows:

March 3 1, December 31, (in millions) 2005 2004 Interest rate cash flow hedges $ 2 S (2)

Interest rate fair value hedges S - $ 3 Cash Flow Hedges Gains and losses from cash flow hedges are recorded in OCI and amounts reclassified to earnings are included in net interest charges as the hedged transactions occur. Amounts in OCI related to terminated hedges are reclassified to earnings as the hedged interest payments occur. The ineffective portion of interest rate cash flow hedges for the three months ending March 31, 2005 and 2004 was not material to the Company's results of operations The following table presents selected information related to the Company's interest rate cash flow hedges included in OCI at March 31, 2005: '

Accumulated Other Portion Expected to Comprehensive be Reclassified to (term in years/ Maximum Income/(Loss), net of Earnings during the millions of dollars) Term tax(') Next 12 Months(b)

Interest rate cash flow hedges 1 $ (15) S (3)

(') Includes amounts related to terminated hedges.

( Actual amounts that will be reclassified to earnings may vary from the expected amounts presented above as a result of changes in interest rates.

As of March 31, 2005 and December 31, 2004, the Company had $275 million notional and $331 million notional, respectively, of interest rate cash flow hedges.

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Fair Value Hedges 'e For interest rate fair value hedges, the change in the fair value of the hedging derivative is recorded in net interest charges and is offset by the change in the fair value of the hedged item. As of March 31, 2005 and December 31, 2004, the Company had $150 million notional of interest rate fair value hedges.

10. SEVERANCE COSTS On February 28, 2005, as part of a previously announced cost management initiative, the Company approved a workforce restructuring which is expected to be completed in September 2005 and result in a reduction of approximately 450 positions. The cost management initiative is designed to permanently reduce by $75 million to $100 million the projected growth in the Company's annual operation and maintenance (O&M) expenses by the end of 2007. In addition to the workforce restructuring, the cost management initiative includes a voluntary enhanced retirement program. In connection with this initiative, the Company currently expects to incur estimated pre-tax charges of approximately $210 million for severance and postretirement benefits as described below.-In addition, the Company expects to incur certain incremental costs other than severance and postretirement benefits for recruiting, training and staff augmentation activities that cannot be quantified at this time.

The Company recorded S31 million of expense during the first quarter of 2005 for the estimated severance benefits to be paid as a result of the approximate number of positions to be eliminated under the restructuring and due to the implementation of an automated meter reading initiative at PEF. These amounts will be paid over time and are subject to revision in future quarters based on the impact of the voluntary enhanced retirement program. The severance expenses are primarily included in O&M expense on the Consolidated Statements of Income.

The activity in the severance liability is as follows:

(in millions)

Balance as of January 1, 2005 $ 5 Severance Costs Accrued 31 Payments (1)

Balance as of March 31, 2005 S 35 The Company has estimated that an additional SI 80 million charge will be recognized in the second quarter of 2005 that relates primarily to postretirement benefits that will be paid over time to those eligible employees who elected to participate in the voluntary enhanced retirement program.

Approximately 3,500 of the Company's 12,300 employees were eligible to participate in the voluntary enhanced retirement program. The results from the employee elections indicate that 1,447 of the Company's employees have elected to participate in the voluntary enhanced retirement program. The cost management initiative charges could change significantly primarily due to the demographics of the specific employees who elected enhanced retirement and its impact on the postretirement benefit actuarial studies.

11. FINANCIAL INFORMATION BY BUSINESS SEGMENT The Company currently provides services through the following business segments: PEC Electric, PEF, Fuels, CCO and Synthetic Fuels. Prior to 2005, Rail Services was reported as a separate segment.

In connection with the divestiture of Progress Rail (see Note 3), the operations of Rail Services were reclassified to discontinued operations in the first quarter of 2005 and therefore are not included in the results from continuing operations during the periods reported. In addition, Synthetic Fuel activities were reported in the Fuels segment prior to 2005 and now are considered a reportable segment. These reportable segment changes reflect the current reporting structure. For comparative purposes, the prior year results have been restated to align with the current presentation.

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PEC Electric and PEF are primarily engaged in the generation, transmission, distribution and sale of electric energy in portions of (i) North Carolina and South Carolina and (ii) Florida, respectively.

These electric operations are subject to the rules and regulations of the FERC, the NCUC, the SCPSC, the FPSC and the United States Nuclear Regulatory Commission (NRC). These electric operations also distribute and sell electricity to other utilities, primarily on the east coast of the United States.

Fuels' operations, which are located throughout the United States, are involved in natural gas drilling and production, coal terminal services, coal mining and fuel transportation and delivery.

CCO's operations, which are located primarily in Georgia, North Carolina and Florida, include nonregulated electric generation operations and marketing activities.

Synthetic Fuel operations include the production and sale of synthetic fuel as defined under the Internal Revenue Code and the operation of synthetic fuel facilities for outside parties. These facilities are located in West Virginia, Virginia and Kentucky. See Note 14 for more information.

In addition to these reportable operating segments, the Company has Corporate and other activities that include holding company and service company operations as well as other nonregulated business areas. These nonregulated business areas include telecommunications and energy service operations and other nonregulated subsidiaries that do not separately meet the disclosure requirements of SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." The profit or loss of the identified segments plus the loss of Corporate and Other represents the Company's total income from continuing operations.

Revenues Income from Continuing (in millions) Unaffiliated Intersegment Total Operations Assets FOR THE THREE MONMIS ENDED MARCH 31,2005 PEC Electric S 935 S - S 935 S 116 S 10,953 PEF 848 - 848 43 7,663 Fuels 136 307 443 10 721 CCO 65 - 65 (5) 1,699 Synthetic Fuels 198 - 198 (1) 302 Corporate and Other 16 102 118 (58) 17,778 Eliminations - (409) (409) - (13,420)

Consolidated totals S 2,198 S - S 2,198 S 105 S 25,696 FOR THE THREE MONTIS ENDED MARCH 31,2004 PECElectric S 901 S - S 901 $116 PEF 784 - 784 49 Fuels 98 269 367 10 CCO 33 - 33 (8)

Synthetic Fuels 172 4 176 36 Corporate and Other 18 97 115 (104)

Eliminations - (370) (370)

Consolidated totals S 2,006 S - S 2,006 S 99 20

12. OTHER INCOME AND OTHER EXPENSE Other income and expense includes interest income and other income and expense items as discussed below. The components of other, net as shown on the accompanying Consolidated Statements of Income are as follows:

Three Months Ended March 31, (in millions) 2005 2004 Other income Nonregulated energy and delivery services income $ 6 $ 6 DIG Issue C20 amortization (See Note 9) 1 2 Investment gains 2 2 AFUDC equity 3 2 Other 7 5 Total other income $ 19 S 17 Other expense Nonregulated energy and delivery services expenses $ 5 $ 4 Donations 4 7 Contingent value obligations unrealized loss - 7 Loss from equity investments 3 2 Write-off of non-trade receivables - 7 Other 5 12 Total other expense S 17 $ 39 Other, net $ 2 $ (22)

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.

13. ENVIRONMENTAL MATTERS The Company is subject to federal, state and local regulations addressing hazardous and solid waste management, air and water quality and other environmental matters. See Note 22 of the Company's 2004 Annual Report on Form 10-K for a more detailed, historical discussion of these federal, state, and local regulations.

HAZARDOUS AND SOLID WASTE MINAGEMENT The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liabilities. Some states, including North and South Carolina and Florida, have similar types of legislation. The Company and its subsidiaries are periodically notified by regulators, including the EPA and various state agencies, of their involvement or potential involvement in sites that may require investigation and/or remediation. There are presently several sites with respect to which the Company has been notified by the EPA, the State of North Carolina or the State of Florida of its potential liability, as described below in greater detail. The Company also is currently in the process of assessing potential costs and exposures at other sites. For all sites, as 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. A discussion of sites by legal entity follows.

Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. PEC and PEF are each potentially responsible parties (PRPs) at several manufactured gas plant (MGP) sites.

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PEC, PEF and Progress Fuels Corporation have filed claims with the Company's general liability insurance carriers to recover. costs arising from actual or potential, environmental liabilities. Some claims have been settled and others are still pending. While the Company cannot predict the outcome of these matters, the outcome is not expected to have a material effect on the consolidated financial position or results of operations.

PEC There are nine former MGP sites and a number cf other sites associated with PEC that have required or are anticipated to require investigation and/or remediation.

During the fourth quarter of 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site located in Raleigh, North Carolina. The EPA offered PEC and 34 other PRPs the opportunity to negotiate cleanup of the site and reimbursement of less than $2 million to the EPA for EPA's past expenditures in addressing conditions at the site. Although a loss is considered probable, an agreement among PRPs has not been reached; consequently, it is not possible at this time to reasonably estimate the total amount of PEC's obligation for remediation of the Ward Transformer site.

As of March 31, 2005 and December 31, 2004, PEC's accruals for probable and estimable costs related to various environmental sites, which are included in other liabilities and deferred credits and are expected to be paid out over many years, were:

(in millions) March 31, 2005 December 31, 2004 Insurance fund $5 $ 7 Transferred from North Carolina Natural Gas 2 2 Corporation at time of sale Total accrual for environmental sites $7 $ 9 The insurance fund in the table above was established when PEC received insurance proceeds to address costs associated with environmental liabilities related to its involvement with some sites. All eligible expenses related to these are charged against a specific fund containing these proceeds. PEC made no additional accruals, spent approximately $2 million related to environmental remediation and received no insurance proceeds for the three months ended March 31, 2005.

This accrual has been recorded on an undiscounted basis. PEC measures its liability for these sites based on available evidence including its experience in investigating and remediating environmentally impaired sites. The process often involves assessing and developing cost-sharing arrangements with other PRPs. PEC will accrue costs for the sites to the extent its liability is probable and the costs can be reasonably estimated. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet reached the stage where a reasonable estimate of the remediation costs can be made, PEC cannot determine the total costs that may be incurred in connection with the remediation of all sites at this time. It is anticipated that sufficient information will become available for several sites during 2005 to allow a reasonable estimate of PEC's obligation for those sites to be made.

On March 30, 2005, the North Carolina Division of Water Quality renewed a PEC permit for the continued use of coal combustion products generated at any of the Company's coal-fired plants located in the state. The Company has reviewed the permit conditions, which could significantly restrict the reuse of coal ash and result in higher ash management costs and plans to adjudicate the permit conditions. The Company cannot predict the outcome of this matter.

22

.1 <!..

L~ s...: - -.

PEF As of March 31, 2005 and December 31, 2004, PEF's accruals for probable and estimable costs related to various environmental sitds, which are included in other liabilities and deferred credits and are expected to be paid out over imiany years, were: .; ' I (in millions) March 31, 2005 December 31, 2004 Remediation of distribution and substation S 25 $ 27 transformers MGP and other sites 18 18 Total accrual for environmental sites $ 43 $ 45 PEF has received approval from the FPSC for recovery of costs associated with the remediation of distribution and substation transformers through the Environmental Cost Recovery Clause (ECRC).

Under agreements with the Florida Department of Environmental Protection (FDEP), PEF is in the process of examining distribution transformer sites and substation sites for potential equipment integrity issues that could result in the need for mineral oil impacted soil remediation. PEF has reviewed a number of distribution transformer sites and all substation sites. PEF expects to have completed its review of distribution transformer sites by the end of 2007. Should further sites be identified, PEF believes that any estimated costs would also be recovered through the ECRC. For the three months ended March 31, 2005, PEF made no additional accruals and spent approximately $2 million related to the remediation of transformers. PEF has recorded a regulatory asset for the probable recovery of these costs through the ECRC.

The amounts for MGP and other sites, in the table above, relate to two former MGP sites and other sites associated with PEF that have required or are anticipated to require investigation and/or remediation. In 2004, PEF received approximately $12 million in insurance claim settlement proceeds and recorded a related accrual for associated environmental expenses, as these insurance proceeds are restricted for use in addressing costs associated with environmental liabilities. PEF made no additional accruals or material expenditures and received no insurance proceeds, for the three months ended March 31, 2005.

These accruals have been recorded on an undiscounted basis. PEF measures its liability for-these sites based on available evidence including its experience in investigating and remediating environmentally impaired sites. This process often includes assessing and developing cost-sharing arrangements with other PRPs. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet advanced to the stage where a reasonable estimate of the remediation costs can be made, at this time PEF is unable to provide an estimate of its obligation to remediate these sites beyond what is currently accrued. As more activity occurs at these sites, PEF will assess the need to adjust the accruals. It is anticipated that sufficient information will become available in 2005 to make a reasonable estimate of PEF's obligation for one of the MGP sites.

in Florida, a risk-based corrective action (RBCA, known as Global RBCA) rule was developed by the FDEP and adopted at the February 2, 2005, Environmental Review Commission hearing. Risk-based corrective action generally means that the corrective action prescribed for contaminated sites can correlate to the level of human health risk imposed by the contamination at the property. The Global RBCA rule expands the use of the risk-based corrective action to all contaminated sites in the state that are not currently in one of the state's waste cleanup programs and has the potential for making future cleanups in Florida more costly to complete. The effective date of the Global RBCA rule was April 17, 2005. The Company is in the process of assessing the impact of this rule.

Florida Progress Corporation In 2001, FPC established an accrual to address indemnities and retained an environmental liability associated with the sale of its Inland Marine Transportation business. In 2003, the accrual was reduced to $4 million based on a change in estimate. As of March 31, 2005 and December 31, 2004, the remaining accrual balance was approximately $3 million. Expenditures related to this liability were not material to the Company's financial condition for. the three months ended March 31, 2005. FPC measures its liability for these exposures based on estimable and probable remediation scenarios.

23

Certain historical sites are being addressed voluntarily by FPC. An immaterial accrual has been established to address investigation expenses related to these sites. At this time, the Company cannot determine the total costs that may be incurred in connection with these sites.

Progress Rail On March 24, 2005, the Company closed 61tthe 'sAieof its Progress Rail subsidiary. In connection with the sale, the Company incurred indemnity obligations related to certain pre-closing liabilities, including certain environmental matters (see discussion under Guarantees in Note 14A).

AIR QUALITY The Company is subject to various current and proposed federal, state, and local environmental compliance laws and regulations, which may result in increased planned capital expenditures and operating and maintenance costs. Significant updates to these laws and regulations and related impacts to the Company since December 31, 2004, are discussed below. Additionally, Congress is considering legislation that would require reductions in air emissions of NOx, SO2 , carbon dioxide and mercury.

Some of these proposals establish nationwide caps and emission rates over an extended period of time.

This national multi-pollutant approach to air pollution control could involve significant capital costs that could be material to the Company's consolidated financial position or results of operations.

Control equipment that will be installed on North Carolina fossil generating facilities as part of the North Carolina Clean Smokestacks Act (Smokestacks Act), enacted in 2002 and discussed below, may address some of the issues outlined above. However, the Company cannot predict the outcome of the matter.

The EPA is conducting an enforcement initiative related to a number of coal-fired utility power plants in an effort to determine whether changes'at those facilities were subject to New Source Review requirements or New Source' Performance Standards under the Clean Air Act. The Company was asked to provide information to the EPA as part of this initiative and cooperated in supplying the requested information. The EPA initiated civil enforcement actions against other unaffiliated utilities as part of this initiative. Some of these actions resulted in settlement agreements calling for expenditures by these unaffiliated utilities in excess of $1.0 billion. These settlement agreements have generally called for expenditures to be made over extended time periods, and some of the companies may seek recovery of the related cost through rate adjustments or similar mechanisms.

Total capital expenditures to meet the requirements of the final rule under Section 110 of the Clean Air Act (NOx SIP Call) in North and South Carolina could reach approximately $370 million. This amount also includes the cost to install NOx' controls under North Carolina's and South Carolina's programs to comply with the federal 8-hour ozone standard. However, further technical analysis and rulemaking may result in requirements for additional controls at some units. To date, the Company has spent approximately $303 million related to these projected amounts. Increased operation and maintenance costs relating to the NOx SIP. Call are not expected to be material to the Company's results of operations. Further controls are anticipated as electricity demand increases. Parties unrelated to the Company have undertaken efforts to have Georgia excluded from the rule and its requirements.

Georgia has not yet submitted a state implementation plan to comply with the Section 110 NOx SIP Call. The Company cannot predict the outcome of this matter for the impact to its nonregulated operations in Georgia.

The Company projects that its capital costs to meet emission targets for NOx and SO2 from coal-fired power plants under the Smokestacks Act, will total approximately S895 million by the end of 2013.

PEC has expended approximately S 141 million of these capital costs through March 31, 2005. The law requires PEC to amortize 70% of the original cost estimate of S813 million, during a five-year rate freeze period. PEC recognized amortization of $27 million for the three months ended March 31, 2005, and has recognized $275 million in cumulative amortization through March 31, 2005. The remaining amortization requirement will be recorded over the future period ending December 31, 2007. The law permits PEC the flexibility to vary the amortization schedule for recording the compliance costs from no amortization expense up to $174 million per year. The NCUC will hold a hearing prior to December 31, 2007, to determine cost recovery amounts for 2008 and future periods.

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O&M expense will significantly increase due to the additional materials, personnel and general maintenance associated with the equipment. O&M expenses are recoverable through base rates, rather than as part of this pro"gram. The Company cannot predict the fifture regulatory interpretation, implementation or impact of this law.

On March 10, 2005, the EPA issued the final Clean Air Interstate Rule (CAIR). The EPA's rule requires 28 states and the District of Columbia, including North Carolina, South Carolina, Georgia and Florida, to reduce NOx and S02 emissions in order to attain state NOx and S02 emissions levels. The Company is reviewing the final rule. Installation of additional air quality controls is likely to be needed to meet the CAIR requirements. The Company is in the process of determining compliance plans and the cost to comply with the rule. The air quality controls already installed for compliance with the NOx SIP Call and currently planned by the Company to comply with the Smokestacks Act will reduce the costs required to meet the CAIR requirements for the Company's North Carolina units.

On March 15, 2005, the EPA finalized two separate but related rules: the Clean Air Mercury Rule (CAMR) that sets emissions limits to be met in two phases and encourages a cap and trade approach to achieving those caps, and a de-listing rule that eliminated any requirement to pursue a maximum achievable control technology (MACT) approach for limiting mercury emissions from coal-fired power plants. NOx and SO2 controls also are effective in reducing mercury emissions, however, according to the EPA the second phase cap reflects a level of mercury emissions reduction that exceeds the level that would be achieved solely as a co-benefit of controlling NOx and S0 2 under CAIR The Company is in the process of determining compliance plans and the cost to comply with the CAMR. Installation of additional air quality controls is likely to be needed to meet the CAMR's requirements. The de-listing rule has been challenged by a number of parties; the resolution of the challenges could impact the Company's final compliance plans and costs.

In conjunction with the proposed mercury rule, the EPA proposed a MACT standard to regulate nickel emissions from residual oil-fired units. The EPA withdrew the proposed nickel rule in March 2005.

PEF is filing a petition through the ECRC program for recovery of costs for development and implementation of an integrated strategy to comply with the CAIR and CAMR PEF is developing an integrated compliance strategy for the CAIR and CAMR rules because NOx and SO2 controls also are effective in reducing mercury emissions. PEF estimates the program costs for the remainder of 2005 to be approximately $2 million for preliminary engineering activities and strategy development work necessary to determine the Company's integrated compliance strategy. PEF projects approximately

$62 million in program costs for 2006. These costs may increase or decrease depending upon the results of the engineering and strategy development work. Among other things, subsequent rule interpretations, equipment availability, or the unexpected acceleration of the initial NOx or other compliance dates could require acceleration of some projects and therefore result in additional costs in 2005 and 2006. PEF expects to incur significant additional capital and O&M costs to achieve compliance with the CAIR and CAMR through 2015 and beyond. The timing and extent of the costs for future projects will depend upon the final compliance strategy.

In March 2004, the North Carolina Attorney General filed a petition with the EPA under Section 126 of the Clean Air Act, asking the federal government to force coal-fired power plants in 13 other states, including South Carolina, to reduce their NOx and SO2 emissions. The state of North Carolina contends these out-of-state emissions interfere with North Carolina's ability to meet national air quality standards for ozone and particulate matter. The EPA has agreed to make a determination on the petition by August 1, 2005. The Company cannot predict the outcome of this matter.

WATER QUAU7Y As a result of the operation of certain control equipment needed to address the air quality issues outlined above, new wastewater streams may be generated at the affected facilities. Integration of these new wastewater streams into the existing wastewater treatment processes may result in permitting, construction and treatment requirements imposed on PEC and PEF in the immediate and extended future.

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I Based on new cost information and changes to the estimated time frame of expenditures, the Company has revised the estimated amounts and time period for expenditures to meet Section 316(b) requirements of the Clean Water Act. The Company currently estimates that from 2005 through 2010 the range of expenditures will be approximately $80 million to $110 million. The range includes S15 million to $25 million at PEC and $65 million to $85 million at PEF.

OTHER ENVIRONMENTAL MA7TERS 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 treaty went into effect on February 16, 2005. The United States has not adopted the Kyoto Protocol, and the Bush administration has stated it favors voluntary programs. A number of carbon dioxide emissions control proposals have been advanced in Congress. Reductions in carbon dioxide emissions to the levels specified by the Kyoto Protocol and some legislative proposals could be materially adverse to the Company's consolidated financial position or results of operations if associated costs of control or limitation cannot be recovered from customers. The Company favors the voluntary program approach recommended by the Bush administration and continually evaluates options for the reduction, avoidance and sequestration of greenhouse gases. However, the Company cannot predict the outcome of this matter.

Progress Energy has announced its plan to issue a report on the Company's activities associated with current and future environmental requirements. The report will include a discussion of the environmental requirements that the Company currently faces and expects to face in the future with respect to its air emissions. The report is expected to be issued by March 31, 2006.

14. COMMITMENTS AND CONTINGENCIES Contingencies and significant changes to the commitments discussed in Note 23 of the Company's 2004 Annual Report on Form 10-K are described below.

A. Guarantees As a part of normal business, Progress Energy and certain wholly-owned subsidiaries enter into various agreements providing future financial or performance assurances to third parties, which are outside the scope of FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN No. 45).

Such agreements include guarantees, standby letters of credit and surety bonds. At March 31, 2005, the Company does not believe conditions are likely for significant performance under these guarantees. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included in the accompanying Consolidated Balance Sheets.

At March 31, 2005, the Company had issued guarantees and indemnifications of certain legal, tax and environmental matters to third parties in connection with sales of businesses and for timely payment of obligations in support of its non-wholly owned synthetic fuel operations. Related to the sales of businesses, the notice period extends until 2012 for the majority of matters provided for in the indemnification provisions. For matters which the Company has received timely notice, the Company's indemnity obligations may extend beyond the notice period. Certain environmental indemnifications related to the sale of synthetic fuel operations have no limitations as to time or maximum potential future payments. Other guarantees and indemnifications have an estimated maximum exposure of approximately $111 million. At March 31, 2005, the Company has recorded liabilities related to guarantees and indemnifications to third-parties of $22 million. Management does not believe conditions are likely for significant performance under these agreements in excess of the recorded liabilities.

B. Insurance PEC and PEF are members of Nuclear Electric Insurance Limited (NEIL), which provides primary and excess insurance coverage against property damage to members' nuclear generating facilities. Under the primary program, each company is insured for $500 million at each of its respective nuclear plants.

In addition to primary coverage, NEIL also provides decontamination, premature decommissioning and excess property insurance with limits of S1 .75 billion on each plant.

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C. Other Commitments As discussed in Note 23B of the Progress Energy annual report on Form 10-K for the year ended December 31, 2004, the Company has certain future commitments related to four synthetic fuel facilities purchased that provide for contingent payments (royalties). The Company has exercised its right in the related agreements to escrow those payments if certain conditions in the agreements were met. The Company previously accrued and retained 2004 and 2003 royalty payments of approximately

$42 million and S48 million, respectively. In May 2005, these funds were placed into escrow upon establishment of the necessary escrow accounts.

D. Other Contingencies

1. Pursuant to the Nuclear Waste Policy Act of 1982, the predecessors to PEF and PEC entered into contracts with the U.S. Department of Energy (DOE) under which the DOE agreed to begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract.

DOE failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004, PEC and PEF filed a complaint in the United States Court of Federal Claims against the DOE, claiming that the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel (SNF) by failing to accept SNF from various Progress Energy facilities on or before January 31, 1998. Damages due to DOE's breach will likely exceed S100 million. Approximately 60 cases involving the Government's actions in connection with spent nuclear fuel are currently pending in the Court of Federal Claims.

DOE and the PEC/PEF parties have agreed to a stay of the lawsuit, including discovery. The parties agreed to, and the trial court entered, a stay of proceedings, in order to allow for possible efficiencies due to the resolution of legal and factual issues in previously filed cases in which similar claims are being pursued by other plaintiffs. These issues may include, among others, so-called "rate issues,' or the minimum mandatory schedule for the acceptance of SNF and high level waste (HLW) by which the Government was contractually obligated to accept contract holders' SNF and/or HLW, and issues regarding recovery of damages under a partial breach of contract theory that will be alleged to occur in the future. These issues have been or are expected to be presented in the trials that are currently scheduled to occur during 2005. Resolution of these issues in other cases could facilitate agreements by the parties in the PEC/PEF lawsuit, or at a minimum, inform the Court of decisions reached by other courts if they remain contested and require resolution in this case. The trial court has continued this stay until June 24,2005.

On February 27, 2004, PEC requested to have its license for the Independent Spent Fuel Storage Installation at the Robinson Plant extended by 20 years with an exemption request for an additional 20-year extension. Its current license is due to expire in August 2006. On March 30, 2005, the NRC issued the 40-year license renewal.

With certain modifications and additional approval by the NRC, including the installation of onsite dry storage facilities at Robinson and Brunswick, PEC's spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on PEC's system through the expiration of the operating licenses for all of PEC's nuclear generating units.

With certain modifications and additional approval by the NRC, including the installation of onsite dry storage facilities at PEF's nuclear unit, Crystal River Unit No. 3 (CR3), PEF's spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on PEF's system through the expiration of the operating license for CR3.

In July 2002, Congress passed an override resolution to Nevada's veto of DOE's proposal to locate a permanent underground nuclear waste storage facility at Yucca Mountain, Nevada. In January 2003, the State of Nevada, Clark County, Nevada, and the City of Las Vegas petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of the Congressional override resolution.

These same parties also challenged EPA's radiation standards for Yucca Mountain. On July 9, 2004, the Court rejected the challenge to the constitutionality of the resolution approving Yucca Mountain, but ruled that the EPA was wrong to set a 10,000-year compliance period in the radiation protection standard. EPA is currently reworking the standard but has not stated when the work will be complete.

DOE originally planned to submit a license application to the NRC to construct the Yucca Mountain 27

facility by the end of 2004. However, in November 2004, DOE announced it would not submit the license application until, mid-2005 or later. Also in November,.2004, Congressional negotiators approved $577 million foirfiscal year 2005 for the Yucca Mountain project, approximately S300 million less than requested by DOE but approximately the same as approved in 2004. The DOE has acknowledged that a working repository will not be operational until sometime after 2010, but the DOE has not identified a new target date. PEC cannot predict the outcome of this matter.

2. In 2001, PEC entered into a contract to purchase coal from Dynegy Marketing and Trade (DMT).

After DMT experienced financial difficulties, including credit ratings downgrades by certain credit reporting agencies, PEC requested credit enhancements in accordance with the terms of the coal purchase agreement in July 2002. When DMT did not offer credit enhancements, as required by a provision in the contract, PEC terminated the contract in July 2002.

PEC initiated a lawsuit seeking a declaratory judgment that the termination was lawful. DMT counterclaimed, stating the termination was a breach of contract and an unfair and deceptive trade practice. On March 23, 2004, the United States District Court for the Eastern District of North Carolina ruled that PEC was liable for breach of contract, but ruled against DMT on its unfair and deceptive trade practices claim. On April 6, 2004, the Court entered a judgment against PEC in the amount of approximately $10 million. The Court did not rule on DMT's request under the contract for pending legal costs.

On May 4, 2004, PEC authorized its outside counsel to file a notice of appeal of the April 6, 2004, judgment, and on May 7, 2004, the notice of appeal was filed with the United States Court of Appeals for the Fourth Circuit. On June 8, 2004, DMT filed a motion to dismiss the appeal on the ground that PEC's notice of appeal should have been filed on or before May 6, 2004. On June 16, 2004, PEC filed a motion with the trial court requesting an extension of the deadline for the filing of the notice of appeal. By order dated September 10, 2004, the trial court denied the extension request. On September 15, 2004, PEC filed a notice of appeal of the September 10, 2004 order, and by order dated September 29, 2004, the appellate court consolidated the first and second appeals. DMT's motion to dismiss the first appeal remains pending. Argument on the consolidated appeal is scheduled for May 25, 2005.

In the first quarter of 2004, PEC recorded a liability for the judgment of approximately S10 million and a regulatory asset for the probable recovery through its fuel adjustment clause. The Company cannot predict the outcome of this matter.

3. On February 1, 2002, PEC filed a complaint with the Surface Transportation Board (STB) challenging the rates charged by Norfolk Southern Railway Company (Norfolk Southern) for coal transportation to certain generating plants. In a decision dated December 23, 2003, the STB found that the rates were unreasonable, awarded reparations and prescribed maximum rates. Both parties petitioned the STB for reconsideration of the December 23, 2003 decision. On October 20, 2004, the STB reconsidered its December 23, 2003 decision and concluded that the rates charged by Norfolk Southern were not unreasonable. Because PEC paid the maximum rates prescribed by the STB in its December 23, 2003 decision for several months during 2004, which were less than the rates ultimately found to be reasonable, the STB ordered PEC to pay to Norfolk Southern the difference between the rate levels plus interest.

PEC subsequently filed a petition with the STB to phase in the new rates over a period of time, and filed a notice of appeal with the U.S. Court of Appeals for the D.C. Circuit. Pursuant to an order issued by the STB on January 6, 2005, the phasing proceeding will proceed on a schedule that appears likely to produce an STB decision before the end of 2005. On January 12, 2005, the STB filed a Motion to Dismiss PEC's appeal on the grounds that its October 20, 2004 order is not final until PEC's phasing application has been decided. PEC responded to this motion on January 26, 2005. The court has not yet ruled on the motion.

As of March 31, 2005, PEC has accrued a liability of $42 million, of which $23 million represents reparations previously remitted to PEC by Norfolk Southern that are now subject to refund. Of the remaining $19 million, S17 million has been recorded as deferred fuel cost on the Consolidated Balance Sheet, while the remaining $2 million attributable to wholesale customers has been charged to fuel used in electric generation on the Consolidated Statements of Income. PEC or Norfolk Southern, as the case may be, will make the appropriate payment to the other to reconcile all charges, including interest, once a final STB decision in the phasing proceeding is served.

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The Company cannot predict the outcome of this matter.

4. The Company, through its subsidiaries, is a majority owner in five entitie.- and a minority owner ir.

one entity that owns facilities that produce synthetic fuel as defined under the Internal Revenue Code (Code). The production and sale of the synthetic fuel from these facilities qualify for tax credits under Section 29 if certain requirements are satisfied, including a requirement that the synthetic fuel differs significantly in chemical composition from the coal used to produce such synthetic fuel and that the fuel was produced from a facility that was placed in service before July 1, 1998. The amount of Section 29 tax credits that the Company is allowed to claim in any calendar year is limited by the amount of the Company's regular federal income tax liability. Synthetic fuel tax credit amounts allowed but not utilized are carried forward indefinitely as deferred alternative minimum tax credits.

All entities have received PLRs from the IRS with respect to their synthetic fuel operations. However, these PLRs do not address the placed-in-service date determination. The PLRs do not limit the production on which synthetic fuel credits may be claimed. Total Section 29 credits generated to date (including those generated by FPC prior to its acquisition by the Company) are approximately S1.5 billion, of which $719 million has been used to offset regular federal income tax liability and $777 million are being carried forward as deferred alternative minimum tax credits. Also, $27 million has not been recognized due to the decrease in tax liability resulting from expenses incurred for the 2004 hurricane damage and loss on sale of Progress Rail. The current Section 29 tax credit program expires at the end of 2007.

The sale of Progress Rail in 2005 (see Note 3) resulted in a capital loss for tax purposes. Capital losses that are not offset with capital gains generated in 2005 will be carried back to reduce the regular federal income tax liability in 2004. The estimated impact of the sale will result in approximately S17 million in tax credits no longer being realized and reflected as a deferred tax asset.

On November 2, 2004, PEF filed a petition with the FPSC to recover S252 million of storm costs plus interest from customers over a two-year period (see Note 4). Based on the reasonable expectation at December 31, 2004, that the FPSC will grant the requested recovery of the storm costs, the Company's loss from the casualty was reduced. Therefore, the Company's 2004 tax liability was greater than originally anticipated, along with its ability to record Section 29 tax credits from its synthetic fuel facilities in 2004.

The Company believes its right to recover storm costs is well established; however, the Company cannot predict the timing or outcome of this matter. If the FPSC should deny PEF's petition for the recovery of storm costs in 2005, there could be a material impact on the amount of 2005 synthetic fuels production and results of operations.

IRSPROCEEDINGS In September 2002, all of Progress Energy's majority-owned synthetic fiel entities were accepted into the IRS's Pre-Filing Agreement (PFA) program. The PFA program allows taxpayers to voluntarily accelerate the IRS exam process in order to seek resolution of specific issues.

In February 2004, subsidiaries of the Company finalized execution of the Colona Closing Agreement with the IRS concerning their Colona synthetic fuel facilities. The Colona Closing Agreement provided that the Colona facilities were placed in service before July 1, 1998, which is one of the qualification requirements for tax credits under Section 29. The Colona Closing Agreement further provides that the fuel produced by the Colona facilities in 2001 is a "qualified fuel" for purposes of the Section 29 tax credits. This action concluded the PFA program with respect to Colona.

In July 2004, Progress Energy was notified that the IRS field auditors anticipated taking an adverse position regarding the placed-in-service date of the Company's four Earthco synthetic fuel facilities.

Due to the IRS auditors' position, the IRS decided to exercise its right to withdraw from the PFA program with Progress Energy. With the IRS's withdrawal from the PFA program, the review of Progress Energy's Earthco facilities is back on the normal procedural audit path of the Company's tax returns.

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On October 29, 2004, Progress Energy received the IRS field auditors' preliminary report concluding that the Earthco facilities had not been placed ,in service before July 1, 1998, and that the tax credits generated by those facilities should be disallowed. The Company disagrees with the field audit team's factual findings and believes that the Earthco facilities were placed in service before July 1, 1998. The Company also believes that the report applies an inappropriate legal standard concerning what constitutes "placed in service." The Company intends to contest the field auditors' findings and their proposed disallowance of the tax credits.

Because of the disagreement between the Company and the field auditors as to the proper legal standard to apply, the Company believes that it is appropriate and helpful to have this issue reviewed by the National Office of the IRS, just as the National Office reviewed the issues involving chemical change. Therefore, the Company is asking the National Office to clarify the legal standard and has initiated this process with the National Office. The Company believes that the appeals process, including proceedings before the National Office, could take up to two years to complete; however, it cannot control the actual timing of resolution and cannot predict the outcome of this matter.

Through March 31, 2005, the Company, on a consolidated basis, has used or carried forward approximately $1.1 billion of tax credits generated by Earthco facilities. If these credits were disallowed, the Company's one-time exposure for cash tax payments would be $300 million (excluding interest), and earnings and equity would be reduced by approximately Si.1 billion, excluding interest. Progress Energy's amended $1.13 billion credit facility includes a covenant that limits the maximum debt-to-total capital ratio to 68%. This ratio includes other forms of indebtedness such as guarantees issued by PGN, letters of credit and capital leases. As of March 31, 2005, the Company's debt-to-total capital ratio was 61.1% based on the credit agreement definition for this ratio.

The impact on this ratio of reversing approximately $1.1 billion of tax credits and paying $300 million for taxes would be to increase the ratio to 65.2%.

The Company believes that it is complying with all the necessary requirements to be allowed such credits under Section 29, and, although it cannot provide certainty, it believes that it will prevail in these matters. Accordingly, while the Company adjusted its synthetic fuel production for 2004 in response to the effects of expenses incurred due to the hurricane damage and its impact on 2004 tax liability, it has no current plans to alter its synthetic fuel production schedule for future years as a result of the IRS field auditors' report. However, should the Company fail to prevail in these matters, there could be material liability for previously used or carried forward Section 29 tax credits, with a material adverse impact on earnings and cash flows.

As discussed in Note 8F of the Progress Energy annual report on Form 10-K for the year ended December 31, 2004, the Company implemented changes in its capitalization policies for its Energy Delivery business units in PEC and PEF effective January 1, 2005. As a result of the changes in accounting estimates for the outage and emergency work and indirect costs, a lesser proportion of PEC's and PEF's costs will be capitalized on a prospective basis. The Company has requested a method change from the IRS. If the IRS does not grant the Company's request, the Company cannot predict how the IRS would suggest that the method change be applied. However, the application of the method change to past periods could be reflected in a cumulative adjustment to taxable income in 2005, which likely would have a material impact on income from synthetic fuel tax credits.

PROPOSEDACCOUNTING RULES FOR UNCERTAIN TAXPOSITIONS In July 2004, the FASB stated that it plans to issue an exposure draft of a proposed interpretation of SFAS No. 109, "Accounting for Income Taxes," that would address the accounting for uncertain tax positions. The FASB has indicated that the interpretation would require that uncertain tax benefits be probable of being sustained in order to record such benefits in the financial statements. The exposure draft is expected to be issued in the second quarter of 2005. The Company cannot predict what actions the FASB will take or how any such actions might ultimately affect the Company's financial position or results of operations, but such changes could have a material impact on the Company's evaluation and recognition of Section 29 tax credits.

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PERMANENT SUBCOMMIITEE In October 2003, the United States Senate Permanent Subcommittee on Investigations began a general investigation concerning synthetic fuel tax credits claimed under Section 29. The investigation is examining the utilization of the credits, the nature of the technologies and fuels created, the use of the synthetic fuel and other aspects of Section 29 and is not specific to the Company's synthetic fuel operations. Progress Energy is providing information in connection with this investigation. The Company cannot predict the outcome of this matter.

IMPA CT OF CRUDE OIL PRICES Although the Internal Revenue Code Section 29 tax credit program is expected to continue through 2007, recent unprecedented increases in the price of oil could limit the amount of those credits or eliminate them entirely for one or more of the years following 2004. This possibility is due to a provision of Section 29 that provides that if the average wellhead price per barrel for unregulated domestic crude oil for the year (the Annual Average Price) exceeds a certain threshold price (the Threshold Price), the amount of Section 29 tax credits are reduced for that year. Also, if the Annual Average Price increases high enough (the Phase Out Price), the Section 29 tax credits are eliminated for that year. For 2004, the Threshold Price was $51.35 per barrel and the Phase Out Price was $64.47 per barrel. The Threshold Price and the Phase Out Price are adjusted annually for inflation.

If the Annual Average Price falls between the Threshold Price and the Phase Out Price for a year, the amount by which Section 29 tax credits are reduced will depend on where the Average Annual Price falls in that continuum. For example, for 2004, if the Annual Average Price had been S57.91 per barrel, there would have been a 50% reduction in the amount of Section 29 tax credits for that year.

The Secretary of the Treasury calculates the Annual Average Price based on the Domestic Crude Oil First Purchases Prices published by the Energy Information Agency (EIA). Because the EIA publishes its information on a three-month lag, the Secretary of the Treasury finalizes its calculations three months after the year in question ends. Thus, the Annual Average Price for calendar year 2004 was published on April 6, 2005, and the Annual Average Price for 2004 did not reach the Threshold Price for 2004. Consequently, the amount of the Company's 2004 Section 29 tax credits was not adversely affected by oil prices.

The Company estimates that the 2005 Threshold Price will be approximately $52 and the Phase Out price will be approximately $65, based on an estimated 2005 inflation adjustment. The monthly Domestic Crude Oil First Purchases price published by the EIA has recently been S5 to $6 lower than the corresponding monthly New York Mercantile Exchange (NYMEX) settlement price for light, sweet crude oil. Through April 30, 2005, the average NYMEX settlement prices for light, sweet crude oil were $50.55. The Company estimates that NYMEX settlement prices would have to average approximately $63 for the remainder of 2005 for the Threshold Price to be reached.

The Company cannot predict with any certainty the Annual Average Price for 2005 or beyond.

Therefore, it cannot predict whether the price of oil will have a material'effect on its synthetic fuel business after 2004. However, if during 2005 through 2007, oil prices remain at historically high levels or increase, the Company's synthetic fuel business may be adversely affected for those years, and, depending on the magnitude of such increases in oil prices, the adverse affect for those years could be material and could have an impact on the Company's synthetic fuel results of operations and production plans.

In response to the historically high oil prices to date in 2005, the Company has adjusted its planned production schedule for its synthetic fuel plants by shifting some of its production planned for April and May 2005 to the second half of 2005. If oil prices rise and stay at levels high enough to cause a phase out of tax credits, the Company may reduce planned production or suspend production at some or all of its synthetic fuel facilities.

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SALE OFPARTNERSHIP INTEREST In June 2004, the Compadny, through its subsidiary Progress Fuels; 'sold in two transactions a combined 49.8% partnership interest in Colona Synfuel Limited Partnership, LLLP, one of its syntheti: fuel facilities. Substantially all proceeds from the sales will be received over time, which is typical of such sales in the industry. Gain from the sales will be recognized on a cost recovery basis as the facility produces and sells synthetic fuel and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectability is reasonably assured. Based on projected production and tax credit levels, the Company anticipates receiving total gross proceeds of approximately S24 million in 2005, approximately $31 million in 2006, approximately $32 million in 2007 and approximately $8 million through the second quarter of 2008. Gain recognition is dependent on the synthetic fuel production qualifying for Section 29 tax credits and the value of such tax credits as discussed above. Until the gain recognition criteria are met, gains from selling interests in Colona will be deferred. It is possible that gains will be deferred in the first, second and/or third quarters of each year until there is persuasive evidence that no tax credit phase out will occur for the applicable calendar year. This could result in shifting earnings from earlier quarters to later quarters in a calendar year. In the event that the synthetic fuel tax credits from the Colona facility are reduced, including an increase in the price of oil that could limit or eliminate synthetic fuel tax credits, the amount of proceeds realized from the sale could be significantly impacted.

5. The Company and its subsidiaries are involved in various litigation matters in the ordinary course of business, some of which involve substantial amounts. Where appropriate, accruals and disclosures have been made in accordance with SFAS No. 5, "Accounting for Contingencies," to provide for such matters. In the opinion of management, the final disposition of pending litigation would not have a material adverse effect on the Cornpany's consolidated results of operations or financial position.

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

CONSOLIDATED INTERIM FINANCIAL STATEMENTS March 31, 2005 UNAUDITED CONSOLIDATED STATEMENTS of INCOME (in millions)

Three months ended March 31, 2005 2004 Operating revenues $ 935 $ 901 Operating expenses Fuel used in electric generation 248 224 Purchased power 67 62 Operation and maintenance 224 209 Depreciation and amortization 129 127 Taxes other than on income 46 43 Total operating expenses 714 665 Operating Income 221 236 Other Income (expense)

Interest income 2 1 Other, net 1 (12)

Total other income (expense) 3 (11)

Interest charges Interest charges 52 49 Allowance for borrowed funds used during construction (1) (1)

Total interest charges, net 51 48 Income before Income tax 173 177 Income tax expense 57 62 Net income 116 115 Preferred stock dividend requirement I I Earnings for common stock S 115 $ 114 See Notes to Consolidated Interim Financial Statements.

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CAROLINA POWER & LIGHT COMPANY dlbla PROGRESS ENERGY CAROLINAS, INC.

UNAUDITED CONSOLIDATED BALANCE SHEETS (in millions) March 31, December31, 2005 2004 ASSETS Utility plant Utility plant in service S 13,567 S 13,521 Accumulated depreciation (5,S77) (5,806)

Utility plant in service, net 7,6°9 7,715 Held for future use 5 5 Construction work in progress 470 379 Nuclear fuel. net of amortization 178 186 Total utility plant, net 8,343 8,285 Current assets Cash and cash equivalents 183 18 Short-term investments 135 82 Receivables 398 397 Receivables from affiliated companies 36 20 Inventory 395 390 Deferred fuel cost 163 140 Prepayments and other current assets 95 135 Total current assets 1,405 1,182 Deferred debits and other assets Regulatory assets 464 473 Nuclear decommissioning trust funds 603 581 Miscellaneous other property and investments 184 158 Other assets and deferred debits 107 108 Total deferred debits and other assets 1,358 1,320 Total assets S 11,106 S 10,787 CAPITALIZATION AND LIABILITIES Common stock equity Common stock without par value, authorized 200 million shares, 160 million shares issued and outstanding S 1,988 S 1,975 Uneamed ESOP common stock (65) (76)

Accumulated other comprehensive loss (112) (114)

Retained earnings 1,256 1,287 Total common stock equity 3,067 3,072 Preferred stock -not subject to mandatory redemption 59 59 Long-term debt, net 3,247 2,750 Total capitalization 6,373 5,881 Current Liabilities Current portion of long-term debt 300 300 Accounts payable 253 254 Payables to affiliated companies 60 83 Notes payable to affiliated companies 23 116 Short-term obligations 108 221 Customer deposits 46 45 Other current liabilities 227 256 Total current liabilities 1,017 1,275 Deferred credits and other liabilities Noncurrent income tax liabilities 1,005 991 Accumulated deferred investment tax credits 139 140 Regulatory liabilities 1,104 1,052 Asset retirement obligations 937 924 Other liabilities and deferred credits 531 524 Total deferred credits and other liabilities 3,716 3,631 Commitments and contingencies (Note 12)

Total capitalization and liabilities S 11,106 S 10,787 See Notes to Consolidated Interim Financial Statements.

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

UNAUDITED CONSOLIDATED STATEMENTS of CASH FLOWS (in millions)

Three Months Ended March 31, 2005 2004 Operating activities Net income S 116 S 115 Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization 149 149 Deferred income taxes 30 22 Investment tax credit (2) (3)

Deferred fuel (credit) cost (17) 13 Other adjustments to net income 5 13 Cash provided (used) by changes in operating assets and liabilities:

Receivables (1) 27 Receivables from affiliated companies (16) 4 Inventory (5) 31 Prepayments and other current assets (12) 4 Accounts payable 27 (4)

Payables to affiliated companies (23) (84)

Other current liabilities (7) 13 Other 37 30 Net cash provided by operating activities 281 330 Investing activities Gross property additions (142) (121)

Nuclear fuel additions (30) (39)

Net contributions to nuclear decommissioning trust (10) (10)

Purchases of short-term investments (763) (601)

Proceeds from sales of short-term investments 710 828 Other investing activities (23) 3 Net cash (used In) provided by Investing activities (258) 60 Financing activities Issuance of long-term debt, net 495 -

Net decrease in short-term obligations (113) (4)

Net change in intercompany notes (93) (109)

Retirement of long-term debt - (150)

Dividends paid to parent (146) (125)

Dividends paid on preferred stock (1) (1)

Net cash provided by (used In) financing activities 142 (389)

Net Increase In cash and cash equivalents 165 1 Cash and cash equivalents at beginning of period 18 12 Cash and cash equivalents at end of period S 183 S 13 See Notes to Consolidated Interim Financial Statements.

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CAROLINA POVER & LIGHT COMPANY dlbla PROGRESS ENERGY CAROLINAS, INC.

NOTES TO CONSOLIDATED INTERIM FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION A. 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 annual 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, 2004 and notes thereto included in Progress Energy Carolinas, Inc.'s (PEC) Form 10-K for the year ended December 31, 2004.

PEC collects from customers certain excise taxes levied by the state or local government upon the customer. PEC accounts for excise taxes on a gross basis. For the three months ended March 31, 2005 and 2004, gross receipts tax and other excise taxes of approximately $22 million and $21 million, respectively, are included in electric revenue and taxes other than on income on the Consolidated Statements of Income.

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 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 2004 have been reclassified to conform to the 2005 presentation.

B. Stock-Based Compensation PEC measures compensation expense for stock options as the difference between the market price of Progress Energy's common stock and the exercise price of the option at the grant date. The exercise price at which options are granted by Progress Energy equals the market price at the grant date, and accordingly, no compensation expense has been recognized for stock option grants. For purposes of the pro forma disclosures required by SFAS No. 148, "Accounting for Stock-Based Compensation -

Transition and Disclosure - an Amendment of FASB Statement No. 123" (SFAS No. 148), the estimated fair value of PEC's stock options is amortized to expense over the options' vesting period.

The following table illustrates the effect on net income and earnings per share if the fair value method had been applied to all outstanding and unvested awards in each period:

(in millions) 2005 2004 Net Income, as reported $ 116 $ 115 Deduct: Total stock option expense determined under fair value method for all awards, net of related tax effects 1 2 Pro forma net income S 115 $ 113 PEC expects to begin expensing stock options on July 1, 2005 (See Note 2).

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C. Consolidation of Variable Interest Entities PEC consolidates all voting interest entities in which it owns a majcrity voting interest and all variable interest entities for which it is the primary beneficiary in accordance with FASB Interpretation No.

46R, "Consolidation of Variable Interest Entities - An Interpretation of ARB No. 51" (FIN No. 46R).

PEC is the primary beneficiary of and consolidates two limited partnerships that qualify for federal affordable housing and historic tax credits under Section 42 of the Internal Revenue Code (Code). As of March 31, 2005, the total assets of the two entities were $37 million, the majority of which are collateral for the entities' obligations and are included in other current assets and miscellaneous other property and investments in the Consolidated Balance Sheets.

PEC has an interest in a limited partnership that invests in 17 low-income housing partnerships that qualify for federal and state tax credits. PEC also has interests in two power plants resulting from long-term power purchase contracts. PEC has requested the necessary information to determine if the 17 partnerships and the two power plant owners are variable interest entities or to identify the primary beneficiaries; all three entities declined to provide PEC with the necessary financial information.

Therefore, PEC has applied the information scope exception in FIN No. 46R, paragraph 4(g) to the 17 partnerships and the two power plants. PEC believes that if it is determined to be the primary beneficiary of any of these entities, the effect of consolidating the entities would result in increases to total assets, long-term debt and other liabilities, but would have an insignificant or no impact on PEC's common stock equity, net earnings or cash flows.

PEC also has interests in several other variable interest entities for which PEC is not the primary beneficiary. These arrangements include investments in approximately 22 limited partnerships, limited liability corporations and venture capital funds and two building leases with special-purpose entities.

The aggregate maximum loss exposure at March 31, 2005, that PEC could be required to record in its income statement as a result of these arrangements totals approximately $24 million. The creditors of these variable interest entities do not have recourse to the general credit of PEC in excess of the aggregate maximum loss exposure.

2. NEW ACCOUNTING STANDARDS STATEMENT OF FINANCIAL ACCOUNTING STANDARDS NO. 123 (REVISED 2004), "SHARE-BASED PAYMENT" (SFAS NO. 123R)

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123R, which revises SEAS No. 123, "Accounting for Stock-Based Compensation" and supersedes Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees." The key requirement of SFAS No. 123R is that the cost of share-based awards to employees will be measured based on an award's fair value at the grant date, with such cost to be amortized over the appropriate service period. Previously, entities could elect to continue accounting for such awards at their grant date intrinsic value under APB Opinion No. 25, and PEC made that election. The intrinsic value method resulted in PEC recording no compensation expense for stock options granted to employees (See Note IB).

As written, SFAS No. 123R had an original effective date of July 1, 2005 for PEC. In April 2005, the SEC delayed the effective date for public companies, which resulted in a required effective date of January 1, 2006 for PEC. The SEC delayed the effective date due to concerns that implementation in mid-year could make compliance more difficult and make comparisons of quarterly reports more difficult. PEC currently intends to implement SEAS No. 123R on the original effective date of July 1, 2005. PEC intends to implement the standard using the required modified prospective method. Under that method and with a July 1, 2005 implementation, PEC will record compensation expense under SFAS No. 123R for all awards it grants after July 1, 2005, and it will record compensation expense (as previous awards continue to vest) for the unvested portion of previously granted awards that remain outstanding at July 1, 2005. In 2004, Progress Energy made the decision to cease granting stock options and replaced that compensation with alternative forms of compensation. Therefore, the amount of stock option expense expected to be recorded in 2005 is below the amount that would have been recorded if the stock option program had continued. PEC expects to record approximately $1 million of pre-tax expense for stock options in 2005.

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FASB INTERPRETATION NO. 47, "ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT OBLIGATIONS"  ; 1  ;

On March 30, 2005, the FASB issued Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations," an interpretation of SFAS No. 143, "Accounting for Asset Retirement Obligations." The interpretation clarifies that a legal obligation to perform an asset retirement activity that is conditional on a future event is within the scope of SFAS No. 143. Accordingly, an entity is required to recognize a liability for the fair value of an asset retirement obligation that is conditional on a future event if the liability's fair value can be reasonably estimated. The interpretation also provides additional guidance for evaluating whether sufficient information is available to make a reasonable estimate of the fair value. The interpretation is effective for PEC no later than December 31, 2005. PEC has not yet determined the impact of the interpretation on its financial position, results of operations or liquidity.

3. REGULATORY MATTERS On April 27, 2005, PEC filed for an increase in the fuel rate charged to its South Carolina customers with the Public Service Commission of South Carolina (SCPSC). PEC is asking the SCPSC to approve a $97 million, or 21 percent, increase in rates. PEC requested the increase for underrecovered fuel costs for the previous 15 months and to meet future expected fuel costs. This request reflects increases in the prices of coal and natural gas. If approved, the increase would take effect July 1, 2005. The Company cannot predict the outcome of this matter.

4. COMPREHENSIVE INCOME (in millions)

Three Months Ended March 31, 2005 2004 Net income $ 116 $ 115 Other comprehensive income:

Changes in net unrealized gains on cash flow hedges (net of tax expense of $1) 2 -

Other - I Other comprehensive income $ 2 $ I Comprehensive income S 118 $ 116

5. DEBT AND CREDIT FACILITIES AND FINANCING ACTIVITIES Changes to PEC's debt and credit facilities since December 31, 2004, discussed in Note 9 of PEC's 2004 Annual Report on Form I 0-K, are described below.

In January 2005, PEC used proceeds from the issuance of commercial paper to pay off $90 million of revolving credit agreement (RCA) loans.

On March 22, 2005, PEC issued $300 million of First Mortgage Bonds, 5.15% Series due 2015, and S200 million of First Mortgage Bonds, 5.70% Series due 2035. The net proceeds from the sale of the bonds were used to pay off $300 million of its 7.50% Senior Notes on April 1, 2005 and reduce the outstanding balance of commercial paper.

On March 28, 2005, PEC entered into a new $450 million RCA with a syndication of financial institutions. The RCA will be used to provide liquidity support for PEC's issuances of commercial paper and other short-term obligations. The RCA will expire on June 28, 2010. The new $450 million RCA replaced PEC's $285 million three-year RCA and S165 million 364-day RCA, which were each terminated effective March 28, 2005. Fees and interest rates under the S450 million RCA are to be determined based upon the credit rating of PEC's long-term unsecured senior non-credit enhanced debt, currently rated as Baal by Moody's and BBB by S&P. The RCA includes a defined maximum total debt to capital ratio of 65%. The RCA also contains various cross-default and other acceleration provisions, including a cross-default provision for defaults of indebtedness in excess of $35 million.

The RCA does not include a material adverse change representation for borrowings, which had been a provision in the terminated agreements.

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6. BENEFIT PLANS .

PEC has a noncontributory defined benefit retirement (pension) plan for substantially all full-time employees. PEC also has supplementary defined benefit pension plans that provide benefits to higher-level employees. In addition to pension benefits, PEC provides contributcry other postretirement benefits (OPEB), including certain health care and life insurance benefits, for retired employees who meet specified criteria. The components of the net periodic benefit cost for the three months ended March 31 are:

Other Postretirement Pension Benefits Benefits (in millions) 2005 2004 2005 2004 Service cost $ 7 $ 6 $ 2 S 2 Interest cost - 13 13 4 4 Expected return on plan assets (16) (17) (1) (1)

Amortization, net 2 - - 1 Net periodic cost / (benefit) $ 6 S 2 $ 5 S 6

7. RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS PEC is exposed to various risks related to changes in market conditions. PEC's parent, Progress Energy, has a risk management committee that 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. Under its risk management policy, PEC may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk if the counterparty fails to perform under the contract. PEC minimizes such risk by performing credit reviews using, among other things, publicly available credit ratings of such counterparties. Potential nonperformance by counterparties is not expected to have a material effect on the consolidated financial position or consolidated results of operations of PEC. See Note 13 to PEC's Annual Report on Form 10-K for the year ended December 31, 2004.

A. Commodity Derivatives General Most of PEC's commodity contracts are not derivatives pursuant to SFAS No. 133 or qualify as normal purchases or sales pursuant to SFAS No. 133. Therefore, such contracts are not recorded at fair value.

In 2003, PEC recorded a $38 million pre-tax ($23 million after-tax) fair value loss transition adjustment pursuant to the provisions of DIG Issue C20, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature." The related liability is being amortized to earnings over the term of the related contract (See Note 10). At March 31, 2005 and December 31, 2004, the remaining liability was $25 million and $26 million, respectively.

Economic Derivatives Derivative products, primarily electricity and natural gas contracts, may be entered into from time to time for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions. PEC manages open positions with strict policies that limit its exposure to market risk and require daily reporting to management of potential financial exposures. Gains and losses from such contracts were not material to results of operations during the three months ending March 31, 2005 and 2004 and PEC did not have material outstanding positions in such contracts at March 31,2005 and December 31, 2004.

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B. Interest Rate Derivatives - Fair Value or Cash Flow Hedges PEC uses cash flow hedging strategies to hedge variable interestirates on long-term and short-term debt and to hedge interest rates with regard to future fixed-rate debt issuances. PEC uses fair value hedging strategies to manage its exposure to fixed interest rates on long-term debt. The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss. In the event of default by the counterparty, the risk in these transactions is the cost of replacing the agreements at current market rates.

Cash Flow Hedges Gains and losses from cash flow hedges are recorded in accumulated other comprehensive income (OCI) and amounts reclassified to earnings are included in net interest charges as the hedged transactions occur. Amounts in OCI related to terminated hedges are reclassified to earnings as the hedged interest payments occur. The ineffective portion of interest rate cash flow hedges for the three months ending March 31, 2005 and 2004 was not material to PEC's results of operations. As of March 31, 2005, PEC had $5 million of after-tax deferred losses in OCI related to terminated hedges, of which an immaterial amount is expected to be reclassified to earnings within the next 12 months.

During the three months ending March 31, 2005, PEC terminated all of its cash flow hedges which were open at December 31, 2004 and had no open interest rate cash flow hedges at March 31, 2005.

As of December 31, 2004, PEC had $131 million notional of open interest rate cash flow hedges.

Fair Value Hedges At March 31, 2005 and December 31, 2004, PEC had no open interest rate fair value hedges.

8. SEVERANCE COSTS On February 28, 2005, as part of a previously announced cost management initiative, Progress Energy, approved a workforce restructuring, which is expected to be completed in September of 2005. In addition to the workforce restructuring, the cost management initiative includes a voluntary enhanced retirement program. In connection with the cost management initiative, PEC currently expects to incur estimated pre-tax charges of approximately $75 million. In addition, PEC expects to incur certain incremental costs other than severance and postretirement benefits for recruiting, training and staff augmentation activities that cannot be quantified at this time.

PEC recorded S14 million of expense during the first quarter of 2005 for the estimated severance benefits to be paid as a result of the approximate number of positions to be eliminated under the restructuring. This amount includes approximately $4 million of severance costs allocated from Progress Energy Service Company. These amounts will be paid over time and are subject to revision in future quarters based on the impact of the voluntary enhanced retirement program. The severance expenses are primarily included in operations and maintenance (O&M) expenses on the Consolidated Statements of Income.

The activity in the severance liability is as follows:

(in millions)

Balance as of January 1,2005 S 2 Severance Costs Accrued 10 Payments Balance as of March 31, 2005 S 12 PEC has estimated that an additional $65 million charge will be recognized in the second quarter of 2005 and relates primarily to postretirement benefits that will be paid over time to those eligible employees who elected to participate in the voluntary enhanced retirement program. The results from the employee elections indicate that 553 of PEC's employees have elected to participate in the voluntary enhanced retirement program. The cost management initiative charges could change significantly primarily due to the demographics of the specific employees who elected enhanced retirement and its impact on the postretirement benefit actuarial studies.

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9. FINANCIAL INFORMATION BY BUSINESS SEGMENT PEC's operations consist primarily of the PEC Electric segment which is engaged in the generation, transmission, distribution and sale of electric energy primarily in portions of North Carolina and South Carolina. These electric operations are subject to the rules and regulations of the FERC, the NCUC, the SCPSC and the NRC. PEC Electric also distributes and sells electricity to other utilities, primarily on the east coast of the United States.

The Other segment, whose operations are primarily in the United States, is made up of other nonregulated business areas that do not separately meet the disclosure requirements of SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" and consolidation entities and eliminations.

The financial information for PEC segments for the three months ended March 31, 2005 and 2004 is as follows:

(inmillions) 2005 - 2004 PEC PEC Electric Other Total Electric Other Total Total revenues S 935 S - S 935 $ 901 S - $ 901 Segmentprofit(loss) 116 (1) 115 116 (2) 114

10. OTHER INCOME AND OTHER EXPENSE Other income and expense includes interest income and other income and expense items as discussed below. The components of other, net as shown on the accompanying Consolidated Statements of Income for the three months ended March 31,2005 and 2004, are as follows:

(inmillions) 2005 2004 Other income Nonregulated energy and delivery services income S 2 S 2 DIG Issue C20 amortization (See Note 7) 1 2 AFUDC equity _ I Other 3 3 Total other income S 6 $ 8 Other expense Nonregulated energy and delivery services expenses S 2 $ 2 Donations 2 4 Write-off of non-trade receivables - 7 Other 1 7 Total other expense S 5 S 20 Other, net S. I $ (12)

Nonregulated energy and delivery services include power protection services and mass market programs such as surge protection, appliance services and area light sales, and delivery, transmission and substation work for other utilities.

11. ENVIRONMENTAL MATTERS PEC is subject to federal, state and local regulations addressing hazardous and solid waste management, air and water quality and other environmental matters. See Note 17 of PEC's 2004 Annual Report on Form 10-K for a more detailed, historical discussion of these federal, state, and local regulations.

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HAZ4RDOUSAND SOLID WASTE MANAGEMENT The provisions of the Comprehensive Environrnental Response,!Coimpensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liabilities. Some states, including North and South Carolina, have similar types of legislation. PEC is periodically notified by regulators, including the EPA and various state agencies, of their involvement or potential involvement in sites that may require investigation and/or remediation. There are presently several sites with respect to which PEC has been notified by the EPA and the State of North Carolina of its potential liability, as described below in greater detail. PEC is also currently in the process of assessing potential costs and exposures at other sites. For all sites, as assessments are developed and analyzed, PEC will accrue costs for the sites to the extent the costs are probable and can be reasonably estimated.

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

Environmental Protection Agency (EPA) and the North Carolina Department of Environment and Natural Resources, Division of Waste Management (DWM).

PEC has filed claims with its general liability insurance carriers to recover costs arising from actual or potential environmental liabilities. All claims have been settled other than with insolvent carriers.

These settlements have not had a material effect on the consolidated financial position or results of operations.

There are nine former MGP sites and a number of other sites associated with PEC that have required or are anticipated to require investigation and/or remediation.

During the fourth quarter of 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site located in Raleigh, North Carolina. The EPA offered PEC and 34 other PRPs the opportunity to negotiate cleanup of the site and reimbursement of less than S2 million to the EPA for EPA's past expenditures in addressing conditions at the site. Although a loss is considered probable, an agreement among PRPs has not been reached; consequently, it is not possible at this time to reasonably estimate the total amount of PEC's obligation for remediation of the Ward Transformer site.

As of March 31, 2005 and December 31, 2004, PEC's accruals for probable and estimable costs related to various environmental sites, which are included in other liabilities and deferred credits and are expected to be paid out over many years, were:

(in millions) March 31, 2005 December 31, 2004 Insurance fund $5 S7 Transferred from North Carolina Natural Gas Corporation at time of sale 2 2 Total accrual for environmental sites S7 S9 The insurance fund in the table above was established when PEC received insurance proceeds to address costs associated with environmental liabilities related to its involvement with some sites. All eligible expenses related to these are charged against a specific fund containing these proceeds. PEC made no additional accruals, spent approximately $2 million related to environmental remediation and received no insurance proceeds, for the three months ended March 31, 2005.

This accrual has been recorded on an undiscounted basis. PEC measures its liability for these sites based on available evidence including its experience in investigating and remediating environmentally impaired sites. The process often involves assessing and developing cost-sharing arrangements with other PRPs. PEC will accrue costs for the sites to the extent its liability is probable and the costs can be reasonably estimated. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and 42

c.)nczrrence of the regulatory authorities have not yet reached the stage where a reasonable estimate of the remediation costs can.be made, PEC cannotdetermine the total costs that may be incurred in connection with the remediation of all sites at this time. It is anticipated that sufficient information will become available for several sites during 2005 to allow a reasonable estimate of PEC's obligation for those sites to be made.

On March 30, 2005, the North Carolina Division of Water Quality renewed a PEC permit for the continued use of coal combustion products generated at any of the Company's coal-fired plants located in the state. PEC has reviewed the permit conditions, which could significantly restrict the reuse of coal ash and result in higher ash management costs, and plans to adjudicate the permit conditions. The Company cannot predict the outcome of this matter.

AIR QUALITY PEC is subject to various current and proposed federal, state, and local environmental compliance laws and regulations, which may result in increased planned capital expenditures and operating and maintenance costs. Significant updates to these laws and regulations and related impacts to PEC since December 31, 2004, are discussed below. Additionally, Congress is considering legislation that would require reductions in air emissions of NOx, SO2, carbon dioxide and mercury. Some of these proposals establish nationwide caps and emission rates over an extended period of time. This national multi-pollutant approach to air pollution control could involve significant capital costs that could be material to PEC's consolidated financial position 'or results of operations. Control equipment that will be installed on North Carolina fossil generating facilities as part of the North Carolina Clean Smokestacks Act (Smokestacks Act), enacted in 2002 and discussed below, may address some of the issues outlined above. However, PEC cannot predict the outcome of the matter.

The EPA is conducting an enforcement initiative related to a number of coal-fired utility power plants in an effort to determine whether changes at those facilities were subject to New Source Review requirements or New Source Performnance Standards 'under the Clean Air Act. The Company was asked to provide information to the EPA as part of this initiative and cooperated in supplying the requested information. The EPA initiated civil enforcement actions against other unaffiliated utilities as part of this initiative., Some of these actions resulted in settlement agreements calling for expenditures by these unaffiliated utilities in excess of SI .0 billion. These settlement agreements have generally called for expenditures to be made over extended time periods, and some of the companies may seek recovery of the related cost through rate adjustments or similar mechanisms.

Total capital expenditures to meet the requirements of the NOx SIP Call Rule in North and South Carolina could reach approximately $370 mnillion. This amount also includes the cost to install NOx controls under North Carolina's and South Carolina's programs to comply with the federal 8-hour ozone standard. However, further technical analysis and rulemaking may result in requirements for additional controls at some units. PEC has spent approximately $303 million to date related to these projected amounts. Increased operation and maintenance costs relating to the NOx SIP Call are not expected to be material to PEC's results of operations. Further controls are anticipated as electricity demand increases.

PEC projects that its capital costs to meet emission targets for NOx and SO2 from coal-fired power plants under the Smokestacks Act, will total approximately S895 million by the end of 2013. PEC has expended approximately S141 million of these capital costs through March 31, 2005. The law requires PEC to amortize 70% of the original cost estimate of $813 million, during a five-year rate freeze period. PEC recognized amortization of $27 million for the three months ended March 31, 2005, and has recognized $275 million in cumulative amortization through March 31, 2005. The remaining amortization requirement will be recorded over the future period ending December 31, 2007. The law permits PEC the flexibility to vary the amortization schedule for recording the compliance costs from no amortization expense up to $174 million per year. The NCUC will hold a hearing prior to December 31, 2007, to determine cost recovery amounts for 2008 and future periods. O&M expense will increase due to the additional materials, personnel and general maintenance associated with the equipment. O&M expenses are recoverable through base rates, rather than as part of this program.

PEC cannot predict the future regulatory interpretation, implementation or impact of this law.

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On March 10, 2005, the EPA issued the final Clean Air Interstate Rule (CAIR). The EPA's rule requires 28 states and the District of Columbia, including North Carolina, South Carolina, Georgia and Florida, to reduce NOx and S02 emissions in order to attain state NOx and S02 emissions levels. The Company is reviewing theifinal rule. Installation of additional; air uality controls is likely to be needed to meet the CAIR requirements. The Company is in the process of determining compliance plans and the cost to comply with the rule. The air quality controls already installed for compliance with the NOx SIP Call and currently planned by the Company to comply with the Smokestacks Act will reduce the costs required to meet the CAIR requirements for the Company's North Carolina units.

On March 15, 2005, the EPA finalized two separate but related rules: the Clean Air Mercury Rule (CAMR) that sets emissions limits to be met in two phases and encourages a cap and trade approach to achieving those caps, and a de-listing rule that eliminated any requirement to pursue a maximum achievable control technology (MACT) approach for limiting mercury emissions from coal-fired power plants. NOx and S02 controls also are effective in reducing mercury emissions; however, according to the EPA the second phase cap reflects a level of mercury emissions reduction that exceeds the level that would be achieved solely as a co-benefit of controlling NOx and S02 under CAIR. The Company is in the process of determining compliance plans and the cost to comply with the CAMR. Installation of additional air quality controls is likely to be needed to meet the CAMR's requirements. The de-listing rule has been challenged by a number of parties; the resolution of the challenges could impact the Company's final compliance plans and costs.

In conjunction with the proposed mercury rule, the EPA proposed a MACT standard to regulate nickel emissions from residual oil-fired units. The EPA withdrew the proposed nickel rule in March 2005.

In March 2004, the North Carolina Attorney General filed a petition with the EPA under Section 126 of the Clean Air Act, asking the federal government to force coal-fired power plants in 13 other states, including South Carolina, to reduce their NOx and SO2 emissions. The state of North Carolina contends these out-of-state emissions interfere with North Carolina's ability to meet national air quality standards for ozone and particulate matter. The EPA has agreed to make a determination on the petition by August 1, 2005. PEC cannot predict the outcome of this matter.

WATER QUALITY As a result of the operation of certain control equipment needed to address the air quality issues outlined above, new wastewater streams may be generated at the affected facilities. Integration of these new wastewater streams into the existing wastewater treatment processes may result in permitting, construction and treatment requirements imposed on PEC in the immediate and extended future.

Based on new cost information and changes to the estimated time frame of expenditures, PEC has revised the estimated amounts and time period for expenditures to meet Section 316(b) requirements of the Clean Water Act. PEC currently estimates that from 2005 through 2010 the range of expenditures will be approximately $15 million to $25 million.

OTHER ENVIRONMENTAL MYTERS 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 treaty went into effect on February 16, 2005. The United States has not adopted the Kyoto Protocol, and the Bush administration has stated it favors voluntary programs. A number of carbon dioxide emissions control proposals have been advanced in Congress. Reductions in carbon dioxide emissions to the levels specified by the Kyoto Protocol and some legislative proposals could be materially adverse to PEC's consolidated financial position or results of operations if associated costs of control or limitation cannot be recovered from customers. PEC favors the voluntary program approach recommended by the Bush administration and continually evaluates options for the reduction, avoidance and sequestration of greenhouse gases. However, PEC cannot predict the outcome of this matter.

Progress Energy has announced its plan to issue a report on the Company's activities associated with current and future environmental requirements. The report will include a discussion of the environmental requirements that PEC currently faces and expects to face in the future with respect to its air emissions. The report is expected to be issued by March 31, 2006.

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12. COMMITMENTS AND CONTINGENCIES  ;,

Contingencies existing as of the date of these statements are described below. No significant changes have occurred since December 31, 2004, with respect to the commitments discussed in Note 18 of PEC's 2004 Annual Report on Form 10-K.

A. Guarantees As a part of normal business, PEC enters into various agreements providing future financial or performance assurances to third parties, which are outside the scope of Financial Accounting Standards Board (FASB) Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN No. 45).

Such agreements include guarantees, standby letters of credit and surety bonds. At March 31, 2005, PEC does not believe conditions are likely for significant performance under these guarantees. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included in the accompanying Consolidated Balance Sheets. At March 31, 2005, PEC had no guarantees issued on behalf of unconsolidated subsidiaries or other third parties.

B. Insurance PEC is a member of Nuclear Electric Insurance Limited (NEIL), which provides primary and excess insurance coverage against property damage to members' nuclear generating facilities. Under the primary program, PEC is insured for $500 million at each of its nuclear plants. In addition to primary coverage, NEIL also provides decontamination, premature decommissioning and excess property insurance with limits of $1.75 billion on each plant.

C. Other Contingencies

1. Pursuant to the Nuclear Waste Policy Act of 1982, the predecessors to PEC entered into contracts with the U.S. Department of Energy (DOE) under which the DOE agreed to begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract.

DOE failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004, PEC filed a complaint in the United States Court of Federal Claims against the DOE, claiming that the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel (SNF) by failing to accept SNF from various PEC facilities on or before January 31, 1998. Damages due to DOE's breach will likely exceed $100 million. Approximately 60 cases involving the Government's actions in connection with spent nuclear fuel are currently pending in the Court of Federal Claims.

DOE and the PEC parties have agreed to a stay of the lawsuit, including discovery. The parties agreed to, and the trial court entered, a stay of proceedings, in order to allow for possible efficiencies due to the resolution of legal and factual issues in previously filed cases in which similar claims are being pursued by other plaintiffs. These issues may include, among others, so-called "rate issues," or the minimum mandatory schedule for the acceptance of SNF and high level waste (HLW) by which the Government was contractually obligated to accept contract holders' SNF and/or HLW, and issues regarding recovery of damages under a partial breach of contract theory that will be alleged to occur in the future. These issues have been or are expected to be presented in the trials that are currently scheduled to occur during 2005. Resolution of these issues in other cases could facilitate agreements by the parties in the PEC lawsuit, or at a minimum, inform the Court of decisions reached by other courts if they remain contested and require resolution in this case. The trial court has continued this stay until June 24, 2005.

On February 27, 2004, PEC requested to have its license for the Independent Spent Fuel Storage Installation at the Robinson Plant extended by 20 years with an exemption request for an additional 20-year extension. Its current license is due to expire in August 2006. On March 30, 2005, the NRC issued the 40-year license renewal.

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With certain modifications and additional approval by the NRC, including the installation of onsite dry storage facilities at Robinso~n and Brunswick, PEC's spent nuclear-: fuel storage facilities will be sufficient to provide storage space for spent fuel generated on PEC's system through the expiration of the operating licenses for all of PEC's nuclear generating units.

In July 2002, Congress passed an override resolution to Nevada's veto of DOE's proposal to iacat- a permanent underground nuclear waste storage facility at Yucca Mountain, Nevada. In January 2003, the State of Nevada, Clark County, Nevada, and the City of Las Vegas petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of the Congressional override resolution.

These same parties also challenged EPA's radiation standards for Yucca Mountain. On July 9, 2004, the Court rejected the challenge to the constitutionality of the resolution approving Yucca Mountain, but ruled that the EPA was wrong to set a 10,000-year compliance period in the radiation protection standard. EPA is currently reworking the standard but has not stated when the work will be complete.

DOE originally planned to submit a license application to the NRC to construct the Yucca Mountain facility by the end of 2004. However, in November 2004, DOE announced it would not submit the license application until mid-2005 or later. Also in November 2004, Congressional negotiators approved $577 million for fiscal year 2005 for the Yucca Mountain project, approximately $300 million less than requested by DOE but approximately the same as approved in 2004. The DOE has acknowledged that a working repository will not be operational until sometime after 2010, but the DOE has not identified a new target date. PEC cannot predict the outcome of this matter.

2. In 2001, PEC entered into a contract to purchase coal from Dynegy Marketing and Trade (DMT).

After DMT experienced financial difficulties, including credit ratings downgrades by certain credit reporting agencies, PEC requested credit enhancements in accordance with the terms of the coal purchase agreement in July 2002. When DMT did not offer credit enhancements, as required by a provision in the contract, PEC terminated the contract in July 2002.

PEC initiated a lawsuit seeking a declaratory judgment that the termination was lawful. DMT counterclaimed, stating the termination was a breach of contract and an unfair and deceptive trade practice. On March 23, 2004, the United States District Court for the Eastern District of North Carolina ruled that PEC was liable for breach of contract, but ruled against DMT on its unfair and deceptive trade practices claim. On April 6, 2004, the Court entered a judgment against PEC in the amount of approximately $IOmillion. The Court did not rule on DMT's request under the contract for pending legal costs.

On May 4, 2004, PEC authorized its outside counsel to file a notice of appeal of the April 6, 2004, judgment and on May 7, 2004, the notice of appeal was filed with the United States Court of Appeals for the Fourth Circuit. On June 8, 2004, DMT filed a motion to dismiss the appeal on the ground that PEC's notice of appeal should have been filed on or before May 6, 2004. On June 16, 2004, PEC filed a motion with the trial court requesting an extension of the deadline for the filing of the notice of appeal. By order dated September 10, 2004, the trial court denied the extension request. On September 15, 2004, PEC filed a notice of appeal of the September 10, 2004 order and by order dated September 29, 2034, the appellate court consolidated the first and second appeals. DMT's motion to dismiss the first appeal remains pending. Argument on the consolidated appeal is scheduled for May 25, 2005.

PEC recorded a liability for the judgment of approximately SI 0 million and a regulatory asset for the probable recovery through its fuel adjustment clause in the first quarter of 2004. PEC cannot predict the outcome of this matter.

3. On February 1, 2002, PEC filed a complaint with the Surface Transportation Board (STB) challenging the rates charged by Norfolk Southern Railway Company (Norfolk Southern) for coal transportation to certain generating plants. In a decision dated December 23, 2003, the STE found that the rates were unreasonable, awarded reparations and prescribed maximum rates. Both parties petitioned the STB for reconsideration of the December 23, 2003 decision. On October 20, 2004, the STB reconsidered its December 23, 2003 decision and concluded that the rates charged by Norfolk Southern were not unreasonable. Because PEC paid the maximum rates prescribed by the STB in its December 23, 2003 decision for several months during 2004, which were less than the rates ultimately found to be reasonable, the STB ordered PEC to pay to Norfolk Southern the difference between the rate levels plus interest.

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PEC subsequently filed a petition with the STB to phase in the new rates over a period of time, and filed a notice of appeal with the U.S. Court of Appeals for the D.C. Circuit. Pursuant to an order issued by the STB on January 6, 2005, the phasing proceeding will proceed on a schedule that appears likely to produce an STB decision before the end of 2005. On January 12, 2005, the STB filed a Motion to Dismiss PEC's appeal on the grounds that its October 20, 2004 order is not final until PEC's phasing application has been decided. PEC responded to this motion on January 26, 2005. The court has not yet ruled on the motion.

As of March 31, 2005, PEC has accrued a liability of $42 million, of which $23 million represents reparations previously remitted to PEC by Norfolk Southern that are now subject to refund. Of the remaining $19 million, S17 million has been recorded as deferred fuel cost on the Consolidated Balance Sheet, while the remaining $2 million attributable to wholesale customers has been charged to fuel used in electric generation on the Consolidated Statements of Income. PEC or Norfolk Southern, as the case may be, will make the appropriate payment to the other to reconcile all charges, including interest, once a final STB decision in the phasing proceeding is served.

PEC cannot predict the outcome of this matter.

4. PEC is involved in various litigation matters in the ordinary course of business, some of which involve substantial amounts. Where appropriate, accruals and disclosures have been made in accordance with SFAS No. 5, "Accounting for Contingencies," to provide for such matters. In the opinion of management, the final disposition of pending litigation would not have a material adverse effect on PEC's consolidated results of operations or financial position.

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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations The following Management's Discussion and Analysis contains forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review "SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS" for a discussion of the factors that may impact any such forward-looking statements made herein and the Risk Factors sections of Progress Energy's and Progress Energy Carolina's (PEC) annual report on Form 10-K for the year ended December 31, 2004.

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 2004 Form 10-K.

RESULTS OF OPERATIONS The Company's reportable business segments and their primary operations include:

• Progress Energy Carolinas Electric (PEC Electric) - primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina;

• Progress Energy Florida (PEF) - primarily engaged in the generation, transmission, distribution and sale of electricity in portions of Florida;

• Competitive Commercial Operations (CCO) - engaged in nonregulated electric generation operations and marketing activities primarily in Georgia, North Carolina and Florida;

• Fuels - primarily engaged in natural gas production in Texas and Louisiana, coal mining, coal terminal services and fuel transportation and delivery in Kentucky, West Virginia and Virginia; and

• Synthetic Fuels - engaged in the production and sale of synthetic fuels and the operation of synthetic fuel facilities for outside parties in Kentucky, West Virginia and Virginia.

The Corporate and Other category includes other businesses engaged in other nonregulated business areas, including telecommunications, primarily in the eastern United States, and energy services operations and holding company results, which do not meet the requirements for separate segment reporting disclosure.

Prior to 2005, Rail Services was reported as a separate segment. In connection with the divestiture of Progress Rail (see Note 3 of the Progress Energy Consolidated Interim Financial Statements), the operations of Rail Services were reclassified to discontinued operations in the first quarter of 2005 and therefore are no longer a reportable segment. In addition, synthetic fuel activities were reported in the Fuels segment prior to 2005 and now are considered a reportable segment. These reportable segment changes reflect the current reporting structure. For comparative purposes, the prior year results have been restated to align with the current presentation.

In this section, earnings and the factors affecting earnings for the three months ended March 31, 2005 as compared to the same period in 2004 are discussed. The discussion begins with a summarized overview of the Company's consolidated earnings, which is followed by a more detailed discussion and analysis by business segment.

OVERVIEW For the quarter ended March 31 2005, Progress Energy's net income was $93 million, or $0.38 per share, compared to $108 million, or SO.45 per share, for the same period in 2004. The decrease in net income as compared to prior year was due primarily to:

• Severance charges recorded throughout the Company related to the cost management initiative.

• Unfavorable weather at both utilities.

• Increased O&M charges at PEF related to a workers compensation adjustment.

• Decreased synthetic fuel earnings.

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Partially offsetting these items were:

• Utility customer growth in the Carolinas and Florida.

• Favorable wholesale sales ii both the Carolina's4and Florida. .

• Increased nonregulated generation earnings due primarily to reduced interest expense.

• Reduced losses recorded on contingent value obligations.

• The impact of tax levelization.

Basic earnings per share decreased in 2005 due in part to the factors outlined above. Dilution related to the issuances under the Company's Investor Plus Stock Purchase Plan and employee benefit programs in 2005 and 2004 also reduced basic earnings per share by $0.01 in the first quarter of 2005.

The Company's segments contributed the following profits or losses for the three months ended March 31, 2005 and 2004:

(in millions) Three Months Ended March 31, Business Segment 2005 2004 PEC Electric S 116 S 116 PEF 43 49 Fuels 10 10 CCO (5) (8)

Synthetic Fuel (1) 36 Total Segment Profit 163 203 Corporate & Other (58) (104)

Income from continuing operations 105 99 Discontinued operations, net of tax (12) 9 Net income S 93 S 108 COST MANAGEMENT INITIATIVE On February 28, 2005, as part of a previously announced cost management initiative, the Company approved a workforce restructuring which is expected to be completed in September 2005 and result in a reduction of approximately 450 positions. The cost management initiative is designed to permanently reduce by $75 million to $100 million the projected growth in the Company's annual operation and maintenance (O&M) expenses by the end of 2007. In addition to the workforce restructuring, the cost management initiative includes a voluntary enhanced retirement program. In connection with this initiative, the Company currently expects to incur estimated pre-tax charges of approximately $210 million. In addition, the Company expects to incur certain incremental costs other than severance and postretirement benefits for recruiting, training and staff augmentation activities that cannot be quantified at this time.

The Company recorded $31 million of expense during the first quarter of 2005 for the estimated severance benefits to be paid as a result of the approximate number of positions to be eliminated under the restructuring and due to the implementation of an automated meter reading initiative at PEF. These amounts will be paid over time and are subject to revision in future quarters based on the impact of the voluntary enhanced retirement program. The severance expenses are primarily included in O&M expense on the Consolidated Statements of Income.

The Company has estimated that an additional $180 million charge will be recognized in the second quarter of 2005 and relates primarily to postretirement benefits that will be paid over time to those eligible employees who elected to participate in the voluntary enhanced retirement program. Approximately 3,500 of the Company's 12,300 employees were eligible to participate in the voluntary enhanced retirement program. The results from the employee elections indicate that 1,447 of the Company's employees have elected to participate in the voluntary enhanced retirement program. The cost management initiative charges could change significantly primarily due to the demographics of the specific employees who elected enhanced retirement and its impact on the postretirement benefit actuarial studies.

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PROGRESS ENERGY CAROLINAS ELECTRIC PEC Electric contributed segment profits of $I 16 million for the three months ended March 31, 2005 and 2004, respectively. Results for 2005 were favorably impacted by increased revenues due to customer growth and usage. In addition, results in 2004 indluded the write-off of non-trade receivables. These favorable items were offset by unfavorable weather, higher O&M expenses due primarily to severarce accruals related to the announced cost management initiative.

Revenues PEC Electric's revenues for the three months ended March 31, 2005 and 2004, and the percentage change by customer class are as follows:

(in millions of S) Three Months Ended March 31, Customer Class 2005 Change  % Change 2004 Residential S 374 $ 3 0.8 S 371 Commercial 215 7 3.4 208 Industrial 149 2 1.4 147 Govemmental 19 - - 19 Total retail revenues 757 12 1.6 745 Wholesale 174 18 11.5 156 Unbilled (19) 4 - (23)

Miscellaneous 23 - - 23 Total electric revenues S 935 $ 34 - 3.8 S 901 Less:

Pass-through fuel revenues (271) (32) (13.4) (239)

Revenues excluding fuel S 664 2 0.3 $ 662 PEC Electric's energy sales for the three months ended March 31, 2005 and 2004, and the amount and percentage change by customer class are as follows:

(in millions of kWh) Three Months Ended March 31, Customer Class 2005 Change  % Change 2004 Residential 4,6712 (69) (1.5) 4,741 Commercia! 3,08 o 22 0.7 3,058 Industrial 2,93 1 (62) (2.1) 2,993 Governmental 32 7 (18) (5.2) 345 Total retail energy sales 11,01 0 (127) (1.1) 11,137 Wholesale 3,93 8 147 3.9 3,791 Unbilled (3031) 82 - (385)

Total kWh sales 14.64 5 102 0.7 14.543 PEC Electric's revenues, excluding recoverable fuel revenues of $271 million and $239 million for the three months ended March 31, 2005 and 2004, respectively, increased $2 million. The increase in revenues is attributable to favorable customer growth of $20 million and an increase in wholesale revenues of $1 million.

Favorable growth was driven by an increase in customers of 27,000 as of March 31, 2005 as compared to March 31, 2004. The increase in wholesale revenues is due primarily to favorable prices on excess generation sales. Favorable customer growth and wholesale revenues were offset partially by unfavorable weather of $19 million with heating degree days 8% below prior year.

Expenses Fuel andPurchasedPower Fuel and purchased power costs represent the costs of generation, which include fuel purchases for generation, as well as energy purchased in the market to meet customer load. Fuel and purchased power expenses are recovered primarily through cost recovery clauses, and, as such changes in these expenses do not have a material impact on earnings. The difference between fuel and purchased power costs incurred and associated fuel revenues that are subject to recovery is deferred for future collection from or refund to customers.

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Fuel and purchased power expenses were $315 million for 2005, which represents a $29 million increase compared to the same period in the prior year. Fuei used in electric generation increased $24 million to $248 million compared to the prior year. This increase is due to an increase in fuel used in generation of $53 million due primarily to higher fuel costs are being driven primarily by an increase in coal prices. The increase in fuel used in generation is offset by a reduction in deferred fuel expense as a result of the under-recovery of current period fuel costs. Purchased power expense increased $5 million to $67 'illioncompared to prior year. The increase in purchased power during the quarter is due to resource availability and increased fuel costs.

Operationsand Maintenance (O&M)

O&M expenses were $224 million for the three months ended March 31, 2005, which represents a $15 million increase compared to the same period in 2004. Severance expense related to the cost management initiative increased O&M expenses by $13 million during 2005. Ir. addition, outage costs were $7 million higher compared to prior year due to a planned outage at a coal-fired plant in March 2005 and O&M expenses also increased S6 million related to the change in Energy Delivery capitalization practice. These unfavorable items were partially offset by lower compensation and benefits of $6 million and a reduction in storm costs. Results for 2004 included $6 million of costs associated with an ice storm that hit the Carolinas service territory. See discussion of change in Energy Delivery capitalization practice in Note 8F of the Progress Energy annual report on Form 10-K for the year ended December 31, 2004.

DepreciationandAmortization Depreciation and amortization expense was $129 million for the three months ended March 31, 2005, which represents a S2 million increase compared to the same period in 2004. The increase is attributable to higher NC Clean Air amortization of $11 million and higher depreciation for assets placed in services of $2 million. These increases were partially offset by a reduction in depreciation expense of S 11 million related to the depreciation studies filed in 2004. Depreciation rates are the same for 2005 and 2004; however, the 2004 year to date retroactive adjustment for the new rates adopted related to the expanded lives of the nuclear units was made in November 2004.

Tares Otherthan on Income Taxes other than on income were $46 million for the three months ended March 31, 2005, which represents a

$3 million increase compared to the same period in 2005. This increase is due to higher property taxes of $1 million due to higher property appraisals and higher payroll taxes of $1 million related to severance accruals recorded during 2005.

Other income, net Other income, net has increased $12 million for the period ending March 31, 2005 as compared to the same period in the prior year. This increase is due primarily to a write-off of $7 million of non-trade receivables in the prior year. In addition, investment losses have decreased $2 million compared to prior year.

PROGRESS ENERGY FLORIDA PEF contributed segment profits of $43 million and $49 million in the three months ended March 31, 2005 and 2004, respectively. The decrease in profits for the three months ended March 31, 2005 when compared to 2004 is primarily due to the impact of milder weather, weaker industrial sales and higher O&M expenses, partially offset by higher wholesale sales and increased customer growth.

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PEF's electric revenues for the three months ended March 31, 2005 and 2004, and the amount and percentage change by customer class are as follows: ..I . %

I ,.-

(in millions of S) Three Months Ended March 31, Customer Class 2005 Change  % Chantg1e- 2-0034 Residential S 431 S 29 7.2 $ 402 Commercial 201 20 11.0 181 Industrial 63 63 Governmental 53 7 15.2 46 Retail revenue sharing (2) 2 (4)

Total retail revenues 746 58 8.4 688 Wholesale 73 6 9.0 67 Unbilled (5) S. 29 i;, i (6)

Miscellaneous 34 (11- (2.9) 8 35 Total electric revenues S 848 S64 - 8.2 S 784 Less:

Pass-through revenues (501) (54) (12.1) (447)

Revenues excluding pass-through revenues $ 347 10 3.0 S 337 PEF's electric energy sales for the three months ended March 31, 2005 and 2004, and the amount and percentage change by customer class are as follows:

(in millions of kWh) Three Months Ended March 31, Customer Class 2005 Change  % Change 2004 Residential 4,347 56 13 4,291 Commercial 2,571 80 3.2 2,491 Industrial 940 (83) (8.1) 1,023 Governmental 709 37 5.5 672 Total retail energy sales 8,567 90 1.1 8,477 Wholesale 1,338 15 1.1 1,323 Unbilled (103) 32 - (135)

Total kWh sales 9,802 137 1.4 9,665 Revenues PEF's revenues, excluding recoverable fuel and other pass-through revenues of $501 million and $447 million for the three months ended March 31, 2005 and 2004, respectively, increased $10 million. The increase in revenues is due to favorable customer growth and increased wholesale revenues of $7 million each. Favorable customer growth was driven by a 35,000 increase in average retail customers compared to prior year.

Wholesale revenue favorability is attributable primarily to new contracts entered into since March 31, 2004.

These increases were partially offset by the impacts of milder weather and weaker industrial sales of $3 million each.

Expenses Fuel and PurchasedPower Fuel and purchased power costs represent the costs of generation, which include fuel purchases for generation, as well as energy purchased in the market to meet customer load. Fuel and purchased power expenses are recovered primarily through cost recovery clauses, and, as such changes in these expenses do not have a material impact on earnings. The difference between fuel and purchased power costs incurred and associated fuel revenues that are subject to recovery is deferred for future collection or refund to customers.

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Fuel and purchased power expenses were S433 million for the three months ended March 31, 2005, which represents a S43 million increase compared to prior year. This increase is due to increases in fuel used in electric generation and purchased -poower expenses of $33 million and $1Omnillion, respectively. Higher system requirements and increased fuel costs in the current year account for $41 million of the increase in fuel used in electric generation. This increase was partially offset by a decrease in deferred fuel expense as recovery of fuel expenses in the prior year (that were previously deferred) was greater than in the current year. In December 2004, the FPSC approved PEF's request for a cost recovery adjustment in its annual filing due to the rising cost of fuel. Fuel recovery rates increased effective January 1, 2005. The increase in purchased power expense was primarily due to higher prices of purchases in the current year as a result of increased fuel costs.

Operationsand Maintenance(O&M)

O&M expenses were $189 million for the three months ended March 31, 2005, which represents an increase of

$29 million, when compared to the S160 million incurred during the three months ended March 31, 2004.

Severance expense related to the cost management initiative increased O&M costs by $14 million during 2005.

In addition, PEF recorded a workers compensation benefit adjustment of $8 million during 2005 as a result of an annual actuarial study. O&M expense also increased $8 million related to the change in Energy Delivery capitalization practice. See discussion of change in Energy Delivery capitalization practice in Note 8F of the Progress Energy annual report on Form 10-K for the year ended December 31, 2004.

Taxes Other than on Income Taxes other than on income were $67 million for the three months ended March 31, 2005, which represents an increase of S5 million compared to prior year. This increase is due to increases in franchise and gross receipts taxes of S2 million and $1 million, respectively, related to an increase in revenues and an increase in property taxes of $1 million due to property additions.

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

FUELS The Fuels' segment operations include natural gas production, coal extraction and terminal operations. The following summarizes Fuels' segment profits for the three months ended March 31, 2005 and 2004:

(in millions) 2005 2004 Gas production S 12 S 13 Coal fuel and other operations (2) (3)

Segment Profits S 10 S 10 Natural Gas Operations Natural gas operations generated profits of $12 million and $13 million for the three months ended March 31, 2005 and 2004, respectively. The decrease in gas earnings compared to prior year is attributable to reduced production as a result of the sale of gas assets in 2004 offset partially by higher natural gas prices. In December 2004, the Company sold certain gas-producing properties and related assets owned by Winchester Production Company, Ltd., a subsidiary of Progress Fuels (North Texas gas operations). The following summarizes the gas production, revenues and gross margins for the three months ended March 31, 2005 and 2004 by production facility:

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2005 2004 Production in Bcf equivalent East Texas/LA gas operations 5.4 4.0 North Texas gas operations - 2.7 Total Production 5.4 6.7 Revenues in millions East Texas/LA gas operations S 33 S 22 North Texas gas operations _ 13 Total Revenues S 33 $ 35 Gross Margin in millions of $ S 28 $ 27 As a % of revenues 85% 77%

Coal Fuel and Other Operations Coal fuel and other operations generated segment losses of $2 million for the three months ended March 31, 2005 compared to losses of S3 million for the three months ended March 31, 2004. The decrease in losses of $1 million is due primarily to increased revenues as a result of higher coal prices. This favorability was partially offset by higher coal mining costs (due to rising prices of fuel and steel), a workers compensation accrual adjustment booked during 2005 and reduced rates related to the waterborne coal transportation settlement in 2004. In addition, results were unfavorably impacted by severance expense of SI million pre-tax recorded in 2005 related to the cost management initiative.

COMPETITIVE COMMERCIAL OPERATIONS CCO's operations generated segment losses of $5 million for the three months ended March 31, 2005 compared to losses of S8 in the prior year. The decrease in losses compared to prior year is due primarily to a reduction in depreciation and amortization expense and interest expense. Depreciation and amortization expenses decreased S4 million pre-tax ($2 million after-tax) as a result of the expiration of certain acquired contracts that were subject to amortization. Interest expense decreased $3 million pre-tax (S2 million after-tax) due to the termination of the Genco financing arrangement in December 2004. In addition, results were favorably impacted by a mark to market gain in the current quarter compared to a loss in the prior year. This favorability was offset partially by lower contract margins as a result of the expiration of certain tolling agreements.

(in millions) 2005 2004 Total revenues $ 65 $ 33 Gross margin Inmillionsof$ S 21 $ 23 As a % of revenues 32% 70%

Segment losses $ (5) $ (8)

The Company has contracts for its planned production capacity, which includes callable resources from the cooperatives, of approximately 77% for 2005, approximately 81% for 2006 and approximately 75% for 2007.

The Company continues to seek opportunities to optimize its nonregulated generation portfolio.

SYNTHETIC FUEL The synthetic fuel operations generated segment losses of $1 million for the three months ended March 31, 2005 compared to segment profits of $36 million for the three months ended March 31, 2004. The production and sale of synthetic fuel generate operating losses, but qualify for tax credits under Section 29 of the Code, which typically more than offset the effect of such losses. See Note 14 to the Progress Energy Consolidated Interim Financial Statements.

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The operations resulted in the following for the three montlv ended March 31, 2005 and 2034:

(in millions) - 2005 A 2004 Tons sold 2.0 2.9 Operating losses, excluding tax credits S (38) $ (42)

Tax credits generated, net 37 78 Segment (losses) profits S (I) S 36 Synthetic fuels' earnings were negatively impacted by lower sales, forfeiture of tax credits as a result of the sale of Progress Rail and decreased margins. The decrease in sales quarter over quarter is primarily attributable to an internal change in the quarterly production schedule in 2005 compared to 2004. The sale of Progress Rail resulted in a capital loss for tax purposes, therefore $17 million of previously recorded tax credits were forfeited during the quarter. See Note 14 to the Progress Energy Consolidated Interim Financial Statements for further discussion.

In response to the historically high oil prices to date in 2005, the Company has adjusted its planned production schedule for its synthetic fuel plant by shifting some of its production planned for April and May 2005 to the second half of 2005. If oil prices rise and stay at levels high enough to cause a phase out of tax credits, the Company may reduce planned production or suspend production at some or all of its synthetic fuel facilities.

CORPORATE & OTHER Corporate & Other consists of the operations of Progress Energy Holding Company (the holding company),

Progress Energy Service Company and otl.er consolidating and non-operating entities. Corporate & Other also includes other nonregulated business areas including the telecommunications operations of Progress Telecommunications Corp. (PTC) and the operations of Strategic Resource Solutions (SRS). PTC LLC operations provide broadband capacity services, dark fiber and wireless services in Florida and the eastern United States. SRS was engaged in providing energy services to industrial, commercial and institutional customers to help manage energy costs primarily in the southeastern United States. During 2004, SRS sold its subsidiary, Progress Energy Solutions (TES). With the disposition of PES, the Company exited this business area.

Other nonregulated business areas Other nonregulated businesses contributed segment losses of SI million for the three months ended March 31, 2005 compared to segment losses of $3 million for the three months ended March 31, 2004. PTC earnings were essentially breakeven for the quarter ended March 31, 2005, compared with segment loss $1 million for the same period last year. PTC's results for 2004 were negatively impacted by integration costs associated with its combination with EPIK in December 2003. The remaining favorability is attributable to a reduction in investment losses recognized by the nonutility subsidiaries of PEC.

Corporate Services Corporate Services (Corporate) includes the operations of the Holding Company, the Service Company and consolidation entities, as summarized below:

Three Months Ended March 31, Income (expense) in millions 2005 2004 Other interest expense $ (71) $(73)

Contingent value obligations - (7)

Tax levelization (3) (39)

Tax reallocation (9) (9)

Other income taxes 29 30 Other (3) (3)

Segment profit (loss) S (57) S(101) 55

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 byPtrogress Energy. The payments, if any, are based on the net after-tax cash flows the facilities generate. At March 31, 2005 and 2004, the CVOs had fair market values of approximately SI 3 million and $30 million, respectively. Progress Energy recorded an unrealized gain of $0.5 million and an unrealized loss of $7 million for the three months ended March 31, 2005 and 2004, respectively, to record the changes in fair value of the CVOs, which had average unit prices of $0.13 and $0.31 at March 31, 2005 and 2004, respectively.

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 $3 million and S39 million for the three months ended March 31, 2005 and 2004, respectively, in crder to maintain an effective tax rate consistent with the estimated annual rate. 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.

DISCONTINUED OPERATIONS On March 24, 2005, the Company completed the sale of Progress Rail to One Equity Partners LLC a private equity firm unit of J.P. Morgan Chase & Company. Gross cash proceeds from the sale are estimated to be $433 million, consisting of $405 million base proceeds plus an estimated working capital adjustment. Proceeds from the sale were used to reduce debt. The accompanying consolidated interim financial statements have been restated for all periods presented for the discontinued operations of Progress Rail. See Notes 3 and 14A to the Progress Energy Consolidated Interim Financial Statements for additional discussion.

Rail discontinued operations resulted in losses of $12 million for the three months ended March 31, 2005 compared to profits of $9 million for the three months ended March 31, 2004. Earnings for 2005 include an estimated after-tax loss on the sale of $17 million. The Company anticipates adjustments to the loss on the divestiture during the second quarter of 2005 related to employee benefit settlements and the finalization of working capital adjustments and other operating estimates. The remaining unfavorability in earnings compared to prior year is attributable primarily to increased transaction costs associated with the sale.

LIQUIDITY AND CAPITAL RESOURCES Progress Energy, Inc.

Progress Energy is a registered holding company and, as such, has no operations of its own. The Company's primary cash needs at the holding company level are its common stock dividend and interest expense and principal payments on its $4.3 billion of senior unsecured debt. The ability to meet these needs is dependent on its access to the capital markets, the earnings and cash flows of its two electric utilities and nonregulated subsidiaries, and the ability of those subsidiaries to pay dividends or repay funds to Progress Energy.

Cash Flows from Operations Net cash provided by operating activities decreased $88 million for the three months ended March 31, 2005, when compared to the corresponding period in the prior year. The decrease in cash from operating activities for the 2004 period is primarily due to lower net income, an under-recovery of fuel costs in 2005 of $44 million when compared with 2004, and approximately $62 million in storm restoration expenditures at PEF.

Investing Activities Net cash used in investing activities increased by $142 million primarily due to net purchases of short-term investments in 2005 compared to net proceeds from short-term investments in 2004. Excluding this activity, cash used in investing activities decreased S232 million. The decrease is due primarily to $405 million in proceeds from the sale of Progress Rail in March 2005. See Note 3 to the Progress Energy Consolidated Interim Financial Statements. This was partially offset by additional capital expenditures for utility additions and nuclear fuel.

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Financing Activities Net cash provided by financing activities was $153 million for the three ietonths ended March 31, 2005, compared to Pet cash used in financing activities of $346 million for the three months ended March 31, 2004, or a net increase of $499 million. The change in cash provided froli financing activities was due primarily to the March 1,2004 maturity of $500 million 6.55% senior unsecured notes. These notes were paid with cash and commercial paper capacity which was created from the sale of assets during 2003.

In January 2005, the Company used proceeds from the issuance of commercial paper to pay off S260 million of revolving credit agreement (RCA) loans, which included $90 million at PEC and $170 million at PEF.

On January 31, 2005, Progress Energy, Inc. entered into a new $600 million RCA, which expires December 30, 2005. This facility was added to provide additional liquidity during 2005 due in part to the uncertainty of the timing of storm restoration cost recovery from the hurricanes in Florida during 2004. The RCA includes a defined maximum total debt to total capital ratio of 68% and a minimum interest coverage ratio of 2.5 to 1. The RCA also contains various cross-default and other acceleration provisions. On February 4, 2005, $300 million was drawn under the new facility to reduce commercial paper and pay off the remaining amount of loans outstanding under other RCA facilities, which consisted of $160 million at Piogress Energy and $55 million at PEF. As discussed below, the maximum size of this RCA was reduced to $300 million on March 22,2005.

On March 22, 2005, PEC issued $300 million of First Mortgage Bonds, 5.15% Series due 2015, and $200 million of First Mortgage Bonds, 5.70% Series due 2035. The net proceeds from the sale of the bonds were used to pay off $300 million of its 7.50% Senior Notes on April 1, 2005 and reduce the outstanding balance of commercial paper. Pursuant to the terms of the Progress Energy $600 million RCA, commitments were reduced to $300 million, effective March 22,2005.

In March 2005, Progress Energy, Inc.'s five-year credit facility was amended to increase the maximum total debt to total capital ratio from 65% to 68% due to the potential impacts of proposed accounting rules for uncertain tax positions. See Note 2 to the Progress Energy Consolidated Interim Financial Statements.

On March 28, 2005, PEF entered into a new $450 million RCA with a syndication of financial institutions. The RCA will be used to provide liquidity support for PEF's issuances of commercial paper and other short-term obligations. The RCA will expire on March 28, 2010. The new S450 million RCA replaced PEF's $200 million three-year RCA and $200 million 364-day RCA, which were each terminated effective March 28, 2005. Fees and interest rates under the $450 million RCA are to be determined based upon the credit rating of PEF's long-term unsecured senior non-credit enhanced debt, currently rated as A3 by Moody's Investor Services (Moody's) and BBB by Standard and Poor's (S&P). The RCA includes a defined maximum total debt to capital ratio of 65%. The RCA also contains various cross-default and other acceleration provisions, including a cross-default provision for defaults of indebtedness in excess of S35 million. The RCA does not include a material adverse change representation for borrowings or a financial covenant for interest coverage, which had been provisions in the terminated agreements.

On March 28, 2005, PEC entered into a new $450 million RCA with a syndication of financial institutions. The RCA will be used to provide liquidity support for PEC's issuances of commercial paper and other short-term obligations. The RCA will expire on June 28, 2010. The new $450 million RCA replaced PEC's $285 million three-year RCA and $165 million 364-day RCA, which were each terminated effective March 28, 2005. Fees and interest rates under the $450 million RCA are to be determined based upon the credit rating of PEC's long-term unsecured senior non-credit enhanced debt, currently rated as Baal by Moody's and BBB by S&P. The RCA includes a defined maximum total debt to capital ratio of 65%. The RCA also contains various cross-default and other acceleration provisions, including a cross-default provision for defaults of indebtedness in excess of $35 million. The RCA does not include a material adverse change representation for borrowings, which had been a provision in the terminated agreements.

For the three months ended March 31, 2005, the Company issued approximately 1.4 million shares representing approximately $60 million in proceeds from its Investor Plus Stock Purchase Plan and its employee benefit and stock option plans, net of purchases of restricted shares. The Company expects to realize approximately $125 million of cash from the sale of stock through these plans during 2005.

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Future Liquidity and Capital Resources As of March 31, 2005, there were no material changes in the Company's "Capital Expenditures," "Other Cash Needs," "Credit Facilities," or "Credit Rating Matters" a- compared to those discussed under in Item 7 of the Form 10-K, other than "Environmental Matters" and as described below and under "Financing Activities."

As of March 31, 2005, the current portion of long-term debt was $1.1 billicn, which the Company expects to fund from issuances of new long-term debt, commercial paper borrowings and/or issuance of new equity securities.

The amount and timing of future sales of company securities will depend on market conditions, operating cash flow, asset sales and the specific needs of the Company. The Company may from time to time sell securities beyond the amount needed to meet capital requirements in order to allow for the early redemption of long-term debt, the redemption of preferred stock, the reduction of short-term debt or for other general corporate purposes.

On April 29, 2005, PEF made its initial filing with the FPSC seeking annual base revenue increase of $206 million. See Note 4 to the Progress Energy Consolidated Interim Financial Statements. Hearings for this proceeding are expected to occur during the third quarter of 2005. A final ruling from the FPSC is expected in December 2005 with new rates in effect January 2006.

PEF's petition for recovery of $252 million of storm costs is scheduled for final order July 5, 2005. PEF has filed for a two-year recovery of storm costs.

On May 4, 2005, a bill was approved by the Florida Legislature that would authorize the FPSC to consider allowing the state's investor-owned utilities to issue bonds that are secured by surcharges on utility customer bills. These bonds would be issued for recovery of storm damage costs and potentially to restore depleted storm reserves. The amount of funds established for recovery is subject to the review and approval of the FPSC. The bill will now be sent to Governor Bush for his consideration. The Governor has indicated that he supports the bill. The Company cannot predict the outcome of this matter.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS The Company's off-balance sheet arrangements and contractual obligations are described below.

Guarantees As a part of normal business, Progress Energy and certain wholly owned subsidiaries enter into various agreements providing future financial or performance assurances to third parties that are outside the scope of Financial Accounting Standards Board (FASB) Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN No. 45). These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to Progress Energy and subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended commercial purposes. The Company's guarantees include performance obligations under power supply agreements, tolling agreements, transmission agreements, gas agreements, fuel procurement agreements and trading operations. The Company's guarantees also include standby letters of credit, surety bonds and guarantees in support of nuclear decommissioning. At March 31, 2005, the Company had issued S1.3 billion of guarantees for future financial or performanze assurance. The Company does not believe conditions are likely for significant performance under the guarantees of performance issued by or on behalf of affiliates.

The majority of contracts supported by the guarantees contain provisions that trigger guarantee obligations based on downgrade events to below investment grade (below BBB- or Baa3), ratings triggers, monthly netting of exposure and/or payments and offset provisions in the event of a default. As of March 31, 2005, no guarantee obligations had been triggered. If the guarantee obligations were triggered, the maximum amount of liquidity requirements to support ongoing operations within a 90-day period, associated with guarantees for the Company's nonregulated portfolio and power supply agreements was $457 million. The Company would meet this obligation with cash or letters of credit.

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At March 31, 2005, the Company had issued guarantees and indemnifications of certain legal, tax and environmental matters to third parties in connection with sales of businesses and for timely payment of obligations in support of its non-wholly owned synthetic fuel operations. Related to the sales of businesses, the notice period extends until 2012 for the majority of matters provided for fi the indemnification proirisions. For matters which the Company has received timely notice, the Company's indemnity obligations may extend beyond the notice period. Certain environmental indemnifications related to the sale of synthetic fuel operations have no limitations as to time or maximum potential future payments. Other guarantees and indemnifications have an estimated maximum exposure of approximately SIll million. At March 31, 2005, the Company has recorded liabilities related to guarantees and indemnifications to tnird-parties of $22 million. Management does not believe conditions are likely for significant performance under these agreements in excess of the recorded liabilities.

Market Risk and Derivatives Under its risk management policy, the Company may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 9 to the Progress Energy Consolidated Interim Financial Statements and Item 3, "Quantitative and Qualitative Disclosures About Market Risk," for a discussion of market risk and derivatives.

ContractualObligations As of March 31, 2005, the Company's contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2004 Annual Report on Form 10-K.

OTHER MATTERS Synthetic Fuels Tax Credits The Company has substantial operations associated with the production of coal-based synthetic fuels. The production and sale of these products qualifies for federal income tax credits so long as certain requirements are satisfied. These operations are subject to numerous risks.

Although the Company believes that it operates its synthetic fuel facilities in compliance with applicable legal requirements for claiming the credits, its four Earthco facilities are under audit by the IRS. IRS field auditors have taken an adverse position with respect to the Company's compliance with one of these legal requirements, and if the Company fails to prevail with respect to this position, it could incur significant liability and/or lose the ability to claim the benefit of tax credits carried forward or generated in the future. Similarly, the Financial Accounting Standards Board may issue new accounting rules that would require that uncertain tax benefits (such as those associated with the Earthco plants) be probable of being sustained in order to be recorded on the financial statements; if adopted, this provision could have an adverse financial impact on the Company.

The Company's ability to utilize tax credits is dependent on having sufficient tax liability. Any conditions that negatively impact the Company's tax liability, such as weather, could also diminish the Company's ability to utilize credits, including those previously generated, and the synthetic fuel is generally not economical to produce absent the credits. Finally, the tax credits associated with synthetic fuels may be phased out if market prices for crude oil exceed certain prices.

The Company's synthetic fuel operations and related risks are described in more detail in Note 14 to the Progress Energy Consolidated Interim Financial Statements and in the Risk Factors section of Progress Energy's Annual Report on Form 10-K for the year ended December 31, 2004, which was filed with the SEC on March 16, 2005.

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PEFRate Case Filing On April 29, 2005, PEF submitted minimum filing requirements, based on a 2006 projected test year, to initiate a base rate proceeding regarding lis future base rates. In its filing, PEF has-requested a $206 million annual increase in base rates effective January 1, 2006. PEF's request for an increase in base rates reflects an increase in operational costs with (i) the addition of Hines 2 generation facility intc base rates rather than the Fuel Clause as was permitted under the terms of existing Stipulation and Settlement Agreement (the Agreement), (ii) completion of the Hines 3 generation facility, (iii) the need to replenish PEE's depleted storm reserve by adjusting the annual accrual in light of recent history on a going-forward basis, (iv) the expected infrastructure investment necessary to meet high customer expectations, coupled with the demands placed on PEF's strong customer growth, (v) significant additional costs including increased depreciation and fossil dismantlement expenses and (vi) general inflationary pressures.

Hearings on the base rate proceeding are expected during the third quarter of 2005 and a final decision is expected by the end of 2005. The Company cannot predict the outcome of this matter.

PEFStorm Cost Filing Hearings on PEF's petition for recovery of $252 million of storm costs filed with the FPSC were held from March 30, 2005 to April 1, 2005. The FPSC is scheduled to vote on the Company's petition on June 14, 2005, with an order expected on July 5, 2005. The Company cannot predict the outcome of this matter.

On May 4, 2005, a bill was approved by the Florida Legislature that would authorize the FPSC to consider allowing the state's investor-owned utilities to issue bonds that are secured by surcharges on utility customer bills. These bonds would be issued for recovery of storm damage costs and potentially to restore depleted storm reserves. The amount of funds established for recovery is subject to the review and approval of the FPSC. The bill will now be sent to Governor Bush for his consideration. The Governor has indicated that he supports the bill. The Company cannot predict the outcome of this matter.

FranchiseLitigation Three cities, with a total of approximately 18,000 customers, have litigation pending against PEF in various circuit courts in Florida. As previously reported, three other cities, with a total of approximately 30,000 customers, have subsequently settled their lawsuits with PEF and signed new, 30-year franchise agreements.

The lawsuits principally seek (I) 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, as long as PEF continues to occupy the cities' rights-of-way to provide electric service, notwithstanding the expiration of the franchise ordinances under which PEF had agreed to collect such fees. The circuit courts in those cases have entered orders requiring arbitration to establish the purchase price of PEF's electric distribution system within five cities. Two appellate courts have upheld those circuit court decisions and authorized the cities to determine the value of PEF's electric distribution system within the cities through arbitration.

Arbitration in one of the cases (with the 13,000-customer City of Winter Park) was completed in February 2003. That arbitration panel issued an award in May 2003 setting the value of PEF's distribution system within the City of Winter Park (the City) at approximately $32 million, not including separation and reintegration and construction work in progress, which could add several million dollars to the award. The panel also awarded PEF approximately S11 million in stranded costs, which, according to the award, decrease over time. In September 2003, Winter Park voters passed a referendum that would authorize the City to issue bonds of up to approximately $50 million to acquire PEF's electric distribution system. While the City has not yet definitively decided whether it will acquire the system, on April 26, 2004, the City Commission voted to proceed with the acquisition. The City sought and received wholesale power supply bids and on June 24, 2004, executed a wholesale power supply contract with PEF with a five-year term from the date service begins and a renewal option. On May 12, 2004, the City solicited bids to operate and maintain the distribution system and awarded a contract in January 2005. The City has indicated that its goal is to begin electric operations in June 2005. On February 10, 2005, PEF filed a petition with the Florida Public Service Commission (FPSC) to relieve the Company of its statutory obligation to serve customers in Winter Park on June 1, 2005, or at such time when the City is able to provide retail service. On April 19, 2005, the FPSC voted to approve PEF's petition. At this 60

time, whether and when there will be further proceedings regarding the City of Winter Park cannot be determined.

Arbitration with the 2,500-customer Town of Belleair was completed in June 2003. In September 2003, the arbitration panel issued an award in that case setting the value of the electric 'distribution system within the Town at approximately S6 million. The panel further required the Town to pay to PEF its requested SI million in separation and reintegration costs and $2 million in stranded costs. The Town has not yet decided whether it will attempt to acquire the system; however, on January 18, 2005, it issued a request for proposals for wholesale power supply and to operate and maintain the distribution system. In March 2005, PEF submitted a bid to supply wholesale power to the Town. The Town received several other proposals for wholesale power and distribution services. In February 2005, the Town Commission also voted to put the issue of whether to acquire the distribution system to a voter referendum on or before October 2, 2005. At this time, whether and when there will be further proceedings regarding the Town of Belleair cannot be determined.

Arbitration in the remaining city's litigation (the 1,500-customer City of Edgewood) has not yet been scheduled. On February 17, 2005, the parties filed a joint motion to stay the litigation for a 90-day period during which the parties will discuss potential settlement. In April, the City Council voted to proceed with arbitration. At this time, whether and when there will be further proceedings regarding the City of Edgewood cannot be determined.

A fourth city (the 7,000-customer City of Maitland) is contemplating municipalization and has indicated its intent to proceed with arbitration to determine the value of PEF's electric distribution system within the City.

Maitland's franchise expires in August 2005. At this time, whether and when there will be further proceedings regarding the City of Maitland cannot be determined.

As part of the above litigation, two appellate courts reached opposite conclusions regarding whether PEF must continue to collect from its customers and remit to the cities "franchise fees" under the expired franchise ordinances. PEF filed an appeal with the Florida Supreme Court to resolve the conflict between the two appellate courts. On October 28, 2004, the Court issued a decision holding that PEF must collect from its customers and remit to the cities franchise fees during the interim period when the city exercises its purchase option or executes a new franchise. The Court's decision should not have a material impact on the Company.

EnvironmentalMatters The Company is subject to federal, state and local regulations addressing air and water quality, hazardous and solid waste management and other environmental matters. These environmental matters are discussed in detail in Note 13. This discussion identifies specific environmental issues, the status of the issues, accruals associated with issue resolutions and the associated exposures to the Company. The Company accrues costs to the extent they are probable and can be reasonably estimated. It is reasonably possible that additional losses, which could be material, may be incurred in the future.

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 nonutility subsidiaries for the three months ended March 31, 2005 and 2004 are not material to PEC's consolidated financial statements.

LIOUIDITY AND CAPITAL RESOURCES Cash provided by operating activities decreased $49 million for the three months ended March 31, 2005, when compared to the corresponding period in the prior year. The decrease was caused primarily by the impact of an under-recovery of fuel costs in 2005 and increase in working capital requirements.

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' '.-.--l;F.+V.;. ;xi . - ,,.

Cash used in investing activities increased $318 million for the three months ended March 31, 2005, when compared to the corresponding period in the prior year primarily due to net purchases of short-terin investments in 2005 compared to net proceeds from short-term investments in 2004.

The current portion of long-term debt includes S300 million of 7.50% Senior Notes which matured on April 1, 2005.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS PEC's off-balance sheet arrangements and contractual obligations are described below.

Market Risk and Derivatives Under its risk management policy, PEC may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 7 to PEC's Consolidated Interim Financial Statements and Item 3, "Quantitative and Qualitative Disclosures About Market Risk," for a discussion of market risk and derivatives.

ContractualObligations As of March 31, 2005, PEC's contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2004 Annual Report on Form I 0-K.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk Progress Energy, Inc.

Other than described below, the various risks that the Company is exposed to has not materially changed since December 31,2004. - ,

Progress Energy and its subsidiaries are exposed to various risks related to changes in market conditions.

Market risk represents the potential loss arising from adverse changes in market rates and prices. The Company has a risk management committee that 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. Under its risk policy, the Company may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk if the counterparty fails to perform under the contract. The Company minimizes such risk by performing credit reviews using, among other things, publicly available credit ratings of such counterparties.

Certain market risks are inherent in the Company's financial instruments, which arise from transactions entered into in the normal course of business. The Company's primary exposures are changes in interest rates with respect to its long-term debt and commercial paper, fluctuations in the return on marketable securities with respect to its nuclear decommissioning trust funds, changes in the market value of CVOs, and changes in energy related commodity prices.

Interest Rate Risk Progress Energy uses a number of models and methods to determine interest rate risk exposure and fair value of derivative positions. For reporting purposes, fair values and exposures are determined as of the end of the reporting period using the Bloomberg Financial Markets system.

The exposure to changes in interest rates from the Company's fixed rate and variable rate long-term debt at March 31, 2005 has changed from December 31, 2004. The total fixed rate long-term debt at March 31, 2005 was $9.36 billion, with an average interest rate of 6.50% and fair market value of S9.88 billion. The total variable rate long-term debt at March 31, 2005, was $0.86 billion, with an average interest rate of 2.12% and fair market value of $0.86 billion.

The Company maintains a portion of its outstanding debt with floating interest rates. As of March 31, 2005 approximately 13.8% of consolidated debt was in floating rate mode compared to 16.1% at the end of 2004.

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. In accordance with FAS 133 interest rate derivatives that qualify as hedges are broken into one of two categories, cash flow hedges or fair value hedges. Cash flow hedges are used to reduce exposure to changes in cash flow due to fluctuating interest rates. Fair value hedges are used to reduce exposure to changes in fair value due to interest rate changes.

The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss.

In the event of default by a counterparty, the risk in 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.

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E tt : I-

.~n S Fair Value Hedges:

As of March 31, 2005, Progress Energy had $150 million of fixed rate debt swapped to floating rate debt by executing receive fixed interest rate swap agreements. Under terms of these swap agreements, Progress Energy will rtceive a fixed rate and pay a flatiing rate based on 3-month LIBOR.--,

Fair Value Hedges (dollars in millions)

Notional Fair Progress Energy, Inc. Amount Receive PZy(b) Value Exposure (C)

Risk hedged as of March 31, 2005:

5.85% Notes due 10/30/2008 $ 100 4.10% 3-month LIBOR $ - $ (1) 7.10%Notes due 3/1/2011 $ 50 4.65% 3-month LIBOR $ - $ (1)

Total $ 150 4.28%(') 3-month LIBOR $ - $ (2)

Risk hedged as of December 31, 2004:

5.85% Notes due 10/30/2008 $ 100 4.10% 3-month LIBOR $ I $ (1) 7.10% Notes due 3/1/2011 S 50 4.65% 3-month LIBOR $ 2 $ (1)

Total $ 150 4.28%(') 3-month LIBOR $ 3 $ (2)

(')Weighted average rate

()3-month LIBOR rate was 3.12% at March 31, 2005 and 2.56% at December31, 2004.

(') Exposure indicates change in value due to 25 basis point unfavorable shift in interest rates.

Cash Flow Hedges:

As of March 31, 2005 Progress Ene gy had $75 million of pay-fixed forward starting swaps in place to hedge cash flow risk due to future financing transactions and $200 million of pay-fixed swaps to hedged cash flow for commercial paper interest. Under terms of these swap agreements, Progress Energy will pay a fixed rate and receive a floating rate based on either 1-month or 3-month LIBOR.

Cash Flow Hedges (dollars in millions)

Notional Fair Progress Energy, Inc. Amount Pay Receive(b) Value Exposure(c)

Risk hedged as of March 31, 2005:

Commercial Paper interest risk through 2005 $ 200 3.07% 1-month LIBOR $ I S -

Anticipated 10-year debt issue(d) $ :75 4.92% 3-month LIBOR $ I $ (1)

Total $ 275 4.91%(s) 3-month LIBOR $ 2 $ (1)

Risk hedged as of December 31,2004:

Commercial Paper interest risk from 2005 through 2008 $ 200 3.07% I-month LIBOR $ - S -

Progress Energy Carolinas Risk hedged as of March 31, 2005: None Risk hedged as of December 31, 2004:

Anticipated 10-year debt issue $ 110 4.85% 3-month LIBOR $ (1) S (2)

Rail car lease payment $ 21 5.17% 3-month LIBOR S (1) $ -

Total $ 131 4.900/o(a) 3-month LIBOR S (2) S (2) tWeighted average rate

(')3-month LIBORrate was 3.12% at March 31, 2005 and 2.56% at December 31, 2004.

1-month LIBOR rate was 2.87% at March 31, 2005 and 2.40% at December 31, 2004.

(c)Exposure indicates change in value due to 25 basis point unfavorable shift in interest rates.

(d)Anticipated 10-year debt issue hedges mature on March 1,2016 and require mandatory cash settlement on March 1, 2006.

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Marketable Securities Price Risk The Company's exposure to return on marketable securities for the nuclear decommissioning trust funds has not changed materially since December 31, 2004.

CVO Market Value Risk The Company's exposure to market value risk with respect to the CVOs has not changed materially since December 31, 2004.

Commodity Price Risk The Company is exposed to the effects of market fluctuations in the price of natural gas, coal, fuel oil, electricity and other energy-related products marketed and purchased as a result of its ownership of energy-related assets. The Company's exposure to these fluctuations is significantly limited by the cost-based regulation of PEC and PEF. Each state commission allows electric utilities to recover certain of these costs through various cost recovery clauses to the extent the respective commission determines that such costs are prudent. Therefore, while there may be a delay in the timing between when these costs are incurred and when these costs are recovered from the ratepayers, changes from year to year have no material impact on operating results. In addition, many of the Company's long-term power sales contracts shift substantially all fuel responsibility to the purchaser. The Company also has oil price risk exposure related to synfuel tax credits. See discussion in Note 14 to the Progress Energy Consolidated Interim Financial Statements.

Derivative products, primarily electricity and natural gas contracts, may be entered into from time to time for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions. The Company manages open positions with strict policies that limit its exposure to market risk and require daily reporting to management of potential financial exposures.

The Company recorded a S2 million pre-tax gain and a $12 million pre-tax loss on such contracts for the three months ended March 31, 2005 and 2004, respectively. The Company did not have material outstanding positions in such contracts at March 31, 2005 or December 31, 2004.

PEF has derivative instruments related to its exposure to price fluctuations on fuel oil purchases. At March 31, 2005, the fair values of these instruments were a S34 million short-term derivative asset position included in other current assets and a $23 million long-term derivative asset position included in other assets and deferred debits. At December 31, 2004, the fair values of these instruments were a S2 million long-term derivative asset position included in other assets and deferred debits and a $5 million short-term derivative liability position included in other current liabilities. These instruments receive regulatory accounting treatment. Unrealized gains and losses are recorded in regulatory liabilities and regulatory assets, respectively.

The Company uses natural gas hedging instruments to manage a portion of the market risk associated with fluctuations in the future purchase and sales prices of the Company's natural gas. The fair values of commodity cash flow hedges at March 31, 2005 and December 31, 2004 were as follows:

(in millions) March 31, Decembe: 31, 2005 2004 Fair value of assets S 19 $ -

Fair value of liabilities (26) (15)

Fair value, net S (7) $ (15)

The Company performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. The Company's exposure to commodity price risk has not changed materially since December 31, 2004. A hypothetical 10% increase or decrease in quoted market prices in the near term on the Company's derivative commodity instruments would not have had a material effect on the Company's consolidated financial position, results of operations or cash flows as of March 31, 2005.

Refer to Note 9 for additional information with regard to the Company's commodity contracts and use of derivative financial instruments.

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Progress Energv Carolinas. Inc.

PEC has certain market risks inherent in its financial instruments, which arise from transactions entered into in the normal course of business. PEC's primary exposures are changes in interest rates, vwith respect to long-term debt and commercial paper, and fluctuations in the return on marketazble securities, with respect tz its nuclear decommissioning trust funds. PEC's exposure to these risks has not materially changed since December 31, 2004.

The information required by this item is incorporated herein by reference to the Quantitative and Qualitative Disclosures About Market Risk discussed above insofar as it relates to PEC.

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Item 4: Controls and Procedures Progress Energy. Inc.

Pursuant to Rule 13a-15(b) under theSecurities Exchange Act of 1934, Progress Energy carried out ar.

evaluation, with the participatikn-o f its management, including Progress Energy's Chairman and Chief Executive Officer and Chief Financial Officer, of the effectiveness of Progress Energy's disclosure ccntrols and procedures (as defined under Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, Progress Energy's Chief Executive Officer and Chief Financial Officer concluded that its disclosure controls and procedures are effective to ensure that information required to be disclosed by Progress Energy in the reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to Progress Energy's management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There has been no change in Progress Energy's internal control over financial reporting during the quarter ended March 31, 2005, that has materially affected, or is reasonably likely to materially affect, Progress Energy's internal control over financial reporting.

Progress Energv Carolinas. Inc.

Pursuant to the Securities Exchange Act of 1934, PEC carried out an evaluation, with the participation of its management, including PEC's Chairman and Chief Executive Officer and Chief Financial Officer, of the effectiveness of PEC's disclosure controls and procedures (as defined under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, PEC's Chief Executive Officer and Chief Financial Officer concluded that its disclosure controls and procedures are effective to ensure that information required to be disclosed by PEC in the reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to PEC's management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There has been no change in PEC's internal control over financial reporting during the quarter ended March 31, 2005, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

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PART II. OTHER INFORMATION Item 1. Lenal Proceedings Legal aspects of certain matters are set forth in Part I, Item 1. See Note 14 to the Progress Energy, Inc.

Consolidated Interim Financial Staieriients and Note 10 to the PEC Consolidated Interim Financial Statements.

Item 2. Unregistered Sale of Equity Securities and Use of Proceeds

a. RESTRICTED STOCK AWARDS:

(a) Securities Delivered. On January 1, 2005, March 7, 2005, March 15, 2005 and March 21, 2005, 13,000, 2,200, 101,500 and 3,500 restricted shares, respectively, of the Company's Common Shares were granted to certain key employees pursuant to the terms of the Company's 2002 Equity Incentive Plan (Plan), which was approved by the Company's shareholders on May 8, 2002. The Common Shares delivered pursuant to the Plan were acquired in market transactions directly for the accounts of the recipients and do not represent newly issued shares of the Company.

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

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

(d) Exemption from Registration Claimed. The Common Shares described in this Item were delivered on the basis of an exemption from registration under Section 4(2) of the Securities Act of 1933. Receipt of the Common Shares required no investment decision on the part of the recipients.

c. ISSUER PURCHASES OF EQUITY SECURITIES FOR FIRST QUARTER OF 2005 (d)

(c) Maximum Number (or (a) (b) Total Number of Shares Approximate Dollar Value)

Total Number of Average (or Units) Purchased as of Shares (or Units) that Shares Price Paid Part of Publicly May Yet Be Purchased (or Units) Per Share Announced Plans or Under the Plans or Period Purchased(l) (or Unit) Programs(l) Programs(l)

January I - January 31 13,000 $45.11 N/A N/A February 1- February 0 N/A N/A N/A 28 March I -March 31 107,200 $42.26 N/A N/A Total: 120,200(2) $42.57 N/A N/A (1) As of March 31, 2005, Progress Energy does not have any publicly announced plans or programs to purchase shares of its common stock.

(2) Shares of common stock were purchased in open-market transactions in connection with restricted stock awards that were granted to certain key employees pursuant to the terms of the Progress Energy 2002 Equity Incentive Plan, which was approved by Progress Energy's Shareholders on May 8,2002.

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Item 6. Exhibits (a) Exhibits Exhibit Progress Progress Energy Number Description v Inc. Carolinas. Inc.

31(a) Certifications pursuant to Section 302 of the X X Sarbanes-Oxley Act of 2002 - Chairman and Chief Executive Officer 31(b) Certifications pursuant to Section 302 of the X X Sarbanes-Oxley Act of 2002 - Executive Vice President and Chief Financial Officer 32(a) Certifications pursuant to Section 906 of the X X Sarbanes-Oxley Act of 2002 - Chairman and Chief Executive Officer 32(b) Certifications pursuant to Section 906 of the X X Sarbanes-Oxley Act of 2002 - Executive Vice President and Chief Financial Officer 69

.. . i, .: : - . .

• l i, ,  ;

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 CGMPANY Date: May 6,2005 (Registrants)

By: Isl Geoffrey S. Chatas Geoffrey S. Chatas Executive Vice President and Chief Financial Officer By: Is/ Robert H. Bazemore, Jr.

Robert H. Bazemore, Jr.

Controller and Chief Accounting Officer 70