ML051230417

Submittal of Licensee Annual Financial Report

ML051230417
Person / Time
Site:	Harris, Brunswick, Robinson, 07200003
Issue date:	04/27/2005
From:	Burton C Progress Energy Carolinas
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
PE&RAS05-025
Download: ML051230417 (118)

Text

10 CFR 50.71 (b), 10 CFR 72.80(b) 8$ Progress Energy PO Box 1551 411 Fayetteville Street Mall Raleigh NC 27602 PE&RAS05-025 April 27, 2005 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555-0001 U.S. Nuclear Regulatory Commission Director, Spent Fuel Project Office Office of Nuclear Material Safety and Safeguards 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 SHEARON HARRIS NUCLEAR POWER PLANT, UNIT NO. 1 DOCKET NO. 50-400 / LICENSE NO. NPF-63 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT NO. 2 DOCKET NO. 50-261 /LICENSE NO. DPR-23 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT NO. 2 INDEPENDENT SPENT FUEL STORAGE INSTALLATION DOCKET NO. 72-3 / LICENSE NO. SNM-2502 Submittal of Licensee Annual Financial Report Ladies and Gentlemen:

In accordance with 10 CFR 50.7 1(b) and 10 CFR 72.80(b), Carolina Power & Light Company doing business as Progress Energy Carolinas, Inc. (PEC) submits the enclosed Annual Report, including certified financial statements.

No new commitments have been made in this submittal. If you have questions, please notify Tony Groblewvski at (919) 546-4579.

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United States Nuclear Regulatory Commission PE&RAS05-025 Page 2 Sincerely, Chris Burton Manager, Performance Evaluation &

Regulatory Affairs RTG

Enclosure:

Progress Energy 2004 Annual Report c:

W. D. Travers, USNRC Regional Administrator - Region II USNRC Senior Resident Inspector - BSEP, Unit Nos. I and 2 B. L. Mozafari, NRR Project Manager - BSEP, Unit Nos. 1 and 2 USNRC Senior Resident Inspector - HNP, Unit No. I C. P. Patel, NRR Project Manager - HNP, Unit No. 1, HBRSEP, Unit No. 2 USNRC Senior Resident Inspector - HBRSEP, Unit No. 2 J. Sanford, North Carolina Utilities Commission Geneva Thigpen, Chief Clerk, North Carolina Utilities Commission Sam Watson, Staff Attorney, North Carolina Utilities Commission

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- -,.-i,.h..s It's focus. And at Progress Energy, it keeps our sights set on balanced long-term performance. It's:about having a sound strategyfor the futureel as steady execution today.i ts promoting successful economic development to: create tomorrow's oppor-tunities. And it's investing in communityt initiatives that make our territory a more attractive, more to.,.0

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Dear Fellow Shareholders:

Progress Energy kept a relentless focus on excellence and long-term value in 2004. We increased the dividend for the 17th consecutive year and for the 29th time in the last 30 years. And we entered 2005 with a clear vision of what we 'need to accomplish and a well-founded confidence in our ability to do it.

Even though the unprecedented series of hurricanes last year created serious problems for our customers and company in the short run, the' fundamentals of our core business remain sound.

Moreover, our employees once again proved how well they rise to any challenge.

Executing a Clear Strategic Plan-In 2004, our management team conducted an extensive analysis of our industry and our company. We developed a clear road map for the next three years and beyond that will reinforce our position as a buy-and-hold stock providing good value at modest risk.

We reaffirmed the basic strategic focus on our three core energy businesses: Progress Energy Carolinas and Progress Energy Florida - our electric utilities serving regulated markets -

and Progress Ventures (excluding synthetic fuels), which serves competitive energy markets in the eastern United States.

Our strategic plan also includes selective asset sales to complete the restoration of our balance sheet. We sold our North Texas natural gas properties in December 2004 and have used the over $250 million in proceeds to retire debt. In February 2005, we reached a definitive agree-,

ment to sell Progress Rail, a subsidiary acquired In the 2000 merger. The $405 million in proceeds also will be used for debt reduction.,

In addition, our plan calls for growing our core-business earnings per share over the long term by 3 percent to 5 percent a year, which will support continued'dividend growth. We know that consistent dividend growth is a major reason investors buy our stock.

Our strategy will help us maintain and enhance shareholder value as we make the transition beyond the federal synthetic-fuel tax program that expires at the end of 2007. In 2004, we resolved the federal tax audit issues with our Colona synthetic-fuel facilities, but, as of early 2005, we are still working with the Internal Revenue Service to resolve issues with the Earthco synthetic-fuel audit. While we feel good about our case, we can't predict the outcome.

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Progress Energy Annual Report 2004 EXECUTIVE AND SENIOR OFFICERS Robert B. McGehee Chairman and Chief Executive Officer William D. Johnson President and Chief Operating Officer Peter M. Scott IlIl President and Chief Executive Officer Progress Energy Service Company, LLC Fred N. Day IV President and Chief Executive Officer Progress Energy Carolinas, Inc.

H. William Habermeyer, Jr.

President and Chief Executive Officer Progress Energy Florida, Inc.

Geoffrey S. Chatas Executive Vice President and Chief Financial Officer Donald K. Davis Executive Vice President-Diversified Operations C. S. Hinnant Senior Vice President - Nuclear Generation Jeffrey J. Lyash Senior Vice President - Energy Delivery Progress Energy Florida, Inc.

John R. McArthur Senior Vice President-Corporate Relations, General Counsel and Secretary E. Michael Williams Senior Vice President-Power Operations Lloyd M. Yates Senior Vice President - Energy Delivery Progress Energy Carolinas, Inc.

FINANCIAL REPORT Management's Discussion and Analysis...............................

20 Market Risk Disclosures...............................

48 Forward-Looking Statements............................................................................ 51 Independent Auditors' and Management Reports...............................

52 Consolidated Financial Statements Income...............................

55 Balance Sheets...............................

56 Cash Flows...............................

58 Changes in Common Stock Equity...............................

59 Comprehensive Income...............................

59 Notes to Consolidated Financial Statements...............................

60 Selected Consolidated Financial and Operating Data (Unaudited)........................................... 110 Reconciliation of Ongoing Earnings Per Share to Reported GAAP Earnings Per Share (Unaudited)......

....... 111 19

V Management's Discussion and Analysis The following Management's Discussion and Analysis contains forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review the 'Safe Harbor For Forward-Looking Statements for a discussion of the factors that may impact any such forward-looking statements made herein. Management's Discussion and Analysis should be read in conjunction with the Progress Energy Consolidated Financial Statements.

INTRODUCTION The Company's reportable business segments and their primary operations include:

• 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 the southeastern United States;

• Fuels - primarily engaged in natural gas production in Texas and Louisiana, coal mining and related services, and the production of synthetic fuels and related services, which are located in Kentucky, West Virginia and Virginia; and

• Rail Services (Rail) - engaged in various rail and railcar-related services in 23 states, Mexico and Canada.

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

In 2004, the Company realigned its business segments to no longer report the other nonregulated businesses as a reportable business segment. For comparative purposes, 2003 and 2002 segment information has been restated to align with the 2004 reporting structure.

Strategy Progress Energy is an integrated energy company, with its primary focus on the end-use and wholesale electricity markets. The Company operates in retail utility markets in the southeastern United States and competitive markets in the eastern United States. The target is to develop a business mix of approximately 80% regulated and 20% nonregulated business. The Company is focused on achieving the following key goals: restoring balance sheet strength and flexibility, disciplined capital and operations and maintenance (O&M) management to support earnings and current dividend policy and achieving constructive regulatory frameworks in all three regulated jurisdictions. A summary of the significant financial objectives or issues impacting Progress Energy, its regulated utilities and nonregulated operations is addressed more fully in the following discussion.

Progress Energy has several key financial objectives, the first of which is to achieve sustainable earnings growth in its three core energy businesses, which include PEC Electric, PEF and Progress Ventures (excluding synthetic fuels). In addition, the Company seeks to continue its track record of dividend growth, as the Company has increased its dividend for 17 consecutive years, and 29 of the last 30.

The Company also seeks to restore balance sheet strength and flexibility by reducing its debt to total capitalization ratio through selected asset sales, free cash flow (defined as cash from operations less capital expenditures and common dividends) and increased equity from retained earnings and ongoing equity issuances.

In the short term the Company's ability to achieve its objectiveswill be impacted by, among otherthings,its ability to recover storm costs incurred during 2004, cash flow available to reduce debt after funding capital expenditures and common dividends, obtaining a reasonable rate agreement in Florida at the expiration of the current agreement in December 2005 and the outcome of the ongoing Internal Revenue Service (IRS) audit of the Company's synthetic fuel facilities. The Company's long-term challenges include escalating nonfuel operating costs, the need for sufficient earnings growth to sustain the track record of dividend growth, and the scheduled expiration of the Section 29 tax credit program for its synthetic fuels business at the end of 2007.

The Company's ability to meet its financial objectives is largely dependent on the earnings and cash flows of its two regulated utilities. The regulated utilities contributed

$797 million of net income and produced 100% of consolidated cash flow from operations in 2004. In 20

Progress Energy Annual Report 2004 addition, Fuels contributed $180 million of net income, of which $91 million represented synthetic fuel net income.

Partially offsetting the net income contribution provided by the regulated utilities and Fuels was a loss of

$236 million recorded at Corporate and Other, primarily related to interest expense on holding company debt While the Company's synthetic fuel operations currently provide significant earnings that are scheduled to expire atthe end of 2007, the associated cash flow benefits from synthetic fuels are expected to come in the future when deferred tax credits are ultimately utilized. Credits that have been generated but not yet utilized are carried forward indefinitely as alternative minimum tax credits and will provide positive cash flow when utilized. At December 31, 2004, deferred credits were $745 million.

See Note 23E for additional information on the Company's synthetic fuel operations and its ability to utilize its current and future tax credits.

Progress Energy reduced its debt to total capitalization ratio to 57.6% at the end of 2004 as compared to 58.8% at the end of 2003. The Company seeks to continue to improve this ratio as it plans to reduce total debt with proceeds from asset sales, free cash flow (defined as cash from operations less capital expenditures and common dividends) and growth in equity from retained earnings and ongoing equity issuances. The Company expects total capital expenditures to be approximately $1.3 billion in both 2005 and 2006.

Progress Energy's ratings outlook was changed to negative" from 'stable" in 2004 by both Moody's and Standard & Poor's (S&P). Both these ratings agencies cited the uncertainty around the timing of storm cost recovery, potential delays in the Company's de-leveraging plan, uncertainty about the upcoming rate case in Florida and uncertainty about the IRS audit of the Company's synthetic fuel partnerships in their ratings actions. The change in outlook has not materially affected Progress Energy's access to liquidity or the cost of its short-term borrowings. If Standard & Poor's lowers Progress Energy's senior unsecured rating one ratings category to BB+ from its current rating, it would be a non-investment grade rating. The effect of a noninvestment grade rating would primarily be to increase borrowing costs. The Company's liquidity would essentially remain unchanged as the Company believes it could borrow under its revolving credit facilities instead of issuing commercial paper for its short-term borrowing needs.

However, there would be additional funding requirements of approximately $450 million due to ratings triggers embedded in various contracts. See 'Guarantees' Section under FUTURE LIQUIDITY AND CAPITAL RESOURCES below for more information regarding the potential impact on the Company's financial condition and results of operations resulting from a ratings downgrade.

REGULATED UTILITIES The regulated utilities earnings and operating cash flows are heavily influenced by weather, including related storm damage, the economy, demand for electricity related to customer growth, actions of regulatory agencies and cost controls.

Both PEC Electric and PEF operate in retail service territories that are forecasted to have income and population growth higher than the U.S. average. In recent years, lower industrial sales mainly related to weakness in the textile sector at PEC Electric have negatively impacted earnings growth. The Company does not expect any significant improvement in industrial sales in the near term. These combined factors under normal weather conditions are expected to contribute approximately 2% annual retail kilowatt-hour (KWh) sales growth at PEC Electric and approximately 3% annual retail kilowatt-hour (KWh) sales growth at PEF through at least 2007. The utilities must continue to invest significant capital in new generation, transmission and distribution facilities to support this load growth. Subject to regulatory approval, these investments are expected to increase the utilities' rate base, upon which additional return can be realized that creates the basis for long-term financial growth in the utilities. The Company will meet this load growth through the two previously planned approximately 500 MW combined-cycle units at PEFs Hines Energy Complex in 2005 and 2007. The contribution from the utilities' regulated wholesale business is expected to increase slightly in 2005 and be relatively flat over the following few years.

While the two utilities expect retail sales growth in the future, they are facing rising costs. The Company began a cost-management initiative in late 2004 to permanently reduce by$75 million to $100 million the projected growth in the Company's annual nonfuel O&M costs by the end of 2007. See 'Cost-Management Initiative' under RESULTS OF OPERATIONS for more information. The utilities expect capital expenditures to be approximately $1.1 billion in both 2005 and 2006. The Company will continue an approximate $900 million program of installing new emission-control equipment at PEC's coal-fired power plants in North Carolina. Operating cash flows are expected to be sufficient to fund capital spending in 2005 and in 2006.

21

V Management's Discussion and Analysis The costs associated with the unprecedented series of major hurricanes that impacted the Company's service territories significantly impacted the utility operations in 2004. Restoration of the Company's systems from hurricane-related damage cost almost $400 million.

Although PEF has filed for recovery of approximately

$252 million of these storm costs, the timing of recovery is not certain at this time. See OTHER MATTERS below for more information on storm costs incurred during 2004.

PEC Electric and PEF continue to monitor progress toward a more competitive environment. No retail electric restructuring legislation has been introduced in the jurisdictions in which PEC Electric and PEF operate.

As part of the Clean Smokestacks bill in North Carolina and an agreement with the Public Service Commission of South Carolina (SCPSC), PEC Electric is operating under a rate freeze in North Carolina through 2007 and an agreement not to seek a base retail electric rate increase in South Carolina through 2005. PEF is operating under a retail rate agreement in Florida through 2005. PEF has initiated a rate proceeding in 2005 regarding its future base rates. See Note 8 for further discussion of the utilities' retail rates.

NONREGULATED BUSINESSES The Company's primary nonregulated businesses are CCO, Fuels and Progress Rail.

Cash flows and earnings of the nonregulated businesses are impacted largely by the ability to obtain additional term contracts or sell energy on the spot market at favorable terms, the volume of synthetic fuel produced and tax credits utilized, and volumes and prices of both coal and natural gas sales.

Progress Energy expects an excess of supply in the wholesale electric energy market for the next several years. During 2004, CCO entered into additional wholesale power contracts with cooperatives in Georgia and will serve approximately one-third of the Georgia cooperative market starting in 2005. CCO completed the build out of its nonregulated generation assets in 2003 and currently has total capacity of 3,100 MW. The Company has no current plans to expand its portfolio of nonregulated generating plants.

CCO short-term challenges include absorbing the fixed costs associated with these plants and the general weakness in wholesale power markets. Three above-market tolling agreements for approximately 1,200 MW of capacity expired at the end of 2004. CCO has replaced the expired agreements with the increased cooperative load in Georgia. The increased cooperative load in Georgia will significantly increase CCO's revenue and cost of sales from 2004 to 2005 with lower margins expected. Currently CCO has contracts for its planned production capacity, which includes callable resources from the cooperatives, of approximately 77% for 2005, 81% for 2006 and 75% for 2007. CCO will continue its optimization strategy for the nonregulated generation portfolio.

Fuels will continue to develop its natural gas production asset base both as a long-term economic hedge for the Company's nonregulated generation fuel needs and to continue its presence in natural gas markets that will allow it to provide attractive returns for the Company's shareholders.

The Company has begun exploring strategic alternatives regarding the Fuels' coal mining business, which could include divesting assets. As of December 31, 2004, the carrying value of long-lived assets of the coal mining business was $66 million.

The Company, through its subsidiaries, is a majority owner in five entities and a minority owner in one entity that owns facilities that produce synthetic fuel as defined under the Internal Revenue Code. The production and sale of the synthetic fuel from these facilities qualifies for tax credits under Section 29 if certain requirements are satisfied. These facilities have private letter rulings (PLRs) from the IRS with respect to their synthetic fuel operations. However, these PLRs do not address placed-in-service date requirements. The Company has resolved certain synthetic fuel tax credit issues with the IRS and is continuing to work with the IRS to resolve any remaining issues. The Company cannot predict the final resolution of any outstanding matters. The Company has no current plans to alter its synthetic fuel production schedule as a result of these matters. The Company plans to produce approximately 8 million to 12 million tons of synthetic fuel in 2005. Through December 31, 2004, the Company had generated approximately $1.5 billion of synthetic fuel tax credits to date (including FPC prior to the acquisition by the Company). See additional discussion of synthetic fuel tax credits in Note 23E.

In February 2005, Progress Energy signed a definitive agreement to sell its Progress Rail subsidiary to subsidiaries of One Equity Partners LLC for a sales price of S405 million. Proceeds from the sale are expected to be used to reduce debt. See Note 24 for more information.

Progress Energy and its consolidated subsidiaries are subject to various risks. For a complete discussion of these risks, see the Company's filings with the SEC.

22

Progress Energy Annual Report 2004 RESULTS OF OPERATIONS For 2004 as compared to 2003 and 2003 as compared to 2002 In this section, earnings and the factors affecting earnings are discussed. The discussion begins with a summarized overview of the Company's consolidated earnings, which is followed by a more detailed discussion and analysis by business segment Overview For the year ended December 31,2004, Progress Energy's net income was S759 million or$3.13 per share compared to $782 million or $3.30 per share for the same period in 2003. The decrease in net income as compared to prior year was due primarily to:

• Reduction in synthetic fuel earnings due to lower synthetic fuel sales due to the impact of hurricanes during the year.

• Lower off-system wholesale sales, primarily at PEC Electric.

• Higher O&M expenses at PEC Electric.

• Recording of litigation settlement reached in the civil suit by Strategic Resource Solutions (SRS).

• Decreased nonregulated generation earnings due to receipt of a contract termination payment on a tolling agreement in 2003, loss recognized on early extinguishment of debt in 2004 and higher fixed costs and interest charges in 2004.

• Reduction in revenues due to customer outages in Florida associated with the hurricanes.

• Increased interest charges due to the reversal of interest expense for resolved tax matters in 2003.

Partially offsetting these items were:

• Favorable weather in the Carolinas.

• Reduction in revenue sharing provisions in Florida.

• Favorable customer growth in both the Carolinas and Florida.

• Increased margins as a result of the allowed return on the Hines Unit 2 in Florida.

• Increased earnings for natural gas operations, which include the gain recorded on the disposition of certain Winchester Production Company assets.

• Increased earnings for Rail operations.

• Unrealized gains recorded on contingent value obligations (CVOs).

• Reduction in impairments recorded for an investment portfolio and long-lived assets.

• Reduction in losses recorded for discontinued operations.

• Reduction in losses recorded for changes in accounting principles.

For the year ended December 31, 2003, Progress Energy's net income was $782 million, or$3.30 per share, compared to $528 million, or $2.43 per share, for the same period in 2002. Income from continuing operations before the cumulative effect of changes in accounting principles and discontinued operations was $811 million in 2003, a 47%

increase from $552 million in 2002. Net income for 2003 increased compared to 2002 primarily due to the inclusion in 2002 of an impairment of $265 million after-tax related to assets in the telecommunications and rail businesses.

The Company recorded impairments of $23 million after-tax in 2003 on an investment portfolio and on long-lived assets. The increase in net income in 2003 of $12 million, excluding the impairments, is primarily due to:

• Increase in retail customer growth at the utilities.

• Growth in natural gas production and sales.

• Higher synthetic fuel sales.

• Absence of severe storm costs incurred in 2002 in the Carolinas.

• Lower loss recorded in 2003 related to the sale of North Carolina Natural Gas Company (NCNG), with the majority of the loss on the sale being recorded in 2002.

• Lower interest charges in 2003.

Partially offsetting these items were the:

• Net impact of the 2002 Florida Rate settlement.

• Impact of the change in the fair value of the CVOs.

• Milder weather in 2003 as compared to 2002.

• Increased benefit-related costs.

• Higher depreciation expense at both utilities and the Fuels and CCO segments.

• The impact of changes in accounting principles in 2003.

Basic earnings per share decreased in 2004 and increased in 2003 due in part to the factors outlined above. Dilution related to issuances under the Company's Investor Plus and employee benefit programs in 2004 also reduced basic earnings per share by $0.06 in 2004. Dilution related to a November 2002 equity issuance of 14. million shares and issuances under the Company's Investor Plus and employee benefit programs in 2002 and 2003 also reduced basic earnings per share by $0.33 in 2003.

Beginning in the fourth quarter of 2003, the Company ceased recording portions of the Fuels segment's 23

V Management's Discussion and Analysis operations, primarily synthetic fuel facilities, one month in arrears. As a result, earnings forthe yearended December 31, 2003, included 13 months of operations, resulting in a net income increase of $2 million for the year.

The Company's segments contributed the following profit or loss from continuing operations:

(in millions) 2004 Change 2003 Change 2002 PEC Electric

$464

$151)

$515

$2 $513 PEF 333 38 295 128) 323 Fuels 180 (55) 235 59 176 CCO (4)

(24) 20

17) 27 Rail services 16 17

11) 41 (42)

Total segment profit (loss) 989 (75) 1,064 67 997 Corporate and other 1236) 17 (253) 192 (445)

Total income from continuing operations 753 (58) 811 259 552 Discontinued operations, netof tax 6

14 (8) 16 124)

Cumulative effect of changes in accounting principles 21 (21)

(21)

Netincome S759

$123)

S782

$254 $528 2005. 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 expenses bythe end of 2007. In additiontothe workforce restructuring, the cost-management initiative includes a voluntary enhanced retirement program.

In March 2003, the SEC completed an audit of Progress Energy Service Company, LLC (Service Company), and recommended that the Company change its cost allocation methodology for allocating Service Company costs. As part of the audit process, the Company was required to change the cost allocation methodology for 2003 and record retroactive reallocations between its affiliates in the first quarter of 2003 for allocations originally made in 2001 and 2002. This change in allocation methodology and the related retroactive adjustments have no impact on consolidated expense or earnings. The new allocation methodology, as compared to the previous allocation methodology, generally decreases expenses in the regulated utilities and increases expenses in the nonregulated businesses. The regulated utilities' reallocations are within O&M expense, while the diversified businesses' reallocations are generally within diversified business expenses. The impact on the individual lines of business is included in the following discussions.

Cost-Management Initiative On February 28, 2005, as part of a previously announced cost-management initiative, the executive officers of the Company approved a workforce restructuring. The restructuring will result in a reduction of approximately 450 positions and is expected to be completed in September of In connection with the cost-management initiative, the Company expects to incur one-time pre-tax charges of approximately $130 million. Approximately $30 million of that amount relates to payments for severance benefits, and will be recognized in the first quarter of 2005 and paid over time. The remaining approximately $100 million will be recognized in the second quarter of 2005 and relates primarily to postretirement benefits that will be paid over time to those eligible employees who elect to participate in the voluntary enhanced retirement program.

Approximately 3,500 of the Company's 15,700 employees are eligible to participate in the voluntary enhanced retirement program. The total cost-management initiative charges could change significantly depending upon how many eligible employees elect early retirement under the voluntary enhanced retirement program and the salary, service years and age of such employees (See Note 24).

Energy Delivery Capitalization Practice The Company has reviewed its capitalization policies for its Energy Delivery business units in PEC and PEF. That review indicated that in the areas of outage and emergency work not associated with major storms and allocation of indirect costs, both PEC and PEF should revise the way that they estimate the amount of capital costs associated with such work. The Company has implemented such changes effective January 1, 2005, which include more detailed classification of outage and emergency work and result in more precise estimation and a process of retesting accounting estimates on an annual basis. As a result of the changes in accounting estimates for the outage and emergency work and indirect costs, a lesser proportion of PEC's and PEF's costs will be capitalized on a prospective basis. The Company estimates that the combined impact for both utilities in 2005 will be that approximately $55 million of costs that would have been capitalized under the previous policies will be expensed. Pursuant to SFAS No.

71, PEC and PEF have informed the state regulators having jurisdiction over them of this change and that the new estimation process will be implemented effective January 1, 2005. The Company has also requested a method change from the IRS.

24

Progress Energy Annual Report 2004 Progress Energy Carolinas Electric PEC Electric contributed segment profits of $464 million,

$515 million and $513 million in 2004, 2003 and 2002, respectively. The decrease in profits for 2004 as compared to 2003 is primarily due to higher O&M charges and lower wholesale revenues partially offset by the favorable impact of weather, increased revenues from customer growth and a reduction in investment losses and impairment charges compared to the prior year. The slight increase in profits in 2003, when compared to 2002, was primarily due to customer growth, strong wholesale sales during the first quarter of 2003, lower Service Company allocations and lower interest costs, which were offset by unfavorable weather in 2003, higher depreciation expense and increased benefit-related costs.

REVENUES PEC Electric's electric revenues and the percentage change by year and by customer class are as follows:

(in millions]

Customer Class 2004 % Change 2003 % Change 2002 Residential

$1,324 5.2 S1,259 1.5 S1,241 Commercial 888 4.5 850 2.2 832 Industrial 659 3.6 636 (1.4) 645 Governmental 82 3.8 79 1.3 78 Total retail revenues 2.953 4.6 2,824 1.0 2,796 Wholesale 575 (16.3) 687 5.5 651 Unbilled 10 (6) 15 Miscellaneous 90 7.1 84 9.1 77 Total electric revenues

$3,628 1.1 $3,589 1.4 $3,539 revenues was due primarily to increased retail revenues of $35 million as a result of favorable weather, with cooling degree days 16% above prior year. Retail customer growth contributed an additional $55 million in revenues in 2004. PEC Electric's retail customer base increased as approximately 26,000 new customers were added in 2004.

The increase in retail revenues was offset partially by lower wholesale revenues. Wholesale revenues decreased $86 million when compared to $393 million in 2003. The decrease in PEC Electric's wholesale revenues in 2004 from 2003 is primarily the result of reduced excess generation sales. Revenues for 2003 included strong sales to the northeastern United States as a result of favorable market conditions. In addition, lower contracted capacity compared to 2003 further reduced wholesale revenues.

The remaining reduction in wholesale revenues is attributable to an inelastic power market While the cost of fuel continues to rise, the power market prices have not responded as quickly to the fuel increases. The differential between fuel cost and market price limited opportunities to enter the market. PEC monitors its wholesale contract portfolio on a regular basis. During 2003 and 2004, several contracts expired or were renegotiated at lower prices. Due to the slightly depressed wholesale market and increased competition, this trend could continue as contracts are renewed in the upcoming years. The expiration and renegotiation of wholesale contracts is a normal business activity. PEC actively manages its portfolio by seeking to sign new contracts to replace expiring arrangements.

PEC Electric's revenues, excluding recoverable fuel revenues of $901 million and S851 million in 2003 and 2002, respectively, were unchanged from 2002 to 2003. Milder weather in 2003, when compared to 2002, accounted for a $61 million retail revenue reduction. While heating degree days in 2003 were 4.8% above prior year, cooling degree days were 25.2% below prior year. However, the more severe weather in the northeast region of the United States during the first quarter of 2003 drove a

$19 million increase in wholesale revenues. Additionally, retail customer growth in 2003 generated an additional S42 million of revenues in 2003. PEC Electric's retail customer base increased as approximately 23,000 new customers were added in 2003.

Downturns in the economy during 2002 and 2003 impacted energy usage within the industrial customer class. Total industrial revenues, excluding fuel revenues, declined during 2003 when compared to 2002 by $13 million, as sales to industrial customers decreased due to a general industrial slowdown. Decreases in the textile industry and the chemical industry were among the largest. This PEC Electric's electric energy sales and the percentage change by year and by customer class are as follows:

(in thousands of MM)

Customer Class 2004 % Change 2003 % Change 2002 Residential 16.003 4.7 15,283 0.3 15,239 Commercial 13,019 3.7 12,557 0.7 12,468 Industrial 13,036 2.3 12,749 (2.6) 13,089 Governmental 1.431 1.6 1,408 (2.0) 1,437 Total retail energy sales 43,489 3.6 41,997 (0.6) 42,233 Wholesale 13722 (14.8) 15,518 3.3 15,024 Unbilled 91 (44) 270 Total MWh sales 56,802 1.2 57,471 (0.1) 57,527 PEC Electric's revenues, excluding recoverable fuel revenues of $933 million and $901 million for 2004 and 2003, respectively, increased $7 million. The increase in 25

V Managements Discussion and Analysis declining trend leveled out in 2004 as industrial sales increased in the primary and fabricated metal, chemicals, lumber and food industries. Industrial sales growth is expected to be flat or very low as expired textile quotas are expected to lower textile sales and balance gains in other industries.

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

Fuel and purchased power expenses were $1.137 billion for 2004, which represents a $16 million increase compared to the same period in the prior year. Fuel used in electric generation increased SII million to $836 million compared to the prior year. This increase is due to an increase in fuel used in generation of $78 million due to higher fuel costs and a change in generation mix. Higher fuel costs are being driven primarily by an increase in coal prices. Outages at several nuclear facilities during the year resulted in increased combustion turbine generation, which has a higher average fuel cost The increase in fuel used in generation is offset by a reduction in deferred fuel expense as a result of the underrecovery of current period fuel costs. Purchased power expenses increased $5 million to

$301 million compared to prior year. The increase in purchased power is due primarily to an increase in price.

Fuel and purchased power expenses were $1.121 billion for 2003, which represents a $22 million increase compared to the same period in the prior year. Fuel used in electric generation increased $73 million in 2003, compared to prior year, primarily due to higher prices incurred for coal, oil and natural gas used during generation. Costs for fuel per Btu increased for all three commodities during the year.

Purchased power expense decreased $51 million in 2003, compared to $347 million in 2002, mainly due to a decrease in the volume purchased as milder weather reduced system requirements and due to the renegotiation at more favorable terms of two contracts that expired during the year.

Operations and Maintenance (O&M)

O&M expenses were $871 million for 2004, which represents an $89 million increase compared to 2003.

This increase is driven primarily by higher outage costs and storm costs in 2004 than in the prior year. Outages increased O&M costs by $29 million primarily due to an increase in the number and scope of nuclear plant outages in 2004. In addition, costs associated with restoration efforts after severe storms increased O&M expense $18 million. Storm costs for 2004 included costs related to an ice storm and Hurricanes Charley and Ivan in the North Carolina service territory. PEC Electric also incurred storm costs in 2003; however, the Company requested and the NCUC approved deferral of these costs. The Company did not seek to defer costs associated with the ice storm, which hit the North Carolina service territory, and Hurricanes Charley and Ivan. O&M expenses also increased $9 million due to higher salary-and benefit-related expenditures. In addition, O&M charges in the prior year were favorably impacted by $16 million related to the retroactive reallocation of Service Company costs.

O&M expenses were $782 million in 2003, which represents a $20 million decrease compared to 2002.

O&M expense in 2002 included severe storm costs of

$27 million. Those costs, along with lower 2003 Service Company allocations of $16 million, due to the change in allocation methodology as required by the SEC in early 2003, are the primary reasons for decreased O&M expenses. This decrease was partially offset by higher benefit-related costs of $21 million. PEC Electric incurred O&M costs of S25 million related to three severe storms in 2003. The NCUC allowed deferral of $24 million of these storm costs. These costs are being amortized over a five-year period, beginning in the months the expenses were incurred. PEC Electric amortized $3 million of these costs in 2003, which is included in depreciation and amortization expense on the Consolidated Income Statement Depreciation and Amortization Depreciation and amortization expense was $570 million for 2004, which represents an $8 million increase compared to 2003. This increase is attributable primarily to the impact of the NC Clean Air legislation. PEC Electric recorded the maximum amortization allowed under the legislation in 2004. NC Clean Air amortization increased

$100 million to $174 million in 2004 compared to $74 million in 2003. Depreciation expense also increased $9 million for assets placed in service. These increases were partially offset by a reduction in depreciation expense related to depreciation studies filed during the year.

26

Progress Energy Annual Report 2004 During 2004, PEC met the requirements of both the NCUC and the SCPSC for the implementation of depreciation studies that allowed the utility to reduce the rates used to calculate depreciation expense. The annual reduction in depreciation expense is approximately $82 million compared to 2003. The reduction is due primarily to extended lives at each of PEC's nuclear units. The new rates became effective January 2004.

Depreciation and amortization increased $38 million in 2003, compared to $524 million in 2002. Depreciation and amortization increased $74 million related to the 2003 impact of the NC Clean Air legislation and decreased $53 million related to the 2002 impact of the accelerated nuclear amortization program. Both programs are approved bythe state regulatory agencies and are discussed further at Notes 8B and 22. In addition, depreciation increased

$19 million due to additional assets placed into service.

Progress Energy Florida PEF contributed segment profits of $333 million,

$295 million and $323 million in 2004, 2003 and 2002, respectively. Profits for 2004 increased due to favorable customer growth, a reduction in the provision for revenue sharing, favorable wholesale revenues, the additional return on investment on the Hines Unit 2 and reduced O&M expenses. These items were partially offset by unfavorable weather, a reduction in revenues related to the hurricanes, increased interest expense and increased depreciation expense from assets placed in service. The decrease in profits in 2003, when compared to 2002, was primarily due to the impact of the 2002 rate case stipulation, higher benefit-related costs primarily related to higher pension expense, higher depreciation and the unfavorable impact of weather. These amounts were partially offset by continued customer growth and lower interest charges.

Taxes Other than on Income Taxes other than on income were $173 million for 2004, which represents an $11 million increase compared to the prior year. This increase is due primarily to an increase in gross receipts taxes of $8 million related to an increase in revenues and a 2004 adjustment related to the prior year. The remaining variance in other taxes is due to an increase in property taxes of $7 million due to higher property appraisals partially offset by a reduction in payroll taxes of $4 million.

Taxes other than on income were $162 million in 2003, which represents a $4 million increase compared to prior year. This increase is due to an increase in property taxes and payroll taxes of $2 million each.

Interest Expense Net interest expense was $192 million, $197 million and S212 million in 2004, 2003 and 2002, respectively. Declines in interest expense in 2003 resulted from reduced short-term debt and refinancing certain long-term debt with lower interest rate debt.

Income Tax Expense Income tax expense was $237 million, $238 million and

$237 million in 2004, 2003 and 2002, respectively. In 2004, 2003 and 2002, S22 million, $24 million and $35 million, respectively, of the tax benefitthatwas previously held at the Company's holding company was allocated to PEC Electric. As required by an SEC order issued in 2002, certain holding company tax benefits are allocated to profitable subsidiaries. Other fluctuations in income taxes are primarily due to changes in pre-tax income.

In 2002, PEF's profits were affected by the outcome of the rate case stipulation, which included a one-time retroactive revenue refund, a decrease in retail rates of 9.25% (effective May 1, 2002), provisions for revenue sharing with the retail customer base, lower depreciation and amortization and increased service revenue rates (See Note 8C).

REVENUES PEF's electric revenues and the percentage change by year and by customer class, as well as the impact of the rate case settlement on revenue, are as follows:

(in millionsJ Customer Class 2004 % Change 2003 % Change 2002 Residential S1.806 6.8 $1,691 2.8 $1,645 Commercial 853 15.3 740 1.2 731 Industrial 254 16.0 219 3.8 211 Governmental 211 16.6 181 4.6 173 Revenue sharing refund (11)

(35)

(5)

Retroactive retail rate refund (35)

Total retail revenues 3.113 11.3 2,796 2.8 2,720 Wholesale 268 18.1 227 (1.3) 230 Unbilled 7

(2)

(3)

Miscellaneous 137 4.6 131 13.9 115 Total electric revenues

$3.525 11.8 $3,152 2.9 S3,062 27

V Management's Discussion and Analysis PEF's electric energy sales and the percentage change by year and by customer class are as follows:

(in thousands of MIM])

Customer Class 2004 % Change 2003 % Change 2002 Residential 19,347 (0.4) 19,429 3.6 18,754 Commercial 11,734 1.6 11,553 1.2 11,420 Industrial 4,069 1.7 4,000 4.3 3,835 Governmental 3,044 2.4 2,974 4.4 2,850 Total retail energy sales 38,194 0.6 37,956 3.0 36,859 Wholesale 5,101 18.0 4,323 3.4 4,180 Unbilled 358 233 5

Total MWh sales 43,653 2.6 42,512 3.6 41,044 PEFs revenues, excluding recoverable fuel and other pass-through revenues of $2.007 billion and $1.692 billion for 2004 and 2003, respectively, increased $58 million. This increase was due primarily to favorable customer growth, which increased revenues $34 million. PEF has 37,000 additional retail customers compared to prior year.

Revenues were also favorably impacted by a reduction in the provision for revenue sharing of $24 million. Results for 2003 included an additional refund of $18 million related to the 2002 revenue sharing provision as ordered by the Florida Public Service Commission (FPSC) in July 2003. In addition, improved wholesale sales increased revenues by$11 million. Included in fuel revenues is the recovery of depreciation and capital costs associated with the Hines Unit 2, which was placed into service in December 2003 and contributed $36 million in additional revenues in 2004.

The recovery of the Hines Unit 2 costs through the fuel clause is in accordance with the 2002 rate stipulation (See Note 8C). These increases were partially offset by the reduction in revenues related to customer outages for Hurricanes Charley, Frances and Jeanne of approximately

$12 million and the impact of milderweather in the current year of $10 million.

PEF's revenues, excluding recoverable fuel and other pass-through revenues of S1.692 billion and $1.602 billion in 2003 and 2002, respectively, were unchanged from 2002 to 2003. Revenues were favorably impacted by $49 million in 2003, primarily as a result of customer growth (approximately 36,000 additional customers). In addition, other operating revenues were favorable by$16 million due primarily to higher wheeling and transmission revenues and higher service charge revenues (resulting from increased rates allowed under the 2002 rate settlement).

These increases were offset by the negative impact of the rate settlement, which decreased revenues, lower wholesale sales and the impact of unfavorable weather.

The provision for revenue sharing increased

$12 million in 2003 compared to the $5 million provision recorded in 2002. Revenues in 2003 were also impacted by the final resolution of the 2002 revenue sharing provisions, as the FPSC issued an order in July 2003 that required PEF to refund an additional $18 million to customers related to 2002. The 9.25% rate reduction from the settlement accounted for an additional $46 million decline in revenues.

The 2003 impact of the rate settlement was partially offset by the absence of the prior year interim rate refund of

$35 million. Lower wholesale revenues (excluding fuel revenues) of $17 million and the $8 million impact of milder weather also reduced base revenues during 2003.

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

Fuel and purchased power expenses were $1.742 billion in 2004, which represents a $306 million increase compared to 2003. This increase is due to increases in fuel used in electric generation and purchased power expenses of

$305 million and $1 million, respectively. Higher system requirements and increased fuel costs in the currentyear account for $87 million of the increase in fuel used in electric generation. The remaining increase is due to the recovery of fuel expenses that were deferred in the prior year, partially offset by the deferral of current year underrecovered fuel expenses. In November 2003, the FPSC approved PEF's request for a cost adjustment in its annual fuel filing due to the rising costs of fuel. The new rates became effective January 2004.

Fuel used in generation and purchased power expenses were $1.436 billion in 2003, which represents an

$87 million increase compared to the prior year. Higher costs to generate electricity and higher purchased power costs as a result of an increase in volume due to system requirements and higher natural gas prices resulted in a $229 million increase partially offset by the deferral of 2003 underrecovered fuel and purchased power expense of $142 million.

28

Progress Energy Annual Report 2004 Operations and Maintenance (O&M)

O&M expenses were $630 million in 2004, which represents a $10 million decrease when compared to the prior year. This decrease is primarily related to favorable benefit-related costs of $16 million, primarily due to lower pension costs, which resulted from improved pension asset performance.

O&M expenses were $640 million in 2003, which represents a $49 million increase when compared to the prior year. The increase is largely related to increases in certain benefit-related expenses of $36 million, which consisted primarily of higher pension expense of

$27 million and higher operational costs related to the Crystal River Unit 3 nuclear outage and plant maintenance.

Depreciation and Amortization Depreciation and amortization expense was $281 million for 2004, which represents a decrease of $26 million when compared to the prior year, primarily due to the amortization of the Tiger Bay regulatory asset in the prior year. The Tiger Bay regulatory asset, for contract termination costs, was recovered pursuant to an agreement between PEF and the FPSC that was approved in 1997. The amortization of the regulatory asset was calculated using revenues collected underthe fuel adjustment clause; as such, fluctuations in this expense did not have an impact on earnings. During 2003, Tiger Bay amortization was $47 million. The Tiger Bay asset was fully amortized in September 2003. The decrease in Tiger Bay amortization was partially offset by additional depreciation for assets placed in service, including depreciation for Hines Unit 2, of approximately

$9 million. This depreciation expense is being recovered through the fuel cost recovery clause as allowed by the FPSC. See discussion of the return on Hines 2 in the revenues analysis above.

Depreciation and amortization was S307 million in 2003, which represents an increase of $12 million when compared to 2002. Depreciation increased primarily as a result of additional assets being placed into service that were partially offset by lower amortization of the Tiger Bay regulatory asset of $2 million, which was fully amortized in September 2003.

Taxes Other than on Income Taxes other than on income were $254 million in 2004, which represents an increase of $13 million compared to the prior year. This increase is due to increases in gross receipts and franchise taxes of $8 million and $7 million, respectively, related to an increase in revenues and an increase in property taxes of $5 million due to increases in property placed in service and tax rates. These increases were partially offset by a reduction in payroll taxes of $7 million.

Taxes other than on income were $241 million in 2003, which represents an increase of $13 million compared to prior year. This increase was due to increases in payroll taxes of $10 million and increases in gross receipts and franchise taxes of $4 million combined.

Interest Expense Interest charges, net were $114 million in 2004, which represents an increase of $23 million compared to the prior year. Interest charges, net were $91 million in 2003, which represents a $15 million decrease compared to the prior year. The fluctuations were primarily due to interest costs in 2003 being favorably impacted by the reversal of interest expense due to the resolution of certain tax matters.

Income Tax Expense Income tax expense was $174 million, $147 million and

$163 million in 2004, 2003 and 2002, respectively. In 2004, 2003 and 2002, $14 million, $13 million and $20 million, respectively, of the tax benefitthatwas previously held at the Company's holding company was allocated to PEF. As required by an SEC order issued in 2002, certain holding company tax benefits are allocated to profitable subsidiaries. Other fluctuations in income taxes are primarily due to changes in pre-tax income.

Diversified Businesses The Company's diversified businesses consist of the Fuels segment, the CCO segment and the Rail Services segment.

Fuels The Fuels' segment operations include synthetic fuel production, natural gas production, coal extraction and terminal operations. Beginning in the fourth quarter of 2003, the Company ceased recording portions of Fuels' segment operations, primarily synthetic fuel facilities, one month in arrears. As a result, earnings for the year ended December 31, 2003, included 13 months of operations, resulting in a net income increase of

$2 million for the year.

29

V Managements Discussion and Analysis The following summarizes Fuels' segment profits:

(in millions) 2004 2003 2002 Synthetic fuel operations

$91 S205

$156 Natural gas operations 85 34 10 Coal fuel and other operations 4

(4) 10 Segment profits

$180 S235

$176 SYNTHETIC FUEL OPERATIONS The production and sale of synthetic fuel generate operating losses, but qualify for tax credits under Section 29 of the Code, which more than offset the effect of such losses (See Note 23E).

The operations resulted in the following losses (prior to tax credits):

tin millions) 2004 2003 2002 Tons sold 8.3 12.4 11.2 After-tax losses (excluding tax credits)

$(124)

S(141)

S(135)

Tax credits 215 346 291 Net profit

$91 S205

$156 The Company's synthetic fuel production levels and the amount of tax credits it can claim each year are a function of the Company's projected consolidated regular federal income tax liability. Synthetic fuel operations' net profits decreased in 2004 as compared to 2003 due primarilyto a decrease in synthetic fuel production and an increase in operating expenses in 2004. The Company's total synthetic fuel production of approximately eight million tons in 2004 is down compared to 2003 production levels of approximately 12 million tons as a result of hurricane costs, which reduced the Company's projected 2004 regular tax liability and its corresponding ability to record tax credits from its synthetic fuel production. In addition, earnings in 2003 include a S13 million favorable tax credit true-up related to 2002.

As of September 30, 2004, the Company anticipated an ability to record approximately five million tons of synthetic fuel production based on the Company's projected regular tax liability for 2004. This estimate was based upon the Company's projected casualty loss as a result of the storms. Therefore, the Company recorded a charge of

$79 million in the third quarter for tax credits associated with approximately 2.7 million tons sold during the year that the Company anticipated it would not be able to use.

On November 2, 2004, PEF filed a petition with the FPSC to recover $252 million of storm costs plus interest from customers over a two-year period. Based on a reasonable expectation at December 31,2004, that the FPSC will grant the requested recovery of the storm costs, the Company's loss from the casualty is less than originally anticipated.

Accordingly, as of December 31, 2004, the Company's anticipated 2004 tax liability supported credits on approximately eight million tons. Therefore, the Company recorded tax credits of $90 million for the quarter ended December 31, 2004, for tax credits associated with approximately three million tons sold during the year that the Company now anticipates can be used. As of December 31, 2004, the Company anticipates that approximately S7 million of tax credits associated with approximately 0.2 million tons sold during the year could not be used (See Note 23E). The Company ceased operations at its Earthco facilities for the last three months of 2004 due to the decrease in the Company's projected 2004 tax liability, and these facilities were restarted in January 2005.

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 PEFs petition for the recovery of storm costs in 2005, there could be a material impact on the amount of 2005 synthetic fuel production and results of operations.

Synthetic fuels' net profits for 2003 increased as compared to 2002 due to higher sales, improved margins and a higher tax credit per ton. The 2003 tax credits also include a $13 million favorable true-up from 2002.

Additionally, synthetic fuels' results in 2003 include 13 months of operations for some facilities. Prior to the fourth quarter of 2003, results of these synthetic fuels' operations had been recognized one month in arrears.

The net impact of this action increased net income by

$2 million for the year.

NATURAL GAS OPERATIONS Natural gas operations generated profits of $85 million,

$34 million and $10 million for the years ended December 31, 2004, 2003 and 2002, respectively. Natural gas profits increased $51 million in 2004 compared to 2003. This increase is attributable primarily to the gain recognized on the sale of gas assets during the year. In December 2004, the Company sold certain gas-producing properties and related assets owned by Winchester Production Company, Ltd. (North Texas gas operations).

Because the sale significantly altered the ongoing relationship between capitalized costs and remaining proved reserves, under the full-cost method of accounting the pre-tax gain of S56 million ($31 million net of taxes) was recognized in earnings rather than as a reduction of the basis of the Company's remaining oil and gas properties. In addition, an increase in 30

Progress Energy Annual Report 2004 production, coupled with higher gas prices in 2004, contributed to the increased earnings in 2004 as compared to 2003. Production levels increased resulting from the acquisition of North Texas Gas in late February 2003 and increased drilling in 2004. Volume and prices have increased 21% and 16%, respectively, for 2004 compared to 2003.

Natural gas profits increased to $34 million in 2003 compared to $10 million in 2002. The increase in production and price resulting from the acquisitions of Westchester in 2002 (renamed Winchester Energy in 2004) and NorthTexas Gas in the first quarter of 2003 drove increased revenue and earnings in 2003 compared to 2002. In October 2003, the Company completed the sale of certain gas-producing properties owned by Mesa Hydrocarbons, LLC (Mesa). See Notes 5B and 4D to the Progress Energy Consolidated Financial Statements for discussions of the North Texas Gas acquisitions and the Mesa disposition.

The following table summarizes the production and revenues of the natural gas operations by location:

2004 2003 2002 Production in Bcf equivalent EastTexas/LAgasoperations 20 13 6

North Texas gas operations 10 7

Mesa 5

7 Total production 30 25 13 Revenues in millions EastTexaslLAgasoperations

$110

$65 S24 North Texas gas operations 52 38 Mesa 13 15 Total revenues

$162

£116

£39 Gross margin In millions of S

$126

£91

£29 As a % of revenues 78%

78%

74%

of $10 million in 2004. Corporate costs in the prior year included $4 million of favorability related to the reduction of an environmental reserve (See Note 22). The remaining unfavorability in corporate costs is attributable to increased interest expense related to unresolved tax matters and higher professional fees.

Coal fuel and other operations' profits decreased

$9 million from 2002 to 2003. The decrease is due primarily to the recording of an impairment of certain assets at the Kentucky May coal mine totaling $11 million after-tax. The decrease in profits is also due to the impact of the retroactive Service Company allocation in 2003.

The Company is exploring strategic alternatives regarding the Fuels' coal mining business, which could include divesting these assets. As of December 31, 2004, the carrying value of long-lived assets of the coal mining business was $66 million. The Company cannot currently predict the outcome of this matter.

Competitive Commercial Operations CCO generates and sells electricity to the wholesale market from nonregulated plants. These operations also include marketing activities. The following summarizes the annual revenues, gross margin and segment profits from the CCO plants:

(in millions) 2004 2003 2002 Total revenues

$240 S170 S92 Gross margin In millions ofS

$158 S141

£83 As a % of revenues 66%

83%

90%

Segment profits (losses)

$14)

S20

£27 COAL FUEL AND OTHER OPERATIONS Coal fuel and other operations generated profits of

$4 million, losses of $4 million and profits of $10 million for the years ended December 31, 2004, 2003 and 2002, respectively. The increase in profits for 2004 is primarily due to higher volumes and margins for coal fuel operations of $16 million after-tax. In addition, coal results in 2003 included the recording of an impairment of certain assets at the Kentucky May coal mine totaling

$11 million after-tax. This favorability was offset by a reduction in profits of S7 million after-tax for fuel transportation operations related to the waterborne transportation ruling by the FPSC (See Note 8C). Profits were also negatively impacted by higher corporate costs CCO's operations generated segment losses of $4 million in 2004 compared to segment profits of $20 million in 2003.

Results for 2004 were favorably impacted by increased gross margin, which was more than offset by higher fixed costs and costs associated with the extinguishment of debt Revenues increased for 2004 due to increased revenues from marketing and tolling contracts offset by a termination payment received on a marketing contract in 2003. Expenses forthe cost of fuel and purchased powerto supply marketing contracts partially offset the increased revenues netting to an increase in gross margin for 2004 as compared to 2003. Fixed costs increased $16 million pre-tax from additional depreciation and amortization on plants placed into service in 2003 and from an increase in interest expense of $13 million pre-tax due primarily to interest no longer being capitalized due to the completion of construction in the prior year. In addition, plant operating expenses increased $12 million pre-tax primarily 31

V Management's Discussion and Analysis due to higher gas transportation service charges, which increased over prior year due to a full period of expenses being reflected in currentyear results. CCO results for 2004 also include losses of $15 million pre-tax associated with the extinguishment of a debt obligation. CCO terminated the Genco financing arrangement in December 2004. The

$15 million pre-tax loss is comprised of a $9 million write-off of remaining unamortized debt issuance costs and a

$6 million realized loss on exiting the related interest rate hedge. Expenses were favorably impacted by a reduction in Service Company allocations. Results for 2003 were negatively impacted by the retroactive reallocation of Service Company costs of $3 million ($2 million after-tax).

CCO's operations generated segment profits of $20 million in 2003 compared to segment profits of $27 million in 2002.

The increase in revenue for 2003 when compared to 2002 is primarily due to increased contracted capacity on newly constructed plants, energy revenue from a new, full-requirements power supply contract and a tolling agreement termination payment received during the first quarter. Generating capacity increased from 1,554 MW at December 31, 2002, to 3,100 MW at December 31, 2003, with the Effingham, Rowan Phase 2 and Washington plants being placed in service in 2003. In the second quarter of 2003, PVI acquired from Williams Energy Marketing and Trading a full-requirements power supply agreement with Jackson Electric Membership Corporation in Georgia for $188 million, which resulted in additional revenues of $21 million when compared to the same periods in 2002. The revenue increases related to higher volumes were partially offset by higher depreciation costs of $22 million, increased interest charges of $16 million and other fixed charges.

The Company has contracts for its planned production capacity, which includes callable resources from the cooperatives, of approximately 77%

for

2005, approximately 81% for 2006 and approximately 75% for 2007. The Company continues to seek opportunities to optimize its nonregulated generation portfolio.

Rail Services Rail Services' (Rail) operations represent the activities of Progress Rail and include railcar and locomotive repair, track-work, rail parts reconditioning and sales, scrap metal recycling, railcar leasing and other rail-related services.

Rail contributed segment profits of $16 million for 2004 compared with segment losses of $1 million and

$42 million for the years ended December 31, 2003, and 2002, respectively. Results in 2004 were favorably impacted by the strong scrap metal market in 2004.

Revenues were $1.131 billion in 2004, which represents an increase of $284 million compared to prior year. This increase is due primarily to increased volumes and higher prices in recycling operations and in part to increased production and sales in locomotive and railcar services and engineering and track services.Tonnage for recycling operations is up approximately 35% on an annualized basis compared to 2003. The increase in tonnage, coupled with an increase in the average index price of approximately 80%, accounts for the significant increase in revenues year over year. The American Metal Market index price for #1 railroad heavy melt (which is used as the index for buying and selling of railcars) has increased to $191 as of December 31, 2004, from $106 as of December 31,2003. Cost of goods sold was $990 million in 2004, which represents an increase of $252 million compared to the prior year. The increase in costs of goods sold is due to increased costs for inventory, labor and operations as a result of the increased volume in the recycling operations, locomotive and railcar services and engineering and track services. In addition, results in 2003 were negatively impacted by the retroactive reallocation of Service Company costs of $3 million after-tax. The favorability related to the reallocation was offset by an increase in general and administrative costs in 2004 related primarily to higher professional fees associated with divestiture efforts. See discussion below.

Rail's operations generated segment losses of $1 million in 2003 compared to segment losses of $42 million in 2002.

The reduction in losses in 2003 compared to 2002 is due primarily to an impairment charge recorded in 2002. The net loss in 2002 includes a $40 million after-tax estimated impairment of assets held for sale related to Railcar Ltd.,

a leasing subsidiary of Progress Rail (See Note 40).

Excluding the impairment recorded in 2002, profits for Rail were flat year over year 2003 compared to 2002.

In February 2005, Progress Energy signed a definitive agreement to sell its Progress Rail subsidiary to subsidiaries of One Equity Partners LLC for a sales price of $405 million. Proceeds from the sale are expected to be used to reduce debt. See Note 24 for more information.

Corporate & Other Corporate and Other consists of the operations of Progress Energy Holding Company (the holding company), Progress Energy Service Company and other consolidating and nonoperating entities. Corporate and Other also includes other nonregulated business areas including the operations of SRS and the telecommunication operations.

32

Progress Energy Annual Report 2004 OTHER NONREGULATED BUSINESS AREAS Progress Energy's other business areas include the operations of SRS and the telecommunications operations. SRS was engaged in providing energy services to industrial, commercial and institutional customers to help manage energy costs primarily in the southeastern United States. During 2004, SRS sold its subsidiary, Progress Energy Solutions (PES). With the disposition of PES, the Company exited this business area. Telecommunication operations provide broadband capacity services, dark fiber and wireless services in Florida and the eastern United States. In December 2003, PTC and Caronet, both wholly owned telecommunication subsidiaries of Progress Energy, and EPIK, a wholly owned subsidiary of Odyssey, contributed substantially all of their assets and transferred certain liabilities to PT LLC, a subsidiary of PTC. The accounts of PT LLC have been included in the Company's Consolidated Financial Statements since the transaction date. See additional discussion on the telecommunication business combination in Note 5A.

Other nonregulated business areas contributed segment losses of $38 million compared to losses of $24 million for the years ended December 31, 2004, and 2003, respectively. SRS recorded a net loss of $27 million for 2004 compared to a net loss of S6 million for 2003. The increased loss compared to the prior year is due primarily to the recording of the litigation settlement reached with San Francisco United School District (the District) related to civil proceedings. In June 2004, SRS reached a settlement with the District that settled all outstanding claims for approximately $43 million pre-tax ($29 million after-tax). The reduction in earnings due to the settlement was offset partially by a gain recognized on the sale of Progress Energy Solutions.

Telecommunication operations recorded a net loss of $5 million in 2004 compared to a net profit of $2 million in 2003. The increase in losses compared to prior year is due to an increase in fixed costs, mainly depreciation expense, and professional fees related to the merger with EPIK. The increased losses at SRS and telecommunication operations were offset partially by a reduction in losses at the nonutility subsidiaries of PEC. The nonutility subsidiaries of PEC contributed segment losses of

$6 million and $18 million for the years ended December 31, 2004, and 2003, respectively. Included in the 2003 segment losses is an investment impairment of $6 million after-tax on the Affordable Housing portfolio held by the nonutility subsidiaries of PEC (See Note 10B). A reduction in investment losses accounted for the remaining favorability compared to prior year.

Other nonregulated business areas contributed segment losses of $24 million in 2003 compared to $250 million for the year ended December 31, 2002. The 2002 segment losses include an asset impairment and other charges in the telecommunications business of $225 million after-tax. See discussion of impairments at Note 10 of the Consolidated Financial Statements.

CORPORATE SERVICES Corporate Services (Corporate) includes the operations of the holding company, Progress Energy Service Company and other consolidating summarized below:

and nonoperating entities, as Income (Expense) (in millions) 2004 Change 2003 Change 2002 Other interest expense

$1270)

$15 S(285)

S$IO) S(275)

Contingent value obligations 9

18 (9)

(37) 28 Tax reallocation (37) 1 (38) 18 (56)

Otherincometaxes 102 (22) 124 11 113 Other income (expense)

(2) 19 (21)

(16) 15)

Segment loss

$1198)

$31 $(229)

S134) S(195)

The other interest expense decrease for 2004 compared to 2003 is partially due to the repayment of a $500 million unsecured note by the Holding Company on March 1,2004, which reduced interest expense by $27 million pre-tax for 2004. This reduction was offset by interest no longer being capitalized due to the completion of construction in the CCO segment in 2003. Approximately$10 million ($6 million after-tax) was capitalized in 2003. No interest expense was capitalized during 2004. Interest expense increased

$10 million in 2003 compared to 2002 due to a decrease of

$9 million in the amount of interest capitalized related to the construction of plants by CCO which was completed in 2003.

Progress Energy issued 98.6 million contingent value obligations (CVOs) in connection with the acquisition of FPC in 2000. Each CVO represents the right to receive contingent payments based on the performance of four synthetic fuel facilities owned by Progress Energy. The payments, if any, are based on the net after-tax cash flows the facilities generate. At December 31, 2004, 2003 and 2002, the CVOs had a fair market value of approximately $13 million, $23 million and $14 million, respectively. Progress Energy recorded unrealized losses of S9 million for 2003 and an unrealized gain of

$9 million and $28 million for 2004 and 2002, respectively, to record the changes in fair value of CVOs, which 33

V Management's Discussion and Analysis had average unit prices of SO.14, $0.23 and $0.14 at December 31, 2004, 2003 and 2002, respectively.

Progress Energy and its affiliates file a consolidated federal income tax return. The consolidated income tax of Progress Energy is allocated to subsidiaries in accordance with the Intercompany Income Tax Allocation Agreement (Tax Agreement). The Tax Agreement provided an allocation that recognizes positive and negative corporate taxable income. The Tax Agreement provides for an equitable method of apportioning the carry over of uncompensated tax benefits. Progress Energy tax benefits not related to acquisition interest expense are allocated to profitable subsidiaries, beginning in 2002, in accordance with a Public Utility Holding Company Act of 1935, as amended (PUHCA) order.

Other income taxes benefit decreased for 2004 compared to 2003 due primarily to increased taxes booked at the Holding Company of $21 million. Income taxes increased an additional $9 million at the Holding Company as a result of a reserve booked related to identified state tax deficiencies. Other income taxes benefit decreased for 2003 compared to 2002 primarily for the tax allocation to the profitable subsidiaries. Other fluctuations in income taxes are primarily due to changes in pre-tax income.

Discontinued Operations In 2002, the Company approved the sale of NCNG to Piedmont Natural Gas Company, Inc. As a result, the operating results of NCNG were reclassified to discontinued operations for all reportable periods. In September 2003, Progress Energy completed the sale of NCNG and ENCNG for net proceeds of approximately

$450 million in September 2003. Progress Energy incurred a loss from discontinued operations of $8 million for 2003 compared with a loss of $24 million for 2002. During the year ended December 31, 2004, the Company recorded a reduction to the loss on the sale of NCNG of approximately

$6 million related to deferred taxes (See Note 4E).

Cumulative Effect of Accounting Changes In 2003, Progress Energy recorded adjustments for the cumulative effects of changes in accounting principles due to the adoption of several new accounting pronouncements. These adjustments totaled to a S21 million loss after-tax,which was due primarily to new Financial Accounting Standards Board (FASB) guidance related to the accounting for certain contracts. This guidance discusses whether the pricing in a contract that contains broad market indices qualifies for certain exceptions that would not require the contract to be recorded at its fair value. PEC Electric had a purchase power contract with Broad River LLC that did not meet the criteria for an exception, and a negative fair value adjustmentwas recorded in 2003for$23 million after-tax (See Note 18A).

APPLICATION OF CRITICAL ACCOUNTING POLICIES AND ESTIMATES The Company prepared its Consolidated Financial Statements in accordance with accounting principles generally accepted in the United States. In doing so, certain estimates were made that were critical in nature to the results of operations. The following discusses those significant estimates that may have a material impact on the financial results of the Company and are subject to the greatest amount of subjectivity. Senior management has discussed the development and selection of these critical accounting policies with the Audit Committee of the Company's Board of Directors.

Utility Regulation As discussed in Note 8, the Company's regulated utilities segments are subject to regulation that sets the prices (rates) the Company is permitted to charge customers based on the costs that regulatory agencies determine the Company is permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by a nonregulated company. This rate-making process results in deferral of expense recognition and the recording of regulatory assets based on anticipated future cash inflows. As a result of the changing regulatory framework in each state in which the Company operates, a significant amount of regulatory assets has been recorded. The Company continually reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines.

Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future. Additionally, the state regulatory agencies often provide flexibility in the manner and timing of the depreciation of property, nuclear decommissioning costs and amortization of the regulatory assets. Note 8 provides additional information related to the impact of utility regulation on the Company.

Asset Impairments As discussed in Note 10, the Company evaluates the carrying value of long-lived assets for impairment whenever indicators exist. Examples of these indicators include current period losses combined with a history of 34

Progress Energy Annual Report 2004 losses, or a projection of continuing losses, or a significant decrease in the market price of a long-lived asset group. If an indicator exists, the asset group held and used is tested for recoverability by comparing the carrying value to the sum of undiscounted expected future cash flows directly attributable to the asset group.

If the asset group is not recoverable through undiscounted cash flows or if the asset group is to be disposed of, an impairment loss is recognized for the difference between the carrying value and the fair value of the asset group. A high degree of judgment is required in developing estimates related to these evaluations and various factors are considered, including projected revenues and cost and market conditions.

Due to the reduction in coal production at the Kentucky May coal mine, the Company evaluated its long-lived assets in 2003 and recorded an impairment of $17 million before tax ($11 million after-tax). Fair value was determined based on discounted cash flows. During 2002, the Company recorded pre-tax long-lived asset impairments of

$305 million related to its telecommunications business. The fair value of these assets was determined considering various factors, including a valuation study heavily weighted on a discounted cash flow methodology and using market approaches as supporting information.

The Company continually reviews its investments to determine whether a decline in fair value below the cost basis is other than temporary. In 2003, PEC's affordable housing investment (AHI) portfolio was reviewed and deemed to be impaired based on various factors, including continued operating losses of the AHI portfolio and management performance issues arising at certain properties within the AHI portfolio. As a result, PEC recorded an impairment of $18 million on a pre-tax basis during 2003. PEC also recorded an impairment of

$3 million for a cost investment During 2002, the Company recorded pre-tax impairments to its cost method investment in Interpath of $25 million. The fair value of this investment was determined considering various factors, including a valuation study heavily weighted on a discounted cash flow methodology and using market approaches as supporting information. These cash flows included numerous assumptions, including the pace at which the telecommunications market would rebound. In the fourth quarter of 2002, the Company sold its remaining interest in Interpath for a nominal amount Under the full-cost method of accounting for oil and gas properties, total capitalized costs are limited to a ceiling based on the present value of discounted (at 10%) future net revenues using current prices, plus the lower of cost or fair market value of unproved properties. The ceiling test takes into consideration the prices of qualifying cash flow hedges as of the balance sheet date. If the ceiling (discounted revenues) is not equal to or greater than total capitalized costs, the Company is required to write-down capitalized costs to this level. The Company performs this ceiling test calculation every quarter. No write-downs were required in 2004, 2003 or 2002.

Goodwill As discussed in Note 9, effective January 1, 2002, the Company adopted FASB Statement No. 142, 'Goodwill and Other Intangible Assets,' which requires that goodwill be tested for impairment at least annually and more frequently when indicators of impairment exist The Company completed the initial transitional goodwill impairment test, which indicated that the Company's goodwill was not impaired as of January 1, 2002. The Company performed the annual goodwill impairment test for the CCO segment in the first quarters of 2004 and 2003, and the annual goodwill impairment test for the PEC Electric and PEF segments in the second quarters of 2004 and 2003, each of which indicated no impairment If the fair values for the utility segments were lower by approximately 10%, there still would be no impact on the reported value of their goodwill. The carrying amounts of goodwill at December 31, 2004, and 2003, for reportable segments PEC Electric, PEF and CCO, are $1,922 million,

$1,733 million and $64 million, respectively. In December 2003, $7 million in goodwill was acquired as part of Progress Telecommunications Corporation's partial acquisition of EPIK and was reported in the Corporate and Other segment The Company revised the preliminary EPIK purchase price allocation as of September 2004, and the $7 million of goodwill was reallocated to certain tangible assets acquired based on the results of valuations and appraisals.

Synthetic Fuels Tax Credits As discussed in Note 23E, Progress Energy, through the Fuels business unit, owns facilities that produce synthetic fuels as defined under the Internal Revenue Code. The production and sale of the synthetic fuels from these facilities qualifies for tax credits under Section 29 if certain requirements are satisfied, including a requirementthatthe synthetic fuels differs significantlyin chemical composition from the coal used to produce such synthetic fuels and that the fuel was produced from a facility placed in service before July 1, 1998. The amount of Section 29 credits thatthe Company is allowed to claim in any calendar year is limited by the amount of 35

V Management's Discussion and Analysis the Company's regular federal income tax liability.

Synthetic fuels tax credit amounts allowed but not utilized are carried forward indefinitely as deferred alternative minimum tax credits on the Consolidated Balance Sheets. All of Progress Energy's synthetic fuel facilities have received PLRs from the IRS with respectto their operations, although these do not address placed-in-service date determinations. The PLRs do not limit the production on which synthetic fuel credits may be claimed. The current Section 29 tax credit program expires at the end of 2007. These tax credits are subject to review by the IRS, and if Progress Energy fails to prevail through the administrative or legal process, there could be a significant tax liability owed for previously taken Section 29 credits, with a significant impact on earnings and cash flows. Additionally, the ability to use tax credits currently being carried forward could be denied. See further discussion in "OTHER MATTERS' below, and Note 23E.

Pension Costs As discussed in Note 17A, Progress Energy maintains qualified noncontributory defined benefit retirement (pension) plans. The Company's reported costs are dependent on numerous factors resulting from actual plan experience and assumptions of future experience.

For example, such costs are impacted by employee demographics, changes made to plan provisions, actual plan asset returns and key actuarial assumptions, such as expected long-term rates of return on plan assets and discount rates used in determining benefit obligations and annual costs.

Due to a slight decline in the market interest rates for high-quality (AAIAA) debt securities, which are used as the benchmark for setting the discount rate used to present value future benefit payments, the Company lowered the discount rate to 5.9% at December 31, 2004, which will increase the 2005 benefit costs recognized, all other factors remaining constant. Plan assets performed well in 2004, with returns of approximately 14%. That positive asset performance will result in decreased pension costs in 2005, all other factors remaining constant. Evaluations of the effects of these and other factors have not been completed, but the Company estimates that the total cost recognized for pensions in 2005 will be approximately $12 million to $20 million higher than the amount recorded in 2004.

The Company has pension plan assets with a fair value of approximately $1.8 billion at December 31, 2004. The Company's expected rate of return on pension plan assets is 9.25%. The Company reviews this rate on a regular basis. Under Statement of Financial Accounting Standards No. 87, 'Employer's Accounting for Pensions' (SFAS No. 87), the expected rate of return used in pension cost recognition is a long-term rate of return; therefore, the Company would adjust that return only if its fundamental assessment of the debt and equity markets changes or its investment policy changes significantly. The Company believes that its pension plans' asset investment mix and historical performance support the long-term rate of 9.25% being used. The Company did not adjust the rate in response to short-term market fluctuations such as the abnormally high market return levels of the latter 1990s, recent years' market declines and the market rebound in 2003 and 2004. A 0.25% change in the expected rate of return for 2004 would have changed 2004 pension costs by approximately $4 million.

Another factor affecting the Company's pension costs, and sensitivity of the costs to plan asset performance, is its selection of a method to determine the market-related value of assets, i.e., the asset value to which the 9.25%

expected long-term rate of return is applied. SFAS No. 87 specifies that entities may use either fair value or an averaging method that recognizes changes in fair value over a period not to exceed five years, with the method selected applied on a consistent basis from year to year.

The Company has historically used a five-year averaging method. When the Company acquired Florida Progress Corporation (Florida Progress) in 2000, it retained the Florida Progress historical use of fair value to determine market-related value for Florida Progress pension assets. Changes in plan asset performance are reflected in pension costs soonerunderthe fairvalue method than the five-year averaging method, and, therefore, pension costs tend to be more volatile using the fair value method. For example, in 2004 the expected return for assets subject to the averaging method was 2% lower than in 2003, whereas the expected return for assets subject to the fair value method was 24% higher than in 2003. Approximately 50% of the Company's pension plan assets is subjectto each of the two methods.

LIQUIDITY AND CAPITAL RESOURCES Overview Progress Energy is a registered holding company and, as such, has no operations of its own. The Company's primary cash needs at the holding company level are its common stock dividend and interest expense and principal payments on its S4.3 billion of senior unsecured debt The 36

Progress Energy Annual Report 2004 ability to meet these needs is dependent on the earnings and cash flows of its two electric utilities and nonregulated subsidiaries, and the ability of those subsidiaries to pay dividends or repay funds to Progress Energy.

Other significant cash requirements of the Company arise primarily from the capital-intensive nature of its electric utility operations and expenditures for its diversified businesses, primarily those of the Fuels segment.

The Company relies upon its operating cash flow, primarily generated by its two regulated electric utility subsidiaries, commercial paper and bank facilities, and its ability to access long-term debt and equity capital markets for sources of liquidity.

The majority of the Company's operating costs are related to its two regulated electric utilities, and a significant portion of these costs is recovered from customers through fuel and energy cost recovery clauses.

Other significant uses of liquid resources include debt interest and principal payments, capital expenditures and dividends on preferred and common stock.

As a registered holding company under PUHCA, Progress Energy obtains approval from the SEC for the issuance and sale of securities as well as the establishment of intercompany extensions of credit (utility and nonutility money pools). PEC and PEF participate in the utility money pool, which allows the two utilities to lend and borrow between each other. A nonutility money pool allows Progress Energy's nonregulated operations to lend and borrow funds among each other. Progress Energy can lend money to the utility and nonutility money pools but cannot borrow funds.

Cash from operations, asset sales and the issuance of common stock are expected to fund capital expenditures and common dividends for 2005. Any excess cash proceeds would be used to reduce debt To the extent necessary, short-and long-term debt may also be used as a source of liquidity.

The Company believes its internal and external liquidity resources will be sufficient to fund its current business plans.

The following discussion of the Company's liquidity and capital resources is on a consolidated basis.

Historical for 2004 as compared to 2003 and 2003 as compared to 2002 Cash Flows from Operations Cash from operations is the primary source used to meet operating requirements and capital expenditures. Net cash provided by operating activities from continuing operations forthe three years ending December31, 2004, 2003 and 2002 were $1.6 billion, $1.7 billion and

$1.6 billion, respectively.

Cash from operating activities for 2004 when compared with 2003 decreased $117 million, as the net result of the impact of hurricane costs, partially offset bythe impact of an underrecovery of fuel costs in 2003. The increase in cash from operating activities for 2003 when compared with 2002 is largely the result of improved operating results at PEC.

During the third quarter of 2004, four hurricanes struck significant portions of the Company's service territories, with the most significant impact on PEFs territory.

Restoration of the Company's systems from storm-related damage cost an estimated $398 million. PEC's costtotaled

$13 million, of which $12 million was charged to O&M and

$1 million was charged to capital. PEFs cost totaled

$385 million, of which S338 million was charged to Storm Damage Reserve pursuant to a regulatory order and

$47 million was charged to capital. On November 2, 2004, PEF filed a petition with the FPSC to recover $252 million of storm costs plus interest from retail rate payers over a two-year period (See Note 3).

Progress Energy is allowed to recover fuel costs incurred by PEC and PEF through their respective fuel cost recovery surcharges. Fuel price volatility can lead to over-or underrecovery of fuel costs, as changes in fuel prices are not immediately reflected in fuel surcharges due to regulatory lag in setting the surcharges. As a result, fuel price volatility can be both a source of and a drag on liquidity resources, depending on what phase of the cycle of price volatility the Company is experiencing. In addition, in 2004 PEF agreed with the FPSC to use a two-year period to determine the surcharge for the underrecovered fuel costs incurred in 2004 (See Note 8C).

Investing Activities Net cash used in investing activities for the three years ending December 31, 2004, 2003 and 2002 were

$0.9 billion, $1.5 billion and $2.2 billion, respectively.

37

V Management's Discussion and Analysis Utility property additions for the Company's regulated electric operations were $1.0 billion or approximately 75%

of consolidated capital expenditures in 2004 and

$1.0 billion or approximately 58% of consolidated capital expenditures in 2003, excluding proceeds from asset sales.

Capital expenditures for the regulated electric operations are primarily for normal construction activity and ongoing capital expenditures related to environmental compliance programs. Capital expenditures for the nonregulated operations are primarily for natural gas development activities and normal construction activity.

Excluding proceeds from sales of subsidiaries and other investments, cash used in investing activities decreased approximately $887 million in 2004 when compared with 2003.The decrease is due primarilytothe acquisition of a nonregulated generation contract and acquisition of gas assets in 2003 and net proceeds from short-term investments in 2004, compared to net purchases of short-term investments in 2003.

Excluding proceeds from sales of subsidiaries and other investments, cash used in investing activities was

$2.1 billion in 2003, down approximately $119 million when compared with 2002. The decrease is due primarily to lower utility property additions due to completion of Hines 2 construction at PEF and lower acquisitions of nonregulated assets.

During 2004, sales of subsidiaries and other investments primarily included proceeds from the sale of Railcar Ltd.

assets of approximately S75 million and proceeds of approximately $251 million related to the sale of natural gas assets in the Forth Worth basin of Texas. Progress Energy used the proceeds from these sales to reduce indebtedness, including $241 million to pay off the Progress Genco Ventures, LLC, bank facility.

During 2003, the Company realized approximately

$450 million of net cash proceeds from the sale of NCNG and ENCNG. The Company also received net proceeds of approximately $97 million in October 2003 for the sale of its Mesa gas properties in Colorado. Progress Energy used the proceeds from these sales to reduce indebtedness, primarily commercial paper, then outstanding.

During 2002, the Company purchased two electric generation projects for a cash purchase price of

$348 million.

Financing Activities Net cash provided by financing activities for the three years ending December 31, 2004, 2003 and 2002 were

$(720) million, $4192) million and S581 million, respectively.

See Note 13 for details of debt and credit facilities.

For 2004 and 2003, cash from operations exceeded net cash used in investing activities by $735 million and $178 million, respectively, due primarily to asset sales, which allowed for a net decrease in cash provided by financing activities.

For 2002, net cash used in investing activity exceeded cash from operations by $574 million, which resulted in net cash from financing activities of $581 million.

In addition to the financing activities discussed under Overview,' the financing activities of the Company included:

2005

• In March 2005, Progress Energy, Inc.'s five-year credit facility was amended to increase the maximum total debt to total capital ratio from 65% to 68% in anticipation of the potential impacts of proposed accounting rules for uncertain tax positions. See Notes 2 and 23E.

• On January31, 2005, Progress Energy, Inc. entered into a new $600 million revolving credit agreement, which expires December 30, 2005. This facility was added to provide additional liquidity during 2005 due in part to the uncertainty of the timing of storm restoration cost recovery from the hurricanes in Florida during 2004.

The credit agreement includes a defined maximum total debt to total capital ratio of 68% and a minimum interest coverage ratio of 2.5 to 1. The credit agreement also contains various cross-default and other acceleration provisions. On February 4, 2005,

$300 million was drawn under the new facility to reduce commercial paper and pay off the remaining amount of RCA loans outstanding.

• In January 2005, the Company used proceeds from the issuance of commercial paper to pay off $260 million of revolving credit agreement (RCA) loans.

During 2003, the Company acquired approximately 200 natural gas-producing wells for a cash purchase price of $168 million. The Company also acquired a long-term full-requirements powersupply agreementwith Jackson Electric Membership Corporation for a cash payment of

$188 million.

2004

• During the fourth quarter of 2004, Progress Energy and its subsidiaries PEC and PEF borrowed a net total of

$475 million under certain revolving credit facilities.

The borrowed funds were used to pay off maturing 38

Progress Energy Annual Report 2004 commercial paper and for other cash needs. A summary of RCA loans and available capacity as of December 31, 2004 is as follows:

(in millions)

Company Description Total Outstanding Available Progress Energy.

5-Year Inc.

(expiring 8/MM09)

S1,130 S160

$970 Progress Energy 364-Day Carolinas, Inc.

(expiring 7/27/05) 165 90 75 Progress Energy 3-Year Carorinas, Inc.

(expiring 7/31/05) 285 285 Progress Energy 364-Day Florida, Inc.

(expiring 3/29/05) 200 170 30 Progress Energy 3-Year Florida, Inc.

(expiring 4/01/06) 200 55 145 Less: amounts reservedla)

(574)

Total credit facilities

$1,980

$475

$931

{alTo the extent amounts are reserved for commercial paper outstanding or backing letters of credit they are not available for additional borrowings.

• On December 17, 2004, the Company used proceeds from the sale of natural gas assets to extinguish Progress Genco Ventures, LLC's $241 million bank facility (See Note 13D).

• Progress Energy took advantage of favorable market conditions and entered into a new $1.1 billion five-year line of credit, effective August 5, 2004, and expiring August 5, 2009. This facility replaced Progress Energy's

$250 million 364-day line of credit and its three-year

$450 million line of credit, which were both scheduled to expire in November 2004.

• On July 28, 2004, PEC extended its $165 million 364-day line of credit, which was scheduled to expire on July 29,2004.The line of creditwill expire on July27,2005.

• On July 1, 2004, PEF paid at maturity $40 million 6.69%

Medium-Term Notes Series B with commercial paper proceeds and cash from operations.

• On April 30,2004, PEC redeemed $35 million of Darlington County 6.6% Series Pollution Control Bonds at 102.5% of par, $2 million of New Hanover County 6.3% Series Pollution Control Bonds at 101.5% of par, and $2 million of Chatham County 6.3% Series Pollution Control Bonds at 101.5% of par with cash from operations.

• On March 1, 2004, Progress Energy used available cash and proceeds from the issuance of commercial paper to pay at maturity $500 million 6.55% senior unsecured notes. Cash and commercial paper capacity for this retirement was created primarily from proceeds of the sale of assets in 2003.

• On February 9, 2004, Progress Capital Holdings, Inc.,

paid at maturity $25 million 6.48% medium-term notes with available cash from operations.

• On January 15, 2004, PEC paid at maturity $150 million 5.875% First Mortgage Bonds with commercial paper proceeds. On April 15, 2004, PEC also paid at maturity

$150 million 7.875% First Mortgage Bonds with commercial paper proceeds and cash from operations.

• For 2004, the Company issued approximately 1 million shares of its common stock for approximately

$73 million in net proceeds from its Investor Plus Stock Purchase Plan and its employee benefit and stock option plans, net of purchases of restricted shares. For 2004, the dividends paid on common stock were approximately $558 million.

2003

• Progress Energy obtained a three-year financing order, allowing it to issue up to $2.8 billion of long-term securities, $1.5 billion of short-term debt, and $3 billion in parent guarantees. Progress Energy issued approximately 8 million shares of common stock for approximately $304 million in net proceeds from its Investor Plus Stock Purchase Plan and its employee benefit plans, net of purchases of restricted shares.

For 2003, the dividends paid on common stock were approximately$541 million.

• PEC redeemed $250 million and issued $600 million in first mortgage bonds.

• PEF redeemed $250 million, issued $950 million and paid at maturity$180 million in first mortgage bonds. PEF also paid at maturity $35 million in medium-term notes.

• Progress Capital Holdings, Inc., paid at maturity

$58 million in medium-term notes.

• Progress Genco Ventures, LLC, terminated its

$50 million working capital credit facility. Under its related construction facility, Genco had drawn

$241 million at December 31, 2003.

2002

• Progress Energy issued $800 million in senior unsecured notes. Progress Energy issued approximately 2 million shares representing approximately $86 million in proceeds from its Investor Plus Stock Purchase Plan and its employee benefit plans.

• PEC issued and redeemed $500 million in senior unsecured notes and $48.5 million in pollution control obligations. PEC also redeemed $150 million and paid at maturity $100 million in first mortgage bonds.

39

V Management's Discussion and Analysis

• PEF issued and redeemed S241 million in pollution control obligations and paid at maturity $30 million in medium-term notes.

• Progress Capital Holdings, Inc., paid at maturity

$50 million in medium-term notes.

• Progress Genco Ventures, LLC, obtained a $440 million bank facility, including $50 million for working capital. During the year, $130 million of the facility was terminated.

The amount outstanding at December 31, 2002, was $225 million.

• In November 2002, the Company issued 14.7 million shares of common stock for net cash proceeds of approximately $600 million, which were primarily used to retire commercial paper. For 2002, the dividends paid on common stock were approximately $480 million.

Future liquidity and capital resources The Company's two electric utilities produced over 100%

of consolidated cash from operations in 2004. It is expected that the two electric utilities will continue to produce a majority of the consolidated cash flows from operations overthe next several years as its nonregulated investments, primarily generation assets, improve asset utilization and increase their operating cash flows.

PEF notified the FPSC in January 2005 of its intentto file for an increase in its base rates effective January 1, 2006. If approved by the FPSC, an increase in PEF's base rates would increase future operating cash flows. PEF has faced significant costincreases overthe past decade and expects its operational costs to continue to increase.

These costs include the costs associated with completion of the Hines 3 generation facility, extraordinary hurricane damage costs including capital costs not expected to be directly recoverable, the need to replenish the depleted storm reserve and the expected infrastructure investment necessary to meet high customer expectations, coupled with the demands placed on PEF as a result of strong customer growth. If the FPSC does not approve PEF's request to increase base rates, the Company's results of operations and financial condition could be negatively impacted. The Company cannot predict the outcome of this matter.

In addition, Fuels' synthetic fuel operations do not currently produce positive operating cash flow due to the difference in timing of when tax credits are recognized for financial reporting purposes and when tax credits are realized for tax purposes. See Note 23E for further discussion.

Capital Expenditures Total cash from operations provided the funding for the Company's capital expenditures, including property additions, nuclear fuel expenditures and diversified business property additions during 2004, excluding proceeds from asset sales of $366 million.

As shown in the table below, Progress Energy expects the majority of its capital expenditures to be incurred at its regulated operations. See Note 8F for a discussion of expected impacts on future capital expenditures due to changes in capitalization practice for regulated operations. The Company anticipates its regulated capital expenditures will increase in 2005 due to increased spending on Clean Air initiatives. Forecasted nonregulated expenditures relate primarily to Progress Fuels and its gas operations, mainly for drilling new wells.

Actual Forecasted

[in millions) 2004 2005 2006 2007 Regulated capital expenditures S998

$1,030

$1,040

$1,090 Nuclear fuel expenditures 101 120 90 150 AFUOC-borrowed funds (6)

(10)

(10)

(10)

Nonregulated capital expenditures 236 190 180 190 Total

$1,329

$1,330

$1,300

$1,420 Regulated capital expenditures in the table above include total expenditures from 2005 through 2006 of approximately$65 million expected to be incurred at PEC fossil-fueled electric generating facilities to comply with Section 110 of the Clean Air Act, referred to as the NOx SIP Call.

The Company also expects to incur expenditures of approximately $15 million (S10 million at PEC and

$5 million at PEF) from 2005 through 2007 and additional expenditures of approximately $70 million to $100 million

($10 million to S20 million at PEC and $60 million to

$80 million at PEF) from 2008 through 2009 for compliance with the Section 316(b) requirements of the Clean Water Act (See Note 22).

In June 2002, legislation was enacted in North Carolina requiring the state's electric utilities to reduce the emissions of nitrogen oxide (NOx) and sulfur dioxide (SO2) from coal-fired power plants. PEC expects its capital costs to meet these emission targets will be approximately $895 million by 2013. For the years 2005 through

2007, the Company expects to incur approximately $475 million of total capital costs 40

Progress Energy Annual Report 2004 associated with this legislation, which is included in the table above (See Note 22).

All projected capital and investment expenditures are subject to periodic review and revision and may vary significantly depending on a number of factors including, but not limited to, industry restructuring, regulatory constraints, market volatility and economic trends.

Other Cash Needs As of December 31, 2004, on a consolidated basis, the Company had $349 million of long-term debt maturing in 2005. Progress Energy expects to pay these maturities using funds from operations, issuance of new long-term debt, commercial paper borrowings and/or issuance of new equity securities.

In 2006, $800 million of Progress Energy senior unsecured notes will mature. The Company expects to fund the maturity using proceeds from the sale of the Progress Rail subsidiary, issuance of new long-term debt, commercial paper borrowings and/or issuance of new equity securities.

During the fourth quarter of 2004, Progress Energy announced the launch of a new cost-management initiative aimed at achieving nonfuel O&M expense reductions of $75 million to $100 million annually by the end of 2007. In connection with this cost-management initiative, the Company expects to incur one-time pre-tax charges of approximately $130 million. Approximately

$30 million of that amount relates to payments for severance benefits, which will be recognized in the first quarter of 2005 and paid over time. The remaining approximately $100 million will be recognized in the second quarter of 2005 and relates primarily to postretirement benefits that will be paid over time to those eligible employees who elect to participate in the voluntary enhanced retirement program (See Note 24).

Credit Facilities At December 31, 2004, the Company and its subsidiaries had committed lines of credit and outstanding balances as shown in the table in Note 13. All of the creditfacilities supporting the credit were arranged through a syndication of financial institutions. There are no bilateral contracts associated with these facilities.

The Company's financial policy precludes issuing commercial paper in excess of its supporting lines of credit. At December 31, 2004, the Company had

$424 million of commercial paper outstanding, $150 million reserved for backing of letters of credit and an additional

$475 million drawn directly from the credit facilities, leaving $931 million available for issuance or drawdown.

In addition, the Company has requirements to pay minimal annual commitment fees to maintain its credit facilities. At December 31, 2003, the Company had

$4 million of commercial paper outstanding. The Company expects to continue to use commercial paper issuances as a source of liquidity as long as it maintains its current short-term ratings.

All of the credit facilities include a defined maximum total debt-to-total capital ratio (leverage) and coverage ratios. The Company is in compliance with these covenants at December 31, 2004. See Note 13 for a discussion of the credit facilities' financial covenants, material adverse change clause provisions and cross-default provisions. At December 31, 2004, the calculated ratios for the companies, pursuant to the terms of the agreements, are as disclosed in Note 13.

Both PEC and PEF plan to enter into new five-year lines of credit in 2005 to replace their existing credit facilities.

The Company has on file with the SEC a shelf registration statement under which senior notes, junior debentures, common and preferred stock and other trust preferred securities are available for issuance by the Company.

At December 31, 2004, the Company had approximately

$1.1 billion available under this shelf registration.

Progress Energy and PEF each have an uncommitted bank bid facility authorizing each of them to borrow and reborrow, and have loans outstanding at any time, up to

$300 million and $100 million, respectively. At December 31, 2004, there were no outstanding loans against these facilities.

PEC currently has on file with the SEC a shelf registration statement under which it can issue up to $900 million of various long-term securities. PEF currently has on file registration statements under which it can issue an aggregate of $750 million of various long-term debt securities.

Both PEC and PEF can issue First Mortgage Bonds under their respective First Mortgage Bond indentures. At December 31, 2004, PEC and PEF could issue up to

$2.9 billion and $3.7 billion, respectively, based on property additions and S2.2 billion and $176 million, respectively, based upon retirements.

41

V Management's Discussion and Analysis The following table shows Progress Energy's capital structure at December31:

2004 2003 Common stock 41.7%

40.5%

Preferred stock and minority interest 0.7%

0.7%

Total debt 57.6%

58.8%

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 orderto allowforthe early redemption of long-term debt, the redemption of preferred stock, the reduction of short-term debt or for other general corporate purposes.

Credit Rating Matters The major credit rating agencies have currently rated the Company's securities as follows:

Moods Standard &

Fitch Investors Senice Poor's Ratings Progress Energy, Inc.

Outlook Negative Negative Stable Corporate credit rating n/a BBB n/a Senior unsecured debt Baa2 BBB-BBB-Commercial paper P-2 A-3 n/a Progress Energy Carolinas, Inc.

Corporate credit rating n/a BBB n/a Commercial paper P-2 A-3 F2 Senior secured debt A3 BBB A-Senior unsecured debt Baal BBB BBB+

Progress Energy Florida. Inc.

Corporate credit rating n/a BBB n/a Commercial paper P-2 A-3 F2 Senior secured debt A2 BBB A-Senior unsecured debt A3 BBB BBB+

FPC Capital I Preferred stock*

Baa2 BB+

n/a Progress Capital Holdings, Inc.

Senior unsecured debt Baal BBB-n/a

• Guaranteed by Florida Progress Corporation.

However, the Company monitors its financial condition as well as market conditions that could ultimately affect its credit ratings.

On February 11, 2005, Moody's credit rating agency announced that it lowered the ratings of PEF, Progress Capital Holdings and FPC Capital Trust I and changed their rating outlooks to stable from negative. Moody's affirmed the ratings of Progress Energy and PEC.The rating outlooks continue to be stable at PEC and negative at Progress Energy. Moody's stated that it took this action primarily due to declining cash flow coverages and rising leverage, higher O&M costs, uncertainty regarding the timing of hurricane cost recovery, regulatory risks associated with the upcoming rate case in Florida and ongoing capital requirements to meet Florida's growing demand.

On October 19, 2004, S&P changed Progress Energy's outlook from stable to negative. S&P cited the uncertainties regarding the timing of the recovery of hurricane costs, the Company's debt reduction plans and the IRS audit of the Company's Earthco synthetic fuels facilities as the reasons for the change in outlook. On October 25, 2004, S&P reduced the short-term debt rating of Progress Energy, PEC and PEF to A-3 from A-2, as a result of their change in outlook discussed above.

On October 20, 2004, Moody's changed its outlook for Progress Energy from stable to negative and placed the ratings of PEF under review for possible downgrade.

PEC's ratings were affirmed by Moody's.

Moody's cited the following reasons for its change in the outlook for Progress Energy-financial ratios that are weak for its current rating category; rising O&M, pension, benefit and insurance costs; and delays in executing its deleveraging plan. With respect to PEF, Moody's cited declining cash flow coverages and rising leverage over the last several years, expected funding needs for a large capital expenditure program, risks with regard to its upcoming 2005 rate case and the timing of hurricane cost recovery as reasons for putting its ratings under review.

The changes by S&P and Moody's do nottrigger any debt or guarantee collateral requirements, nor do they have any material impact on the overall liquidity of Progress Energy or any of its affiliates. To date, Progress Energy's, PEC's and PEF's access to the commercial paper markets has not been materially impacted by the rating agencies' actions. However, the changes have increased the interest rate incurred on its short-term borrowings by 0.25% to 0.875%.

These ratings reflect the current views of these rating agencies, and no assurances can be given that these ratings will continue for any given period of time.

42

Progress Energy Annual Report 2004 If Standard & Poor's lowers Progress Energy's senior unsecured rating one ratings category to BB+ from its current rating, it would be a noninvestment grade rating.

The effect of a noninvestment grade rating would primarily be to increase borrowing costs. The Company's liquidity would essentially remain unchanged, as the Company believes it could borrow under its revolving credit facilities instead of issuing commercial paper for its short-term borrowing needs. However, there would be additional funding requirements of approximately $450 million due to ratings triggers embedded in various contracts, as more fully described below under Guarantees.'

The Company and its subsidiaries' debt indentures and credit agreements do not contain any ratings triggers,"

which would cause the acceleration of interest and principal payments in the event of a ratings downgrade.

However, in the event of a downgrade, the Company and/or its subsidiaries may be subject to increased interest costs on the credit facilities backing up the commercial paper programs. In addition, the Company and its subsidiaries have certain contracts that have provisions triggered by a ratings downgrade to a rating below investment grade. These contracts include counterparty trade agreements, derivative contracts, certain Progress Energy guarantees and various types of third-party purchase agreements.

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

Guarantees As a part of normal business, Progress Energy and certain wholly owned subsidiaries enter into various agreements providing future financial or performance assurances to third parties that are outside the scope of Financial Accounting Standards Board (FASB) Interpretation No. 45,

'Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others' (FIN No. 45). These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to Progress Energy and subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended commercial purposes. The Company's guarantees include performance obligations under power supply agreements, tolling agreements, transmission agreements, gas agreements, fuel procurement agreements and trading operations. The Company's guarantees also include standby letters of credit, surety bonds and guarantees in support of nuclear decommissioning. At December31,2004,the Company had issued $1.3 billion of guarantees for future financial or performance assurance. Management does not believe conditions are likely for significant performance under the guarantees of performance issued by or on behalf of affiliates.

The majority of contracts supported by the guarantees contain provisions that trigger guarantee obligations based on downgrade events to below investment grade (below BBB-or Baa3), ratings triggers, monthly netting of exposure and/or payments and offset provisions in the event of a default The recent outlook changes from S&P and Moody's do nottrigger any guarantee obligations. As of December 31, 2004, if the guarantee obligations were triggered, the maximum amount of liquidity requirements to support ongoing operations within a 90-day period, associated with guarantees for the Company's nonregulated portfolio and power supply agreements, was $450 million. The Company would meet this obligation with cash or letters of credit As of December 31, 2004, Progress Energy had guarantees issued on behalf of third parties of approximately $10 million. See Note 23D for a discussion of guarantees in accordance with FIN No. 45.

Market Risk and Derivatives Under its risk management policy, the Company may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 18 and

'Quantitative and Qualitative Disclosures about Market Risk" for a discussion of market risk and derivatives.

Contractual Obligations The Company is party to numerous contracts and arrangements obligating it to make cash payments in future years.

These contracts include financial arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services.

Amounts in the following table are estimated based upon contractual terms and will likely differ from amounts presented below. Further disclosure regarding the Company's contractual obligations is included in the respective notes. The Company takes into consideration the future commitments following when assessing its 43

V Management's Discussion and Analysis liquidity and future financing needs. The following table reflects Progress Energy's contractual cash obligations and other commercial commitments at December 31,2004, in the respective periods in which they are due:

(in millions)

Total Less than I year 1-3 years 3-5 years More than 5 years Long-term debt al)See Note 13)

$9,942

$349

$1,637 S1,387 S6,569 Interest payments on long-term debt and interest rate derivativeslb) 3,064 301 489 423 1,851 Capital lease obligations ISee Note 23C) 50 4

8 7

31 Operating leases (See Note 23C) 597 66 113 112 306 Fuel and purchased power(c)

(See Note 23A) 13,010 2,692 3,088 1,346 5,884 Other purchase obligations (See Note 23A) 633 151 134 80 268 North Carolina Clean Air capital commitments (See Note 22) 764 170 297 143 154 Other commitrnents(d)(e) 243 42 70 26 105 Total S28,303

$3,775 S5,836

$3,524

$15,168 la) The Company's maturing debt obligations are generally expected to be refinanced with new debt issuances in the capital markets. However, the Company does plan to annually reduce its debt to total capitalization leverage over the next few years through selected asset sales, free cash flow and increased equity from retained earnings and ongoing equity issuances.

lb) Interest payments on long-term debt and interest rate derivatives are based on the interest rate effective as of December 31, 2004, and the LIBOR forward curve as of December 31, 2004, respectively.

IC) Fuel and purchased power commitments represent the majority of the Company's remaining future commitments after its debt obligations. Essentially all of the Company's fuel and purchased power costs are recovered through pass-through clauses in accordance with North Carolina, South Carolina and Florida regulations and therefore do not require separate liquidity support.

Id) In 2008, PEC must begin transitioning amounts currently retained internally to its external decommissioning funds. The transition of S131 million must be complete by December 31,2017, and at least 10% must be transitioned each year.

(e) The Company has certain future commitments related to four synthetic fuel facilities purchased that provide for contingent payments Iroyalties) through 2007 (See Note 23B).

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

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

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

The Company's synthetic fuel operations and related risks are described in more detail in Note 23E.

44

Progress Energy Annual Report 2004 Hurricane Costs Hurricanes Charley, Frances, Ivan and Jeanne struck significant portions of the Company's service territories during the third quarter of 2004, significantly impacting PEF'sterritory.As of December31, 2004, restoration of the Company's systems from hurricane-related damage was estimated at $398 million. PEC incurred restoration costs of S13 million, of which S12 million was charged to operation and maintenance expense and S1 million was charged to capital expenditures. PEF had estimated total costs of $385 million, of which $47 million was charged to capital expenditures, and S338 million was charged to the storm damage reserve pursuant to a regulatory order.

In accordance with a regulatory order, PEF accrues

$6 million annually to a storm damage reserve and is allowed to defer losses in excess of the accumulated reserve for major storms. Under the order, the storm reserve is charged with operation and maintenance expenses related to storm restoration and with capital expenditures related to storm restoration that are in excess of expenditures assuming normal operating conditions. As of December 31, 2004, $291 million of hurricane restoration costs in excess of the previously recorded storm reserve of S47 million had been classified as a regulatory asset recognizing the probable recoverability of these costs. On November 2, 2004, PEF filed a petition with the FPSC to recover $252 million of storm costs plus interest from retail ratepayers over a two-year period. Storm reserve costs of $13 million were attributable to wholesale customers. The Company has received approval from the FERC to amortize these costs consistent with recovery of such amounts in wholesale rates. PEF continues to review the restoration cost invoices received. Given that not all invoices have been received as of December 31, 2004, PEF will update its petition with the FPSC upon receipt and audit of all actual charges incurred. Hearings on PEF's petition for recovery of S252 million of storm costs filed with the FPSC are scheduled to begin on March 30, 2005.

On November 17, 2004, the Citizens of the State of Florida, by and through Harold McLean, Public Counsel, and the Florida Industrial Power Users Group (FIPUG) (collectively, Joint Movants) filed a Motion to Dismiss PEFs petition to recover the $252 million in storm costs. On November 24, 2004, PEF responded in opposition to the motion, which was also the FPSC staff's position in its recommendation to the Commission on December 21, 2004, that it should deny the Motion to Dismiss. On January 4, 2005, the Commission ruled in favor of PEF and denied the Joint Movant's Motion to Dismiss.

PEF's January 2005 notice to the FPSC of its intent to file for an increase in its base rates effective January 1, 2006, anticipates the need to replenish the depleted storm reserve balance and adjust the annual S6 million accrual in light of recent storm history to restore the reserve to an adequate level over a reasonable time period.

PEC does not have an ongoing regulatory mechanism to recover storm costs; therefore, hurricane restoration costs recorded in the third quarter of 2004 were charged to operations and maintenance expenses or capital expenditures based on the nature of the work performed.

In connection with other storms, PEC has previously sought and received permission from the NCUC and the SCPSC to defer storm expenses and amortize them over a five-year period. PEC did not seek deferral of 2004 storm costs from the NCUC (See Note 8B).

Regulatory Environment and Matters The Company's electric utility operations in North Carolina, South Carolina and Florida are regulated by the NCUC, the Public Service Commission of South Carolina (SCPSC) and the FPSC, respectively. The electric businesses are also subjectto regulation bythe FERC,the NRC and otherfederal and state agencies common to the utility business. In addition, the Company is subject to SEC regulation as a registered holding company under PUHCA. As a result of regulation, many of the fundamental business decisions, as well as the rate of return the electric utilities are permitted to earn, are subject to the approval of governmental agencies.

PEC and PEF continue to monitor any developments toward a more competitive environment and have actively participated in regulatory reform deliberations in North Carolina, South Carolina and Florida. Movement toward deregulation in these states has been affected by recent developments, including developments related to deregulation of the electric industry in other states. The Company expects the legislatures in all three states will continue to monitor the experiences of states that have implemented electric restructuring legislation. The Company cannot anticipate when, or if, any of these states will move to increase competition in the electric industry.

The retail rate matters affected by the regulatory authorities are discussed in detail in Notes 8B and 8C.

This discussion identifies specific retail rate matters, the status of the issues and the associated effects to the Company's consolidated financial statements.

The regulatory authorities continue to evaluate issues related to the formation of Regional Transmission 45

V Management's Discussion and Analysis Organizations. The Company cannot predict the outcome of these matters on the Company's earnings, revenues or prices or the investments in GridSouth and GridFlorida (See Note 8D).

A FERC order issued in November 2001 on certain unaffiliated utilities' triennial market-based wholesale power rate authorization updates required certain mitigation actions thatthose utilities would need to take for sales/purchases within their control areas and required those utilities to post information on their Web sites regarding their power systems' status. As a result of a request for rehearing filed by certain market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. In April 2004,the FERC issued two orders concerning utilities' ability to sell wholesale electricity at market-based rates. In the first order, the FERC adopted two new interim screens for assessing potential generation market power of applicants for wholesale market-based rates, and described additional analyses and mitigation measures that could be presented if an applicant does not pass one of these interim screens. In July 2004, the FERC issued an order on rehearing affirming its conclusions in the April order. In the second order, the FERC initiated a rulemaking to consider whether the FERC's current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in anyway. Management is unable to predict the outcome of these actions by the FERC or their effect on future results of operations and cash flows. PEF does not have market-based rate authority for wholesale sales in peninsular Florida. Given the difficulty PEC believes it would experience in passing one of the interim screens, on August 12, 2004, PEC notified the FERC that it would revise its Market-based Rate tariff to restrict it to sales outside PEC's control area and file a new cost-based tariff for sales within PEC's control area that incorporates the FERC's default cost-based rate methodologies for sales of one year or less.

PEC anticipates making this filing in the first quarter of 2005. Although the Company cannot predict the ultimate outcome of these changes, the Company does not anticipate that the current operations of PEC or PEF would be impacted materially if they were unable to sell power at market-based rates in their respective control areas.

Franchise Litigation Three cities, with a total of approximately 18,000 customers, have litigation pending against PEF in various circuit courts in Florida. As previously reported, three other cities, with a total of approximately 30,000 customers, have subsequently settled their lawsuits with PEF and signed new, 30-year franchise agreements. The lawsuits principally seek (1) a declaratory judgment that the cities have the right to purchase PEF's electric distribution system located within the municipal boundaries of the cities, (2) a declaratory judgment that the value of the distribution system must be determined through arbitration, and (3) injunctive relief requiring PEF to continue to collect from PEF's customers, and remitto the cities, franchise fees during the pending litigation, and as long as PEF continues to occupythe cities' rights-of-way to provide electric service, notwithstanding the expiration of the franchise ordinances under which PEF had agreed to collect such fees. The circuit courts in those cases have entered orders requiring arbitration to establish the purchase price of PEF's electric distribution system within five cities. Two appellate courts have upheld those circuit court decisions and authorized the cities to determine the value of PEF's electric distribution system within the cities through arbitration.

Arbitration in one of the cases (with the 13,000-customer City of Winter Park) was completed in February 2003.

That arbitration panel issued an award in May 2003 setting the value of PEF's distribution system within the City of Winter Park (the City) at approximately$32 million, not including separation and reintegration and construction work in progress, which could add several million dollars to the award. The panel also awarded PEF approximately $11 million in stranded costs, which, according to the award, decrease over time. In September 2003, Winter Park voters passed a referendum that would authorize the City to issue bonds of up to approximately $50 million to acquire PEF's electric distribution system. While the City has not yet definitively decided whether it will acquire the system, on April 26, 2004, the City Commission voted to proceed with the acquisition. The City sought and received wholesale power supply bids and on June 24, 2004, executed a wholesale power supply contract with PEF.

On May 12, 2004, the City solicited bids to operate and maintain the distribution system and awarded a contract in January 2005. The City has indicated that its goal is to begin electric operations in June 2005. On February 10, 2005, PEF filed a petition with the Florida Public Service Commission to relieve the Company of its statutory obligation to serve customers in Winter Park 46

Progress Energy Annual Report 2004 on June 1, 2005, or at such time when the City is able to provide retail service. At this time, whether and when there will be further proceedings regarding the City of Winter Park cannot be determined.

Arbitration with the 2,500-customer Town of Belleair was completed in June 2003. In September 2003, the arbitration panel issued an award in that case setting the value of the electric distribution system within the Town at approximately $6 million. The panel further required the Town to pay to PEF its requested $1 million in separation and reintegration costs and $2 million in stranded costs. The Town has not yet decided whether it will attempt to acquire the system; however, on January 18, 2005, it issued a request for proposals for wholesale power supply and to operate and maintain the distribution system. Proposals are due in early March 2005. In February 2005, the Town Commission also voted to put the issue of whether to acquire the distribution system to a voter referendum on or before October2,2005.Atthistime,whether and when there will be further proceedings regarding the Town of Belleair cannot be determined.

Arbitration in the remaining city's litigation (the 1,500-customer City of Edgewood) has not yet been scheduled.

On February 17, 2005, the parties filed a joint motion to stay the litigation for a 90-day period during which the parties will discuss potential settlement.

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

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

Legal The Company is subject to federal, state and local legislation and court orders. These matters are discussed in detail in Note 23E. This discussion identifies specific issues, the status of the issues, accruals associated with issue resolutions and the associated exposures to the Company.

Nuclear Nuclear generating units are regulated bythe NRC. Inthe event of noncompliance, the NRC has the authority to impose fines, set license conditions, shut down a nuclear unit or some combination of these, depending upon its assessment of the severity of the situation, until compliance is achieved. The nuclear units are periodically removed from service to accommodate normal refueling and maintenance outages, repairs and certain other modifications (See Notes 6 and 23E).

Environmental Matters The Company is subject to federal, state and local regulations addressing air and water quality, hazardous and solid waste management and other environmental matters. These environmental matters are discussed in detail in Note 22. This discussion identifies specific environmental issues, the status of the issues, accruals associated with issue resolutions and the associated exposures to the Company. The Company accrues costs to the extent they are probable and can be reasonably estimated. It is reasonably possible that additional losses, which could be material, may be incurred in the future.

New Accounting Standards See Note 2 for a discussion of the impact of new accounting standards.

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. PEFfiled 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 remitto 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.

47

V Market Risk Disclosures QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Market risk represents the potential loss arising from adverse changes in market rates and prices. Certain market risks are inherent in the Company's financial instruments, which arise from transactions entered into in the normal course of business. The Company's primary exposures are changes in interest rates with respect to its long-term debt and commercial paper, and fluctuations in the return on marketable securities with respect to its nuclear decommissioning trust funds. The Company manages its market risk in accordance with its established risk management policies, which may include entering into various derivative transactions.

These financial instruments are held for purposes other than trading. The risks discussed below do not include the price risks associated with nonfinancial instrument transactions and positions associated with the Company's operations, such as purchase and sales commitments and inventory.

Interest Rate Risk The Company manages its interest rate risks through the use of a combination of fixed and variable rate debt Variable rate debt has rates that adjust in periods ranging from daily to monthly. Interest rate derivative instruments may be used to adjust interest rate exposures and to protect against adverse movements in rates.

The following tables provide information at December31, 2004 and 2003, aboutthe Company's interest rate risk-sensitive instruments. The tables present principal cash flows and weighted-average interest rates by expected maturity dates for the fixed and variable rate long-term debt and FPC obligated mandatorily redeemable securities of trust The tables also include estimates of the fair value of the Company's interest rate risk-sensitive instruments based on quoted market prices for these or similar issues. For interest rate swaps and interest rate forward contracts, the tables present notional amounts and weighted-average interest rates by contractual maturity dates for 2005-2009 and thereafter and the fair value of the related hedges. Notional amounts are used to calculate the contractual cash flows to be exchanged under the interest rate swaps and the settlement amounts under the interest rate forward contracts. See Note 18 for more information on interest rate derivatives.

(dollars in millions)

December31. 2004 Fixed rate long-term debt Average interest rate Variable rate long-term debt Average interest rate Debt to affiliated trust(al 20(

734 7.38' 05 2006 2007 2008 2009 Thereafter 19

$908

$674

$827

$400

$5,399 Y%

6.78%

6.41%

6.27%

5.95%

6.55%

$55

$160

$861 2.95%

3.19%

1.70%

$309 7.10%

Total

$8,557 6.54%

$1,076 1.99%

S309 7.10%

Fair Value

$9,454

$1,077

$312 Interest rate Interest rate derivatives:

Pay variable/receive fixed Average pay rate 5(100)

(b) 1$50)

_b)

Average receive rate Interest rate forward contracts S200 Average pay rate 3.07%

Average receive rate Ic) la) FPC Capital I - Quarterly Income Preferred Securities.

(b) Rate is 3-month LIBOR, which was 2.56% at December 31, 2004.

Ic) Rate is 1-month LIBOR. which was 2.40% at December 31, 2004.

4.10%

4.65%

$131 4.90%

(b)

$(150)

(b) 4.28%

$331 3.79%

Ib~c)

$3

$(2) 48

Progress Energy Annual Report 2004 (dollars in millions)

December3l,2003 2004 2005 2006 2007 2008 Thereafter Total Fair Value Fixed rate long-term debt

$868 S349

$909

£674 S827 S5,836

$9,463

$10,501 Averageinterestrate 6.67%

7.38%

6.78%

6.41%

6.27%

6.51%

6.55%

Variable rate long-term debt

$241 S861 S1,102

$1,103 Average interest rate 3.04%

1.08%

1.51%

Debtto affiliated trustfa1

$309

$309 S313 Interest rate 7.10%

7.10%

Interest rate derivatives:

Pay variablelreceive fixed

$(300)

$1350)

$(200)

S(850)

S(4)

Average pay rate (b)

(b)

(b)

(b)

Average receive rate 2.75%

3.35%

2.93%

3.04%

Payer swaptions

$400

$400

$5 Average pay rate 4.75%

Average receive rate (b)

Interestrate collarslc)

$65

$130

$195

$(11)

Cap rate 6.00%

6.50%

Floor rate 4.13%

5.13%

(a)

FPC Capital I - Quarterly Income Preferred Securities.

(b) Rate is 3-month LIBOR, which was 1.15% at December 31.2003.

(c) Notional amount is varying with a maximum of $195 million, decreasing to S130 million after December 2004.

Marketable Securities Price Risk The Company's electric utility subsidiaries maintain trust funds, pursuant to NRC requirements, to fund certain costs of decommissioning their nuclear plants. These funds are primarily invested in stocks, bonds and cash equivalents, which are exposed to price fluctuations in equity markets and to changes in interest rates. The fair value of these funds was $1.044 billion and $938 million at December 31, 2004 and 2003, respectively. The Company actively monitors its portfolio by benchmarking the performance of its investments against certain indices and by maintaining, and periodically reviewing, target allocation percentages for various asset classes. The accounting for nuclear decommissioning recognizes that the Company's regulated electric rates provide for recovery of these costs net of any trust fund earnings, and, therefore, fluctuations in trust fund marketable security returns do not affectthe earnings of the Company.

Contingent Value Obligations Market Value Risk In connection with the acquisition of FPC, the Company issued 98.6 million CVOs. Each CVO represents the right to receive contingent payments based on the performance of four synthetic fuel facilities purchased by subsidiaries of FPC in October 1999. The payments, if any, are based on the net after-tax cash flows the facilities generate. These CVOs are recorded at fair value, and unrealized gains and losses from changes in fair value are recognized in earnings. At December 31, 2004 and 2003, the fair value of these CVOs was S13 million and $23 million, respectively.

A hypothetical 10% decrease in the December 31, 2004, market price would result in a $1 million decrease in the fair value of the CVOs.

Commodity Price Risk The Company is exposed to the effects of market fluctuations in the price of natural gas, coal, fuel oil, electricity and other energy-related products marketed and purchased as a result of its ownership of energy-related assets. The Company's exposure to these fluctuations is significantly limited by the cost-based regulation of PEC and PEF. Each state commission allows electric utilities to recover certain of these costs through various cost recovery clauses to the extent the respective commission determines that such costs are prudent. Therefore, while there may be a delay in the timing between when these costs are incurred and when these costs are recovered from the ratepayers, changes from year to year have no material impact on operating results. In addition, many of the Company's long-term power sales contracts shift substantially all fuel responsibility to the purchaser. The Company also has oil price risk exposure related to synfuel tax credits. See discussion in Note 23E.

49

V Market Risk Disclosures The Company uses natural gas hedging instruments to manage a portion of the market risk associated with fluctuations in the future sales price of the Company's natural gas. In addition, the Company may engage in limited economic hedging activity using natural gas and electricity financial instruments.

In 2004, PEF entered into derivative instruments related to its exposure to price fluctuations on fuel oil purchases. At December 31, 2004, the fair values of these instruments were a $2 million long-term derivative asset position included in other assets and deferred debits and a

$5 million short-term derivative liability position included in other current liabilities. These instruments receive regulatory accounting treatment. Gains are recorded in regulatory liabilities and losses are recorded in regulatory assets.

Refer to Note 18 for additional information with regard to the Company's commodity contracts and use of derivative financial instruments.

The Company performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions.

A hypothetical 10% increase or decrease in quoted market prices in the near term on the Company's derivative commodity instruments would not have had a material effect on the Company's consolidated financial position, results of operations or cash flows as of December 31, 2004.

50

V Forward-Looking Statements SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS Certain matters discussed throughout this Annual Report that are not historical facts are forward-looking and, accordingly, involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements.

In addition, examples of forward-looking statements discussed in this Annual Report include Management's Discussion and Analysis of Financial Condition and Results of Operations' including, but not limited to, statements under the following headings: a) "Results of Operations' about trends and uncertainties; b) Liquidity and Capital Resources" about operating cash flows, estimated capital requirements through the year 2007 and future financing plans; c) 'Strategy' about Progress Energy, Inc.'s, strategy; and d) 'Other Matters about the effects of new environmental regulations, nuclear decommissioning costs and the effect of electric utility industry restructuring.

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 Progress Energy, Inc., (the Company) does not undertake 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 thatyou should consider with respect to any forward-looking statements made throughout this document include, but are not limited to, the following: the impact of fluid and complex government laws and regulations, including those relating to the environment; deregulation or restructuring in the electric industry that may result in increased competition and unrecovered (stranded) costs; the ability of the Company to implement its cost-management initiatives as planned; the uncertainty regarding the timing, creation and structure of regional transmission organizations; weather conditions that directly influence the demand for electricity; the Company's ability to recover through the regulatory process, and the timing of such recovery of, the costs associated with the four hurricanes that impacted our service territory in 2004 or other future significantweather 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 Progress Energy Annual Report 2004 ability of the Company's subsidiaries to pay upstream dividends or distributions to it; the impact on the facilities and the businesses of the Company from a terrorist attack; the inherent risks associated with the operation of nuclear facilities, including environmental, health, regulatory and financial risks; the ability to successfully access capital markets on favorable terms; the impact on the Company's financial condition and ability to meet its cash and other financial obligations in the event its credit ratings are downgraded below investment grade; the impact that increases in leverage may have on the Company; the ability of the Company to maintain its current credit ratings; the impact of derivative contracts used in the normal course of business by the Company; investment performance of pension and benefit plans; the Company's ability to control costs, including pension and benefit expense, and achieve its cost-management targets for 2007; the availability and use of Internal Revenue Code Section 29 (Section 29) tax credits by synthetic fuel producers and the Company's continued ability to use Section 29 tax credits related to its coal and synthetic fuel businesses; the impact to the Company's financial condition and performance in the event it is determined the Company is not entitled to previously taken Section 29 tax credits; the impact of future accounting pronouncements regarding uncertain tax positions; the outcome of PEF's rate proceeding in 2005 regarding its future base rates; the Company's ability to manage the risks involved with the operation of its nonregulated plants, including dependence on third parties and related counter-party risks, and a lack of operating history; the Company's ability to manage the risks associated with its energy marketing operations; the outcome of any ongoing or future litigation or similar disputes and the impact of any such outcome or related settlements; and unanticipated changes in operating expenses and capital expenditures. Many of these risks similarly impact the Company's subsidiaries.

These and other risk factors are detailed from time to time in the Company's filings with the United States Securities and Exchange Commission (SEC).

All such factors are difficult to predict, contain uncertainties that may materially affect actual results and may be beyond the control of Progress Energy. New factors emerge from time to time, and it is not possible for managementto predict all such factors, nor can it assess the effect of each such factor on Progress Energy.

51

V Independent Auditors' and Management Reports MANAGEMENT'S REPORT OF INTERNAL CONTROLS OVER FINANCIAL REPORTING It is the responsibility of Progress Energy's management to establish and maintain adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15(d)-15(f) of the Securities Exchange Act of 1934, as amended. Progress Energy's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America. Internal control over financial reporting includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of Progress Energy; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles in the United States of America; (3) provide reasonable assurance that receipts and expenditures of Progress Energy are being made only in accordance with authorizations of management and directors of Progress Energy; and (4) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Progress Energy's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of Progress Energy's internal control over financial reporting as of December 31, 2004. Management based this assessment on criteria for effective internal control over financial reporting described in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management's assessment included an evaluation of the design of Progress Energy's internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of the Board of Directors.

Based on our assessment, management determined that, as of December 31, 2004, Progress Energy maintained effective internal control over financial reporting.

Management's assessment of the effectiveness of Progress Energy's internal control over financial reporting as of December 31, 2004, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report.

Robert B. McGehee Chairman and Chief Executive Officer Geoffrey S. Chatas Executive Vice President and Chief Financial Officer March 7, 2005 52

Progress Energy Annual Report 2004 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Progress Energy, Inc.

We have audited management's assessment, included in the accompanying Management's Report of Internal Controls, that Progress Energy, Inc., and its subsidiaries (the 'Company') maintained effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control overfinancial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the Company's principal executive and principal financial officers, or persons performing similar functions, and effected by the Company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance thattransactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2004, of the Company, and our report dated March 7, 2005, expressed an unqualified opinion on those consolidated financial statements.

Raleigh, North Carolina March 7, 2005 53

V Independent Auditors' and Management Reports REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Progress Energy, Inc.

We have audited the accompanying consolidated balance sheets of Progress Energy, Inc., and its subsidiaries (the Company) at December 31, 2004 and 2003, and the related consolidated statements of income, comprehensive income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2004.

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes ID and 18A to the consolidated financial statements, in 2003, the Company adopted Statement of Financial Accounting Standards No. 143 and Derivatives Implementation Group Issue C20.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, based on the criteria established in IntemalControl-IntegratedFrameworkissued bythe Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 7, 2005, expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control overfinancial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

Raleigh, North Carolina March 7, 2005 54

V Consolidated Financial Statements CONSOLIDATED STATEMENTS OF INCOME Progress Energy Annual Report 2004 (in millions except per share data)

Years ended December 31 2004 2003 2002 Operating Revenues Electric

$7,153

$6,741

$6,601 Diversified business Z619 2,000 1,490 Total Operating Revenues 9,772 8,741 8,091 Operating Expenses Utility Fuel used in electric generation z2011 1,695 1,586 Purchased power 868 862 862 Operation and maintenance 1,475 1,421 1,390 Depreciation and amrortization 878 883 820 Taxes other than on income 425 405 386 Diversified business Cost of sales 2,288 1,748 1,410 Depreciation and amortization 190 157 118 Impairment of long-lived assets 17 364 (Gain)Aloss on the sale of assets (57) 1 Other 218 195 145 Total Operating Expenses 8,296 7,384 7,081 Operating Income 1,476 1,357 1,010 Other Income (Expense)

Interest income 14 11 15 Impairment of investments (21)

(25)

Other, net 8

(16) 27 Total Other Income (Expense) 22 (26) 17 Interest Charges Net interest charges 653 635 641 Allowance for borrowed funds used during construction (6)

(7)

(8)

Total Interest Charges, Net 647 628 633 Income from Continuing Operations before Income Tax, Minority Interest and Cumulative Effect of Changes in Accounting Principles 851 703 394 Income Tax Expense (Benefit) 115 (111)

(158)

Income from Continuing Operations before Minority Interest and Cumulative Effect of Changes in Accounting Principles 736 814 552 Minority Interest Net of Tax (17) 3 Income from Continuing Operations Before Cumulative Effect of Changes in Accounting Principles 753 811 552 Discontinued Operations, Net of Tax 6

(8)

(24)

Cumulative Effect of Changes in Accounting Principles, Net of Tax (21)

Net Income

$759

$782

$528 Average Common Shares Outstanding 242 237 217 Basic Earnings per Common Share Income from continuing operations before cumulative effect of changes in accounting principles

$3.11

$3.42

$2.54 Discontinued operations, net of tax

.02

(.03)

(.1 1)

Cumulative effect of changes in accounting principles, net of tax

(.09)

Net Income

$3.13

$3.30

$2.43 Diluted Earnings per Common Share Income from continuing operations before cumulative effect of changes in accounting principles S3.10 S3.40

$2.53 Discontinued operations, net of tax

.02

(.03)

(.11)

Cumulative effect of changes in accounting principles, net of tax

(.09)

Net Income S3.12

$3.28

$2.42 Dividends Declared per Common Share

$2.32

$2.26

$2.20 See Notes to Consolidated Financial Statements.

55

V Consolidated Financial Statements CONSOLIDATED BALANCE SHEETS tin millions)

December31 2004 2003 ASSETS Utility Plant Utility plantin service S22.103

$21,680 Accumulated depreciation (8.783)

(8,174)

Utility plant in service, net 13,320 13,506 Held for future use 13 13 Construction work in progress 799 559 Nuclear fuel, net of amortization 231 228 Total Utility Plant, Net 14,363 14,306 Current Assets Cash and cash equivalents 62 47 Short-term investments 82 226 Receivables 1,084 1,084 Inventory 982 907 Deferred fuel cost 229 270 Deferred income taxes 121 87 Prepayments and other current assets 175 268 Total Current Assets 2.735 2,889 Deferred Debits and Other Assets Regulatory assets Nuclear decommissioning trust funds Diversified business property, net Miscellaneous other property and investments Goodwill Prepaid pension costs Intangibles, net Other assets and deferred debits Total Deferred Debits and Other Assets Total Assets See Notes to Consolidated Financial Statements.

1,064 1,044 2010 446 3,719 42 337 233 8,895

$25,993 598 938 2,095 464 3,726 462 357 258 8,898

$26,093 56

Progress Energy Annual Report 2004 CONSOLIDATED BALANCE SHEETS (in millions)

December31 CAPITAUZATION AND LIABIUTIES Common Stock Equity Common stock Without par value, 500 million shares authorized, 247 million and 246 million shares issued and outstanding, respectively Unearned restricted shares (1 million and 1 million shares, respectively)

Unearned ESOP shares (3 million and 4 million shares, respectively)

Accumulated other comprehensive loss Retained earnings Total Common Stock Equity Preferred Stock of Subsidiaries - Not Subject to Mandatory Redemption Minority Interest Long-Term Debt, Affiliate Long-Term Debt, Net Total Capitalization Current Liabilities Current portion of long-term debt Accounts payable Interest accrued Dividends declared Short-term obligations Customer deposits Other current liabilities Total Current Liabilities Deferred Credits and Other Liabilities Noncurrent income tax liabilities Accumulated deferred investment tax credits Regulatory liabilities Asset retirement obligations Accrued pension and other benefits Other liabilities and deferred credits Total Deferred Credits and Other Liabilities Commitments and Contingencies (Notes 22 and 23)

Total Capitalization and Liabilities See Notes to Consolidated Financial Statements.

2004 2003 S5,360 (13) 176)

(164) 2,526 7,633 93 36 270 9,251 17,283 S5,270 (17)

(89)

(50) 2,330 7,444 93 30 270 9,664 17,501 349 742 219 145 684 180 742 3,061 868 635 228 140 4

167 608 2,650 599 701 176 190 Z654 2,879 1,282 1,271 562 508 376 393 5,649 5,942

$25,993 S26,093 57

V Consolidated Financial Statements CONSOLIDATED STATEMENTS OF CASH FLOWS tin millions)

Years ended December 31 2004 2003 2002 Operating Activities Net income S759

$782

$528 Adjustments to reconcile net income to net cash provided by operating activities (Income) loss from discontinued operations (6) 8 24 Net (gain) loss on sale of operating assets (57) 1 Impairment of long-lived assets and investments 38 389 Cumulative effect of changes in accounting principles 21 Depreciation and amortization 1,181 1,146 1,099 Deferred income taxes (74)

(276)

(402)

Investment tax credit (14)

(16)

(18)

Deferred fuel credit (19)

(133)

(37)

Cash provided (used) by changes in operating assets and liabilities Receivables 135)

(158)

(50)

Inventory (108) 8 (66)

Prepayments and other current assets (18) 39 (24)

Accounts payable 33 37 100 Other current liabilities 82 121 56 Regulatory assets and liabilities (284)

(21) 46 Other 167 127 (118)

Net Cash Provided by Operating Activities 1,607 1,724 1,627 Investing Activities Gross utility property additions (998)

(972)

(1,169)

Diversified business property additions (236)

(584)

(558)

Nuclear fuel additions (101)

(117)

(81)

Proceeds from sales of subsidiaries and other investments 366 579 43 Acquisition of businesses, net of cash (365)

Purchases of short-term investments (2M108)

(2,813)

(2,962)

Proceeds from sales of short-term investments 2,252 2,587 2,962 Acquisifion of intangibles (1)

(200)

(10)

Other (46)

(26)

(61)

Net Cash Used in Investing Activities (872)

(1,546)

(2,201)

Financing Activities Issuance of common stock, net 73 304 687 Issuance of long-term debt, net 421 1,539 1,783 Net increase (decrease) in short-term indebtedness 680 (696)

(247)

Retirement of long-term debt (1,353)

(810)

(1,157)

Dividends paid on common stock (558)

(541)

(480)

Other 17 12 (5)

Net Cash (Used in) Provided by Financing Activities (720)

(192) 581 Net Increase (Decrease) in Cash and Cash Equivalents 15 (14) 7 Cash and Cash Equivalents at Beginning of Year 47 61 54 Cash and Cash Equivalents at End of Year

$62

$47

$61 Supplemental Disclosures of Cash Flow Information Cash paid during the year - interest (net of amount capitalized)

$657

$643

$651

- income taxes (net of refunds)

$189

$177

$219 Noncash Activities

• In April 2002, Progress Fuels Corporation, a subsidiary of the Company, acquired 100% of Westchester Gas Company. In conjunction with the purchase, the Company issued approximately S129 million in common stock (See Note 5D).

• In December 2003, Progress Telecommunications Corporation (PTC) and Caronet, Inc., both indirectly wholly owned subsidiaries of Progress Energy, and EPIK Communications, Inc., a wholly owned subsidiary of Odyssey Telecorp, Inc., contributed substantially all of their assets and transferred certain liabilities to Progress Telecom, LLC, a subsidiary of PTC (See Note 5A).

See Notes to Consolidated Financial Statements.

58

Progress Energy Annual Report 2004 CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY Common Common Accumulated Total Stock Stock Unearned Unearned Other Common Outstanding Outstanding Restricted ESOP Comprehensive Retained Stock (inmillionsexceptpersharedata)

Shares Amount Shares Shares Income (Loss)

Earnings Equity Balance, January 1. 2002 219 S4,121 S(14)

$(114)

S(32)

$2,043

$6,004 Net income 528 528 Other comprehensive loss (206)

(206)

Issuance of shares 19 815 815 Purchase of restricted stock (16)

(161 Restricted stock expense recognition 8

8 Cancellation of restricted shares (1) 1 Allocation of ESOP shares 16 12 28 Dividends ($2.20 per share)

(484)

(484)

Balance, December31, 2002 238 4,951 (21)

(102)

(238) 2,087 6,677 Net income 782 782 Other comprehensive income 188 188 Issuance of shares 8

305 305 Stock options exercised 4

4 Purchase of restricted stock (11 (7)

(8)

Restricted stock expense recognition 10 10 Cancellation of restricted shares (11 1

Allocation of ESOP shares 12 13 25 Dividends (S2.26 per share)

(539)

(539)

Balance, December 31, 2003 246 5,270 (17)

(89)

(50) 2,330 7,444 Net Income 759 759 Other comprehensive loss (114) 1114)

Issuance of shares 1

62 62 Stock options exercised 16 18 Purchase of restricted stock (7)

(7)

Restricted stock expense recognition 7

7 Cancellation of restricted shares (4) 4 Allocation of ESOP shares 14 13 27 Dividends ($2.32 per share)

(563)

(563)

Balance. December31,2004 247 S5,360 5(13) 5(76) 5(164) 52.526 57,633 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (in millions)

Years ended December 31 2004 2003 2002 Net Income S759 5782

$528 Other Comprehensive Income (Loss)

Changes in net unrealized losses on cash flow hedges (net of tax benefit of $10, S7 and $18, respectively)

(18) 112)

(28)

Reclassification adjustmentfor amounts included in net income (net of tax expense of (S16),1 (il and ($10), respectively) 26 19 16 Reclassification of minimum pension liability to regulatory assets (net of tax expense of ($2))

4 Minimum pension liability adjustment (net of tax benefit (expense) of $78, ($112) and $121, respectively)

Foreign currency translation and other Other Comprehensive Income (Loss)

(130) 177 (192) 4 4

(2)

$(114) 5188 51206)

Comprehensive Income 5645 5970

$322 See Notes to Consolidated Financial Statements.

59

V Notes to Consolidated Financial Statements

1. ORGANIZATION AND

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES A. Organization Progress Energy, Inc. (Progress Energy or the Company) is a holding company headquartered in Raleigh, North Carolina. The Company is registered under the Public Utility Holding Company Act of 1935 (PUHCA), as amended, and as such, the Company and rts subsidiaries are subject to the regulatory provisions of PUHCA.

Effective January 1, 2003, three of the Company's subsidiaries, Carolina Power & Light Company (CP&L),

Florida Power Corporation and Progress Ventures, Inc.,

began doing business under the assumed names Progress Energy Carolinas, Inc. (PEC), Progress Energy Florida, Inc. (PEF) and Progress Energy Ventures, Inc.

(PVI), respectively.

Through its wholly owned subsidiaries, PEC and PEF, the Company's PEC Electric and PEF segments are primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina, South Carolina and Florida. The Progress Ventures business unit consists of the Fuels business segment (Fuels) and Competitive Commercial Operations (CCO) operating segments. The Fuels segment is involved in natural gas drilling and production, coal terminal services, coal mining, synthetic fuel production, fuel transportation and delivery.

The CCO segment includes nonregulated generation and energy marketing activities. Through the Rail Services (Rail) segment, the Company is involved in nonregulated railcar repair, rail parts reconditioning and sales and scrap metal recycling. Through its other business units, the Company engages in other nonregulated business areas, including telecommunications and energy management and related services. Progress Energy's legal structure is not currently aligned with the functional management and financial reporting of the Progress Ventures business unit.

Whether, and when, the legal and functional structures will converge depends upon legislative and regulatory action, which cannot currently be anticipated.

B. Basis of Presentation The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) and include the activities of the Company and its majority-owned subsidiaries. Significant intercompany balances and transactions have been eliminated in consolidation except as permitted by Statement of Financial Accounting Standards (SFAS) No.71, Accounting forthe Effects of Certain Types of Regulation," which provides that profits on intercompany sales to regulated affiliates are not eliminated if the sales price is reasonable and the future recovery of the sales price through the ratemaking process is probable.

The consolidated financial statements of the Company and its subsidiaries include the majority-owned and controlled subsidiaries. Noncontrolling interests in the subsidiaries along with the income or loss attributed to these interests are included in minority interest in both the Consolidated Balance Sheets and in the Consolidated Statements of Income. The results of operations for minority interest are reported on a net of tax basis if the underlying subsidiary is structured as a taxable entity.

Unconsolidated investments in companies over which the Company does not have control, but has the ability to exercise influence over operating and financial policies (generally 20%-50% ownership), are accounted for under the equity method of accounting. These investments are primarily in limited liability corporations and limited liability partnerships, and the earnings from these investments are recorded on a pre-tax basis (See Note 21). These equity method investments are included in miscellaneous other property and investments in the Consolidated Balance Sheets. At December 31, 2004 and 2003, the Company has equity method investments of approximately $27 million and $36 million, respectively.

Certain investments in debt and equity securities that have readily determinable market values, and for which the Company does not have control, are accounted for as available-for-sale securities at fair value in accordance with SFAS No. 115, 'Accounting for Certain Investments in Debt and Equity Securities.' These investments include investments held in trust funds, pursuant to the United States Nuclear Regulatory Commission (NRC) requirements, to fund certain costs of decommissioning nuclear plants. The fair value of these trust funds was

$1.044 billion and S938 million at December 31, 2004 and 2003, respectively. The Company also actively invests available cash balances in various financial instruments, such as tax-exempt debt securities that have stated maturities of 20 years or more. These instruments provide for a high degree of liquidity through arrangements with banks that provide daily and weekly liquidity and 7,28 and 35 day auctions that allow for the redemption of the investment at its face amount plus earned income. As the Company intends to sell these instruments generally within 30 days from the balance sheet date, they are classified as current assets. At December 31, 2004 and 2003, the fair value of these investments was $82 million 60

Progress Energy Annual Report 2004 and $226 million, respectively. Other investments in debt and equity securities are included in miscellaneous other property and investments in the Consolidated Balance Sheets. At December 31, 2004 and 2003, the fair value of these other investments was S39 million and

$39 million, respectively.

Other investments are stated principally at cost These cost method investments are included in miscellaneous other property and investments in the Consolidated Balance Sheets. At December 31, 2004, and 2003, the Company has approximately $14 million and $14 million, respectively, of cost method investments.

The results of operations of Rail are reported one month in arrears. During 2003, the Company ceased recording portions of the Fuels' segment operations one month in arrears. The net impact of this action increased net income by$2 million for the year.

Certain amounts for 2003 and 2002 have been reclassified to conform to the 2004 presentation.

Reclassifications include the reclassification of instruments used in PEC's cash management program from cash and cash equivalents to short-term investments of $226 million at December 31, 2003, in the Consolidated Balance Sheets. In the Consolidated Statements of Cash Flow for each of the three years in the period ended December 31, 2004, total cash balances and total cash flows used in investing activities were revised to reflect the reclassification of these instruments from cash and cash equivalents to short-term investments.

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

46R, "Consolidation of Variable Interest Entities -An Interpretation of ARB No. 51" (FIN No. 46R). The Company is the primary beneficiary of and consolidates two limited partnerships that qualify for federal affordable housing and historic tax credits under Section 42 of the Internal Revenue Code (Code). As of December 31,2004, the total assets of the two entities were $37 million, the majority of which are collateral for the entities' obligations and are included in other current assets and miscellaneous other property and investments in the Consolidated Balance Sheets.

The Company is the primary beneficiary of a limited partnership that invests in 17 low-income housing partnerships that qualify for federal and state tax credits.

The Company has requested but has not received all the necessary information to determine the primary beneficiary of the limited partnership's underlying 17 partnership investments, and has applied the information scope exception in FIN No. 46R, paragraph 4(g) to the 17 partnerships. The Company has no direct exposure to loss from the 17 partnerships; the Company's only exposure to loss is from its investment of less than $1 million in the consolidated limited partnership. The Company will continue its efforts to obtain the necessary information to fully apply FIN No.46R to the 17 partnerships. The Company believes that if the limited partnership is determined to be the primary beneficiary of the 17 partnerships, the effect of consolidating the 17 partnerships would not be significant to the Company's Consolidated Balance Sheets.

The Company has variable interests in two power plants resulting from long-term power purchase contracts. The Company has requested the necessary information to determine if the counterparties are variable interest entities or to identify the primary beneficiaries. Both entities declined to provide the Company with the necessary financial information, and the Company has applied the information scope exception in FIN No. 46R, paragraph 4(g). The Company's only significant exposure to variability from these contracts results from fluctuations in the market price of fuel used by the two entities' plants to produce the power purchased by the Company. The Company is able to recover these fuel costs under PEC's fuel clause. Total purchases from these counterparties were approximately $58 million, $53 million and $53 million in 2004, 2003 and 2002, respectively. The Company will continue its efforts to obtain the necessary information to fully apply FIN No. 46R to these contracts.

The combined generation capacity of the two entities' power plants is approximately 880 MW. The Company believes that if it is determined to be the primary beneficiary of these two entities, the effect of consolidating the entities would result in increases to total assets, long-term debt and other liabilities, butwould have an insignificant or no impact on the Company's common stock equity, net earnings or cash flows.

However, because the Company has not received any financial information from these two counterparties, the impact cannot be determined at this time.

The Company also has interests in several other variable interest entities for which the Company is not the primary beneficiary. These arrangements include investments in approximately 28 limited partnerships, limited liability corporations and venture capital funds and two building leases with special-purpose entities.

61

V Notes to Consolidated Financial Statements The aggregate maximum loss exposure at December31,2004, that the Company could be required to record in its income statement as a result of these arrangements totals approximately $38 million. The creditors of these variable interest entities do not have recourse to the general credit of the Company in excess of the aggregate maximum loss exposure.

D. Significant Accounting Policies USE OF ESTIMATES AND ASSUMPTIONS In preparing consolidated financial statements that conform with GAAP, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the consolidated financial statements and amounts of revenues and expenses reflected during the reporting period. Actual results could differ from those estimates.

REVENUE RECOGNITION The Company recognizes electric utility revenues as service is rendered to customers. Operating revenues include unbilled electric utility revenues earned when service has been delivered but not billed by the end of the accounting period. Diversified business revenues are generally recognized at the time products are shipped or as services are rendered. Leasing activities are accounted for in accordance with SFAS No. 13, Accounting for Leases.' Revenues related to design and construction of wireless infrastructure are recognized upon completion of services for each completed phase of design and construction. Revenues from the sale of oil and gas production are recognized when title passes, net of royalties.

excise taxes of approximately S240 million, $217 million and $212 million, respectively, are included in utility revenues and taxes other than on income in the Consolidated Statements of Income.

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

Transition and Disclosure - An Amendment of FASB Statement No. 123" ISFAS No. 148), the estimated fair value of the Company's stock options is amortized to expense over the options' vesting period. The following table illustrates the effect on net income and earnings per share if the fair value method had been applied to all outstanding and unvested awards in each period:

(in millions except per share data) 2004 2003 2002 Net income, as reported

$759

$782

$528 Deduct Total stock option expense determined under fair value method for all awards, net of related tax effects 10 11 8

Pro forma net income

$749

$771 S520 Earnings per share Basic - as reported

$3.13

$3.30

$2.43 Basic - pro forma

$3.09

$3.25 S2.40 Diluted - as reported

$3.12

$3.28

$2.42 Diluted - pro forma

$3.08

$3.24

$2.39 See Note 2 for a discussion of newly issued accounting FUEL COST DEFERRALS guidance related to stock-based compensation.

Fuel expense includes fuel costs or recoveries that are deferred through fuel clauses established by the electric utilities' regulators. These clauses allow the utilities to recover fuel costs and portions of purchased power costs through surcharges on customer rates. These deferred fuel costs are recognized in revenues and fuel expenses as they are billable to customers.

EXCISE TAXES PEC and PEF collect from customers certain excise taxes levied by the state or local government upon the customers. PEC and PEF account for excise taxes on a gross basis. For the years ended December 31,2004,2003 and 2002, gross receipts tax, franchise taxes and other UTILITY PLANT Utility plant in service is stated at historical cost less accumulated depreciation. The Company capitalizes all construction-related direct labor and material costs of units of property as well as indirect construction costs.

Certain costs that would otherwise not be capitalized under GAAP are capitalized in accordance with regulatory treatment. The cost of renewals and betterments is also capitalized. Maintenance and repairs of property (including planned major maintenance activities), and replacements and renewals of items determined to be less than units of property, are charged to maintenance expense as incurred, with the exception of nuclear outages at PEF. Pursuant to a regulatory order, 62

Progress Energy Annual Report 2004 PEF accrues for nuclear outage costs in advance of scheduled outages, which occur every two years. The cost of units of property replaced or retired, less salvage, is charged to accumulated depreciation. Removal or disposal costs that do not represent SFAS No. 143,

'Accounting for Asset Retirement Obligations' (SFAS No.

143), are charged to a regulatory liability.

Allowance for funds used during construction (AFUDC) represents the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated assets. As prescribed in the regulatory uniform system of accounts, AFUDC is charged to the cost of the plant. The equity funds portion of AFUDC is credited to other income and the borrowed funds portion is credited to interest charges.

ASSET RETIREMENT OBLIGATIONS Effective January 1, 2003, the Company adopted the guidance in SFAS No. 143 to account for legal obligations associated with the retirement of certain tangible long-lived assets. The present value of retirement costs for which the Company has a legal obligation are recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period.

The liability is then accreted over time by applying an interest method of allocation to the liability.

The adoption of this statement had no impact on the income of the regulated entities, as the effects were offset by the establishment of a regulatory asset and a regulatory liability pursuant to SFAS No.71 (See Note 8A).

The North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (SCPSC) and the Florida Public Service Commission (FPSC) issued orders to authorize deferral of all prospective effects related to SFAS No. 143 as a regulatory asset or liability (See Note 8A). Therefore, SFAS No. 143 has no impact on the income of the regulated entities.

DEPRECIATION AND AMORTIZATION - UTILITY PLANT For financial reporting purposes, substantially all depreciation of utility plant other than nuclear fuel is computed on the straight-line method based on the estimated remaining useful life of the property, adjusted for estimated salvage (See Note 6A). Pursuant to their rate-setting authority, the NCUC, SCPSC and FPSC can also grant approval to accelerate or reduce depreciation and amortization of utility assets (See Note 8).

Amortization of nuclear fuel costs is computed primarily on the units-of-production method. In the Company's retail jurisdictions, provisions for nuclear decommissioning costs are approved bythe NCUC,the SCPSC and the FPSC and are based on site-specific estimates that include the costs for removal of all radioactive and other structures at the site. In the wholesale jurisdictions, the provisions for nuclear decommissioning costs are approved by the Federal Energy Regulatory Commission (FERC).

CASH AND CASH EQUIVALENTS The Company considers cash and cash equivalents to include unrestricted cash on hand, cash in banks and temporary investments purchased with a maturity of three months or less.

INVENTORY The Company accounts for inventory using the average-cost method. Inventories are valued at the lower of average cost or market.

REGULATORY ASSETS AND LIABILITIES The Company's regulated operations are subject to SFAS No. 71, which allows a regulated companyto record costs that have been or are expected to be allowed in the ratemaking process in a period differentfrom the period in which the costs would be charged to expense by a nonregulated enterprise. Accordingly, the Company records assets and liabilities that result from the regulated ratemaking processthatwould not be recorded under GAAP for nonregulated entities. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the Consolidated Balance Sheets as regulatory assets and regulatory liabilities (See Note 8A).

DIVERSIFIED BUSINESS PROPERTY Diversified business property is stated at cost less accumulated depreciation. If an impairment is recognized on an asset, the fair value becomes its new cost basis.

The costs of renewals and betterments are capitalized.

The cost of repairs and maintenance is charged to expense as incurred. For properties other than oil and gas properties, depreciation is computed on a straight-line basis using the estimated useful lives disclosed in Note 6B. Depletion of mineral rights is provided on the units-of-production method based upon the estimates of recoverable amounts of clean mineral.

The Company uses the full-cost method to account for its oil and gas properties. Under the full-cost method, substantially all productive and nonproductive costs 63

V Notes to Consolidated Financial Statements incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized.

These capitalized costs include the costs of all unproved properties and internal costs directly related to acquisition and exploration activities. The amortization base also includes the estimated future cost to develop proved reserves. Except for costs of unproved properties and major development projects in progress, all costs are amortized using the units-of-production method on a country by country basis over the life of the Company's proved reserves. Accordingly, all property acquisition, exploration, and development costs of proved oil and gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized as incurred, including internal costs directly attributable to such activities. Related interest expense incurred during property development activities is capitalized as a cost of such activity. Net capitalized costs of unproved property are reclassified as proved property and well costs when related proved reserves are found. Costs to operate and maintain wells and field equipment are expensed as incurred. In accordance with Rule 4-10 of Regulation S-X, sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless certain significance tests are met.

GOODWILL AND INTANGIBLE ASSETS Goodwill is subject to at least an annual assessment for impairment by applying a two-step fair-value-based test.

This assessment could result in periodic impairment charges. Intangible assets are being amortized based on the economic benefit of their respective lives.

UNAMORTIZED DEBT PREMIUMS, DISCOUNTS AND EXPENSES Long-term debt premiums, discounts and issuance expenses are amortized over the terms of the debt issues. Any expenses or call premiums associated with the reacquisition of debt obligations by the utilities are amortized over the applicable life using the straight-line method consistent with ratemaking treatment (See Note 8A).

INCOME TAXES The Company and its affiliates file a consolidated federal income tax return. Deferred income taxes have been provided for temporary differences. These occur when there are differences between the book and tax carrying amounts of assets and liabilities. Investment tax credits related to regulated operations have been deferred and are being amortized over the estimated service life of the related properties. Credits for the production and sale of synthetic fuel are deferred as AMT credits to the extent they cannot be or have not been utilized in the annual consolidated federal income tax returns, and are included in income tax expense (benefit) in the Consolidated Statements of Income.

DERIVATIVES The Company accounts for derivative instruments in accordance with SFAS No. 133, 'Accounting for Derivative Instruments and Hedging Activities' (SFAS No. 133), as amended by SFAS No. 138 and SFAS No. 149.

SFAS No. 133, as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS No. 133 requires that an entity recognize all derivatives as assets or liabilities in the balance sheet and measure those instruments at fair value, unless the derivatives meet the SFAS No. 133 criteria for normal purchases or normal sales and are designated as such. The Company generally designates derivative instruments as normal purchases or normal sales whenever the SFAS No. 133 criteria are met. If normal purchase or normal sale criteria are not met, the Company will generally designate the derivative instruments as cash flow or fair value hedges if the related SFAS No. 133 hedge criteria are met. During 2003, the FASB reconsidered an interpretation of SFAS No. 133. See Note 18 for the effect of the interpretation and additional information regarding risk management activities and derivative transactions.

ENVIRONMENTAL As discussed in Note 22, the Company accrues environmental remediation liabilities when the criteria for SFAS No. 5, 'Accounting for Contingencies" (SFAS No.

5), have been met. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed.

Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as additional information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recognized when their receipt is deemed probable.

Environmental expenditures that have future economic benefits are capitalized in accordance with the Company's asset capitalization policy.

64

Progress Energy Annual Report 2004 IMPAIRMENT OF LONG-LIVED ASSETS AND INVESTMENTS As discussed in Note 10, the Company reviews the recoverability of long-lived tangible and intangible assets whenever indicators exist Examples of these indicators include current period losses, combined with a history of losses or a projection of continuing losses, or a significant decrease in the market price of a long-lived asset group.

If an indicator exists for assets to be held and used, then the asset group is tested for recoverability by comparing the carrying value to the sum of undiscounted expected future cash flows directly attributable to the asset group.

If the asset group is not recoverable through undiscounted cash flows or the asset group is to be disposed of, then an impairment loss is recognized for the difference between the carrying value and the fair value of the asset group. The accounting for impairment of assets is based on SFAS No. 144, 'Accounting for the Impairment or Disposal of Long-Lived Assets."

The Company reviews its investments to evaluate whether or not a decline in fair value below the carrying value is an other-than-temporary decline. The Company considers various factors, such as the investee's cash position, earnings and revenue outlook, liquidity and management's ability to raise capital in determining whether the decline is other-than-temporary. If the Company determines that an other-than-temporary decline exists in the value of its investments, it is the Company's policy to write-down these investments to fair value.

Under the full-cost method of accounting for oil and gas properties, total capitalized costs are limited to a ceiling based on the present value of discounted (at 10%) future net revenues using current prices, plus the lower of cost or fair market value of unproved properties. The ceiling test takes into consideration the prices of qualifying cash flow hedges as of the balance sheet date. If the ceiling (discounted revenues) is not equal to or greaterthan total capitalized costs, the Company is required to write-down capitalized costs to this level. The Company performs this ceiling test calculation every quarter. No write-downs were required in 2004, 2003 or 2002.

SUBSIDIARY STOCK TRANSACTIONS Gains and losses realized as a result of common stock sales by the Company's subsidiaries are recorded in the Consolidated Statements of Income, except for any transactions that must be credited directly to equity in accordance with the provisions of Staff Accounting Bulletin No. 51, 'Accounting for Sales of Stock by a Subsidiary."

2.

NEW ACCOUNTING STANDARDS FASB STAFF POSITION 106-2, 'ACCOUNTING AND DISCLOSURE REQUIREMENTS RELATED TO THE MEDICARE PRESCRIPTION DRUG IMPROVEMENT AND MODERNIZATION ACT OF 2003" In December 2003, the Medicare Prescription Drug Improvement and Modernization Act of 2003 (Medicare Act) was signed into law. In accordance with guidance issued by the Financial Accounting Standards Board (FASB) in FASB Staff Position 106-1, 'Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003" (FASB Staff Position 106-1), the Company elected to defer accounting for the effects of the Medicare Act due to uncertainties regarding the effects of the implementation of the Medicare Act and the accounting for certain provisions of the Medicare Act In May 2004, the FASB issued definitive accounting guidance for the Medicare Act in FASB Staff Position 106-2, which was effective for the Company in the third quarter of 2004.

FASB Staff Position 106-2 results in the recognition of lower other postretirement employment benefit (OPEB) costs to reflect prescription drug-related federal subsidies to be received under the Medicare Act As a result of the Medicare Act, the Company's accumulated postretirement benefit obligation as of January 1, 2004, was reduced by approximately $83 million, and the Company's 2004 net periodic cost was reduced by approximately $13 million.

SFAS NO.

123 (REVISED 2004),

SHARE-BASED PAYMENT' (SFAS NO. 123R)

In December 2004, the FASB issued SFAS No. 123R, which revises SFAS No. 123, 'Accounting for Stock-Based Compensation," and supersedes Accounting Principles Board {APB) Opinion No. 25, "Accounting for Stock Issued to Employees." The key requirement of SFAS No. 123R is that the cost of share-based awards to employees will be measured based on an award's fair value at the grant date, with such cost to be amortized over the appropriate service period. Previously, entities could elect to continue accounting for such awards at their grant date intrinsic value under APB Opinion No. 25, and the Company made that election. The intrinsic value method resulted in the Company recording no compensation expense for stock options granted to employees (See Note 11).

SFAS No. 123R will be effective for the Company on July 1, 2005. The Company intends to implement the standard using the required modified prospective method. Under that method, the Company will record 65

V Notes to Consolidated Financial Statements compensation expense under SFAS No. 123R for all awards it grants after July 1, 2005, and it will record compensation expense (as previous awards continue to vest) for the unvested portion of previously granted awards that remain outstanding at July 1, 2005. In 2004, the Company made the decision to cease granting stock options and intends to replace that compensation program with other programs. Therefore, the amount of stock option expense expected to be recorded in 2005 is below the amount that would have been recorded if the stock option program had continued. The Company expects to record approximately $3 million of pre-tax expense for stock options in 2005.

PROPOSED FASB INTERPRETATION OF SFAS NO. 109, "ACCOUNTING FOR INCOME TAXES" In July 2004, the FASB stated that it plans to issue an exposure draft of a proposed interpretation of SFAS No.

109, Accounting for Income Taxes" (SFAS No. 109), that would address the accounting for uncertain tax positions. The FASB has indicated that the interpretation would require that uncertain tax benefits be probable of being sustained in order to record such benefits in the consolidated financial statements. The exposure draft is expected to be issued in the first quarter of 2005. The Company cannot predict what actions the FASB will take or how any such actions might ultimately affect the Company's financial position or results of operations, but such changes could have a material impact on the Company's evaluation and recognition of Section 29 tax credits (See Note 23E).

3. HURRICANE-RELATED COSTS Hurricanes Charley, Frances, Ivan and Jeanne struck significant portions of the Company's service territories during the third quarter of 2004, significantly impacting PEF's territory. As of December 31, 2004, restoration of the Company's systems from hurricane-related damage was estimated at S398 million. PEC incurred restoration costs of $13 million, of which $12 million was charged to operation and maintenance expense and $1 million was charged to capital expenditures. PEF had estimated total costs of $385 million, of which $47 million was charged to capital expenditures, and S338 million was charged to the storm damage reserve pursuant to a regulatory order.

In accordance with a regulatory order, PEF accrues

$6 million annually to a storm damage reserve and is allowed to defer losses in excess of the accumulated reserve for major storms. Under the order, the storm reserve is charged with operation and maintenance expenses related to storm restoration and with capital expenditures related to storm restoration that are in excess of expenditures assuming normal operating conditions. As of December 31, 2004, $291 million of hurricane restoration costs in excess of the previously recorded storm reserve of $47 million had been classified as a regulatory asset recognizing the probable recoverability of these costs. On November 2, 2004, PEF filed a petition with the FPSC to recover $252 million of storm costs plus interest from retail ratepayers over a two-year period. Storm reserve costs of $13 million were attributable to wholesale customers. The Company has received approval from the FERC to amortize these costs consistent with recovery of such amounts in wholesale rates. PEF continues to review the restoration cost invoices received. Given that not all invoices have been received as of December 31, 2004, PEF will update its petition with the FPSC upon receipt and audit of all actual charges incurred. Hearings on PEF's petition for recovery of $252 million of storm costs filed with the FPSC are scheduled to begin on March 30, 2005.

On November 17, 2004, the Citizens of the State of Florida, by and through Harold McLean, Public Counsel, and the Florida Industrial Power Users Group (FIPUG),

(collectively, Joint Movants), filed a Motion to Dismiss PEF's petition to recover the $252 million in storm costs.

On November 24, 2004, PEF responded in opposition to the motion, which was also the FPSC staff's position in its recommendation to the Commission on December 21, 2004, that it should deny the Motion to Dismiss. On January 4,2005, the Commission ruled in favor of PEF and denied Joint Movant's Motion to Dismiss.

PEF's January 2005 notice to the FPSC of its intent to file for an increase in its base rates effective January 1, 2006, anticipates the need to replenish the depleted storm reserve balance and adjustthe annual $6 million accrual in light of recent storm history to restore the reserve to an adequate level over a reasonable time period (See Note 8C).

PEC does not have an ongoing regulatory mechanism to recover storm costs; therefore, hurricane restoration costs recorded in the third quarter of 2004 were charged to operations and maintenance expenses or capital expenditures based on the nature of the work performed.

In connection with other storms, PEC has previously sought and received permission from the NCUC and the SCPSC to defer storm expenses and amortize them over a five-year period. PEC did not seek deferral of 2004 storm costs from the NCUC (See Note 8B).

66

Progress Energy Annual Report 2004

4. DIVESTITURES A. Sale of Natural Gas Assets In December 2004, the Company sold certain gas-producing properties and related assets owned by Winchester Production Company, Ltd. (Winchester Production), an indirectly wholly owned subsidiary of Progress Fuels Corporation (Progress Fuels), which is included in the Fuels segment. Net proceeds of approximately S251 million were used to reduce debt Because the sale significantly altered the ongoing relationship between capitalized costs and remaining proved reserves, under the full-cost method of accounting, the pre-tax gain of $56 million was recognized in earnings rather than as a reduction of the basis of the Company's remaining oil and gas properties.

The pre-tax gain has been included in (gain)Iloss on the sale of assets in the Consolidated Statements of Income.

B. Divestiture of Synthetic Fuel Partnership Interests In June 2004, the Company through its subsidiary, Progress Fuels, sold, in two transactions, a combined 49.8%

partnership interest in Colona Synfuel Limited Partnership, LLLP, one of its synthetic fuel facilities. Substantially all proceeds from the sales will be received over time, which is typical of such sales in the industry. Gain from the sales will be recognized on a cost recovery basis. The Company's book value of the interests sold totaled approximately

$5 million. The Company received total gross proceeds of

$10 million in 2004. Based on projected production and tax credit levels, the Company anticipates receiving approximately S24 million in 2005, approximately $31 million in 2006, approximately$32 million in 2007, and approximately S8 million through the second quarter of 2008. In the event that the synthetic fuel tax credits from the Colona facility are reduced, including an increase in the price of oil that could limit or eliminate synthetic fuel tax credits, the amount of proceeds realized from the sale could be significantly impacted.

C. Railcar Ltd., Divestiture In December 2002, the Progress Energy Board of Directors adopted a resolution approving the sale of Railcar Ltd., a subsidiary included in the Rail Services segment. An estimated pre-tax impairment of $59 million on assets held for sale was recognized in December 2002 to write-down the assets to fair value less costs to sell.

This impairment has been included in impairment of long-lived assets in the Consolidated Statements of Income (See Note 10A). In March 2003, the Company signed a letter of intent to sell the majority of Railcar Ltd. assets to The Andersons, Inc., and the transaction closed in February 2004.

Proceeds from the sale were approximately $82 million before transaction costs and taxes of approximately $13 million. In July 2004, the Company sold the remaining assets classified as held for sale to a third-party for net proceeds of $6 million. The assets of Railcar Ltd. were grouped as assets held for sale and were included in other current assets on the Consolidated Balance Sheets at December 31, 2003, at approximately $75 million, which reflected the Company's estimates of the fair value expected to be realized from the sale of these assets less costs to sell.

D. Mesa Hydrocarbons, Inc., Divestiture In October 2003, the Company sold certain gas-producing properties owned by Mesa Hydrocarbons, LLC, a wholly owned subsidiary of Progress Fuels. Net proceeds were approximately $97 million. Because the Company utilizes the full-cost method of accounting for its oil and gas operations, the pre-tax gain of approximately $18 million was applied to reduce the basis of the Company's other U.S. oil and gas investments and will prospectively result in a reduction of the amortization rate applied to those investments as production occurs.

E. NCNG Divestiture On September 30, 2003, the Company completed the sale of North Carolina Natural Gas Corporation (NCNG) and the Company's equity investment in Eastern North Carolina Natural Gas Company (ENCNG) to Piedmont Natural Gas Company, Inc. Net proceeds from the sale of NCNG of approximately $443 million were used to reduce debt.

The consolidated financial statements have been restated for all periods presented for the discontinued operations of NCNG. The net income of these operations is reported as discontinued operations in the Consolidated Statements of Income. Interest expense of

$10 million and $16 million for the years ended December 31, 2003 and 2002, respectively, has been allocated to discontinued operations based on the net assets of NCNG, assuming a uniform debt-to-equity ratio across the Company's operations. The Company ceased recording depreciation effective October 1, 2002, upon classification of the assets as discontinued operations.

After-tax depreciation expense recorded by NCNG for the year ended December 31, 2002, was $9 million.

Results of discontinued operations for years ended December 31 were as follows:

67

V Notes to Consolidated Financial Statements (in millionsJ Revenues Earnings before income taxes Income tax expense Net earnings from discontinued operations Gain/l(Loss) on disposal of discontinued operations, including applicable income tax benefit/lexpense) of $6, S1 and $3. respectively Earnings (loss) from discontnued operations 2004 2003

$284

$6 2

4 2002

$3D0

$9 4

5 6

(12)

(29)

S6

$(8)

S(24)

During 2004, the Company recorded an additional tax gain of approximately $6 million due to final tax adjustments related to the divestiture of NCNG.

The sale of ENCNG resulted in net proceeds of S7 million and a pre-tax loss of $2 million, which is included in other, net on the Consolidated Statements of Income for the year ended December 31, 2003.

5. ACQUISITIONS AND BUSINESS COMBINATIONS A. Progress Telecommunications Corporation In December

2003, Progress Telecommunications Corporation (PTC) and Caronet, Inc. (Caronet), both wholly owned subsidiaries of Progress Energy, and EPIK Communications, Inc. (EPIK), a wholly owned subsidiary of OdysseyTelecorp, Inc. (Odyssey), contributed substantially all of their assets and transferred certain liabilities to Progress Telecom, LLC (PT LLC), a subsidiary of PTC.

Subsequently, the stock of Caronet was sold to an affiliate of Odyssey for $2 million in cash and Caronet became a wholly owned subsidiary of Odyssey. Following consummation of all the transactions described above, PTC holds a 55% ownership interest in, and is the parent of, PT LLC. Odyssey holds a combined 45% ownership interest in PT LLC through EPIK and Caronet The accounts of PT LLC have been included in the Company's Consolidated Financial Statements since the transaction date.

The transaction was accounted for as a partial acquisition of EPIK through the issuance of the stock of a consolidated subsidiary. The contributions of PTC's and Caronet's net assets were recorded at their carrying values of approximately $31 million. EPIK's contribution was recorded at its estimated fair value of $22 million using the purchase method. No gain or loss was recognized on the transaction. The EPIK purchase price was initially allocated as follows: property and equipment

- $27 million; other current assets - $9 million; current liabilities - $21 million; and goodwill - $7 million. During 2004, PT LLC developed a restructuring plan to exit certain leasing arrangements of EPIK and finalized its valuation of acquired assets and liabilities. Management considered a number of factors, including valuations and appraisals, when making these determinations. Based on the results of these activities, the preliminary purchase price allocation for EPIK was revised as follows at December 31, 2004: property and equipment-S36 million; other current assets - $7 million; intangible assets -

$1 million; current liabilities -$18 million; and exit costs -

$4 million. The exit costs consist primarily of lease termination penalties and noncancelable lease payments made after certain leased properties are vacated. The pro forma results of operations reflecting the acquisition would not be materially different than the reported results of operations for 2003 or 2002.

B. Acquisition of Natural Gas Reserves During 2003, Progress Fuels entered into several independent transactions to acquire approximately 200 natural gas-producing wells with proven reserves of approximately 190 billion cubic feet (Bcf) from Republic Energy, Inc., and three other privately owned companies, all headquartered in Texas. The total cash purchase price forthe transactions was $168 million. The pro forma results of operations reflecting the acquisition would not be materially different from the reported results of operations for the years ended December 31,2003 and 2002.

C. Wholesale Energy Contract Acquisition In May 2003, PVI entered into a definitive agreement with Williams Energy Marketing and Trading, a subsidiary of The Williams Companies, Inc.,to acquire a long-term full-requirements power supply agreement at fixed prices with Jackson Electric Membership Corporation (Jackson), located in Jefferson, Georgia. The agreement calls for a $188 million cash payment to Williams Energy Marketing and Trading in exchange for assignment of the Jackson supply agreement; the $188 million cash payment was recorded as an intangible asset and is being amortized based on the economic benefit of the contract (See Note 9). The power supply agreement terminates in 2015, with a first refusal right to extend for five years. The agreement includes the use of 640 megawatts (MW) of contracted Georgia System generation comprised of nuclear, coal, gas and pumped-storage hydro resources. PVI expects to supplement the acquired resources with open market purchases and with its own intermediate and peaking assets in Georgia to serve Jackson's forecasted 1,100 MW peak demand in 2005 growing to a forecasted 1,700 MW demand by 2015.

68

Progress Energy Annual Report 2004 D. Westchester Acquisition In April 2002, Progress Fuels, a subsidiary of Progress Energy, acquired 100% of Westchester Gas Company (Westchester). During 2004 the name of the company was changed to Winchester Energy Co. Ltd. The acquisition included approximately 215 natural gas-producing wells, 52 miles of intrastate gas pipeline and 170 miles of gas-gathering systems located within a 25-mile radius of Jonesville, Texas, on the Texas-Louisiana border.

The aggregate purchase price of approximately

$153 million consisted of cash consideration of approximately $22 million and the issuance of 2.5 million shares of Progress Energy common stock then valued at approximately $129 million. The purchase price included approximately $2 million of direct transaction costs. The final purchase price was allocated to oil and gas properties, intangible assets, diversified business property, networking capital and deferred tax liabilities for approximatelySi52 million,$9 million,$32 million,$5 million and $45 million, respectively. The $9 million intangible assets relates to customer contracts (See Note 9).

Marketing, Inc., for each project and S23 million was assigned to interconnection contracts. Goodwill was assigned to the CCO segment and will be deductible for tax purposes.

The pro forma results of operations reflecting the acquisition would not be materially different from the reported results of operations for the year ended December 31, 2002.

6. PROPERTY, PLANT AND EQUIPMENT A. Utility Plant The balances of electric utility plant in service at December31 are listed below, with a range of depreciable lives for each:

(in millions) 2004 2003 Production plant 17-33 years)

$11,966 S12,044 Transmission plant (30-75 years) 2,282 2,167 Distribution plant (12-50 years) 6.749 6,432 General plant and other (8-75 years) 1.106 1,037 Utility plant in service

$22103

$21,680 The acquisition has been accounted for using the purchase method of accounting and, accordingly, the results of operations forWestchester have been included in Progress Energy's Consolidated Financial Statements since the date of acquisition. The pro forma results of operations reflecting the acquisition would not be materially different from the reported results of operations for the year ended December 31,2002.

E. Generation Acquisition In February 2002, PVI acquired 100% of two electric generating projects located in Georgia from LG&E Energy Corp., a subsidiary of Powergen plc. The two projects consist of 1) Walton County Power, LLC, in Monroe, Georgia, a 460 MW natural gas-fired plant placed in service in June 2001 and 2) Washington County Power, LLC, in Washington County, Georgia, a 600 MW natural gas-fired plant placed in service in June 2003. The Walton and Washington projects have been accounted for using the purchase method of accounting and, accordingly, have been included in the Consolidated Financial Statements since the acquisition date.

In the final allocation, the aggregate cash purchase price of approximately S348 million was allocated to diversified business property, intangibles and goodwill for$228 million,

$56 million and S64 million, respectively (See Note 9). Of the acquired intangible assets, $33 million was assigned to tolling and power sale agreements with LG&E Energy Generally, electric utility plant at PEC and PEF, other than nuclear fuel, is pledged as collateral for the first mortgage bonds of PEC and PEF, respectively.

AFUDC represents the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated assets. As prescribed in the regulatory uniform systems of accounts, AFUDC is charged to the cost of the plant. The equity funds portion of AFUDC is credited to other income, and the borrowed funds portion is credited to interest charges. Regulatory authorities consider AFUDC an appropriate charge for inclusion in the rates charged to customers by the utilities over the service life of the property. The composite AFUDC rate for PEC's electric utility plant was 7.2% in 2004, 4.0% in 2003 and 6.2% in 2002, respectively.

The composite AFUDC rate for PEF's electric utility plant was 7.8% in 2004, 2003 and 2002.

Depreciation provisions on utility plant, as a percent of average depreciable property otherthan nuclearfuel,were 2.2%, 2.5% and 2.6% in 2004, 2003 and 2002, respectively.

The depreciation provisions related to utility plant were

$463 million, $517 million and $488 million in 2004, 2003 and 2002, respectively. In addition to utility plant depreciation provisions, depreciation and amortization expense also includes decommissioning cost provisions, asset retirement obligation (ARO) accretion, cost of removal 69

V Notes to Consolidated Financial Statements provisions (See Note 6D), regulatory approved expenses (See Note 8 and Note 22) and NC Clean Air Legislation amortization (See Note 8B).

During 2004, PEC met the requirements of both the NCUC and the SCPSC for the implementation of two depreciation studies that allowed the utility to reduce the rates used to calculate depreciation expense. The annual reduction in depreciation expense is approximately

$82 million. The reduction is due primarily to extended lives at each of PEC's nuclear units. The new depreciation rates were effective January 1, 2004.

Amortization of nuclear fuel costs, including disposal costs associated with obligations to the U.S. Department of Energy (DOE) and costs associated with obligations to the DOE for the decommissioning and decontamination of enrichment facilities, for the years ended December 31, 2004,2003 and 2002 were S140 million, S143 million and $141 million, respectively, and are included in fuel used for electric generation in the Consolidated Statements of Income.

B. Diversified Business Property The balances of diversified business property at December 31 are listed below, with a range of depreciable lives for each:

(in millions) 2004 2003 Equipment (3-25 years)

£383

£246 Nonregulated generation plant and equipment (3-40 years) 1,302 1,299 Land and mineral rights 107 93 Buildings and plants (5-40 years) 131 125 Oil and gas properties (units-of-production) 336 412 Telecommunications equipment (5-20years) 80 63 Rail equipment (3-20 years) 29 125 Marine equipment (3-35 years) 87 83 Computers, office equipment and software (3-10 years) 36 36 Construction work in progress 26 13 Accumulated depreciation (507)

(400)

Diversified business property, net

$2.010 S 2,095 The synthetic fuel facilities are being depreciated through 2007 when the Section 29 tax credits will expire. The Company's nonregulated businesses capitalize interest costs under SFAS No.34, 'Capitalization of Interest Costs.'

During the years ended December 31,2004,2003 and 2002, respectively, the Company capitalized $7 million,

$20 million and $38 million, respectively, of its interest cost of $660 million, $655 million and $679 million. Capitalized interest for 2004 is related to the expansion of Fuels' gas operations. Capitalized interest in 2003 and 2002 is related to the expansion of its nonregulated generation portfolio at PVI. Capitalized interest is included in diversified business property, net on the Consolidated Balance Sheets. Diversified business depreciation expense was $148 million, $120 million and $85 million for December 31, 2004, 2003 and 2002, respectively.

C. Joint Ownership of Generating Facilities PEC and PEF hold ownership interests in certain jointly owned generating facilities. Each is entitled to shares of the generating capability and output of each unit equal to their respective ownership interests. Each also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. PEC's and PEF's share of expenses for the jointly owned facilities is included in the appropriate expense category. The co-owner of Intercession City Unit P11 (P11) has exclusive rights to the output of the unit during the months of June through September. PEF has that right for the remainder of the year. PEC's and PEF's ownership interests in the jointly owned generating facilities are listed on the following table with related information at December 31 ($ in millions):

70

Progress Energy Annual Report 2004 2004 Company Construction Ownership Plant Accumulated Work in Subsidiary Facility Interest Investment Depreciation Progress PEC Mayo Plant 83.83%

5516 S249 S1 PEC Harris Plant 83.83%

3,185 1.387 13 PEC Brunswick Plant 81.67%

1,624 888 28 PEC Roxboro Unit 4 87.06%

323 147 1

PEF Crystal River Unit 3 91.78%

889 443 9

PEF Intercession City Unit P11 66.67%

22 7

8 2003 Company Construction Ownership Plant Accumulated Work in Subsidiary Facility Interest Investment Depreciation Progress PEC Mayo Plant 83.83%

S464

$242 550 PEC Harris Plant 83.83%

3,248 1,424 7

PEC Brunswick Plant 81.67%

1,611 885 21 PEC Roxboro Unit 4 87.06%

323 139 1

PEF Crystal River Unit 3 91.78%

875 442 46 PEF Intercession City Unit PI1 66.67%

22 6

6 In the tables above, plant investment and accumulated depreciation are not reduced by the regulatory disallowances related to the Shearon Harris Nuclear Plant (Harris Plant).

D. Asset Retirement Obligations At December 31, 2004 and 2003, the asset retirement costs related to nuclear decommissioning of irradiated plant, net of accumulated depreciation, totaled $277 million and

$354 million, respectively. Funds set aside in the Company's nuclear decommissioning trust funds for the nuclear decommissioning liability totaled $1.044 billion and

$938 million at December 31, 2004 and 2003, respectively.

Net nuclear decommissioning trust unrealized gains are included in regulatory liabilities (See Note 8A).

Decommissioning cost provisions, which are included in depreciation and amortization expense, were $31 million in each of 2004, 2003 and 2002. Management believes that decommissioning costs that have been and will be recovered through rates by PEC and PEF will be sufficient to provide for the costs of decommissioning. The Company's expenses recognized for the disposal or removal of utility assets that are not SFAS No. 143 asset removal obligations, which are included in depreciation and amortization expense, were $160 million, $158 million and $149 million in 2004, 2003 and 2002, respectively.

The utilities recognize

removal, nonirradiated decommissioning and dismantlement costs in regulatory liabilities on the Consolidated Balance Sheets (See Note 8A). At December 31, 2004, such costs consist of removal costs of $1.606 billion, removal costs for nonirradiated areas at nuclear facilities of $131 million and amounts previously collected for dismantlement of fossil generation plants of $144 million. At December 31, 2003, such costs consist of removal costs of $1.846 billion, removal costs for nonirradiated areas at nuclearfacilities of $129 million and amounts previously collected for dismantlement of fossil generation plants of $143 million.

During 2004, PEC reduced its estimated removal costs to take into account the estimates used in the depreciation studies implemented during 2004 (See Note 6A). This resulted in a downward revision in the PEC estimated removal costs and equal increase in accumulated depreciation of approximately $345 million.

PEC's most recent site-specific estimates of decommissioning costs were developed in 2004, using 2004 cost factors, and are based on prompt dismantlement decommissioning, which reflects the cost of removal of all radioactive and other structures currently at the site, with such removal occurring after operating license expiration. These estimates, in 2004 dollars, are $294 million for Robinson Unit No. 2,

$290 million for Brunswick Unit No. 1, $313 million for Brunswick Unit No. 2 and $359 million for the Harris Plant. The estimates are subject to change based on a variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning and changes in federal, state or local regulations. The cost estimates exclude the portion attributable to North Carolina Eastern Municipal Power 71

V Notes to Consolidated Financial Statements Agency (Power Agency), which holds an undivided ownership interest in the Brunswick and Harris nuclear generating facilities. NRC operating licenses held by PEC currently expire in December 2014 and September 2016 for Brunswick Units 2 and 1, respectively. An application to extend these licenses 20 years was submitted in October2004. The NRC operating license held by PECfor the Harris Plant currently expires in October 2026. An application to extend this license 20 years is expected to be submitted in the fourth quarter of 2006. On April 19, 2004, the NRC announced that it has renewed the operating license for PEC's Robinson Nuclear Plant (Robinson) for an additional 20 years through July 2030.

PEF's most recent site-specific estimate of decommissioning costs for the Crystal River Nuclear Unit 3 (CR3) was developed in 2000 based on prompt dismantlement decommissioning. The estimate, in 2000 dollars, is $491 million and is subject to change based on the same factors as discussed above for PEC's estimates. The cost estimate excludes the portion attributable to other co-owners of CR3. The NRC operating license held by PEF for CR3 currently expires in December 2016. An application to extend this license 20 years is expected to be submitted in the first quarter of 2009.

The Company has identified but not recognized AROs related to electric transmission and distribution and telecommunications assets as the result of easements over property not owned bythe Company. These easements are generally perpetual and require retirement action only upon abandonment or cessation of use of the property for the specified purpose. The ARO is not estimable for such easements, as the Company intends to utilize these properties indefinitely. In the eventthe Company decides to abandon or cease the use of a particular easement, an ARO would be recorded at that time.

The Company's nonregulated AROs relate to coal mine operations, synthetic fuel operations and gas production of Progress Fuels.The related asset retirement costs, net of accumulated depreciation, totaled $10 million and S5 million at December 31, 2004 and 2003, respectively.

The following table shows the changes to the asset retirement obligations. Additions relate primarily to additional reclamation obligations at coal mine operations of Progress Fuels. The deductions to regulated ARO related to PEC re-measuring the nuclear decommissioning costs of irradiated plants to take into account updated site-specific decommissioning cost studies, which are required by the NCUC every five years.

(in millions)

Regulated Nonregulated Asset retirement obligations as of January 1, 2003 S1,183 S10 Additions 11 Accretion expense 68 1

Deductions (2)

Asset retirement obligations as of December 31, 2003 1,251 20 Additions 6

Accretion expense 73 2

Deductions (63)

(7)

Asset retirement obligations asofDecember31,2004 S1,261

$21 The cumulative effect of initial adoption of this statement related to nonregulated operations was $1 million of income, which is included in cumulative effect of change in accounting principles, net of tax on the Consolidated Statements of Income for the year ended December 31, 2003. Pro forma net income has not been presented for prior years because the pro forma application of SFAS No. 143 to prior years would result in pro forma net income not materially different from the actual amounts reported.

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

coverage, NEIL also provides decontamination, premature decommissioning and excess property insurance with limits of $2.0 billion on the Brunswick and Harris plants, and $1.1 billion on the Robinson Plant and CR3.

Insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at nuclear generating units is also provided through membership in NEIL Both PEC and PEF are insured under NEIL, following a 12-week deductible period, for 52 weeks in the amount of $3 million per week at the Brunswick and Harris plants, $2.5 million per week at the Robinson Plant and $4.5 million per week at CR3.

An additional 110 weeks (71 weeks for CR3) of coverage is provided at 80% of the above weekly amounts.

For the current policy period, the companies are subject to retrospective premium assessments of up to approximately $29.3 million with respect to the primary coverage, S32.4 million with respect to the decontamination, decommissioning and excess property 72

Progress Energy Annual Report 2004 coverage, and $20.2 million for the incremental replacement power costs coverage, in the event covered losses at insured facilities exceed premiums, reserves, reinsurance and other NEIL resources. Pursuant to regulations of the NRC, each company's property damage insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and stable condition after an accident and, second, to decontaminate, before any proceeds can be used for decommissioning, plant repair or restoration. Each company is responsible to the extent losses may exceed limits of the coverage described above.

Both PEC and PEF are insured against public liability for a nuclear incident up to$10.8 billion per occurrence. Under the current provisions of the Price Anderson Act, which limits liability for accidents at nuclear power plants, each company, as an owner of nuclear units, can be assessed for a portion of any third-party liability claims arising from an accident at any commercial nuclear power plant in the United States. In the event that public liability claims from an insured nuclear incident exceed $300 million (currently available through commercial insurers), each company would be subjectto pro rata assessments of up to $101 million for each reactor owned per occurrence.

Payment of such assessments would be made over time as necessary to limit the payment in any one year to no more than $10 million per reactor owned. Congress could possibly approve revisions to the Price Anderson Act during 2005 that could include increased limits and assessments per reactor owned. The final outcome of this matter cannot be predicted at this time.

damage reserve pursuant to a regulatory order and may defer losses in excess of the reserve (See Notes 3 and 8A).

7. CURRENT ASSETS Receivables At December 31, receivables were comprised of:

(in millions) 2004 2003 Trade accounts receivable

$689

$705 Unbilled accounts receivable 271 293 Notes receivable 98 61 Other receivables 27 47 Unbilled other receivables 28 10 Allowance for doubtful accounts receivable (29)

(32)

Total receivables

$1,084

$1,084 Income tax receivables and interest income receivables are not included in this classification.These amounts are in prepaids and other current assets on the Consolidated Balance Sheet.

Inventory At December 31, inventory was comprised of:

(in millions) 2004 2003 Fuel for production

$235

$210 Inventoryforsale 230 167 Materials and supplies 517 530 Total inventory

$982 S907 Under the NEIL policies, if there were multiple terrorism losses occurring within one year, NEIL would make available one industry aggregate limit of $3.2 billion, along with any amounts it recovers from reinsurance, government indemnity or other sources up to the limits for each claimant. If terrorism losses occurred beyond the one-year period, a new set of limits and resources would apply. For nuclear liability claims arising out of terrorist acts, the primary level available through commercial insurers is now subject to an industry aggregate limit of S300 million. The second level of coverage obtained through the assessments discussed above would continue to apply to losses exceeding

$300 million and would provide coverage in excess of any diminished primary limits due to the terrorist acts.

PEC and PEFself-insuretheirtransmission and distribution lines against loss due to storm damage and other natural disasters. PEF accrues S6 million annually to a storm

8. REGULATORY MATTERS A. Regulatory Assets and Liabilities As regulated entities, the utilities are subject to the provisions of SFAS No. 71. Accordingly, the utilities record certain assets and liabilities resulting from the effects of the ratemaking process that would not be recorded under GAAP for nonregulated entities. The utilities' ability to continue to meet the criteria for application of SFAS No. 71 may be affected in the future by competitive forces and restructuring in the electric utility industry. In the event that SFAS No. 71 no longer applied to a separable portion of the Company's operations, related regulatory assets and liabilities would be eliminated unless an appropriate regulatory recovery mechanism was provided. Additionally, these factors could result in an impairment of utility plant assets as determined pursuant to SFAS No. 144.

73

V Notes to Consolidated Financial Statements At December 31, the balances of regulatory assets (liabilities) were as follows:

(in millions) 2004 2003 Deferred fuel cost-current (Note SB and 8C)

$229

$270 Deferred fuel cost-long-term (Note BB and 8C) 107 47 Deferred impact of ARO - PEC (Note 1D) 305 291 Income taxes recoverable through future rates 84 75 (Note 15)

Loss on reacquired debt (Note 1 D) 53 55 Deferred DOE enrichment facilities-related costs 16 24 Storm deferral (Notes 3 and BB) 316 21 Postretirement benefits (Note 17) 74 9

Other 109 76 Total long-term regulatory assets

$1,064 S598 Deferred energy conservation cost-current (8)

(7)

Non-ARO cost of removal (Note 6D) 11.881)

(2,118)

Deferred impact of ARO (Note 1D)

(221)

(212)

Net nuclear decommissioning trust unrealized gains (Note 6D)

(224)

(204)

Postretirement benefits (Note 17B)

(45)

(211)

Storm reserve (Note 3)

(41)

Clean air compliance (Note BB)

(248)

(74)

Other (35)

(19)

Total long-term regulatory liabilities 12.654)

(2,879)

Net regulatory liabiities

$(1369)

SI(Z08)

PEC obtained SCPSC and NCUC approval of fuel factors in annual fuel-adjustment proceedings. The NCUC approved an annual increase of $62 million, $20 million and $46 million by orders issued in September 2004, 2003 and 2002, respectively. The SCPSC approved PEC's petition each year and the changes were insignificant.

PEC filed with the SCPSC seeking permission to defer expenses incurred from the first quarter 2004 winter storm. The SCPSC approved PEC's request to defer the costs and amortize them ratably over five years beginning in January 2005. Approximately $9 million related to storm costs was deferred in 2004.

In October 2003, PEC filed with the NCUC seeking permission to defer expenses incurred from Hurricane Isabel and the February 2003 winter storms. In December 2003,the NCUC approved PEC's requestto deferthe costs associated with Hurricane Isabel and the February 2003 ice storm and amortize them over a period of five years.

PEC charged approximately $24 million in 2003 from Hurricane Isabel and from ice storms to the deferred account. PEC recognized $5 million and $3 million of NC storm amortization during 2004 and 2003, respectively.

The NCUC and SCPSC have approved proposals to accelerate cost recovery of PEC's nuclear generating assets beginning January 1, 2000, and continuing through 2009. The aggregate minimum and maximum amounts of cost recovery are $530 million and $750 million, respectively. Accelerated cost recovery of these assets resulted in no additional expense in 2004 and 2003 and additional depreciation expense of approximately

$53 million in 2002. Total accelerated depreciation recorded through December 31, 2004, was $403 million.

The North Carolina Clean Smokestacks Act enacted in June 2002 (NC Clean Air) requires state utilities to reduce emissions of nitrogen oxide (NOx) and sulfur dioxide (SO2) from coal-fired plants. The NCUC has allowed the utilities to amortize and recover the costs associated with meeting the new emission standards over a seven-year period beginning January 1, 2003. The legislation provides for significant flexibility in the amount of annual amortization recorded, which allows the utilities to vary the amount amortized within certain limits. This flexibility provides a utility with the opportunity to consider the impacts of other factors on its regulatory return on equity when setting the amortization amount for each year. PEC recognized $174 million and $74 million of clean air amortization during 2004 and 2003, respectively. This legislation freezes PEC's base rates in North Carolina for five years, subject to certain conditions (See Note 22).

Except for portions of deferred fuel costs and deferred storm costs, all regulatory assets earn a return or the cash has not yet been expended, in which case the assets are offset by liabilities that do not incur a carrying cost. The Company expects to fully recover these assets and refund the liabilities through customer rates under current regulatory practice.

B. PEC Retail Rate Matters As of December 31, 2004, PEC's North Carolina retail fuel costs were underrecovered by $145 million. This amount is comprised of $117 million eligible for recovery in 2005 and $28 million deferred from a 2001 order from the NCUC that cannot be collected during 2005, and has therefore been classified as a long-term asset. PEC intends to collect this amount by October 31, 2007.

On October 15, 2004, the SCPSC approved PEC's request to leave fuel rates unchanged. The deferred fuel balance at December 31,2004, is $23 million. This amount is eligible for recovery in PECs 2005 South Carolina fuel review.

74

Progress Energy Annual Report 2004 In conjunction with the FPC merger, PEC reached a settlement with the Public Staff of the NCUC in which it agreed to provide credits to its nonreal time pricing customers in the amounts of $3 million in 2002, $5 million in 2003 and $6 million in both 2004 and 2005.

In conjunction with the acquisition of NCNG in 1999, PEC agreed not to seek a base retail electric rate increase in North Carolina and South Carolina through December 2004. The agreement not to seek a base retail electric rate increase in South Carolina was extended to December 2005 in conjunction with regulatory approval to form a holding company.

C. PEF Retail Rate Matters On November 9, 2004, the FPSC approved PEF's underrecovered fuel costs of S156 million for 2004, of which PEF plans to defer $79 million until 2006 to mitigate the impact on customers resulting from the need to also recover hurricane-related costs. Therefore, S79 million of deferred fuel costs has been classified as a long-term asset As of December31, 2004, PEF was underrecovered in fuel costs by$168 million. The additional $12 million over and above the $156 million approved by the FPSC will be included in PEF's 2005 fuel filing.

On June 29, 2004, the FPSC approved a Stipulation and Settlement Agreement, executed on April 29, 2004, by PEF, the Office of Public Counsel and the Florida Industrial Power Users Group. The stipulation and settlement resolved the issue pending before the FPSC regarding the costs PEF will be allowed to recover through its Fuel and Purchased Power Cost Recovery clause in 2004 and beyond for waterborne coal deliveries by the Company's affiliated coal supplier, Progress Fuels Corporation. The settlement sets fixed per ton prices based on point of origin for all waterborne coal deliveries in 2004, and establishes a market-based pricing methodology for determining recoverable waterborne coal transportation costs through a competitive solicitation process or market price proxies in 2005 and thereafter. The settlement reduces the amount that PEF will charge to the Fuel and Purchased Power Cost Recovery clause for waterborne transportation by approximately $11 million beginning in 2004.

On November 3, 2004, the FPSC approved PEF's petition for Determination of Need for the construction of a fourth unit at PEF's Hines Energy Complex. Hines Unit 4 is needed to maintain electric system reliability and integrity and to continue to provide adequate electricity to its ratepayers at a reasonable cost Hines Unit 4 will be a combined cycle unit with a generating capacity of 461 MW (summer rating). The estimated total in-service cost of Hines Unit 4 is $286 million, and the unit is planned for commercial operation in December 2007. If the actual cost is less than the estimate, customers will receive the benefit of such cost underruns. Any costs that exceed this estimate will not be recoverable absent extraordinary circumstances as found by the FPSC in subsequent proceedings.

See Note 3 for information on PEF's petition for storm cost recovery.

PEF RATE CASE SETTLEMENT The FPSC initiated a rate proceeding in 2001 regarding PEFs future base rates. In March 2002, the parties in PEF's rate case entered into a Stipulation and Settlement Agreement (the Agreement) related to retail rate matters.

The Agreement was approved by the FPSC in April 2002.

The Agreement is generally effective from May 2002 through December 2005, provided, however, that if PEF's base rate earnings fall below a 10% return on equity, PEF may petition the FPSC to amend its base rates.

The Agreement provides that PEF will reduce its retail revenues from the sale of electricity by an annual amount of $125 million. The Agreement also provides that PEF will operate under a Revenue Sharing Incentive Plan (the Plan) through 2005, and thereafter until terminated by the FPSC, that establishes annual revenue caps and sharing thresholds. The Plan provides that retail base rate revenues between the sharing thresholds and the retail base rate revenue caps will be divided into two shares -

a 1/3 share to be received by PEF's shareholders, and a 2/3 share to be refunded to PEF's retail customers, provided, however, that for the year 2002 only, the refund to customers was limited to 67.1% of the 2/3 customer share. The retail base rate revenue sharing threshold amounts for 2004, 2003 and 2002 were S1.370 billion,

$1.333 billion and $1.296 billion, respectively, and will increase $37 million in 2005. The Plan also provides that all retail base rate revenues above the retail base rate revenue caps established for each year will be refunded to retail customers on an annual basis. For 2002, the refund to customers was limited to 67.1% of the retail base rate revenues that exceeded the 2002 cap. The retail base revenue caps for 2004, 2003 and 2002 were

$1.430 billion, $1.393 billion and $1.356

billion, respectively, and will increase $37 million in 2005. Any amounts above the retail base revenue caps will be refunded 100% to customers. At December 31, 2004,

$9 million has been accrued and will be refunded to retail customers by March 2005. The 2003 revenue sharing amount was S18 million, and was refunded to customers 75

V Notes to Consolidated Financial Statements by April 30, 2004. Approximately $5 million was originally returned in March 2003 related to 2002 revenue sharing.

However, in February 2003, the parties to the Agreement filed a motion seeking an order from the FPSC to enforce the Agreement In this motion, the parties disputed PEF's calculation of retail revenue subject to refund and contended that the refund should be approximately

$23 million. In July 2003, the FPSC ruled that PEF must provide an additional $18 million to its retail customers related to the 2002 revenue sharing calculation. PEF recorded this refund in the second quarter of 2003 as a charge against electric operating revenue and refunded this amount by October 2003.

The Agreement also provides that beginning with the in-service date of PEF's Hines Unit 2 and continuing through December 2005, PEF will be allowed to recover through the fuel cost recovery clause a return on average investment and depreciation expense for Hines Unit 2, to the extent such costs do not exceed the unit's cumulative fuel savings over the recovery period. Hines Unit 2 is a 516 MW combined-cycle unit that was placed in service in December 2003. PEF recovered $36 million through this clause related to Hines Unit 2.

In addition, PEF suspended retail accruals on its reserves for nuclear decommissioning and fossil dismantlement through December 2005. Additionally, for each calendar year during the term of the Agreement, PEF will record a

$63 million depreciation expense reduction and may, at its option, record up to an equal annual amount as an offsetting accelerated depreciation expense. No accelerated depreciation expense was recorded during 2004 and 2003. In addition, PEF is authorized, at its discretion, to accelerate the amortization of certain regulatory assets over the term of the Agreement Under the terms of the Agreement, PEF agreed to continue the implementation of its four-year Commitment to Excellence Reliability Plan and expected to achieve a 20%

improvement in its annual System Average Interruption Duration Index by no later than 2004. If this improvement level was not achieved for calendar years 2004 or 2005, PEF would have provided a refund of $3 million for each year the level is not achieved to 10% of its total retail customers served by its worst performing distribution feeder lines. PEF achieved this improvement level in 2004.

In January 2005, in anticipation of the expiration of its Stipulation and Settlement approved by the FPSC in 2002 to conclude PEF's then-pending rate case, PEF notified the FPSC that it intends to request an increase in its base rates, effective January 1, 2006. In its notice, PEF requested the FPSC to approve calendar year 2006 as the projected test period for setting new base rates. The requestfor increased base rates is based onthefactthat PEF has faced significant cost increases over the past decade and expects its operational costs to continue to increase. These costs include the costs associated with completion of the Hines Unit 3 generation facility, extraordinary hurricane damage costs including capital costs which are not expected to be directly recoverable, the need to replenish the depleted storm reserve and the expected infrastructure investment necessary to meet high customer expectations, coupled with the demands placed on PEF as a result of its strong customer growth.

On February 7, 2005, the FPSC acknowledged receipt of PEF's notice and authorized minimum filing requirements and testimony to be filed May 1, 2005.

D. Regional Transmission Organizations and Standard Market Design In 2000, the FERC issued Order No. 2000 regarding regional transmission organizations (RTOs). This Order set minimum characteristics and functions that RTOs must meet, including independent transmission service. In July 2002, the FERC issued its Notice of Proposed Rulemaking in Docket No. RM01 000, Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). If adopted as proposed, the rules set forth in the SMD NOPR would have materially altered the manner in which transmission and generation services are provided and paid for. In April 2003, the FERC released a White Paper on the Wholesale Market Platform. The White Paper provided an overview of what the FERC intended to include in a final rule in the SMD NOPR docket The White Paper retained the fundamental and most protested aspects of SMD NOPR, including mandatory RTOs and the FERC's assertion of jurisdiction over certain aspects of retail service. The FERC has not yet issued a final rule on SMD NOPR. The Company cannot predictthe outcome of these matters orthe effectthatthey may have on the GridSouth and GridFlorida proceedings currently ongoing before the FERC. By order issued December 22, 2004, the FERC terminated a portion of the proceedings regarding GridSouth. The GridSouth Companies asked the FERC for further clarification as to the portions of the GridSouth docket it intended to address. On March 2, 2005, the FERC affirmed that it only intended to close the mediation portion of the GridSouth docket It is unknown what impact the future proceedings will have on the Company's earnings, revenues or prices.

The FPSC ruled in December 2001 that the formation of GridFlorida by the three major investor-owned utilities in Florida, including PEF, was prudent but ordered changes in 76

Progress Energy Annual Report 2004 the structure and market design of the proposed organization. In September 2002, the FPSC set a hearing for market design issues; this order was appealed to the Florida Supreme Court by the consumer advocate of the state of Florida. In June 2003, the Florida Supreme Court dismissed the appeal without prejudice. In September 2003, the FERC held a Joint Technical Conference with the FPSC to consider issues related to formation of an RTO for peninsular Florida. In December 2003, the FPSC ordered further state proceedings and established a collaborative workshop process to be conducted during 2004. In June 2004, the workshop process was abated pending completion of a cost-benefit study currently scheduled to be presented at a FPSC workshop on May 25, 2005, with subsequent action by the FPSC to be thereafter determined.

The Company has $33 million and $4 million invested in GridSouth and GridFlorida, respectively, related to startup costs at December 31, 2004. The Company expects to recover these startup costs in conjunction with the GridSouth and GridFlorida original structures or in conjunction with any alternate combined transmission structures that emerge.

E. FERC Market Power Mitigation A FERC order issued in November 2001 on certain unaffiliated utilities' triennial market-based wholesale power rate authorization updates required certain mitigation actions thatthose utilities would need to take for sales/purchases within their control areas and required those utilities to post information on their Web sites regarding their power systems' status. As a result of a request for rehearing filed by certain market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. In April 2004, the FERC issued two orders concerning utilities' ability to sell wholesale electricity at market-based rates. In the first order, the FERC adopted two new interim screens for assessing potential generation market power of applicants for wholesale market-based rates, and described additional analyses and mitigation measures that could be presented if an applicant does not pass one of these interim screens. In July 2004, the FERC issued an order on rehearing affirming its conclusions in the April order. In the second order, the FERC initiated a rulemaking to consider whether the FERC's current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in any way. PEF does not have market-based rate authority for wholesale sales in peninsular Florida. Given the difficulty PEC believes it would experience in passing one of the interim screens, on August 12, 2004, PEC notified the FERC that it would revise its Market-based Rate tariff to restrict it to sales outside PEC's control area and file a new cost-based tariff for sales within PEC's control area that incorporates the FERC's default cost-based rate methodologies for sales of one year or less. PEC anticipates making this filing in the first quarter of 2005.

PEC does not anticipate that the current operations will be materially impacted bythis change. Although the Company cannot predictthe ultimate outcome of these changes, the Company does not anticipate that the current operations of PEC or PEF would be impacted materially if they were unable to sell power at market-based rates in their respective control areas.

F. Energy Delivery Capitalization Practice The Company has reviewed its capitalization policies for its Energy Delivery business units in PEC and PEF That review indicated that in the areas of outage and emergency work not associated with major storms and allocation of indirect costs, both PEC and PEF should revise the way that they estimate the amount of capital costs associated with such work. The Company has implemented such changes effective January 1, 2005, which include more detailed classification of outage and emergency work and result in more precise estimation and a process of retesting accounting estimates on an annual basis. As a result of the changes in accounting estimates for the outage and emergency work and indirect costs, a lesser proportion of PECs and PEFs costs will be capitalized on a prospective basis. The Company estimates that the combined impact for both utilities in 2005 will be that approximately $55 million of costs that would have been capitalized under the previous policies will be expensed. Pursuant to SFAS No. 71, PEC and PEF have informed the state regulators having jurisdiction over them of this change and thatthe new estimation process will be implemented effective January 1, 2005. The Company has also requested a method change from the IRS.

9. GOODWILL AND OTHER INTANGIBLE ASSETS The Company performed the annual goodwill impairment test in accordance with FASB Statement No. 142, Goodwill and Other Intangible Assets,' for the CCO segment in the first quarter of 2004, and the annual goodwill impairment test for the PEC Electric and PEF segments in the second quarter of 2004, each of which indicated no impairment.

77

V Notes to Consolidated Financial Statements The changes in the carrying amount reportable segment, are as follows:

of goodwill, by PEC Corporate (in millions)

Electric PEF CCO and Other Total Balance as of January 1. 2003 S1.922

$1,733 S64 S-

$3,719 Acquisitions 7

7 Balance as of December31,2003

$1,922

$1.733 S64 S7

$3,726 Purchase accounting adjustment

17)

(7)

Balance as of December3l.2004

$1,922

$1,733 S64 S3.719 In December 2003, $7 million in goodwill was recorded based on a preliminary purchase price allocation as part of the Progress Telecommunications Corporation partial acquisition of EPIK and was reported in the Corporate and Other segment The Company revised the preliminary EPIK purchase price allocation as of September 2004, and the $7 million of goodwill was reallocated to certain tangible assets acquired based on the results of valuations and appraisals (See Note 5A).

The gross carrying amount and accumulated amortization of the Company's intangible assets at December 31 are as follows:

2004 2003 Gross Gross Carrying Accumulated Carrying Accumulated (in millions)

Amount Amortization Amount Amortization Synthetic fuel intangibles

$134 S(80)

$140

$(64)

Power agreements acquired 221 (39) 221 (20)

Other 119 (18) 93 (13)

Total

$474 5(137)

$454

$(97) economic benefits of the contracts (See Notes 5C and 5D). Other intangibles are primarily acquired customer contracts and permits that are amortized over their respective lives. Of the increase in other intangible assets, $24 million resulted from the minimum pension liability adjustment at December 31, 2004 (See Note 17).

Amortization expense recorded on intangible assets for the years ended December 31, 2004, 2003 and 2002 was, in millions, $42, $37 and $33, respectively. The estimated annual amortization expense for intangible assets for 2005 through 2009, in millions, is approximately $35, $36,

$36, $18 and $18, respectively.

10. IMPAIRMENTS OF LONG-LIVED ASSETS AND INVESTMENTS The Companyapplies SFAS No.144forthe accounting and reporting of impairment or disposal of long-lived assets. In 2003 and 2002, the Company recorded pre-tax long-lived asset and investment impairments and other charges of approximately $38 million and $414 million, respectively.

A. Long-Lived Assets Due to the reduction in coal production, the Company evaluated Kentucky May coal mine's long-lived assets in 2003. Fair value was determined based on discounted cash flows. As a result of this review, the Company recorded asset impairments of $17 million on a pre-tax basis during the fourth quarter of 2003.

An estimated impairment of assets held for sale of

$59 million is included in the 2002 amount, which relates to Railcar Ltd. (See Note 4C).

Due to the decline of the telecommunications industry and continued operating losses, the Company initiated an independent valuation study during 2002 to assess the recoverability of the long-lived assets of PTC and Caronet. Based on this assessment, the Company recorded asset impairments of $305 million on a pre-tax basis and other charges of $25 million on a pre-tax basis primarily related to inventory adjustments in the third quarter of 2002. This write-down constitutes a significant reduction in the book value of these long-lived assets.

The long-lived asset impairments include an impairment of property, plant and equipment, construction work in process and intangible assets. The impairment charge represents the difference between the fair value and carrying amount of these long-lived assets. The fair value of these assets was determined using a valuation study heavilyweighted onthe discounted cash flow methodology, using market approaches as supporting information.

In June 2004, the Company sold, in two transactions, a combined 49.8% partnership interest in Colona Synfuel Limited Partnership, LLLP, one of its synthetic fuel operations.

Approximately $6 million in synthetic fuel intangibles and

$3 million in related accumulated amortization were included in the basis of the partnership interest sold.

All of the Company's intangibles are subject to amortization. Synthetic fuel intangibles represent intangibles for synthetic fuel technology. These intangibles are being amortized on a straight-line basis until the expiration of tax credits under Section 29 of the Internal Revenue Code (Section 29) in December 2007 (See Note 23E). The intangibles related to power agreements acquired are being amortized based on the 78

Progress Energy Annual Report 2004 B. Investments The Company continually reviews its investments to determine whether a decline in fair value below the cost basis is other than temporary. In 2003, PEC's affordable housing investment (AHI) portfolio was reviewed and deemed to be impaired based on various factors including continued operating losses of the AHI portfolio and management performance issues arising at certain properties within the AHI portfolio. As a result, PEC recorded an impairment of $18 million on a pre-tax basis during the fourth quarter of 2003. PEC also recorded an impairment of $3 million for a cost investment.

In May 2002, Interpath Communication, Inc., merged with a third party. As a result, the Company reviewed the Interpath investment for impairment and wrote off the remaining amount of its cost-basis investment in Interpath, recording a pre-tax impairment of $25 million in the third quarter of 2002. In the fourth quarter of 2002, the Company sold its remaining interest in Interpath for a nominal amount.

11. EQUITY A. Common Stock At December 31, 2004, the Company had approximately 63 million shares of common stock authorized by the Board of Directors that remained unissued and reserved, primarily to satisfy the requirements of the Company's stock plans. In 2002, the Board of Directors authorized meeting the requirements of the Progress Energy 401(k)

Savings and Stock Ownership Plan and the Investor Plus Stock Purchase Plan with original issue shares. During 2004, 2003 and 2002, respectively, the Company issued approximately 1 million, 8 million and 2 million shares under these plans for net proceeds of approximately

$62 million, $305 million and $86 million. The Company continues to meet the requirements of the restricted stock plan with issued and outstanding shares.

In November 2002, the Company issued 14.7 million shares of common stock for net cash proceeds of approximately $600 million, which were primarily used to retire commercial paper. In April 2002, the Company issued 2.5 million shares of common stock, valued at approximately $129 million, in conjunction with the purchase of Westchester (See Note 5D).

There are various provisions limiting the use of retained earnings for the payment of dividends under certain circumstances. At December 31, 2004, there were no significant restrictions on the use of retained earnings.

B. Stock-Based Compensation EMPLOYEE STOCK OWNERSHIP PLAN The Company sponsors the Progress Energy 401(k) Savings and Stock Ownership Plan (401(k)) for which substantially all full-time nonbargaining unit employees and certain part-time nonbargaining unit employees within participating subsidiaries are eligible. Participating subsidiaries within the Company as of January 1, 2003, were PEC, PEF, PTC, Progress Fuels (Corporate) and Progress Energy Service Company. Effective December 19, 2003, (the PT LLC/EPIK merger date), PTC no longer participates in the 401(k) plan.

The 401(k), which has Company matching and incentive goal features, encourages systematic savings by employees and provides a method of acquiring Company common stock and other diverse investments. The 401(k),

as amended in 1989, is an Employee Stock Ownership Plan (ESOP) that can enter into acquisition loans to acquire Company common stock to satisfy 401(k) common share needs. Qualification as an ESOP did not change the level of benefits received by employees under the 401(k). Common stock acquired with the proceeds of an ESOP loan is held by the 401(k) Trustee in a suspense account. The common stock is released from the suspense account and made available for allocation to participants as the ESOP loan is repaid. Such allocations are used to partially meet common stock needs related to Company matching and incentive contributions and/or reinvested dividends. All or a portion of the dividends paid on ESOP suspense shares and on ESOP shares allocated to participants may be used to repay ESOP acquisition loans. To the extent used to repay such loans, the dividends are deductible for income tax purposes. Also, beginning in 2002, the dividends paid on ESOP shares that are either paid directly to participants or used to purchase additional shares, which are then allocated to participants, are fully deductible for income tax purposes.

There were 3.5 million and 4.0 million ESOP suspense shares at December 31, 2004 and 2003, respectively, with a fair value of $156 million and $183 million, respectively.

ESOP shares allocated to plan participants totaled 12.6 million and 13.1 million at December 31, 2004 and 2003, respectively. The Company's matching and incentive goal compensation cost under the 401(k) is determined based on matching percentages and incentive goal attainment as defined in the plan. Such compensation cost is allocated to participants' accounts in the form of Company common stock, with the number of shares determined by dividing compensation cost by the common stock market value atthe time of allocation.

The Company currently meets common stock share needs with open market purchases, with shares 79

V Notes to Consolidated Financial Statements released from the ESOP suspense account and with newly issued shares. Costs for incentive goal compensation are accrued during the fiscal year and typically paid in shares in the following year, while costs for the matching component are typically met with shares in the same year incurred. Matching and incentive costs, which were met and will be met with shares released from the suspense account, totaled approximately $21 million, $20 million and $20 million for the years ended December 31, 2004, 2003 and 2002, respectively. Total matching and incentive cost totaled approximately $32 million, $35 million and $30 million for the years ended December 31, 2004, 2003 and 2002, respectively. The Company has a long-term note receivable from the 4011k) Trustee related to the purchase of common stock from the Company in 1989.

The balance of the note receivable from the 401(k)

Trustee is included in the determination of unearned ESOP common stock, which reduces common stock equity. ESOP shares that have not been committed to be released to participants' accounts are not considered outstanding for the determination of earnings per common share. Interest income on the note receivable and dividends on unallocated ESOP shares are not recognized for financial statement purposes.

STOCK OPTION AGREEMENTS Pursuant to the Company's 1997 Equity Incentive Plan and 2002 Equity Incentive Plan, amended and restated as of July 10, 2002, the Company may grant options to purchase shares of common stock to directors, officers and eligible employees for up to 5 million and 15 million shares, respectively. Generally, options granted to employees vest one-third per year with 100% vesting at the end of year three, while options granted to directors vest 100% at the end of one year. The options expire 10 years from the date of grant. All option grants have an exercise price equal to the fair market value of the Company's common stock on the grant date. The Company measures compensation expense for stock options as the difference between the market price of its common stock and the exercise price of the option atthe grant date. The exercise price at which options are granted by the Company equals the market price at grant date and, accordingly, no compensation expense has been recognized for any options granted during 2004, 2003 and 2002. The Company will begin expensing stock options on July 1, 2005, based on SFAS No. 123R (See Note 2). In 2004, however, the Company made the decision to cease granting stock options and intends to replace that compensation program with other programs. Therefore, the amount of stock option expense expected to be recorded in 2005 is below the amount that would have been recorded if the stock option program had continued.

The pro forma information presented in Note 1 regarding net income and earnings per share is required by SFAS No. 148. Under this statement, compensation cost is measured atthe grant date based onthe fairvalue of the award and is recognized overthe vesting period. The pro forma amounts presented in Note 1 have been determined as if the Company had accounted for its employee stock options under SFAS No. 123. The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions:

2004 2003 2002 Risk-free interest rate 4.22%

4.25%

4.14%

Dividend yield 5.19%

4.75%

5.20%

Volatility factor 20.30%

22.28%

24.98%

Weighted-average expected life of the options (in years) 10 10 10 The option valuation model requires the input of highly subjective assumptions, primarily stock price volatility, changes in which can materially affect the fair value estimate.

The options outstanding at December 31, 2004, 2003 and 2002 had a weighted-average remaining contractual life of 7.6, 8.7 and 9.3 years, respectively, and had exercise prices that ranged from $40.41 to $51.85. The tabular information forthe option activity is as follows:

80

Progress Energy Annual Report 2004 2004 2003 2002 Weighted-Weighted-Weighted-Average Average Average Number of Exercise Number of Exercise Number of Exercise (option quantities in millions)

Options Price Options Price Options Price Options outstanding, January 1 8.0

$43.54 5.2

$42.84 2.3 S43.49 Granted 3.0

$44.70 2.9 S42.34 Forfeited (0.1)

S.76 (0.1)

$43.64

$43.71 Canceled (0.1)

$43.67 (0.1)

$43.62 Exercised (0.4)

$42.82

$43.00 Options outstanding, December31 7.4

$43.57 8.0

$43.54 5.2 S42.84 Options exercisable, December 31 with a remaining contractual life of 7.6 years 4.6

$43.35 2.4

$43.09 0.8

$43.49 Weighted-average grant date fair value of options granted during the year S7.16

$6.83 OTHER STOCK-BASED COMPENSATION PLANS The Company has additional compensation plans for officers and key employees of the Company that are stock-based in whole or in part. The two primary active stock-based compensation programs are the Performance Share Sub-Plan (PSSP) and the Restricted Stock Awards program (RSA), both of which were established pursuantto the Company's 1997 Equity Incentive Plan and were continued under the Company's 2002 Equity Incentive Plan, as amended and restated as of July 10, 2002.

Under the terms of the PSSP, officers and key employees of the Company are granted performance shares on an annual basis that vest over a three-year consecutive period. Each performance share has a value that is equal to, and changes with, the value of a share of the Company's common stock, and dividend equivalents are accrued on, and reinvested in, the performance shares.

The PSSP has two equally weighted performance measures, both of which are based on the Company's results as compared to a peer group of utilities.

Compensation expense is recognized over the vesting period based on the expected ultimate cash payout and is reduced by any forfeitures. Effective January 1, 2005, new awards granted pursuant to the PSSP will be payable in Company common stock rather than in cash.

The RSA program allows the Company to grant shares of restricted common stock to officers and key employees of the Company. The restricted shares generally vest on a graded vesting schedule over a minimum of three years.

Compensation expense, which is based on the fair value of common stock at the grant date, is recognized over the applicable vesting period, with corresponding increases in common stock equity. The weighted-average price of restricted shares at the grant date was $46.95, $39.53 and

$44.27 in 2004, 2003 and 2002, respectively. Compensation expense is reduced by any forfeitures. Restricted shares are not included as shares outstanding in the basic earnings per share calculation until the shares are no longer forfeitable. Changes in restricted stock shares outstanding were:

2004 2003 2002 Beginning balance 944.883 950,180 674,511 Granted 154.500 180,200 365,920 Vested (367,107) 1151,677)

(75,200)

Forfeited (87,100)

(33,820)

(15,051)

Ending balance 645.176 944,883 950,180 The total amount expensed for other stock-based compensation plans was $10 million, $27 million and

$17 million in 2004, 2003 and 2002, respectively.

C. Earnings Per Common Share Basic earnings per common share is based on the weighted-average number of common shares outstanding. Diluted earnings per share includes the effect of the nonvested portion of restricted stock awards and the effect of stock options outstanding.

A reconciliation of the weighted-average number of common shares outstanding for basic and dilutive purposes is as follows:

(in millions) 2004 2003 2002 Weighted-average common shares - basic 242.2 237.2 217.2 Restricted stock awards

.8 1.0

.8 Stock options

.1

.2 Weighted-average shares -

fully diluted 243.1 238.2 218.2 81

V Notes to Consolidated Financial Statements There are no adjustments to net income or to income from continuing operations between the calculations of basic and fully diluted earnings per common share.

ESOP shares that have not been committed to be released to participants' accounts are not considered outstanding for the determination of earnings per common share. The weighted-average of these shares totaled 3.6 million, 4.1 million and 4.8 million for the years ended December 31, 2004, 2003 and 2002, respectively.

There were 3.0 million, 5.3 million and 92 thousand stock options outstanding at December 31,2004,2003 and 2002, respectively, which were not included in the weighted-average number of shares for computing the fully diluted earnings per share because they were antidilutive.

D. Accumulated Other Comprehensive Loss Components of accumulated other comprehensive loss are as follows:

tin millions) 2004 2003 Loss on cash flow hedges S(28)

$136)

Minimum pension liability adjustments (142)

(16)

Foreign currency translation and other 6

2 Total accumulated other comprehensive loss S(164)

$(50)

12. PREFERRED STOCK OF SUBSIDIARIES - NOT SUBJECT TO MANDATORY REDEMPTION All of the Company's preferred stock was issued by its subsidiaries and was not subjectto mandatory redemption.

Preferred stock outstanding at December 31, 2004 and 2003 consisted of the following:

(in millions, except share data and par value)

Progress Energy Carolinas, Inc.

Authorized -

300,000 shares, cumulative, $100 par value Preferred Stock; 20,000,000 shares, cumulative, S100 par value Serial Preferred Stock

$5.00 Preferred -236,997 shares outstanding

$24 (redemption price $110.00)

$4.20 Serial Preferred -100,000 shares outstanding (redemption price $102.00)

$5.44 Serial Preferred -249,850 shares outstanding (redemption price $101.00) 10 25

$59 Progress Energy Florida, Inc.

Authorized -

4,000,000 shares, cumulative,

$100 par value Preferred Stock; 5,000,000 shares, cumulative, no par value Preferred Stock; 1,000,000 shares, $100 par value Preference Stock;

$100 par value Preferred Stock:

4.00% - 39,980 shares outstanding (redemption price $104.25) 4.40% - 75,000 shares outstanding (redemption price S10200) 4.58% - 99,990 shares outstanding (redemption price S101.00) 4.60% - 39,997 shares outstanding (redemption price S103.25) 4.75% - 80,000 shares outstanding (redemption price S102.00)

$4 8

10 4

8

$34 Total Preferred Stock of Subsidiaries

$93 82

Progress Energy Annual Report 2004

13. DEBT AND CREDIT FACILITIES A. Debt and Credit Facilities At December 31, the Company's long-term debt consisted of the following (maturities and weighted-average interest rates at December 31, 2004):

(in millions) 2004 2003 Progress Energy, Inc.

Senior unsecured notes, maturing 2006-2031 6.90%

$4,300

$4,800 Draws on revolving credit agreement expiring 2009 3.19%

160 Unamortized fair value hedge gain, net 12 19 Unamortized premium and discount net (23)

(27) 4,449 4,792 Progress Energy Carolinas, Inc.

First mortgage bonds, maturing 2005-2033 6.33%

1,600 1,900 Pollution control obligations, maturing 2017-2024 1.98%

669 708 Unsecured notes, maturing 2012 6.50%

500 500 Medium-term notes, maturing 2008 6.65%

300 300 Unamortized premium and discount net (19)

(22) 3,050 3,386 Progress Energy Florida, Inc.

First mortgage bonds, maturing 2008-2033 5.60%

1,330 1,330 Pollution control obligations, maturing 2018-2027 1.67%

241 241 Medium-term notes, maturing 2005-2028 6.76%

337 379 Draws on revolving credit agreement expiring 2006 2.95%

55 Unamortized premium and discount net (3)

(3) 1,960 1,947 Florida Progress Funding Corporation (See Note 19)

Debt to affiliated trust maturing 2039 7.10%

309 309 Unamortized premium and discount net (39)

(39) 270 270 Progress Capital Holdings, Inc.

Medium-term notes, maturing 2006-2008 6.84%

140 165 Miscellaneous notes 1

1 141 166 Progress Genco Ventures, LLC Variable rate project financing, maturing 2007 241 Current portion of long-term debt (349)

(868)

Total long-term debt

$9,521

$9,934 At December 31, 2004, the Company had committed lines of credit used to support its commercial paper borrowings. The Progress Energy five-year credit facility and the PEF three-year credit facility are included in long-term debt. All other credit facilities are included in short-term obligations. At December 31, 2004, the Company had $260 million outstanding under its credit facilities classified as short-term obligations at a weighted-average interest rate of 3.18%. No amount was outstanding under the Company's committed lines of credit at December 31, 2003. The Company is required to pay minimal annual commitment fees to maintain its credit facilities.

83

V Notes to Consolidated Financial Statements The following table summarizes the Company's credit facilities:

tin millions)

Company Description Total Outstanding Available Progress Energy, Inc.

5-Year (expiring 8/5109)

S1,130

$160

$970 Progress Energy Carolinas, Inc.

364-Day (expiring 7/27/05) 165 90 75 Progress Energy Carolinas, Inc.

3-Year (expiring 7/31/05) 285 285 Progress Energy Florida, Inc.

364-Day (expiring 3/29/05) 200 170 30 Progress Energy Florida, Inc.

3-Year (expiring 4/01/06) 200 55 145 Less: amounts reserved(a)

(574)

Total credit facilities S1,980

$475 S931 TaT To the extent amounts are reserved for commercial paper outstanding or backing letters of credit, they are not available for additional borrowings.

At December 31, 2004 and 2003, the Company had

$424 million and $4 million, respectively, of outstanding commercial paper and other short-term debt classified as short-term obligations. The weighted-average interest rates of such short-term obligations at December 31, 2004 and 2003 were 2.77% and 2.25%, respectively. At December31,2004, the Company has reserved $150 million of its lines of credit for backing of letters of credit Both Progress Energy and PEF have an uncommitted bank bid facility authorizing them to borrow and reborrow, and have loans outstanding at any time, up to

$300 million and $100 million, respectively. These bank bid facilities were not drawn at December 31, 2004.

On January 31, 2005, Progress Energy, Inc., entered into a new $600 million revolving credit agreement, which expires December 30, 2005. This facility was added to provide additional liquidity during 2005 due in part to storm restoration costs incurred in Florida during 2004.

The credit agreement includes a defined maximum total debt to total capital ratio of 68% and a minimum interest coverage ratio of 2.5 to 1. The credit agreement also contains various cross-default and other acceleration provisions. On February 4, 2005, S300 million was drawn under the new facility to reduce commercial paper and bank loans outstanding.

The combined aggregate maturities of long-term debt for 2005 through 2009 are approximately $349 million, S963 million, $674 million, $827 million and $560 million, respectively.

B. Covenants and Default Provisions FINANCIAL COVENANTS Progress Energy's, PEC's and PEF's credit lines contain various terms and conditions that could affect the Company's ability to borrow under these facilities. These include maximum debt to total capital ratios, interest coverage tests, material adverse change clauses and cross-default provisions.

All of the credit facilities include a defined maximum total debt to total capital ratio. At December 31, 2004, the maximum and calculated ratios for the companies, pursuant to the terms of the agreements, are as follows:

Company Maximum Ratio Actual Ratio(a)

Progress Energy, Inc.

65%

60.7%

Progress Energy Carolinas, Inc.

65%

52.3%

Progress Energy Florida, Inc.

65%

50.8%

1a3lndebtedness as defined by the bank agreements includes certain letters of credit and guarantees that are not recorded on the Consolidated Balance Sheets.

Progress Energy's 364-day credit facility and both PEF's 364-day and three-year credit facilities have a financial covenant for interest coverage. The covenants require Progress Energy's and PEF's earnings before interest, taxes, and depreciation and amortization to interest expense ratio to be at least 2.5 to 1 and 3 to 1, respectively. For the year ended December 31, 2004, the ratios were 4.00 to 1 and 7.93 to 1 for the Company and PEF, respectively.

In March 2005, Progress Energy, Inc.'s five-year credit facility was amended to increase the maximum total debt to total capital ratio from 65% to 68% in anticipation of the potential impacts of proposed accounting rules for uncertain tax positions. See Notes 2 and 23E.

MATERIAL ADVERSE CHANGE CLAUSE The credit facilities of Progress Energy, PEC, and PEF include a provision under which lenders could refuse to advance funds in the event of a material adverse change (MAC) in the borrower's financial condition. Pursuant to 84

Progress Energy Annual Report 2004 the terms of Progress Energy's five-year credit facility, even in the event of a MAC, Progress Energy may continue to borrow funds so long as the proceeds are used to repay maturing commercial paper balances.

CROSS-DEFAULT PROVISIONS Each of these credit agreements contains cross-default provisions for defaults of indebtedness in excess of S10 million. Under these provisions, if the applicable borrower or certain subsidiaries of the borrower fail to pay various debt obligations in excess of $10 million, the lenders could accelerate payment of any outstanding borrowing and terminate their commitments to the credit facility. Progress Energy's cross-default provision applies only to Progress Energy and its significant subsidiaries (i.e., PEC, Florida Progress, PEF, Progress Capital Holdings, Inc. (PCH) and Progress Fuels).

Additionally, certain of Progress Energy's long-term debt indentures contain cross-default provisions for defaults of indebtedness in excess of $25 million; these provisions apply onlyto other obligations of Progress Energy, primarily commercial paper issued by the holding company, not its subsidiaries. In the event that these indenture cross-default provisions are triggered, the debt holders could accelerate payment of approximately $4.3 billion in long-term debt Certain agreements underlying the Companys indebtedness also limit its ability to incur additional liens or engage in certain types of sale and leaseback transactions.

OTHER RESTRICTIONS Neither Progress Energy's Articles of Incorporation nor any of its debt obligations contain any restrictions on the payment of dividends. Certain documents restrict the payment of dividends by Progress Energy's subsidiaries as outlined below.

PEC's mortgage indenture provides that, as long as any first mortgage bonds are outstanding, cash dividends and distributions on its common stock and purchases of its common stock are restricted to aggregate net income available for PEC since December 31, 1948, plus S3 million, less the amount of all preferred stock dividends and distributions, and all common stock purchases, since December 31, 1948. At December 31, 2004, none of PEC's retained earnings was restricted.

In addition, PEC's Articles of Incorporation provide that cash dividends on common stock shall be limited to 75% of net income available for dividends if common stock equity falls below 25% of total capitalization, and to 50% if common stock equity falls below 20%. At December 31, 2004, PEC's common stock equity was approximately 52.2% of total capitalization.

PEF's mortgage indenture provides that it will not pay any cash dividends upon its common stock, or make any other distribution to the stockholders, except a payment or distribution out of net income of PEF subsequent to December 31, 1943. At December 31, 2004, none of PEFs retained earnings was restricted.

In addition, PEFs Articles of Incorporation provide that no cash dividends or distributions on common stock shall be paid, if the aggregate amountthereof since April 30,1944, including the amount then proposed to be expended, plus all other charges to retained earnings since April 30,1944, exceed (a) all credits to retained earnings since April 30, 1944, plus (b) all amounts credited to capital surplus after April 30,1944, arising from the donation to PEF of cash or securities or transfers of amounts from retained earnings to capital surplus.

PEF's Articles of Incorporation also provide that cash dividends on common stock shall be limited to 75% of net income available for dividends if common stock equity falls below 25% of total capitalization, and to 50% if common stock equity falls below 20%. On December 31, 2004, PEF's common stock equity was approximately 54.4% of total capitalization.

C. Collateralized Obligations PEC's and PEF's first mortgage bonds are collateralized by their respective mortgage indentures. Each mortgage constitutes a first lien on substantially all of the fixed properties of the respective company, subject to certain permitted encumbrances and exceptions.

Each mortgage also constitutes a lien on subsequently acquired property. At December 31, 2004, PEC and PEF had a total of approximately$3.84 billion of first mortgage bonds outstanding, including those related to pollution control obligations. Each mortgage allows the issuance of additional mortgage bonds upon the satisfaction of certain conditions.

D. Progress Genco Ventures, LLC (Genco) Bank Facility In December 2004, Genco repaid its bank facility and recorded a $9 million pre-tax loss ($6 million after-tax) in other, net on the extinguishment At that time, the related

$195 million notional amount of interest rate collars in place to hedge floating interest rate exposure on the bank facility was terminated and pre-tax deferred losses of

$6 million ($4 million after-tax) were reclassified into 85

V Notes to Consolidated Financial Statements earnings in other, net due to the discontinuance of the hedges. The facility was obtained to be used exclusively for expansion of its nonregulated generation portfolio.

Borrowings under this facility were secured by the assets in the generation portfolio. The facility was for up to

$260 million, of which $241 million had been drawn at December 31, 2003. Borrowings under the facility were restricted for the operations, construction, repayments and other related charges of the credit facility for the development projects. Cash held and restricted to operations was S24 million at December 31,2003, and was included in other current assets. Cash held and restricted for long-term purposes was S9 million at December 31, 2003, and was included in other assets and deferred debits on the Consolidated Balance Sheets.

E. Guarantees of Subsidiary Debt See Note 19 on related party transactions for a discussion of obligations guaranteed or secured by affiliates.

F. Hedging Activities Progress Energy uses interest rate derivatives to adjust the fixed and variable rate components of its debt portfolio and to hedge cash flow risk related to commercial paper and to fixed rate debt to be issued in the future. See discussion of risk management activities and derivative transactions at Note 18.

14. FAIR VALUE OF FINANCIAL INSTRUMENTS The carrying amounts of cash and cash equivalents and short-term obligations approximate fair value due to the short maturities of these instruments. At December31,2004, and 2003, investments in company-owned life insurance and other benefit plan assets, with carrying amounts of approximately $220 million and $210 million, respectively, are included in miscellaneous other property and investments in the Consolidated Balance Sheets and approximate fair value due to the short maturity of the instruments. Other instruments, including short-term investments, are presented at fair value in accordance with GAAP. The carrying amount of the Company's long-term debt, including current maturities, was $9.870 billion and S10.802 billion at December 31, 2004 and 2003, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $10.843 billion and $11.917 billion at December 31, 2004 and 2003, respectively.

External trust funds have been established to fund certain costs of nuclear decommissioning (See Note 6D).

These nuclear decommissioning trust funds are invested in stocks, bonds and cash equivalents. Nuclear decommissioning trust funds are presented on the Consolidated Balance Sheets at amounts that approximate fair value. Fair value is obtained from quoted market prices for the same or similar investments.

15. INCOME TAXES Deferred income taxes have been provided for temporary differences. These occur when there are differences between book and tax carrying amounts of assets and liabilities. Investment tax credits related to regulated operations have been deferred and are being amortized over the estimated service life of the related properties. To the extentthatthe establishment of deferred income taxes under SFAS No. 109, 'Accounting for Income Taxes, (SFAS No. 109) is different from the recovery of taxes by PEC and PEF through the ratemaking process, the differences are deferred pursuant to SFAS No. 71. A regulatory asset or liability has been recognized forthe impact of tax expenses or benefits that are recovered or refunded in different periods by the utilities pursuant to rate orders.

Accumulated deferred income tax assets (liabilities) at December31 are:

tin millions) 2004 2003 Current deferred tax asset Unbilled revenue

$35 S18 Other 86 69 Total current deferred tax asset 121 87 Noncurrent deferred tax asset (liability)

Investments 73 8

Supplemental executive retirement plans 31 30 Other post-employment benefits (OPEB) 126 119 Other pension plans (15)

(97)

Goodwill 34 46 Accumulated depreciation and (1,374)

(1,436) property cost differences Deferred costs (13) 26 Deferred storm costs (113)

Deferred fuel (55) 31 Federal income tax credit carry forward 779 683 State net operating loss carry forward 47 42 Valuation allowance (47)

(42)

Miscellaneous othertemporarydifferences, net 43 (16)

Total noncurrent deferred tax liabilities (484)

(606)

Less amount included in other assets and deferred debits 10 9

Net noncurrent deferred tax liabilities

$(494)

$(615)

Total deferred income tax liabilities were $2,797 million and $2,662 million at December 31, 2004 and 2003, respectively. Total deferred income tax assets were 86

Progress Energy Annual Report 2004

$2,434 million and $2,143 million at December 31,2004 and 2003, respectively. Total noncurrent income tax liabilities on the Consolidated Balance Sheets at December 31,2004 and 2003 include $105 million and $86 million, respectively, related to probable tax liabilities on which the Company accrues interestthatwould be payable with the related tax amount in future years.

The federal income tax credit carry forward at December31, 2004, consists of $749 million of alternative minimum tax credit with an indefinite carry forward period and $30 million of general business credit with a carry forward period that will begin to expire in 2020.

As of December 31, 2004, the Company had a state net operating loss carry forward of $79 million, which will begin to expire in 2007.

The Company established additional valuation allowances of $5 million during 2004 and 2003 and S12 million during 2002, due to the uncertainty of realizing certain future state tax benefits. The Company believes it is more likely than not that the results of future operations will generate sufficient taxable income to allow for the utilization of the remaining deferred tax assets. Progress Energy decreased its 2004 beginning of the year valuation allowance by $8 million for a change in circumstances related to net operating losses.

The Company establishes accruals for certain tax contingencies when, despite the belief that the Company's tax return positions are fully supported, the Company believes that certain positions may be challenged and that it is probable the Company's positions may not be fully sustained. The Company is under continuous examination by the Internal Revenue Service and other tax authorities and accounts for potential losses of tax benefits in accordance with SFAS No. 5. At December 31, 2004 and 2003, respectively, the Company had recorded $60 million and $56 million of tax contingency reserves, excluding accrued interest and penalties, which are included in other current liabilities on the Consolidated Balance Sheets. Considering all tax contingency reserves, the Company does not expect the resolution of these matters to have a material impact on its financial position or result of operations. All tax contingency reserves relate to capitalization and basis issues and do not relate to any potential disallowances of tax credits from synthetic fuel production (See Note 23E).

Reconciliations of the Company's effective income tax rate to the statutory federal income tax rate are:

2004 2003 2002 Effective income tax rate 13.5%

(15.8)%

(40.0)%

State income taxes, net of federal benefit (6.9) 13.3)

(8.2)

AFUDC amortization (0.5)

(1.4)

(5.2)

Federal tax credits 25.6 50.4 78.0 Investmenttaxcreditamortization 1.6 2.3 4.7 ESOP dividend deduction 1.8 2.1 3.8 Otherdifferences, net (0.1) 0.7 1.9 Statutory federal income tax rate 35.0%

35.0%

35.0%

Income tax expense (benefit) applicable to continuing operations is comprised of:

[in millions) 2004 2003 2002 Current-federal S127

$127 S195 state 76 54 67 Deferred - federal (84)

(255)

(379) state 10 (21)

(23)

Investmenttax credit (14)

(16)

(18)

Total income tax expense (benefit)

S115 S0 1l) 5(158)

The company has recognized tax benefits from state net operating loss carry forwards in the amount of $7 million during 2004 and $3 million during 2003 and 2002.

The Company, through its subsidiaries, is a majority owner in five entities and a minority owner in one entity that owns facilities that produce synthetic fuel as defined under the Internal Revenue Code (Code). The production and sale of the synthetic fuel from these facilities qualifies for tax credits under Section 29 if certain requirements are satisfied (See Note 23E).

16. CONTINGENT VALUE OBLIGATIONS In connection with the acquisition of FPC during 2000, the Company issued 98.6 million contingent value obligations (CVOs). Each CVO represents the right to receive contingent payments based on the performance of four synthetic fuel facilities purchased by subsidiaries of FPC in October 1999.The payments, if any, would be based on the net after-tax cash flows the facilities generate. The CVO liability is adjusted to reflect market price fluctuations. The unrealized loss/gain recognized due to these market fluctuations is recorded in other, net on the Consolidated Statements of Income (See Note 21). The liability, included in other liabilities and deferred credits, at December 31, 2004 and 2003, was $13 million and

$23 million, respectively.

87

V Notes to Consolidated Financial Statements

17. BENEFIT PLANS A. Postretirement Benefits The Company and some of its subsidiaries have a noncontributory defined benefit retirement (pension) plan for substantially all full-time employees.The Company also has supplementary defined benefit pension plans that provide benefits to higher-level employees. In addition to pension benefits, the Company and some of its subsidiaries provide contributory other postretirement benefits (OPEB), including certain health care and life insurance benefits, for retired employees who meet specified criteria.The Company uses a measurement date of December31 for its pension and OPEB plans.

The components of netperiodic benefitcostfortheyears ended December 31 are:

Pension Benefits Other Postretirement Benefits (in millions]

2004 2003 2002 2004 2003 2002 Service cost S54 S52 S45

$12

$15

$13 Interest cost 110 108 106 31 33 32 Expected return on plan assets 1155)

(144)

(161)

(5)

(4)

(5)

Amortization of actuarial (gain) loss 21 25 2

4 5

1 Other amortization, net 1

4 4

Net periodic cost/(benefit) 30 41 (8) 43 53 45 Additional cost/(benefit) recognition (Note 17B)

(16)

(18)

(7) 2 2

2 Net periodic cosl(benefit) recognized

$14 S23

$115)

$45

$55 S47 The net periodic cost for other postretirement benefits decreased during 2004 due to the implementation of FASB Staff Position 106-2 (See Note 2). In addition to the net periodic cost and benefit reflected above, in 2003 the Company recorded curtailment and settlement effects related to the disposition of NCNG, which are reflected in income/lloss) from discontinued operations in the Consolidated Statements of Income. These effects included a pension-related loss of $13 million and an OPEB-related gain of $1 million.

Prior service costs and benefits are amortized on a straight-line basis over the average remaining service period of active participants. Actuarial gains and losses in excess of 10% of the greater of the projected benefit obligation or the market-related value of assets are amortized over the average remaining service period of active participants.

To determine the market-related value of assets, the Company uses a five-year averaging method for a portion of its pension assets and fair value for the remaining portion. The Company has historically used the five-year averaging method. When the Company acquired Florida Progress in 2000, it retained the Florida Progress historical use of fair value to determine market-related value for Florida Progress pension assets.

Reconciliations of the changes in the plans' benefit obligations and the plans' funded status are:

88

Progress Energy Annual Report 2004 Pension Benefits Other Postretirement Benefits (in millions) 2004 2003 2004 2003 Projected benefit obligation at January 1

$1,772

$1,694

$472

$514 Service cost 54 52 12 15 Interest cost 110 108 31 33 Disposition of NCNG (39)

(13)

Benefit payments (98)

(94)

(23) 124)

Plan amendment 21 Actuarial loss (gain) 102 51 46 (53)

Obligation at December 31 1,961 1,772 538 472 Fairvalue of plan assets at December31 1.774 1,631 70 65 Funded status (187)

(141)

(468)

(407)

Unrecognized transition obligation 10 25 Unrecognized prior service cost 24 4

6 7

Unrecognized net actuarial loss 530 505 94 40 Minimum pension liability adjustment (470)

(23)

Prepaid (accrued) cost at December 31, net (Note 17B)

S(103)

$345 S(358)

S(335)

The 2003 OPEB obligation information above has been restated due to the implementation of FASB Staff Position 106-2 ISee Note 2).

The net accrued pension cost of $103 million at December 31,2004, is recognized in the Consolidated Balance Sheets as prepaid pension cost of S42 million and accrued benefit cost of $145 million, which is included in accrued pension and other benefits. The net prepaid pension cost of

$345 million at December 31, 2003, is recognized in the Consolidated Balance Sheets as prepaid pension cost of

$462 million and accrued benefit cost of $117 million, which is included in accrued pension and other benefits. The defined benefit pension plans with accumulated benefit obligations in excess of plan assets had projected benefit obligations totaling $1.72 billion and S125 million at December31,2004 and 2003, respectively.Those plans had accumulated benefit obligations totaling $1.71 billion and

$117 million at December 31, 2004 and 2003, respectively,

$1.57 billion of plan assets at December 31, 2004, and no plan assets at December 31, 2003. The total accumulated benefit obligation for pension plans was $1.90 billion and

$1.72 billion at December 31, 2004 and 2003, respectively.

The accrued OPEB cost is included in accrued pension and other benefits in the Consolidated Balance Sheets.

A minimum pension liability adjustment of $470 million was recorded at December 31, 2004. This adjustment resulted in a charge of S24 million to intangible assets, a

$150 million charge to a pension-related regulatory liability (See Note 17B), a $67 million charge to a regulatory asset pursuant to a recent FPSC order and a pre-tax charge of $229 million to accumulated other comprehensive loss, a component of common stock equity. A minimum pension liability adjustment of

$23 million, related to the supplementary defined benefit pension plans, was recorded at December 31, 2003. This adjustment is offset by a corresponding pre-tax amount in accumulated other comprehensive loss.

Reconciliations of the fair value of plan assets are:

(in millions)

Fair value of plan assets January 1 Actual return on plan assets Disposition of NCNG Benefit payments Employer contributions Fair value of plan assets at December 31 Pension Benefits 2004 2003

$1,631

$1,364 211 391 (35)

(98)

(94) 30 5

Other Postretirement Benefits 2004 2003

$65

$52 8

12 (23)

(24) 20 25

$1,774

$1,631

$70

$65 In the table above, substantially all employer contributions represent benefit payments made directly from Company assets except for the 2004 pension amount. The remaining benefits payments were made directly from plan assets. In 2004, the Company made a required contribution of approximately $24 million directly to pension plan assets. The OPEB benefit payments represent the net Company cost after participant contributions.

Participant contributions represent approximately 20% of gross benefit payments.

89

V Notes to Consolidated Financial Statements The asset allocation forthe Company's plans atthe end of 2004 and 2003 and the target allocation for the plans, by asset category, are as follows:

Pension Benefits Other Postretirement Benefits Target Percentage of Plan Target Percentage of Plan Allocations Assets at Year End Allocations Assets at Year End Asset Category 2005 2004 2003 2005 2004 2003 Equity - domestic 48%

47%

49%

34%

34%

35%

Equity-international 15%

21%

22%

11%

15%

16%

Debt-domestic 12%

9%

11%

37%

35%

37%

Debt-international 10%

11%

11%

7%

8%

7%

Other 15%

12%

7%

11%

8%/o 5%

Total 100%

100%0 100%

100%

100%

100%

The Company sets target allocations among asset classes to provide broad diversification to protect against large investment losses and excessive volatility, while recognizing the importance of offsetting the impacts of benefit cost escalation. In addition, the Company employs external investment managers who have complementary investment philosophies and approaches. Tactical shifts (plus or minus 5%) in asset allocation from the target allocations are made based on the near-term view of the risk and return tradeoffs of the asset classes.

In 2005, the Company expects to make no required contributions directly to pension plan assets and

$1 million of discretionary contributions directly to the OPEB plan assets. The expected benefit payments for the pension benefit plan for 2005 through 2009 and in total for 2010-2014, in millions, are approximately $113,$110,$115,

$124, $131 and $794, respectively. The expected benefit payments for the OPEB plan for 2005 through 2009 and in total for 2010-2014, in millions, are approximately $32, $34,

$37, $39, $41 and S230, respectively. The expected benefit payments include benefit payments directly from plan assets and benefit payments directly from Company assets. The benefit payment amounts reflect the net cost to the Company after any participant contributions. The Company expects to begin receiving prescription drug-related federal subsidies in 2006 (See Note 2), and the expected subsidies for 2006 through 2009 and in total for 2010-2014, in millions, are approximately $3, S3, $3, $4 and

$24, respectively. The expected benefit payments above do not reflect the potential effects of a 2005 voluntary enhanced retirement program (See Note 24).

The following weighted-average actuarial assumptions were used in the calculation of the year-end obligation:

Other Pension Postretirement Benefits Benefits (in millions) 2004 2003 2004 2003 Discount rate 5.90%

6.30%

5.9%

6.30%

Rate of increase in future compensation Bargaining 3.50%

3.50%

Supplementary plans 5.25%

5.00%

Initial medical cost trend rate for pre-Medicare benefits 7.25%

7.25%

Initial medical cost trend rate for post-Medicare benefits 7.25%

7.25%

Ultimate medical cost trend rate 5.00%

5.25%

Year ultimate medical costtrend rate is achieved 2008 2009 The Company's primary defined benefit retirement plan for nonbargaining employees is a 'cash balance' pension plan as defined in EITF Issue No. 03-4. Therefore, effective December 31, 2003, the Company began to use the traditional unit credit method for purposes of measuring the benefit obligation of this plan. Under the traditional unit credit' method, no assumptions are included about future changes in compensation, and the accumulated benefit obligation and projected benefit obligation are the same.

90

Progress Energy Annual Report 2004 The following weighted-average actuarial assumptions were used in the calculation of the net periodic cost:

Other Postretirement Pension Benefits Benefits

[in millions) 2004 2003 2002 2004 2003 2002 Discount rate 6.30% 6.60% 7.50% 6.30% 6.60% 7.50%

Rate of increase in future compensation Bargaining 3.50% 3.50% 3.50%

Nonbargaining 4.00% 4.00%

Supplementary plans 5.00% 4.00% 4.00%

Expected long-term rate of return on plan assets 9.25% 9.25% 9.25% 8.50% 8.45% 8.20%

The expected long-term rates of return on plan assets were determined by considering long-term historical returns for the plans and long-term projected returns based on the plans' target asset allocation. For all pension plan assets and a substantial portion of OPEB plans assets, those benchmarks support an expected long-term rate of return between 9.0% and 9.5%. The Company has chosen to use an expected long-term rate of 9.25%.

The medical cost trend rates were assumed to decrease gradually from the initial rates to the ultimate rates.

Assuming a 1% increase in the medical cost trend rates, the aggregate of the service and interest cost components of the net periodic OPEB cost for 2004 would increase by $1 million, and the OPEB obligation at December 31, 2004, would increase by $30 million.

Assuming a 1% decrease in the medical cost trend rates, the aggregate of the service and interest cost components of the net periodic OPEB costfor 2004 would decrease by S1 million, and the OPEB obligation at December 31, 2004, would decrease by $26 million.

B. FPC Acquisition During 2000, the Company completed the acquisition of FPC. FPC's pension and OPEB liabilities, assets and net periodic costs are reflected in the above information as appropriate. Certain of FPC's nonbargaining unit benefit plans were merged with those of the Company effective January 1, 2002.

PEF continues to recover qualified plan pension costs and OPEB costs in rates as if the acquisition had not occurred. Accordingly, a portion of the accrued OPEB cost reflected in the table above has a corresponding regulatory asset at December 31, 2004, and 2003 (See Note 8A). In addition, a portion of the prepaid pension cost reflected in the table above has a corresponding regulatory liability (See Note 8A). Pursuant to its rate treatment, PEF recognized additional periodic pension credits and additional periodic OPEB costs, as indicated in the net periodic cost information above.

18. RISK MANAGEMENT ACTIVITIES AND DERIVATIVES TRANSACTIONS Under its risk management policy, the Company may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. Such instruments contain credit risk if the counterparty fails to perform under the contract. The Company minimizes such risk by performing credit reviews using, among other things, publicly available credit ratings of such counterparties.

Potential nonperformance by counterparties is not expected to have a material effect on the consolidated financial position or consolidated results of operations of the Company.

A. Commodity Derivatives GENERAL Most of the Company's commodity contracts are not derivatives pursuant to SFAS No. 133 or do not qualify as normal purchases or sales pursuant to SFAS No. 133.

Therefore, such contracts are not recorded at fair value.

During 2003 the FASB reconsidered an interpretation of SFAS No. 133 related to the pricing of contracts that include broad market indices (e.g., CPI). In particular, that guidance discussed whether the pricing in a contract that contains broad market indices could qualify as a normal purchase or sale (the normal purchase or sale term is a defined accounting term, and may not, in all cases, indicate whether the contract would be 'normal' from an operating entity viewpoint). The FASB issued final superseding guidance (DIG Issue C20) on this issue effective October 1,2003,for the Company. DIG Issue C20 specifies new pricing-related criteria for qualifying as a normal purchase or sale, and it required a special transition adjustment as of October 1, 2003.

PEC determined that it had one existing 'normal" contract that was affected by DIG Issue C20. Pursuant to the provisions of DIG Issue C20, PEC recorded a pre-tax fair value loss transition adjustment of $38 million

($23 million after-tax) in the fourth quarter of 2003, which was reported as a cumulative effect of a change in accounting principle. The subject contract meets the DIG Issue C20 criteria for normal purchase or sale and, 91

V Notes to Consolidated Financial Statements therefore, was designated as a normal purchase as of October 1, 2003. The original liability of $38 million associated with the fair value loss is being amortized to earnings over the term of the related contract. At December 31, 2004 and 2003, the remaining liability was

$26 million and $35 million, respectively.

ECONOMIC DERIVATIVES Derivative products, primarily electricity and natural gas contracts, are entered into for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions. The Company manages open positions with strict policies that limit its exposure to market risk and require daily reporting to management of potential financial exposures. Gains and losses from such contracts were not material to results of operations during 2004, 2003 or 2002, and the Company did not have material outstanding positions in such contracts at December 31, 2004 and 2003.

In 2004, PEF entered into derivative instruments related to its exposure to price fluctuations on fuel oil purchases. At December 31, 2004, the fair values of these instruments were a $2 million long-term derivative asset position included in other assets and deferred debits and a

$5 million short-term derivative liability position included in other current liabilities. These instruments receive regulatory accounting treatment Gains are recorded in regulatory liabilities and losses are recorded in regulatory assets.

The ineffective portion of commodity cash flow hedges was not material to the Company's results of operations for 2004, 2003 or 2002. At December 31, 2004, there were S9 million of after-tax deferred losses in accumulated other comprehensive income (OCI), of which $5 million is expected to be reclassified to earnings during the next 12 months as the hedged transactions occur. Gains and losses are recorded net in operating revenues. As part of the divestiture of Winchester Production Company, Ltd.,

assets in 2004, $7 million of after-tax deferred losses were reclassified into earnings due to discontinuance of the related cash flow hedges and recorded against the gain on sale. Due to the volatility of the commodities markets, the value in OCI is subject to change prior to its reclassification into earnings.

B. Interest Rate Derivatives -

Fair Value or Cash Flow Hedges The Company uses cash flow hedging strategies to hedge variable interest rates on long-term and short-term debt and to hedge interest rates with regard to future fixed-rate debt issuances. Gains and losses are recorded in OCI and amounts reclassified to earnings are included in net interest charges as the hedged transactions occur. The Company uses fairvalue hedging strategies to manage its exposure to fixed interest rates on long-term debt For interest rate fair value hedges, the change in the fair value of the hedging derivative is recorded in net interest charges and is offset by the change in the fair value of the hedged item.

The fair values of open position interest rate hedges at December 31, 2004 and 2003 were as follows:

CASH FLOW HEDGES Progress Energy's subsidiaries designate a portion of commodity derivative instruments as cash flow hedges under SFAS No. 133. The objective for holding these instruments is to hedge exposure to market risk associated with fluctuations in the price of natural gas for the Company's forecasted purchases and sales. At December 31, 2004, the maximum period over which the Company is hedging exposures to the price variability of natural gas is 10 years.

The total fair value of commodity cash flow hedges at December 31, 2004 and 2003 was as follows:

(millions of dollars) 2004 2003 Fair value of assets S-Fair value of liabilities (15)

(12)

Fairvalue, net 5(15)

S(12)

(in millions) 2004 2003 Interestrate cash flow hedges

$12)

$(6)

Interest rate fair value hedges

$3

$14)

CASH FLOW HEDGES The following table presents selected information related to the Company's interest rate cash flow hedges included in accumulated OCI at December 31, 2004:

Accumulated Other Comprehensive Income/(Loss),

Portion Expected to be net of taxlal Reclassified to Earnings (millions of dollars) during the Next 12 Monthslb)

S(19)

S(4) ta) Includes amounts related to terminated hedges.

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

92

Progress Energy Annual Report 2004 As of December 31, 2004, PEC had $110 million notional amount of pay-fixed forward swaps to hedge its exposure to interest rates with regard to future issuances of debt (pre-issue hedges) and $21 million notional amount of pay-fixed forward starting swaps to hedge its exposure to interest rates with regard to an upcoming railcar lease. On February4,2005, PEC entered another $50 million notional amount of its pre-issue hedges. All the swaps have a computational period of 10 years. PEC held no interest rate cash flow hedges at December 31, 2003. The ineffective portion of interest rate cash flow hedges was not material to the Company's results of operations for 2004 and 2003.

In December 2004, Progress Ventures, Inc. (PVI), a wholly owned subsidiary of Progress Energy, terminated S195 million notional amount of interest rate collars in place to hedge floating interest rate exposure associated with variable-rate long-term debt. The related debt was also extinguished in December 2004 (See Note 13). Pre-tax deferred losses of $6 million ($4 million after-tax) were reclassified into earnings in other, net due to discontinuance of these cash flow hedges.

At December 31, 2004 and 2003, Progress Energy, Inc.,

held interest rate cash flow hedges, with a total notional amount of $200 million and $400 million, respectively, related to projected outstanding balances of commercial paper. The fair value of the hedges at December 31, 2004, was not material to the Company's financial condition and at December 31, 2003, was S5 million. The hedges held at December 31, 2003, were terminated during the year.

Amounts in accumulated other comprehensive income related to these terminated hedges will be reclassified to earnings as the hedged interest payments occur.

FAIR VALUE HEDGES As of December 31, 2004 and 2003, Progress Energy had S150 million notional amount and $850 million notional amount, respectively, of fixed rate debt swapped to floating rate debt by executing interest rate derivative agreements.

These agreements expire on various dates through March 2011. During 2004, Progress Energy entered into S350 million notional amount and terminated $1.05 billion notional amount of interest rate swap agreements.

At December 31, 2004 and 2003, the Company had S9 million and $23 million, respectively, of basis adjustments in long-term debt related to terminated interest rate fair value hedges, which are being amortized over periods ending in 2006 through 2011 coinciding with the maturities of the related debt instruments.

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

In the event of default by a counterparty, the risk in these transactions is the cost of replacing the agreements at current market rates.

19. RELATED PARTY TRANSACTIONS As a part of normal business, Progress Energy and certain subsidiaries enter into various agreements providing financial or performance assurances to third parties. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries' intended commercial purposes. As of December 31,2004, Progress Energy and its subsidiaries' guarantees include: $270 million supporting commodity transactions, $181 million to support nuclear decommissioning, $536 million related to power supply agreements and $182 million for guarantees supporting other agreements of subsidiaries.

Progress Energy also purchased $92 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $50 million. Florida Progress also fully guarantees the medium-term notes outstanding for Progress Capital, a wholly owned subsidiary of Florida Progress (See Note 13). At December 31, 2004, management does not believe conditions are likely for significant performance under these agreements. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included in the Balance Sheets.

Progress Fuels sells coal to PEF for an insignificant profit. These intercompany revenues and expenses are eliminated in consolidation; however, in accordance with SFAS No. 71, profits on intercompany sales to regulated affiliates are not eliminated if the sales price is reasonable and the future recovery of sales price through the ratemaking process is probable. Sales, net of insignificant profits, of $331 million, $346 million and

$329 million for the years ended December 31, 2004, 2003 and 2002, respectively, are included in fuel used in electric generation on the Consolidated Statements of Income.

Florida Progress Funding Corporation's (Funding Corp.)

$309 million 7.10% Junior Subordinated Deferrable Interest Notes (Subordinated Notes) are due to FPC Capital I (the Trust). The Trust was established for the sole purpose of issuing $300 million Preferred Securities and using the proceeds thereof to purchase from Funding Corp. its Subordinated Notes due 2039. The 93

V Notes to Consolidated Financial Statements Company has fully and unconditionally guaranteed the obligations of Funding Corp. under the Subordinated Notes (the Notes Guarantee). In addition, the Company has guaranteed the payment of all distributions related to the $300 million Preferred Securities required to be made by the Trust, but only to the extent that the Trust has funds available for such distributions (Preferred Securities Guarantee).

The Preferred Securities Guarantee, considered together with the Notes Guarantee, constitutes a full and unconditional guarantee by the Company of the Trust's obligations under the Preferred Securities. The Subordinated Notes and the Notes Guarantee are the sole assets of the Trust The Subordinated Notes may be redeemed at the option of Funding Corp. at par value plus accrued interest through the redemption date. The proceeds of any redemption of the Subordinated Notes will be used by the Trust to redeem proportional amounts of the Preferred Securities and common securities in accordance with their terms. Upon liquidation or dissolution of Funding Corp., holders of the Preferred Securities would be entitled to the liquidation preference of $25 per share plus all accrued and unpaid dividends thereon to the date of payment. The yearly interest expense is $21 million and is reflected in the Consolidated Statements of Income.

The Company sold NCNG to Piedmont Natural Gas Company, Inc. on September 30, 2003 (See Note 4E).

Prior to disposition, NCNG sold natural gas to affiliates.

During the years ended December 31, 2003 and 2002, sales of natural gas to affiliates amounted to $11 million and $20 million, respectively. These revenues are included in discontinued operations on the Consolidated Statements of Income.

20. FINANCIAL INFORMATION BY BUSINESS SEGMENT The Company currently provides services through the following business segments: PEC Electric, PEF, Fuels, CCO and Rail Services. Prior to 2004, other nonregulated business activities were reported separately in the Other segment. These reportable segment changes reflect the current reporting structure. For comparative purposes, the results have been restated to align with the current presentation.

PEC Electric and PEF are primarily engaged in the generation, transmission, distribution and sale of electric energy in portions of North Carolina, South Carolina and Florida. These electric operations are subject to the rules and regulations of the FERC, the NCUC, the SCPSC and the FPSC. These electric operations also distribute and sell electricity to other utilities, primarily on the east coast of the United States.

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

CCO's operations, which are located in the southeastern United States, include nonregulated electric generation operations and marketing activities.

Rail Services' operations include railcar repair, rail parts reconditioning and sales, railcar leasing and sales and scrap metal recycling. These activities include maintenance and reconditioning of salvageable scrap components of railcars, locomotive repair and right-of-way maintenance. Rail Services' operations are located in the United States, Canada and Mexico.

In addition to these reportable operating segments, the Company has Corporate and Other activities that include holding company and service company operations as well as other nonregulated business areas. These nonregulated business areas include telecommunications and energy service operations and other nonregulated subsidiaries that do notseparatelymeetthe disclosure requirements of SFAS No. 131, 'Disclosures about Segments of an Enterprise and Related Information." Included in the 2004 losses is a

$43 million pre-tax ($29 million after-tax) settlement agreementthat SRS reached with the San Francisco United School District related to civil proceedings. Included in the 2002 losses are asset impairments and certain other after-tax charges related to the telecommunications operations of $225 million. The operations of NCNG were reclassified to discontinued operations and therefore are not included in the results from continuing operations during the periods reported. The profit or loss of the identified segments plus the loss of Corporate and Other represents the Company's total income from continuing operations.

Products and services are sold between the various reportable segments. All intersegment transactions are at cost except for transactions between Fuels and PEF, which are at rates set by the FPSC. In accordance with SFAS No. 71, profits on intercompany sales between PEF and Fuels are not eliminated if the sales price is reasonable and the future recovery of sales price through the ratemaking process is probable. The profits for all three years presented were not significant.

94

Progress Energy Annual Report 2004 PEC Rail Corporate (in millions)

Electric PEF Fuels CCO Services and Other Eliminations Totals Year ended December 31, 2004 Revenues Unaffiliated

$3,528

$3,525

$1,179

$240

$1.130

$70 S-

$9.772 Intersegment 331 1

441 (773)

Total revenues 3,628 3,525 1,510 240 1,131 511 (773) 9,772 Depreciation and amortization 570 281 93 58 21 45 1,068 Total interest charges, net 192 114 22 17 27 361 (86) 647 Gain on sale of assets 54 3

57 Income tax expense (benefit)(a) 237 174 (230)

(1) 15 (80) 115 Segment profit (loss) 464 333 180 (4) 16 (236) 753 Total assets 10.590 7,924 986 1.709 596 17,741 (13,553) 25.993 Capital and investment expenditures 519 480 157 25 40 14 1,235 Year ended December31,2003 Revenues Unaffiliated

$3,589

$3,152 S928 S170

$846 S56 S-

$8,741 Intersegment 346 1

446 (793)

Total revenues 3,589 3,152 1,274 170 847 502 (793) 8,741 Depreciation and amortization 562 307 80 42 20 29 1,040 Total interest charges, net 197 91 23 4

29 356 (72) 628 Impairment of long-lived assets and investments 11 17 10 38 Income tax expense (benefit)(3) 238 147 (415) 8 2

(46)

(45)

(111)

Segmentprofit(loss) 515 295 235 20 (1)

(253) 811 Total assets 10,748 7,280 1,142 1,747 586 17,955 (13,365) 26,093 Capital and investment expenditures 445 526 309 338 103 35 1,756 Year ended December 31, 2002 Revenues Unaffiliated

$3,539 S3,062

$607

$92

$714

$77 S-

$8,091 Intersegment 329 5

418 (752)

Total revenues 3,539 3,062 936 92 719 495 (752) 8,091 Depreciation and amortization 524 295 47 20 20 32 938 Totalinterestchargesnet 212 106 24 (12) 33 351 (81) 633 Impairment of long-lived assets and investments 59 330 389 Incometaxexpense(beneft)(a) 237 163 (373) 16 (16)

(191) 6 (158)

Segment profit (loss) 513 323 176 27 (42)

(445) 552 Total assets 10,139 6,678 934 1,452 529 15,872 111,886) 23,718 Capital and investment expenditures 619 550 170 682 8

73 2,102 (a)Amounts include income tax benefit reallocation from holding company to profitable subsidiaries according to an SEC order.

95

V Notes to Consolidated Financial Statements Geographic Data (in millions)

U.S.

Canada Mexico Consolidated 2004 Consolidated revenues

$9,644

$112

$16 S9.772 2003 Consolidated revenues

$8,624 S103

$14 S8,741 2002 Consolidated revenues

$7,984 S93

$14

$8,091

22. ENVIRONMENTAL MATTERS

21. OTHER INCOME AND OTHER EXPENSE Other income and expense includes interest income, impairment of investments and other income and expense items as discussed below. The components of other, net as shown on the Consolidated Statements of Income for the years ended December31 are as follows:

(in millions) 2004 2003 2002 Other Income Nonregulated energy and delivery services income

$32

$27

$33 DIG Issue C20 amortization (Note 18A) 9 2

Contingent value obligation unrealized gain (Note 16) 9 28 Investment gains 5

AFUDC equity 11 14 8

Gain on sale of property and partnership investments 12 25 12 Other 34 17 42 Total other income S107

$90

$123 Other Expense Nonregulated energy and delivery services expenses

$20

$20 S29 Donations 10 12 19 Investment losses 6

Contingent value obligation unrealized loss (Note 16) 9 Loss from equity investments 6

40 21 Loss on debt extinguishment and interest rate collars (Note 13D) 15 Other 42 25 27 Total other expense

$99

$106

$96 Other, net

$8 S(16)

$27 The Company is subject to federal, state and local regulations addressing hazardous and solid waste management, air and water quality and other environmental matters.

Hazardous and Solid Waste Management The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liabilities. Some states, including North and South Carolina, have similar types of legislation. The Company and its subsidiaries are periodically notified by regulators including the EPA and various state agencies of their involvement or potential involvement in sites that may require investigation and/or remediation. There are presently several sites with respect to which the Company has been notified by the EPA, the State of North Carolina or the State of Florida of its potential liability, as described below in greater detail.

The Company also is currently in the process of assessing potential costs and exposures at other sites.

For all sites, as assessments are developed and analyzed, the Company will accrue costs for the sites to the extent the costs are probable and can be reasonably estimated. A discussion of sites by legal entity follows.

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

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

PEC There are nine former MGP sites and a numberof othersites associated with PEC that have required or are anticipated to require investigation and/or remediation costs.

During the fourth quarter of 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site located in Raleigh, North Carolina. The EPA offered PEC and 34 other PRPs the opportunity to 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.

96

Progress Energy Annual Report 2004 negotiate cleanup of the site and reimbursement of less than $2 million to the EPA for EPA's past expenditures in addressing conditions at the site. Although a loss is considered probable, an agreement among PRPs has not been reached; consequently, it is not possible at this time to reasonably estimate the total amount of PEC's obligation for remediation of the Ward Transformer site.

At December 31, 2004, and 2003, PEC's accruals for probable and estimable costs related to various environmental sites, which are included in other liabilities and deferred credits and are expected to be paid out over many years, were:

(in millions) 2004 2003 Insurance fund

$7

$9 Transferred from NCNG attime of sale 2

2 Total accrual for environmental sites

$9 S11 environmental sites, which are included in other liabilities and deferred credits and are expected to be paid out over many years, were:

(in millions) 2004 2003 Remediation of distribution and substation transformers

$27

$12 MGP and other sites 18 6

Total accrual for environmental sites

$45

$18 PEC received insurance proceeds to address costs associated with environmental liabilities related to its involvement with some sites. All eligible expenses related to these are charged against a specific fund containing these proceeds. PEC spent approximately

$2 million related to environmental remediation in 2004.

PEC is unable to provide an estimate of the reasonably possible total remediation costs beyond what is currently accrued because investigations have not been completed at all sites.

This accrual has been recorded on an undiscounted basis. PEC measures its liability for these sites based on available evidence including its experience in investigating and remediating environmentally impaired sites. The process often involves assessing and developing cost-sharing arrangements with other PRPs.

PEC will accrue costs for the sites to the extent its liability is probable and the costs can be reasonably estimated.

Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet reached the stage where a reasonable estimate of the remediation costs can be made, PEC cannot determine the total costs that may be incurred in connection with the remediation of all sites at this time. It is anticipated that sufficient information will become available for several sites during 2005 to allow a reasonable estimate of PEC's obligation for those sites to be made.

PEF At December 31, 2004, and 2003, PEF's accruals for probable and estimable costs related to various PEF has received approval from the FPSC for recovery of costs associated with the remediation of distribution and substation transformers through the Environmental Cost Recovery Clause (ECRC). Under agreements with the Florida Department of Environmental Protection (FDEP),

PEF is in the process of examining distribution transformer sites and substation sites for potential equipment integrity issues that could result in the need for mineral oil impacted soil remediation. Through 2004 PEF has reviewed a number of distribution transformer sites and substation sites. PEF expects to have completed its review of distribution transformer sites by the end of 2007 and has completed the review of substation sites in 2004. Should further sites be identified, PEF believes that any estimated costs would also be recovered through the ECRC clause. In 2004, PEF accrued an additional $19 million due to identification of additional sites requiring remediation, and spent approximately

$4 million related to the remediation of transformers. PEF has recorded a regulatory asset for the probable recovery of these costs through the ECRC.

The amounts for MGP and other sites, in the table above, relate to two former MGP sites and other sites associated with PEF that have required or are anticipated to require investigation and/or remediation.

In 2004, PEF received approximately $12 million in insurance claim settlement proceeds and recorded a related accrual for associated environmental expenses.

The proceeds are restricted for use in addressing costs associated with environmental liabilities. Expenditures for the year were less than $1 million.

These accruals have been recorded on an undiscounted basis. PEF measures its liability for these sites based on available evidence including its experience in investigating and remediating environmentally impaired sites. This process often includes assessing and developing cost-sharing arrangements with other PRPs.

Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet advanced to the stage where a reasonable estimate of 97

V Notes to Consolidated Financial Statements 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 atthese sites, PEFAwill assessthe need to adjust the accruals. It is anticipated that sufficient information will become available in 2005 to make a reasonable estimate of PEFs obligation for one of the MGP sites.

The Florida Legislature passed risk-based corrective action (RBCA, known as Global RBCA) legislation in the 2003 regular session. Risk-based corrective action generally means that the corrective action prescribed for contaminated sites can correlate to the level of human health risk imposed by the contamination at the property. The Global RBCA law expands the use of the risk-based corrective action to all contaminated sites in the state that are not currently in one of the state's waste cleanup programs. The FDEP developed the rules required by the RBCA statute, holding meetings with interested stakeholders and hosting public workshops.

The rules have the potential for making future cleanups in Florida more costly to complete. The Global RBCA rule was adopted at the February 2, 2005, Environmental Review Commission hearing. The effective date of the Global RBCA rule is expected to be announced in April 2005. The Company and PEF are in the process of assessing the impact of this matter.

Florida Progress Corporation In 2001, FPC established a $10 million accrual to address indemnities and retained an environmental liability associated with the sale of its Inland Marine Transportation business. In 2003, the accrual was reduced to $4 million based on a change in estimate.

During 2004, expenditures related to this liability were not material to the Company's financial condition. As of December 31, 2004, the remaining accrual balance was approximately $3 million. FPC measures its liability for these exposures based on estimable and probable remediation scenarios.

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

Rail Rail Services is voluntarily addressing certain historical waste sites. At this time, the Company cannot determine the total costs that may be incurred in connection with these sites.

Air Quality Congress is considering legislation that would require reductions in air emissions of NOx, S02, carbon dioxide and mercury. Some of these proposals establish nationwide caps and emission rates over an extended period of time. This national multi-pollutant approach to air pollution control could involve significant capital costs that could be material to the Company's consolidated financial position or results of operations. Control equipment that will be installed on North Carolina fossil generating facilities as part of the NC Clean Air legislation discussed below may address some of the issues outlined above. However, the Company cannot predict the outcome of this matter.

The EPA is conducting an enforcement initiative related to a number of coal-fired utility power plants in an effort to determine whether changes at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act.

The Company was asked to provide information to the EPA as part of this initiative and cooperated in supplying the requested information. The EPA initiated civil enforcement actions against other unaffiliated utilities as part of this initiative. Some of these actions resulted in settlement agreements calling for expenditures by these unaffiliated utilities, in excess of $1.0 billion. These settlement agreements have generally called for expenditures to be made over extended time periods, and some of the companies may seek recovery of the related cost through rate adjustments or similar mechanisms.

The Company cannot predict the outcome of this matter.

In 2003, the EPA published a final rule addressing routine equipment replacement under the New Source Review program.

The rule defines routine equipment replacement and the types of activities that are not subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act.

The rule was challenged in the Federal Appeals Court and its implementation stayed. In July 2004, the EPA announced it will reconsider certain issues arising from the final routine equipment replacement rule. The comment period closed on August30,2004.The Company cannot predict the outcome of this matter.

In 1998, the EPA published a final rule under Section 110 of the Clean Air Act addressing the regional transport of ozone (NOx SIP Call). Total capital expenditures to meet the requirements of the NOx SIP Call Rule in North and South Carolina could reach approximately $370 million, which has not been adjusted for inflation. To date, the Company has spent approximately $282 million related to 98

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V Notes to Consolidated Financial Statements In December 2003, the EPA released its proposed Interstate Air Quality Rule, currently referred to as the Clean Air Interstate Rule (CAIR).The final rule was released on March 10, 2005. The EPA's rule requires 28 states and the District of Columbia, including North Carolina, South Carolina, Georgia and Florida, to reduce NOx and S02 emissions in order to attain preset 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. Compliance plans and cost to comply with the rule will be determined once the Company completes Rts review. The air quality controls already installed for compliance with the NOx SIP Call and currently planned by the Companyto complywith the NC Clean Air legislation will reduce the costs required to meet the CAIR requirements for the Company's North Carolina units.

In March 2004, the North Carolina Attorney General filed a petition with the EPA under Section 126 of the Clean Air Act, asking the federal government to force coal-fired power plants in 13 other states, including South Carolina, to reduce their NOx and S02 emissions. The state of North Carolina contends these out-of-state emissions interfere with North Carolina's ability to meet national air quality standards for ozone and particulate matter. The EPA has agreed to make a determination on the petition by August 1, 2005. The Company cannot predict the outcome of this matter.

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

After many years of litigation and settlement negotiations, the EPA adopted regulations in February 2004to implement Section 316(b) of the Clean Water Act. These regulations became effective September 7, 2004.The purpose of these regulations is to minimize adverse environmental impacts caused by cooling water intake structures and intake systems. Overthe next several years these regulations will impact the larger base load generation facilities and may require the facilities to mitigate the effects to aquatic organisms by constructing intake modifications or undertaking other restorative activities. The Company currently estimates that from 2005 through 2009 the range of its expenditures to meet the Section 316(b) requirements of the Clean Water Act will be $85 million to

$115 million. The range includes $20 million to $30 million at PEC and $65 million to $85 million at PEF Other Environmental Matters The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of carbon dioxide and other greenhouse gases. In 2004, Russia ratified the Protocol, and the treaty went into effect on February 16, 2005. The United States has not adopted the Kyoto Protocol, and the Bush administration has stated it favors voluntary programs. A number of carbon dioxide emissions control proposals have been advanced in Congress. Reductions in carbon dioxide emissions to the levels specified by the Kyoto Protocol and some legislative proposals could be materially adverse to the Company's consolidated financial position or results of operations if associated costs of control or limitation cannot be recovered from customers. The Company favors the voluntary program approach recommended by the administration and continually evaluates options for the reduction, avoidance and sequestration of greenhouse gases.

However, the Company cannot predict the outcome of this matter.

Progress Energy has announced its plan to issue a report on the Company's activities associated with current and future environmental requirements. The report will include a discussion of the environmental requirements that the Company currently faces and expects to face in the future, as well as an assessment of potential mandatory constraints on carbon dioxide emissions. The report will be issued by March 31, 2006.

23. COMMITMENTS AND CONTINGENCIES A. Purchase Obligations At December 31, 2004, the following table reflects Progress Energy's contractual cash obligations and other commercial commitments in which they are due:

the respective periods in (in millions) 2005 2006 2007 2008 2009 Thereafter Fuel S2,219 $1,473

$663

$229

$252

$1,270 Purchased power 473 473 479 449 416 4,614 Construction obligations 51 Other purchase obligations 100 70 64 41 39 268 Total S2,843 $2,016 S1,206 S719

$707 S6,152 100

Progress Energy Annual Report 2004 FUEL AND PURCHASED POWER FPC, PEC and Fuels have entered into various long-term contracts for coal, oil and gas. Payments under these commitments were S2,097 million, $1,719 million and S1,414 million for 2004, 2003 and 2002, respectively.

Pursuant to the terms of the 1981 Power Coordination Agreement, as amended, between PEC and the North Carolina Eastern Municipal Power Agency (Power Agency), PEC is obligated to purchase a percentage of Power Agency's ownership capacity of, and energy from, the Harris Plant In 1993, PEC and Power Agency entered into an agreement to restructure portions of their contracts covering power supplies and interests in jointly owned units. Under the terms of the 1993 agreement, PEC increased the amount of capacity and energy purchased from Power Agency's ownership interest in the Harris Plant, and the buyback period was extended six years through 2007.The estimated minimum annual payments for these purchases, which reflect capacity and energy costs, total approximately $38 million. These contractual purchases totaled $39 million, $36 million and $36 million for 2004, 2003 and 2002, respectively. In 1987, the NCUC ordered PECto reflectthe recovery of the capacity portion of these costs on a levelized basis overthe original 15-year buyback period, thereby deferring for future recovery the difference between such costs and amounts collected through rates. In 1988, the SCPSC ordered similar treatment, but with a 10-year levelization period. At December 31, 2004, all previously deferred costs have been expensed.

PEC has a long-term agreementforthe purchase of power and related transmission services from Indiana Michigan Power Company's Rockport Unit No. 2 (Rockport). The agreement provides for the purchase of 250 MW of capacity through 2009 with estimated minimum annual payments of approximately $43 million, representing capital-related capacity costs. Estimated annual payments for energy and capacity costs are approximately S72 million through 2009. Total purchases (including energy and transmission use charges) under the Rockport agreement amounted to $63 million, $66 million and

$59 million for 2004, 2003 and 2002, respectively.

PEC executed two long-term agreements for the purchase of power from Broad River LLC's Broad River facility. One agreement provides for the purchase of approximately 500 MW of capacity through 2021 with an original minimum annual payment of approximately

$16 million, primarily representing capital-related capacity costs. The second agreement provided for the additional purchase of approximately 300 MW of capacity through 2022 with an original minimum annual payment of approximately $16 million representing capital-related capacity costs. Total purchases for both capacity and energy under the Broad River agreements amounted to $42 million, $37 million and $38 million in 2004, 2003 and 2002 respectively.

PEF has long-term contracts for approximately 489 MW of purchased power with other utilities, including a contract with The Southern Company for approximately 414 MW of purchased power annually through 2015. Total purchases, for both energy and capacity, under these agreements amounted to $129 million, $124 million and $109 million for 2004,2003 and 2002, respectively. Total capacity payments were $56 million, $55 million and $50 million for 2004, 2003 and 2002, respectively. Minimum purchases under these contracts, representing capital-related capacity costs, at December 31, 2004, are $60 million, $63 million, $65 million,

$66 million and $67 million for 2005 through 2009, respectively, and $244 million thereafter.

Both PEC and PEF have ongoing purchased power contracts with certain cogenerators (qualifying facilities) with expiration dates ranging from 2005 to 2025. These purchased power contracts generally provide for capacity and energy payments. Energy payments for the PEF contracts are based on actual power taken under these contracts. Capacity payments are subject to the qualifying facilities (QFs) meeting certain contract performance obligations. PEF's total capacity purchases under these contracts amounted to $248 million,

$244 million and $235 million for 2004, 2003 and 2002, respectively. Minimum expected future capacity payments under these contracts at December 31, 2004, are $271 million, $279 million, $289 million, $298 million and

$263 million for 2005 through 2009, respectively, and

$3.8 billion thereafter.

PEC has various pay-for-performance contracts with QFs for approximately 400 MW of capacity expiring at various times through 2009. Payments for both capacity and energy are contingent upon the QFs' ability to generate. Payments made under these contracts were $91 million in 2004,

$113 million in 2003 and $145 million in 2002.

On December 2, 2004, PEF entered into precedent and related agreements with Southern Natural Gas Company (SNG), Florida Gas Transmission Company (FGT), and BG LNG Services, LLC for the supply of natural gas and associated firm pipeline transportation to augment PEF's gas supply needs for the period from May 1, 2007, to April 30, 2027. The total cost to PEF associated with the agreements is approximately $3.3 billion. The transactions 101

V Notes to Consolidated Financial Statements are subjectto several conditions precedent, which include obtaining the Florida Public Service Commission's approval of the agreements, the completion and commencement of operation of the necessary related expansions to SNG's and FGTs respective natural gas pipeline systems, and other standard closing conditions.

Due to the conditions precedent in the agreements, the estimated costs associated with these agreements are not included in the contractual cash obligations table above.

CONSTRUCTION OBLIGATIONS The Company has purchase obligations related to various capital construction projects. Total payments under these contracts were $102 million, $158 million and

$143 million for 2004, 2003 and 2002, respectively.

OTHER PURCHASE OBLIGATIONS The Company has entered into various other contractual obligations primarily related to service contracts for operational services entered into by PESC, a PVI parts and services contract, and a PEF service agreement related to the Hines Energy Complex. Payments under these agreements were $69 million, $31 million and $420 million for 2004, 2003 and 2002, respectively.

On December 31, 2002, PEC and PVI entered into a contractual commitment to purchase at least $13 million and $4 million, respectively, of capital parts by December31, 2010. During 2004 and 2003, no capital parts have been purchased under this contract B. Other Commitments The Company has certain future commitments related to four synthetic fuel facilities purchased that provide for contingent payments (royalties). The related agreements and their amendments require the payment of minimum annual royalties of approximately $7 million for each plant through 2007. The Company recorded a liability (included in other liabilities and deferred credits on the Consolidated Balance Sheets) and a deferred asset (included in other assets and deferred debits in the Consolidated Balance Sheets), each of approximately $73 million and $94 million at December 31, 2004 and 2003, respectively, representing the minimum amounts due through 2007, discounted at 6.05%.

At December31,2004 and 2003,the portions of the assetand liability recorded that were classified as current were approximately $26 million. The deferred asset will be amortized to expense each year as synthetic fuel sales are made. The maximum amounts payable under these agreements remain unchanged. Actual amounts paid under these agreements were none in 2004, $2 million in 2003 and S51 million in 2002. Future expected minimum royalty payments are approximately $26 million for 2005 through 2007. The Company has the right in the related agreements and their amendments that allow the Company to escrow those payments if certain conditions in the agreements are met The Company has exercised that right and retained 2004 and 2003 royalty payments of approximately$42 million and $48 million, respectively, pending the establishment of the necessary escrow accounts. Once established, those funds will be placed into escrow.

During 2004 Progress Energy made the first installment of

$10 million for a contract dispute. The installments for 2005 and 2006, respectively, are $16 million and $17 million (See Note 20).

C. Leases The Company leases office buildings, computer equipment, vehicles, railcars and other property and equipment with various terms and expiration dates. Some rental payments for transportation equipment include minimum rentals plus contingent rentals based on mileage. These contingent rentals are not significant. Rent expense under operating leases totaled $65 million, $60 million and $71 million for 2004, 2003 and 2002, respectively. Purchased power expense under agreements classified as operating leases were approximately$24 million in 2004 and S5 million in 2003.

Assets recorded under capital leases at December 31 consist of:

(in millions) 2004 2003 Buildings

$30

$30 Equipment and other 2

3 Less: Accumulated amortization (11 1

(10)

$21

$23 Minimum annual payments, excluding executory costs such as property taxes, insurance and maintenance, under long-term noncancelable leases at December 31,2004, are:

Capital Operating (in millions)

Leases Leases 2005

$4

$66 2006 4

55 2007 4

58 2008 4

58 2009 3

54 Thereafter 31 307

$50

$598 Less amount representing imputed interest (21)

Present value of net minimum lease payments under capital leases

$29 102

Progress Energy Annual Report 2004 In 2003, the Company entered into a new operating lease for a building, for which minimum annual rental payments are included in the table above. The lease terms provide for no rental payments during the last 15 years of the lease, during which period S53 million of rental expense will be recorded in the Consolidated Statements of Income.

The Company, excluding PEC and PEF, is also a lessor of land, buildings and other types of properties it owns under operating leases with various terms and expiration dates. The leased buildings are depreciated under the same terms as other buildings included in diversified business property. Minimum rentals receivable under noncancelable leases for 2005 through 2009 are approximately $32 million, $22 million, $14 million,

$9 million and $6 million, respectively, with $17 million receivable thereafter. Rents received under these operating leases totaled $63 million, $46 million and

$53 million for 2004, 2003 and 2002, respectively.

PEC is the lessor of electric poles, streetlights and other facilities. Minimum rentals under noncancelable leases are $9 million for 2005 and none thereafter. Rents received totaled $32 million, S31 million and $28 million for 2004, 2003 and 2002, respectively.

PEF is the lessor of electric poles, streetlights and other facilities. Rents received are based on a fixed minimum rental where price varies by type of equipment and totaled

$63 million, $56 million and $52 million for 2004, 2003 and 2002, respectively. Minimum rentals receivable (excluding streetlights) under noncancelable leases for 2005 is

$5 million, for 2006 through 2009 $1 million, and

$8 million thereafter. Streetlight rentals were $40 million,

$38 million and $34 million for 2004, 2003 and 2002 respectively. Future streetlight rentals would approximate 2004 revenues.

D. Guarantees To facilitate commercial transactions of the Company's subsidiaries, Progress Energy and certain wholly owned subsidiaries enter into agreements providing future financial or performance assurances to third parties (See Note 19).

At December 31, 2004, the Company had issued guarantees on behalf of third parties with an estimated maximum exposure of approximately $10 million. These guarantees support synthetic fuel operations. At December 31, 2004, management does not believe conditions are likely for significant performance under these agreements.

In connection with the sale of partnership interests in Colona (See Note 4B), Progress Fuels indemnified the buyers against any claims related to Colona resulting from violations of any environmental laws. Although the terms of the agreement provide for no limitation to the maximum potential future payments under the indemnification, the Company has estimated that the maximum total of such payments would not be material.

E. Claims and Uncertainties OTHER CONTINGENCIES

1. Pursuant to the Nuclear Waste Policy Act of 1982, the predecessors to PEF and PEC entered into contracts with the U.S. Department of Energy (DOE) under which the DOE agreed to begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract DOE failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004, PEC and PEF filed a complaint in the United States Court of Federal Claims against the DOE, claiming that the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel (SNF) by failing to accept SNF from various Progress Energy facilities on or before January 31, 1998. Damages due to DOE's breach will likely exceed $100 million.

Approximately 60 cases involving the Government's actions in connection with spent nuclear fuel are currently pending in the Court of Federal Claims.

DOE and the PEC/PEF parties have agreed to a stay of the lawsuit, including discovery. The parties agreed to, and the trial court entered, a stay of proceedings, in order to allow for possible efficiencies due to the resolution of legal and factual issues in previously filed cases in which similar claims are being pursued by other plaintiffs. These issues may include, among others, so-called 'rate issues,' or the minimum mandatory schedule for the acceptance of SNF and high level waste (HLW) by which the Governmentwas 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.

103

V Notes to Consolidated Financial Statements 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 PEFs nuclear unit, Crystal River Unit No. 3 (CR3), PEFs spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on PEFs 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 forthe District of Columbia Circuit for review of the Congressional override resolution. These same parties also challenged EPA's radiation standards for Yucca Mountain. On July 9, 2004, the Court rejected the challenge to the constitutionality of the resolution approving Yucca Mountain, but ruled that the EPA was wrong to set a 10,000-year compliance period in the radiation protection standard. EPA is currently reworking the standard but has not stated when the work will be complete. DOE originally planned to submit a license application to the NRC to construct the Yucca Mountain facility by the end of 2004.

However, in November 2004, DOE announced it would not submit the license application until mid-2005 or later. Also in November 2004, Congressional negotiators approved

$577 million for fiscal year 2005 for the Yucca Mountain project approximately $300 million less than requested by DOE but approximately the same as approved in 2004. The DOE continues to state it plans to begin operation of the repository at Yucca Mountain in 2010. PEC and PEF cannot predict the outcome of this matter.

2. In 2001, PEC entered into a contract to purchase coal from Dynegy Marketing and Trade (DMT). After DMT experienced financial difficulties, including credit ratings downgrades by certain credit reporting agencies, PEC requested credit enhancements in accordance with the terms of the coal purchase agreement in July 2002. When DMT did not offer credit enhancements, as required by a provision in the contract, PEC terminated the contract in July 2002.

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

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

The consolidated appeal has been fully briefed, and the court of appeals has indicated that it will hear arguments which tentatively have been scheduled for the week of May 23,2005.

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

3. On February 1, 2002, the Company filed a complaint with the Surface Transportation Board (STB) challenging the rates charged by Norfolk Southern Railway Company (Norfolk Southern) for coal transportation to certain generating plants. In a decision dated December 23, 2003, the STB found that the rates were unreasonable, awarded reparations and prescribed maximum rates. Both parties petitioned the STB for reconsideration of the December 23, 2003 decision. On October 20,

2004, the STB reconsidered its December 23, 2003 decision and concluded that the rates charged by Norfolk Southern were not unreasonable. Because the Company paid the maximum rates prescribed by the STB in its December 23, 2003 decision for several months during 2004, which were 104

Progress Energy Annual Report 2004 less than the rates ultimately found to be reasonable, the STB ordered the Company to pay to Norfolk Southern the difference between the rate levels plus interest.

The Company subsequently filed a petition with the STB to phase in the new rates over a period of time, and filed a notice of appeal withthe U.S. Court of Appealsforthe D.C.

Circuit Pursuant to an order issued by the STB on January6,2005,the phasing proceeding will proceed on a schedule that appears likely to produce an STB decision before the end of 2005. On January 12, 2005, the STB filed a Motion to Dismiss the Company's appeal on the grounds that its October 20, 2004, order is not "final' until the Company's phasing application has been decided.

As of December 31, 2004, the Company has accrued a liability of $42 million, of which $23 million represents reparations previously remitted to PEC by Norfolk Southern that are now subject to refund. Of the remaining

$19 million, $17 million has been recorded as deferred fuel cost on the Consolidated Balance Sheet, while the remaining $2 million attributable to wholesale customers has been charged to fuel used in electric generation on the Consolidated Statements of Income.

The Company cannot predict the outcome of this matter.

4. The Company, through its subsidiaries, is a majority owner in five entities and a minority owner in one entity that owns facilities that produce synthetic fuel as defined under the Internal Revenue Code (Code). The production and sale of the synthetic fuel from these facilities qualify for tax credits under Section 29 if certain requirements are satisfied, including a requirement that the synthetic fuel differs significantly in chemical composition from the coal used to produce such synthetic fuel and thatthe fuel was produced from a facility that was placed in service before July 1, 1998. The amount of Section 29 credits that the Company is allowed to claim in any calendar year is limited by the amount of the Company's regular federal income tax liability. Synthetic fuel tax credit amounts allowed but not utilized are carried forward indefinitely as deferred alternative minimum tax credits. All entities have received PLRs from the IRS with respect to their synthetic fuel operations. However, these PLRs do not address the placed-in-service date determination. The PLRs do not limit the production on which synthetic fuel credits may be claimed. Total Section 29 credits generated to date (including those generated by FPC priorto its acquisition bythe Company) are approximately

$1.5 billion, of which $713 million has been used to offset regular federal income tax liability and $745 million is being carried forward as deferred alternative minimum tax credits. Also, $7 million has not been recognized due to the decrease in tax liability resulting from expenses incurred for the 2004 hurricane damage. The current Section 29 tax credit program expires at the end of 2007.

IMPACT OF HURRICANES For the year ended December 31, 2004, the Company's synthetic fuel facilities sold 8.3 million tons of synthetic fuel and the Company recorded $215 million of Section 29 tax credits. The amount of synthetic fuel sold and tax credits recorded in 2004 was impacted by hurricane costs that reduced the Company's projected 2004 regular tax liability.

For the nine months ended September 30, 2004, the Company's synthetic fuel facilities sold 7.7 million tons of synthetic fuel, which generated an estimated $204 million of Section 29 tax credits. Due to the anticipated decrease in the Company's tax liability as a result of expenses incurred for the 2004 hurricane damage, the Company estimated that it would be able to use in 2004, or carry forward to future years, onlyS125 million of these Section 29 tax credits at September 30, 2004. As a result, the Company recorded a charge of $79 million related to Section 29 tax credits at September 30, 2004.

On November 2,2004, PEF filed a petition with the FPSC to recover $252 million of storm costs plus interest from customers over a two-year period. Based on a reasonable expectation at December 31, 2004, that the FPSC will grant the requested recovery of the storm costs, the Company's loss from the casualty is less than originally anticipated. As of December 31, 2004, the Company estimates that it will be able to use in 2004, or carry forward to future years, S215 million of these Section 29 tax credits. Therefore, the Company recorded tax credits of $90 million for the quarter ended December 31, 2004, which the Company now anticipates can be used. For the year ended December 31, 2004, the Company's synthetic fuel facilities sold 8.3 million tons of synthetic fuel, which generated an estimated $222 million of Section 29 tax credits. As of December 31, 2004, the Company anticipates that approximately $7 million of tax credits related to synthetic fuel sold during the year could not be used and have not been recognized.

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

105

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

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

In July 2004, Progress Energy was notified that the IRS field auditors anticipated taking an adverse position regarding the placed-in-service date of the Company's four Earthco synthetic fuel facilities. Due to the auditors' position, the IRS decided to exercise its right to withdraw from the PFA program with Progress Energy. With the IRS's withdrawal from the PFA program, the review of Progress Energy's Earthco facilities is back on the normal procedural audit path of the Company's tax returns.

Through December 31, 2004, the Company, on a consolidated basis, has used or carried forward approximately $1.0 billion of tax credits generated by Earthco facilities. If these credits were disallowed, the Company's one-time exposure for cash tax payments would be $294 million (excluding interest), and earnings and equity would be reduced by approximately

$1.0 billion, excluding interest. Progress Energy's amended $1.13 billion credit facility includes a covenant that limits the maximum debt-to-total capital ratio to 68%.

This ratio includes other forms of indebtedness such as guarantees issued by PGN, letters of credit and capital leases. As of December 31, 2004, the Company's debt-to-total capital ratio was 60.7% based on the credit agreement definition for this ratio. The impact on this ratio of reversing approximately $1.0 billion of tax credits and paying $294 million for taxes would be to increase the ratio to 65.7%.

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

Because of the disagreement between the Company and the field auditors as to the proper legal standard to apply, the Company believes that it is appropriate and helpful to have this issue reviewed by the National Office of the IRS, just as the National Office reviewed the issues involving chemical change. Therefore, the Company is asking the National Office to clarify the legal standard and has initiated this process with the National Office.

The Company believes that the appeals process, including proceedings before the National Office, could take up to two years to complete; however, it cannot control the actual timing of resolution and cannot predict the outcome of this matter.

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

PROPOSED ACCOUNTING RULES FOR UNCERTAIN TAX POSITIONS In July 2004, the FASB stated that it plans to issue an exposure draft of a proposed interpretation of SFAS No.

109, Accounting for Income Taxes' (SFAS No. 109), that would address the accounting for uncertain tax positions.

The FASB has indicated that the interpretation would require that uncertain tax benefits be probable of being sustained in order to record such benefits in the financial statements. The exposure draft is expected to be issued in the first quarter of 2005. The Company cannot predict what actions the FASB will take or how any such actions might ultimately affectthe 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.

106

Progress Energy Annual Report 2004 PERMANENT SUBCOMMITTEE In October 2003, the United States Senate Permanent Subcommittee on Investigations began a general investigation concerning synthetic fuel tax credits claimed under Section 29. The investigation is examining the utilization of the credits,the nature of the technologies and fuels created, the use of the synthetic fuel and other aspects of Section 29 and is not specific to the Company's synthetic fuel operations. Progress Energy is providing information in connection with this investigation. The Company cannot predict the outcome of this matter.

SALE OF PARTNERSHIP INTEREST In June 2004, the Company, through its subsidiary, Progress Fuels, sold, in two transactions, a combined 49.8% partnership interest in Colona Synfuel Limited Partnership, LLLP, one of its synthetic fuel facilities.

Substantially all proceeds from the sales will be received over time, which is typical of such sales in the industry. Gain from the sales will be recognized on a cost recovery basis. The Company's book value of the interests sold totaled approximately $5 million. The company received total gross proceeds of $10 million in 2004. Based on projected production and tax credit levels, the Company anticipates receiving approximately

$24 million in 2005, approximately $31 million in 2006, approximately $32 million in 2007 and approximately

$8 million through the second quarter of 2008. In the event that the synthetic fuel tax credits from the Colona facility are reduced, including an increase in the price of oil that could limit or eliminate synthetic fuel tax credits, the amount of proceeds realized from the sale could be significantly impacted.

IMPACT OF CRUDE OIL PRICES Although the Internal Revenue Code Section 29 tax credit program is expected to continue through 2007, recent unprecedented and unanticipated increases in the price of oil could limit the amount of those credits or eliminate them altogether for one or more of the years following 2004. This possibility is due to a provision of Section 29 that provides that if the average wellhead price per barrel for unregulated domestic crude oil for the year (the

'Annual Average Price' exceeds a certain threshold value (the Threshold Price"), the amount of Section 29 tax credits are reduced for that year. Also, if the Annual Average Price increases high enough (the 'Phase Out Price"), the Section 29 tax credits are eliminated for that year. For 2003, the Threshold Price was $50.14 per barrel and the Phase Out Price was $62.94 per barrel. The Threshold Price and the Phase Out Price are adjusted annually for inflation.

If the Annual Average Price falls between the Threshold Price and the Phase Out Price for a year, the amount by which Section 29 tax credits are reduced will depend on where the Average Annual Price falls in that continuum. For example, for 2003, if the Annual Average Price had been

$56.54 per barrel, there would have been a 50% reduction in the amount of Section 29 tax credits for thatyear.

The Secretary of the Treasury calculates the Annual Average Price based on the Domestic Crude Oil First Purchases Prices published by the Energy Information Agency (EIA). Because the EIA publishes its information on a three-month lag, the Secretary of the Treasury finalizes its calculations three months after the year in question ends. Thus, the Annual Average Price for calendar year 2003 was published in April 2004.

Although the official notice for 2004 is not expected to be published until April 2005, the Company does not believe that the Annual Average Price for 2004 will reach the Threshold Price for 2004. Consequently, the Company does not expect the amount of its 2004 Section 29 tax credits to be adversely affected by oil prices.

The Company cannot predict with any certainty the Annual Average Price for 2005 or beyond. Therefore, it cannot predict whether the price of oil will have a material effect on its synthetic fuel business after 2004.

However, if during 2005 through 2007, oil prices remain at historically high levels or increase, the Company's synthetic fuel business may be adversely affected for those years, and, depending on the magnitude of such increases in oil prices, the adverse affectforthose years could be material and could have an impact on the Company's synthetic fuel results of operations and production plans.

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

107

V Notes to Consolidated Financial Statements

24. SUBSEQUENT EVENTS Sale of Progress Rail On February 18, 2005, the Company announced it has entered into a definitive agreement to sell Progress Rail to One Equity Partners LLC, a private equity firm unit of J.P.

Morgan Chase & Co. Gross cash proceeds from the transaction will be $405 million, subject to working capital adjustments.The sale is expected to close by mid-2005, and is subject to various closing conditions customary to such transactions. Proceeds from the sale are expected to be used to reduce debt The Company expects to report Progress Rail as a discontinued operation in the first quarter of 2005. The carrying amounts for the assets and liabilities of the discontinued operations disposal group included in the Consolidated Balance Sheets as of December 31, are as follows:

(in millions) 2004 2003 Total current assets

$378

$373 Total property, plant & equipment (net) 173 151 Total other assets 40 77 Total current liabilities 156 114 Total long-term liabilities 3

3 Total capitalization 432 484 Cost-Management Initiative On February 28, 2005, as part of a previously announced cost-management initiative, the executive officers of the Company approved a workforce restructuring. The restructuring will result in a reduction of approximately 450 positions and is expected to be completed in September 2005. The cost-management initiative is designed to permanently reduce by S75 million to

$100 million the projected growth in the Company's annual operation and maintenance expenses bythe end of 2007. In addition to the workforce restructuring, the cost-management initiative includes a voluntary enhanced retirement program.

In connection with the cost-management initiative, the Company expects to incur one-time pre-tax charges of approximately $130 million. Approximately $30 million of that amount relates to payments for severance benefits, and will be recognized in the first quarter of 2005 and paid over time. The remaining approximately $100 million will be recognized in the second quarter of 2005 and relates primarilyto postretirement benefits thatwill be paid over time to those eligible employees who elect to participate in the voluntary enhanced retirement program.

Approximately 3,500 of the Company's 15,700 employees are eligible to participate in the voluntary enhanced retirement program.The total cost-management initiative charges could change significantly depending upon how many eligible employees elect early retirement under the voluntary enhanced retirement program and the salary, service years and age of such employees.

108

Selected Consolidated Financial Data (Unaudited)

Progress Energy Annual Report 2004 CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized quarterly financial data is as follows:

First Second Third Fourth (in millions except per share data)

Quarter Quarter Quarter Quarter Year ended December 31 2004 Operating revenues

$2,245

$2Z408 S2.761

$2Z358 Operating income 296 305 584 291 Income from continuing operations before cumulative effect of changes in accounting principles 108 153 303 189 Net income 108 154 303 194 Common stock data:

Basic earnings per common share Income from continuing operations before cumulative effect of changes in accounting principles 0.45 0.63 1.25 0.78 Net income 0.45 0.63 1.25 0.80 Diluted earnings per common share Income from continuing operations before cumulative effect of changes in accounting principles 0.45 0.63 1.24 0.78 Net income 0.45 0.63 1.24 0.80 Dividends declared per common share 0.575 0.575 0.575 0.590 Market price per share - High 47.95 47.50 44.32 46.10

- Low 43.02 40.09 40.76 40.47 Year ended December 31, 2003 Operating revenues S2Z187

$2,050 S2,457

$2,047 Operating income 357 274 478 248 Income from continuing operations before cumulative effect of changes in accounting principles 207 154 337 113 Net income 219 157 318 88 Common stock data:

Basic earnings per common share Income from continuing operations before cumulative effect of changes in accounting principles 0.89 0.65 1.41 0.47 Net income 0.94 0.66 1.33 0.37 Diluted earnings per common share Income from continuing operations before cumulative effect of changes in accounting principles 0.89 0.65 1.39 0.47 Net income 0.94 0.66 1.31 0.37 Dividends declared per common share 0.560 0.560 0.560 0.575 Market price per share - High 46.10 48.00 45.15 46.00

- Low 37.45 38.99 39.60 41.60 In the opinion of management, all adjustments necessary to fairly present amounts shown for interim periods have been made. Results of operations for an interim period may not give a true indication of results for the year. The 2003 amounts were restated for the cessation of reporting results for portions of the Fuels' segment operations one month in arrears (See Note 18) and for discontinued operations (See Note 4C). Fourth quarter 2004 includes a $31 million after-tax gain on sale of natural gas assets (See Note 4A) and $90 million of Section 29 tax credits being recorded (See Note 23E).

Third quarter 2004 includes reversal of $79 million of Section 29 tax credits (See Note 23E). Second quarter 2004 includes the settlement of a civil proceeding related to SRS of $43 million ($29 million after-tax). Fourth quarter 2003 includes impairments related to Kentucky May and Affordable Housing investment of $38 million ($24 million after-tax) (See Note 10). Fourth quarter 2003 includes a cumulative effect for DIG Issue 20 of $38 million

($23 million after-tax) (See Note 18).

109

V Selected Consolidated Financial and Operating Data (Unaudited)

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (UNAUDITED)

(inrmillionsexceptpersharedataJ 2004 2003 2002 2001 2000 Results of Operationsla)

Operating revenues

$9,772

$8,741

$8,091

$8,129

$3,769 Net income from continuing operations before cumulative effect 753 811 552 541 478 Net income

$759

$782 S528

$542

$478 Balance Sheet Data at Year-end Total assets(b)

$25,993

$26,093

$24,272

$23,701

$22,875 Capitalization:

Common stock equity

$7,633 S7,444

$6,677

$6,004

$5,424 Preferred stock-redemption not required 93 93 93 93 93 Minority interest 36 30 18 12 Long-term debt netdc) 9,521 9,934 9,747 8,619 4,904 Current portion of long-term debt 349 868 275 688 184 Short-term obligations 684 4

695 942 4,959 Total Capitalization and Total Debt

$18,316

$18,373

$17,505

$16,358

$15,564 Other Financial Data Return on average common stock equity (percent) 9.99 11.07 8.44 9.41 13.04 Ratio of earnings to fixed charges 2.26 1.97 1.48 1.52 3.36 Number of common shareholders of record 67,638 70,159 72,792 75,673 80,289 Book value per common share

$3126 S30.94

$28.73

$28.20

$27.17 Basic earnings per common share Income from continuing operations

$3.11 S3.42

$2.54 S2.64

$3.04 Net income

$3.13 S3.30

$2.43

$2.65

$3.04 Diluted earnings per common share Income from continuing operations 3110 S3.40

$2.53

$2.63

$3.03 Net income S3.12 S3.28

$2.42 S2.64

$3.03 Dividends declared per common share

$2.32 S2.26

$2.20

$2.14

$2.08 Energy Supply - Electric Utility (millions of kWh)la)

Generated Steam 50,782 51,501 49,734 48,732 31,132 Nuclear 30,445 30,576 30,126 27,301 23,857 Hydro 802 955 491 245 441 Combustion turbines/combined cycle 9.695 7,819 8,522 6,644 1,337 Purchased 13,466 13,848 14,305 14,469 5,724 Total energy, supply (Company share) 105.190 104,699 103,178 97,391 62,491 Joint-owner shareld) 5,395 5,213 5,258 4,886 4,505 Total System Energy Supply 110,585 109,912 108.436 102,277 66,996 (a) Results of operations and energy supply data includes information for Florida Progress Corporation since November 30,2000, the date of acquisition.

(b) All periods have been restated for the reclassification of cost at removal.

(c) Includes long-term debt to affiliated trust of $270 million at December 31,2004, and 2003.

Id) Amounts are net of Company's purchases from joint-owners.

110

Reconciliation of Ongoing Earnings per Share to Reported GAAP Earnings per Share (Unaudited)

RECONCILIATION OF ONGOING EARNINGS PER SHARE TO REPORTED GAAP EARNINGS PER SHARE (UNAUDITED)

Progress Energy's management uses ongoing earnings per share to evaluate the operations of the Company and to establish goals for management and employees.

Management believes this presentation is appropriate and enables investors to compare more accurately the Company's ongoing financial performance over the periods presented. Ongoing earnings as presented here may not be comparable to similarly titled measures used by other companies. Reconciling adjustments from GAAP earnings to ongoing earnings are as follows:

December31 2004 2003 2002 Ongoing earnings per share

$3.06

$3.56

$3.81 Contingent value obligation mark-to-market 0.04 (0.04) 0.13 NCNG discontinued operations 0.02 (0.03) 10.11)

SRS litigation settlement (0.12)

Gain on sale of natural gas assets 0.13 Cumulative effect of accounting changes (0.09)

Impairments and one-time charges (0.10)

(1.22)

Ice storm impact (0.08)

PEF retroactive revenue refund (0.10)

Reported GAAP earnings per share

$3.13

$3.30

$2.43 Progress Energy Annual Report 2004 suit Management does not believe this settlement charge is indicative of the ongoing operations of the Company.

Gain on Sale of Natural Gas Assets In December2004,the Companyfinalizedthe sale of certain gas-producing properties and related assets and recognized a gain. Management does not believe this gain is representative of the ongoing operations of the Company.

Cumulative Effect of Accounting Changes Progress Energy recorded the cumulative effect of changes in accounting principles due to the adoption of new FASB accounting guidance. The impact to Progress Energy was due primarily to the new FASB guidance related to the accounting for certain contracts. Due to the nonrecurring nature of the adjustment, management believes it is not representative of the 2003 operations of the Company.

Impairments and One-Time Charges During 2003, the Company recorded after-tax impairments of its Affordable Housing portfolio and certain assets at the Kentucky May coal company. During 2002, the Company committed to a divestiture plan for Railcar, Ltd.,

and recorded an estimated loss on assets held for sale.

During 2002, the Company also recorded an after-tax impairment and one-time charge of Progress Telecom's and Caronet's assets. Progress Energy also wrote off the remaining amount of its investment in Interpath.

Management does not believe these impairments and one-time charges are representative of the ongoing operations of the Company.

Ice Storm Impact During 2002,the Company experienced a severe ice storm in the Carolinas that caused extensive damage to the distribution system. Due to the extensive costs associated with the storm damage, management believes the restoration costs are not representative of the 2002 ongoing operations of Progress Energy Carolinas.

PEF Retroactive Revenue Refund The one-time retroactive rate refund under the Progress Energy Florida rate settlementin March 2002 was related to funds collected during the period between March 13, 2001, when the prior rate agreement in Florida expired, and March 27, 2002, the date the parties entered into the settlement agreement Due to the nonrecurring nature of the refund, management believes it is not representative of the 2002 operations of Progress Energy Florida.

Contingent Value Obligation (CVO)

Mark-to-Market In connection with the acquisition of Florida Progress Corporation, Progress Energy issued 98.6 million CVOs.

Each CVO represents the right to receive contingent payments based on after-tax cash flows above certain levels of four synthetic fuel facilities purchased by subsidiaries of Florida Progress Corporation in October 1999. The CVOs are debt instruments and, under GAAP, are valued at market value. Unrealized gains and losses from changes in marketvalue are recognized in earnings. Since changes in the market value of the CVOs do not affect the Company's underlying obligation, management does not consider the adjustment a component of ongoing earnings.

NCNG Discontinued Operations The operations of NCNG are reported as discontinued operations due to its sale, and therefore management does not believe this activity is representative of the ongoing operations of the Company.

SRS Litigation Settlement In June 2004, SRS, a subsidiary of the Company, reached and recorded a chargefora settlementagreementin a civil 111

V Shareholder Information Notice of Annual Meeting Progress Energy's 2005 annual meeting of shareholders will be held on May 11, 2005, at 10 a.m. at the Hilton St. Petersburg, in St. Petersburg, Fla. A formal notice of the meeting with a proxy statement will be mailed to shareholders in early April.

Transfer Agent and Registrar Mailing Address Progress Energy, Inc.

c/o EquiServe Trust Company 250 Royall Street Canton, MA 02021 Toll-free phone number 1.866.290.4388 Shareholder Information and Inquiries Obtain information on your account 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day, seven days a week by calling our stock transfer agent's shareholder information line. This automated system features Progress Energy's common stock closing price, dividend information, stock transfer information and the option to speak with a shareholder services representative. Call toll-free 1.866.290.4388.

You may direct other questions concerning stock ownership to Progress Energy's Shareholder Relations via e-mail at shareholder.relations~pgnmail.com or by writing to the following address:

Progress Energy, Inc.

Shareholder Relations P.O. Box 1551 Raleigh, NC 27602-1551 Stock Listings Progress Energy's common stock is listed and traded under the symbol PGN on the New York Stock Exchange in addition to regional stock exchanges across the United States.

Shareholder Programs Progress Energy offers the Progress Energy Investor Plus Plan, a direct stock purchase and dividend reinvestment plan, and direct deposit of cash dividends to bank accounts for the convenience of shareholders. For information on these programs, contact our transfer agent at the above address or call them toll-free at 1.866.290.4388.

Proxy material, including the annual report, can be electronically delivered to shareholders. Electronic delivery provides immediate access to proxy material and allows Internet voting while saving printing and mailing costs. To take advantage of electronic delivery of proxy material, go to econsentcom/pgn and follow the instructions.

We also offer online access to shareholder accounts. To obtain online access to your shareholder account, go to equiserve.com. If you have access to Progress Energy's annual report at your address, and do not wantto receive a copy for your shareholder account, please call our transfer agent, EquiServe, toll-free at 1.866.290.4388 to discontinue receiving annual reports by mail.

Securities Analyst Inquiries Securities analysts, portfolio managers and representatives of financial institutions seeking information about Progress Energy should contact Robert F. Drennan Jr.,

manager, Investor Relations, at the corporate headquarters' address or 919.546.7474.

Additional Information Progress Energy files periodic reports with the Securities and Exchange Commission that contain additional information about the company. Copies are available to shareholders upon written request to the company's treasurer at the corporate headquarters' address.

This annual report is submitted for shareholders' information. It is not intended for use in connection with any sale or purchase of, or any offer or solicitation of offers to buy or sell, securities.

NYSE Certifications Because Progress Energy's common stock is listed on the New York Stock Exchange ('NYSE'), our chief executive officer is required to make, and he has made, an annual certification to the NYSE stating that he was not aware of any violation by us of the corporate governance listing standards of the NYSE. Our chief executive officer made his annual certification to that effect to the NYSE as of June 10, 2004. In addition, we have filed, as exhibits to the Annual Report on Form 10-K, the certifications of our principal executive officer and principal financial officer required under Section 302 of the Sarbanes-Oxley Act of 2002 to be filed with the Securities and Exchange Commission regarding the quality of our public disclosure.

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)2005 Progress Energy. Inc. SCC-1 12-05 03/05

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