NOTES TO FINANCIAL STATEMENTS

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A. Organization

Florida Progress Corporation (the Company or Florida Progress) is a holding company under the Public Utility Holding Company Act of 1935 (PUHCA). The Company became subject to the regulations of PUHCA when it was acquired by CP&L Energy, Inc. in November 2000. CP&L Energy, Inc. subsequently changed its name to Progress Energy, Inc. (Progress Energy or the Parent). Florida Progress' two primary subsidiaries are Florida Power Corporation (Progress Energy Florida or PEF) and Progress Fuels Corporation (Progress Fuels). Effective January 1, 2003, Florida Power Corporation began doing business under the assumed name Progress Energy Florida, Inc. The legal name of the entity has not changed. The current corporate and business unit structure remains unchanged. Throughout the report, the terms utility and regulated will be used to discuss items pertaining to Progress Energy Florida. Diversified business and nonregulated will be used to discuss the subsidiaries of Florida Progress excluding Progress Energy Florida.

B. Basis of Presentation

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

The Financial Statements of the Company and its subsidiaries include the accounts of their 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 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 19). 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 $11 million and $12 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 NRC requirements, to fund certain costs of decommissioning nuclear plants. The fair value of these trust funds was $463 million and $433 million at December 31, 2004 and 2003, 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 $12 million and $13 million, respectively, of cost method investments.

The results of operations of the Rail Services segment are reported one month in arrears. During 2003, the Company ceased recording portions of the Energy and Related Services 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.

C. Consolidation of Variable Interest Entities

Florida Progress and PEF consolidate all voting interest entities in which they own a majority voting interest and all variable interest entities for which they are the primary beneficiary in accordance with FASB Interpretation No. 46R, "Consolidation of Variable Interest Entities - an Interpretation of ARB No. 51" (FIN No. 46R). A subsidiary of Florida Progress is the primary beneficiary of and consolidates Colona Synfuel Limited Partnership LLLP (Colona), a synthetic fuel production facility that qualifies for federal tax credits under Section 29 of the Internal Revenue Code. As of December 31, 2004, Colona's total assets were $15 million. None of Florida Progress' consolidated assets are collateral for Colona's obligations.

Florida Progress and PEF have interests in several variable interest entities for which they are not the primary beneficiary. These arrangements include investments in approximately five limited partnerships, limited liability corporations and venture capital funds. The aggregate maximum loss exposure at December 31, 2004, that Florida Progress could be required to record in its consolidated income statement as a result of these arrangements totals approximately $13 million. The aggregate maximum loss exposure at December 31, 2004, that PEF could be required to record in its income statement as a result of these arrangements totals approximately $6 million. The creditors of these variable interest entities do not have recourse to the general credit of Florida Progress or PEF in excess of the aggregate maximum loss exposure.

D. Significant Accounting Policies

USE OF ESTIMATES AND ASSUMPTIONS

In preparing financial statements that conform with GAAP, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and amounts of revenues and expenses reflected during the reporting period. Actual results could differ from those estimates.

REVENUE RECOGNITION

PEF 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. Revenues from sales of synthetic fuel and coal are recognized as products are shipped and title passes. Revenues from the sale of oil and gas production are recognized when title passes, net of royalties. Leasing activities are accounted for in accordance with SFAS No. 13, "Accounting for Leases." Lease revenue for dedicated transport and data services is generally billed in advance on a fixed rate basis and recognized over the period the services are provided. Revenues relating to design and construction of wireless infrastructure are recognized upon completion of services for each completed phase of design and construction. Revenues from the sale of oil and gas production are recognized when title passes, net of royalties.

FUEL COST DEFERRALS

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

EXCISE TAXES

PEF collects from customers certain excise taxes levied by the state or local government upon the customer. PEF accounts for excise taxes on a gross basis. For the years ended December 31, 2004, 2003 and 2002, gross receipts tax and franchise taxes of approximately $151 million, $136 million and $132 million, respectively, are included in electric operating revenues and taxes other than on income on the Statements of Income.

INCOME TAXES

Progress Energy and its affiliates file a consolidated federal income tax return. The consolidated income tax of Progress Energy is allocated to Florida Progress and PEF in accordance with the Intercompany Income Tax Allocation Agreement (Tax Agreement). The Tax Agreement provides an allocation that recognizes positive and negative corporate taxable income. The Tax Agreement provides for an equitable method of apportioning the

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 PUHCA order. Except for the allocation of this Progress Energy tax benefit, income taxes are provided as if Florida Progress and PEF filed separate returns.

Deferred income taxes have been provided for temporary differences. These occur when there are differences between the book and tax bases 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 (See Note 14).

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," the estimated fair value of Progress Energy's stock options is amortized to expense over the options' vesting period. The following table illustrates the effect on net income for Florida Progress Corporation and PEF if the fair value method had been applied to all outstanding and unvested awards in each period:

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(in millions)
Florida Progress                                                    2004        2003       2002
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Net income, as reported                                            $ 474       $ 447      $ 235
Deduct:  Total stock option expense determined under fair
    value method for all awards, net of related tax effects           3           3          3
---------------------------------------------------------------------------------------------------
Pro forma net income                                               $ 471       $ 444      $ 232
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(in millions)
Progress Energy Florida                                             2004        2003       2002
---------------------------------------------------------------------------------------------------
Net income, as reported                                            $ 335       $ 297      $ 325
Deduct:  Total stock option expense determined under fair
     value method for all awards, net of related tax effects           2           2          2
---------------------------------------------------------------------------------------------------
Pro forma net income                                               $ 333       $ 295      $ 323
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UTILITY PLANT

Utility plant in service is stated at historical cost less accumulated depreciation. PEF capitalizes all construction-related direct labor and material costs of units of property as well as indirect construction costs. Certain costs that would otherwise not be capitalized under GAAP are capitalized in accordance with regulatory treatment. The cost of renewals and betterments is also capitalized. Maintenance and repairs of property (including planned major maintenance activities), and replacements and renewals of items determined to be less than units of property, are charged to maintenance expense as incurred with the exception of nuclear outages at PEF. Pursuant to a regulatory order, PEF accrues for nuclear outage costs in advance of scheduled outages, which occur every two years. The cost of units of property replaced or retired, less salvage, is charged to accumulated depreciation. Removal, disposal and decommissioning costs that do not represent ARO's under SFAS No. 143 "Accounting for Asset Retirement Obligations," (SFAS No. 143) are charged to regulatory liabilities.

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

ASSET RETIREMENT OBLIGATIONS

Effective January 1, 2003, 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 PEF, as the effects were offset by the establishment of a regulatory liability pursuant to SFAS No. 71 , "Accounting for the Effects of Certain Types of Regulation" (See Note 8A). The Florida Public Service Commission (FPSC) issued an order to authorize deferral of all prospective effects related to SFAS No. 143 as a regulatory asset or liability (See Note 8A).

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 its rate setting authority, the 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 PEF's retail jurisdiction, provisions for nuclear decommissioning costs are approved by 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 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 cost or market.

REGULATORY ASSETS AND LIABILITIES

PEF's regulated operations are subject to SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," which allows a regulated company to record costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by a nonregulated enterprise. Accordingly, PEF records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. These regulatory assets and liabilities represent expenses deferred for future recovery from customers or obligations to be refunded to customers and are primarily classified in the 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 loss is recognized on an asset, the fair value becomes its new cost basis. The cost of renewals and betterments are capitalized. The cost of repairs and maintenance is charged to expense as incurred. For properties other than natural gas and oil properties, depreciation is computed on a straight-line basis over the estimated useful lives as indicated in Note 6B. Depletion of mineral rights is provided on the units-of-production method based upon the estimates of recoverable amounts of clean mineral.

The Company uses the full-cost method to account for its oil and gas properties. Under the full-cost method, substantially all productive and nonproductive costs incurred in connection with the acquisition, exploration and development of oil and gas reserves are capitalized. These capitalized costs include the costs of all unproved properties and internal costs directly related to acquisition and exploration activities. The amortization base also includes the estimated future costs to develop proved reserves. Except for costs on 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 Regulation 210.4-10 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 PEF are amortized over the applicable life using the straight-line method consistent with ratemaking treatment (See Note 8A).

DERIVATIVES

The Company accounts for derivative instruments in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," 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 (See Note 16).

ENVIRONMENTAL

As discussed in Note 20, the Company accrues environmental remediation liabilities when the criteria for SFAS No. 5, "Accounting for Contingencies," have been met. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remedial feasibility study. Such accruals are adjusted as additional information develops or circumstances change. Costs of future expenditures for environmental remediation obligations are not discounted to their present value. Recoveries of environmental remediation costs from other parties are recognized when their receipt is deemed probable. Environmental expenditures that have future economic benefits are capitalized in accordance with the Company's asset capitalization policy.

IMPAIRMENT OF LONG-LIVED ASSETS AND INVESTMENTS

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, 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, then an impairment loss is recognized for the difference between the carrying value and the fair value of the asset group. The accounting for impairment of long-lived assets is based on SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets."

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 (See Note 10). 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 other-than-temporary decline exists in the value of its investments, it is the Company's policy to write-down these investments to fair value.

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

SUBSIDIARY STOCK TRANSACTIONS

Gains and losses realized as a result of common stock sales by the Company's subsidiaries are recorded in the Company's 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. IMPACT OF NEW ACCOUNTING STANDARDS

FASB STAFF POSITION 106-2, "ACCOUNTING AND DISCLOSURE REQUIREMENTS RELATED TO THE MEDICARE PRESCRIPTION DRUG IMPROVEMENT AND MODERNIZATION ACT OF 2003"

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law. In accordance with guidance issued by the FASB in FASB Staff Position 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003" (FASB Staff Position 106-1), 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 benefits (OPEB) costs to reflect prescription drug-related federal subsidies to be received under the Medicare Act. The Company's and PEF's accumulated postretirement benefit obligations as of January 1, 2004 were reduced by approximately $36 million and $35 million, respectively, by the impact of the Medicare Act, and the Company's and PEF's 2004 net periodic cost was lower by approximately $5 million due to the Medicare Act.

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

In December 2004, the FASB Issued SFAS No. 123R, which revises SFAS No. 123, "Accounting for Stock-Based Compensation" (SFAS No. 123) 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 and PEF recording no compensation expense for stock options granted to employees (See Note 11B).

SFAS No. 123R will be effective for the Company on July 1, 2005. The Company intends to implement the standard using the required modified prospective method. Under that method, the Company will record compensation expense under SFAS No. 123R for all awards it grants after July 1, 2005, and it will record compensation expense (as previous awards continue to vest) for the unvested portion of previously granted awards that remain outstanding at July 1, 2005. In 2004, Progress Energy made the decision to cease granting stock options and intends to replace that compensation program with other programs. Therefore, the amount of stock option expense expected to be recorded in 2005 is below the amount that would have been recorded if the stock option program had continued. The Company and PEF expect to record less than $1 million of pre-tax expense for stock options in 2005.

PROPOSED FASB INTERPRETATION OF SFAS 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," that would address the accounting for uncertain tax positions. The FASB has indicated that the interpretation would require that uncertain tax benefits be probable of being sustained in order to record such benefits in the financial statements. The exposure draft is expected to be issued in the first quarter of 2005. The Company cannot predict what actions the FASB will take or how any such actions might ultimately affect the Company's financial position or results of operations, but such changes could have a material impact on the Company's evaluation and recognition of Section 29 tax credits.

3. HURRICANE-RELATED COSTS

Hurricanes Charley, Frances, Ivan and Jeanne struck significant portions of the PEF's service territory during the third quarter of 2004. As of December 31, 2004, restoration costs of PEF's systems from hurricane-related damage was estimated at $385 million, of which $47 million was charged to capital expenditures, and $338 million was charged to the storm damage reserve pursuant to a regulatory order.

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

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

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

4. DIVESTITURES

A. Sale of Natural Gas Assets

In December 2004, the Company sold certain gas-producing properties and related assets owned by Winchester Production Company, Ltd., an indirectly wholly owned subsidiary of Progress Fuels Corporation (Progress Fuels), which is included in the Fuels segment. Net proceeds of approximately $251 million were used to reduce debt. Because the sale significantly altered the ongoing relationship between capitalized costs and remaining proved reserves, under the full-cost method of accounting the pre-tax gain of $56 million was recognized in earnings rather than as a reduction of the basis of the Company's remaining oil and gas properties. The pre-tax gain has been included in (gain)/loss on the sale of assets in the Consolidated Statements of Income.

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 $3 million. The Company received total gross proceeds of $10 million in 2004. Based on projected production and tax credit levels, the Company anticipates receiving approximately $24 million in 2005, approximately $31 million in 2006, approximately $32 million in 2007 and approximately $8 million through the second quarter of 2008. In the event that the synthetic fuel tax credits from the Colona facility are reduced, including an increase in the price of oil that could limit or eliminate synthetic fuel tax credits, the amount of proceeds realized from the sale could be significantly impacted.

C. Railcar Ltd. Divestiture

In December 2002, the Progress Energy Board of Directors adopted a resolution approving the sale of Railcar Ltd., a subsidiary included in the Rail Services segment. An estimated pre-tax impairment of $67 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 10). 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 Corporation (Progress Fuels), which is included in the Fuels segment. Net proceeds were approximately $97 million and were used to reduce debt. 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. Inland Marine Transportation Divestiture

In July 2001, Progress Energy announced the disposition of the Inland Marine Transportation segment of the Company, which was operated by MEMCO Barge Line, Inc. Inland Marine provided transportation of coal, agricultural and other dry-bulk commodities as well as fleet management services. Progress Energy entered into a contract to sell MEMCO Barge Line, Inc., to AEP Resources, Inc., a wholly-owned subsidiary of American Electric Power. In November 2001, the Company completed the sale of the Inland Marine Transportation segment. The net income of these operations is reported in the Company's Consolidated Statements of Income as discontinued operations.

The net gain on disposal of discontinued operations in the Company's Consolidated Statements of Income for year ended December 31, 2002, represents the after-tax gain from the resolution of approximately $5 million of contingencies in the purchase agreement of the Inland Marine Transportation segment. In connection with the sale, the Company entered into environmental indemnification provisions covering both unknown and known sites. In 2003, the Company reduced the estimate for the environmental accrual by $6 million, which is included as discontinued operations in the Company's Consolidated Statements of Income (See Note 20).

5. ACQUISITIONS AND BUSINESS COMBINATIONS

A. Progress Telecommunications Corporation

In December 2003, Progress Telecommunications Corporation (PTC) and Caronet, Inc. (Caronet), both wholly owned subsidiaries of Progress Energy, and EPIK Communications, Inc. (EPIK), a wholly owned subsidiary of Odyssey Telecorp, Inc. (Odyssey), contributed substantially all of their assets and transferred certain liabilities to Progress Telecom, LLC (PT LLC), a subsidiary of PTC. Subsequently, the stock of Caronet was sold to an

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

The transaction was accounted for as a partial acquisition of EPIK through the issuance of the stock of a consolidated subsidiary. The contributions of PTC's and Caronet's net assets were recorded at their carrying values of approximately $31 million. EPIK's contribution was recorded at its estimated fair value of $22 million using the purchase method. No gain or loss was recognized on the transaction. The EPIK purchase price was initially allocated as follows: property and equipment - $27 million; other current assets - $9 million; current liabilities - $21 million, and goodwill - $7 million. During 2004, PT LLC developed a restructuring plan to exit certain leasing arrangements of EPIK and finalized its valuation of acquired assets and liabilities. Management considered a number of factors, including valuations and appraisals, when making these determinations. Based on the results of these activities, the preliminary purchase price allocation for EPIK was revised as follows at December 31, 2004: property and equipment - $36 million; other current assets - $7 million; intangible assets - $1 million; current liabilities - $18 million; and exit costs - $4 million. The exit costs consist primarily of lease termination penalties and noncancellable lease payments made after certain leased properties are vacated. The pro forma results of operations reflecting the acquisition would not be materially different then the reported results of operation for 2003 or 2002.

B. Acquisition of Natural Gas Reserves

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

C. Westchester Acquisition

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

The aggregate purchase price of approximately $153 million consisted of cash consideration of approximately $22 million and the issuance of 2.5 million shares of Progress Energy common stock then valued at approximately $129 million. The purchase price included approximately $2 million of direct transaction costs. The final purchase price was allocated to oil and gas properties, intangible assets, diversified business property, net working capital and deferred tax liabilities for approximately $152 million, $9 million, $32 million, $5 million and $45 million, respectively. The $9 million in intangible assets relates to customer contracts (See Note 9).

The acquisition has been accounted for using the purchase method of accounting and, accordingly, the results of operations for Winchester have been included in the Company's Financial Statements since the date of acquisition. The pro forma results of operations reflecting the acquisition would not be materially different than the reported results of operations for the year ended December 31, 2002.

---------------------------------------------------------------
(in millions)                                2004         2003
---------------------------------------------------------------
Production plant  (7-33 years)            $ 3,818      $ 3,826
Transmission plant  (30-75 years)           1,070        1,012
Distribution plant  (12-50 years)           3,047        2,894
General plant and other (8-75 years)          452          423
---------------------------------------------------------------
Utility plant in service                  $ 8,387      $ 8,155
---------------------------------------------------------------

Substantially all of the electric utility plant is pledged as collateral for the first mortgage bonds of PEF (See Note 12).

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. 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 PEF's electric utility plant was 7.8% in 2004, 2003 and 2002.

Depreciation provisions on utility plant, as a percent of average depreciable property other than nuclear fuel, were 2.3% in 2004, 2003 and 2002. The depreciation provisions related to utility plant were $188 million, $172 million and $162 million in 2004, 2003 and 2002, respectively. In addition to utility plant depreciation provisions, depreciation and amortization expense also includes decommissioning cost provisions, ARO accretion, cost of removal provisions (See Note 6D) and regulatory approved expenses (See Note 8 and 20).

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 $34 million, $31 million and $32 million, respectively. These amounts are charged to fuel used in electric generation in the Statements of Income.

-------------------------------------------------------------------------------
(in millions)                                                  2004      2003
-------------------------------------------------------------------------------
Equipment (3 - 25 years)                                      $ 418     $ 283
Land and mineral rights                                          95        80
Buildings and plants (5 - 40 years)                             106        99
Oil and gas properties (units-of-production) (See Note 4A)      336       412
Telecommunications equipment (5 - 20 years)                      80        63
Rail equipment (3 - 20 years) (See Note 4C)                      35       131
Marine equipment (3 - 35 years)                                  87        83
Computers, office equipment and software (3 - 10 years)          36        33
Construction work in progress                                    18        18
Accumulated depreciation                                       (435)     (361)
-------------------------------------------------------------------------------
Diversified business property, net                            $ 776     $ 841
-------------------------------------------------------------------------------

Diversified business depreciation expense was $112 million, $92 million and $66 million for the years ended December 31, 2004, 2003 and 2002, respectively. The synthetic fuel facilities are being depreciated through 2007 when the Section 29 tax credits will expire. Oil and gas depreciation, depletion, and amortization (DD&A) expense was $41 million, $33 million, and $11 million for the years ended December 31, 2004, 2003, and 2002, respectively. DD&A rates per Mcfe were $1.34, $1.31 and $0.92 for the respective years. Oil and gas properties included costs of $55 million at December 2004 which were excluded from capitalized costs being amortized. This includes $48 million in costs related to acquisitions and capitalized interest on probable reserves of $7 million.

C. Joint Ownership of Generating Facilities

PEF is entitled to shares of the generating capability and output of Crystal River Unit No. 3 (CR3) equal to its ownership interest. PEF also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. PEF's share of expenses for the jointly owned facility is included in the appropriate expense category. The co-owner of Intercession City Unit P-11 (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. PEF's ownership interest in CR3 and P11 is listed below with related information at December 31, ($ in millions):

-----------------------------------------------------------------------------------------------
                                     Company                                     Construction
                                    Ownership        Plant      Accumulated        Work in
                Facility             Interest      Investment   Depreciation       Progress
-----------------------------------------------------------------------------------------------
2004
-----------------------------------------------------------------------------------------------
    Crystal River Unit No. 3          91.78%         $ 889         $ 443              $9
    Intercession City Unit P-11       66.67%            22             7               8
-----------------------------------------------------------------------------------------------
2003
-----------------------------------------------------------------------------------------------
    Crystal River Unit No. 3          91.78%         $ 875         $ 442            $ 46
    Intercession City Unit P-11       66.67%            22             6               6
-----------------------------------------------------------------------------------------------

D. Asset Retirement Obligations

The asset retirement costs related to nuclear decommissioning of irradiated plant, net of accumulated depreciation, totaled $36 million and $37 million for regulated operations at December 31, 2004 and 2003, respectively. The ongoing expense differences between SFAS No. 143 and regulatory cost recovery are being deferred to the regulatory liability. Funds set aside in PEF's nuclear decommissioning trust fund for the nuclear decommissioning liability totaled $463 million at December 31, 2004 and $433 million at December 31, 2003. Net unrealized gains on the nuclear decommissioning trust fund were included in regulatory liabilities.

PEF's expense recognized for the disposal or removal of utility assets that are not SFAS No. 143 asset removal obligations, which are included in depreciation and amortization expense, were $77 million, $72 million and $68 million in 2004, 2003 and 2002, respectively.

PEF recognizes removal, non-nuclear 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 $1,005 million, decommissioning costs for nonirradiated areas at nuclear facilities of $61 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 $945 million, decommissioning costs for nonirradiated areas at nuclear facilities of $62 million and amounts previously collected for dismantlement of fossil generation plants of $143 million.

PEF has identified but not recognized ARO liabilities related to electric transmission and distribution and telecommunications assets as the result of easements over property not owned by PEF. These easements are generally perpetual and only require retirement action upon abandonment or cessation of use of the property for the specified purpose. The ARO is not estimable for such easements, as PEF intends to utilize these properties indefinitely. In the event PEF 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 Corporation. The related asset retirement costs, net of accumulated depreciation, totaled $10 million and $5 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.

-------------------------------------------------------------------------------------------
(in millions)                                                   Regulated   Nonregulated
-------------------------------------------------------------------------------------------
Asset retirement obligations as of January 1, 2003                $ 303        $ 10
Additions                                                             -          11
Accretion expense                                                    16           1
Deductions                                                            -          (2)
-------------------------------------------------------------------------------------------
Asset retirement obligations as of  December 31, 2003               319          20
Additions                                                             -           6
Accretion expense                                                    18           2
Deductions                                                            -          (7)
-------------------------------------------------------------------------------------------
Asset retirement obligations as of  December 31, 2004             $ 337        $ 21
-------------------------------------------------------------------------------------------

The cumulative effect of initial adoption of this statement related to nonregulated operations was $2 million of pre-tax expense, which is included in other, net on the Company's 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

PEF is a member of Nuclear Electric Insurance Limited (NEIL), which provides primary and excess insurance coverage against property damage to members' nuclear generating facilities. Under the primary program, PEF is insured for $500 million at its nuclear plant, CR3. In addition to primary coverage, NEIL also provides decontamination, premature decommissioning and excess property insurance with a limit of $1.1 billion.

Insurance coverage against incremental costs of replacement power resulting from prolonged accidental outages at nuclear generating units is also provided through membership in NEIL. PEF is insured thereunder, following a twelve-week deductible period, for 52 weeks in the amount of $4.5 million per week at CR3. An additional 71 weeks of coverage is provided at 80% of the above weekly amount. For the current policy period, PEF is subject to retrospective premium assessments of up to approximately $6.5 million with respect to the primary coverage, $5.2 million with respect to the decontamination, decommissioning and excess property coverage, and $5.5 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 U.S. Nuclear Regulatory Commission, PEF'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. PEF is responsible to the extent losses may exceed limits of the coverage described above.

PEF is insured against public liability for a nuclear incident up to $10.76 billion per occurrence. Under the current provisions of the Price Anderson Act, which limits liability for accidents at nuclear power plants, PEF, as an owner of a nuclear unit, 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), PEF would be subject to pro rata assessments of up to $101 million for each reactor owned per occurrence. Payment of such assessments would be made over time as necessary to limit the payment in any one year to no more than $10 million per reactor owned. Congress could possibly approve revisions to the Price Anderson Act during 2005, that could include increased limits and assessments per reactor owned. The final outcome of this matter cannot be predicted at this time.

Under the NEIL policies, if there were multiple terrorism losses occurring within one year, NEIL would make available one industry aggregate limit of $3.2 billion, along with any amounts it recovers from reinsurance, government indemnity or other sources up to the limits for each claimant. If terrorism losses occurred beyond the one-year period, a new set of limits and resources would apply. For nuclear liability claims arising out of terrorist acts, the primary level available through commercial insurers is now subject to an industry aggregate limit of $300 million. The second level of coverage obtained through the assessments discussed above would continue to apply to losses exceeding $300 million and would provide coverage in excess of any diminished primary limits due to the terrorist acts.

PEF self-insures its transmission and distribution lines against loss due to storm damage and other natural disasters. Pursuant to a regulatory order, PEF is accruing $6 million annually to a storm damage reserve and may defer any losses in excess of the reserve (See Note 3 and 8A).

---------------------------------------------------------------------------------------------
                                           Florida Progress         Progress Energy Florida
                                      -------------------------     -------------------------
(in millions)                            2004          2003            2004           2003
---------------------------------------------------------------------------------------------
Trade accounts receivable               $ 438         $ 410           $ 195          $ 187
Unbilled accounts receivable               93           135              66             59
Notes receivable                           97            62               -              -
Other receivables                          12            15               7              6
Unbilled other receivables                 28            11               -              -
---------------------------------------------------------------------------------------------
Allowance for doubtful accounts           (19)          (15)             (2)            (2)
  receivable
---------------------------------------------------------------------------------------------
Total receivables                       $ 649         $ 618           $ 266          $ 250
---------------------------------------------------------------------------------------------

Income tax receivables and interest income receivables are not included in this classification. These amounts are in prepayments and other current assets on the Consolidated Balance Sheets.

-------------------------------------------------------------------------------------
                                   Florida Progress          Progress Energy Florida
                            -----------------------------   -------------------------
(in millions)                    2004            2003         2004            2003
-------------------------------------------------------------------------------------
Fuel for production             $ 103           $  90        $ 103           $  90
Inventory for sale                228             167            -               -
Materials and supplies            187             192          176             178
-------------------------------------------------------------------------------------
Total inventory                 $ 518           $ 449        $ 279           $ 268
-------------------------------------------------------------------------------------

8. REGULATORY MATTERS

A. Regulatory Assets and Liabilities

As a regulated entity, PEF is subject to the provisions of SFAS No. 71. Accordingly, PEF records certain assets and liabilities resulting from the effects of the ratemaking process, which would not be recorded under GAAP for nonregulated entities. The utility's ability to continue to meet the criteria for application of SFAS No. 71 may be affected in the future by competitive forces and restructuring in the electric utility industry. In the event that SFAS No. 71 no longer applied to PEF'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.

PEF has regulatory assets (liabilities) at December 31 as follows:

-------------------------------------------------------------------------------------------
(in millions)                                                        2004         2003
-------------------------------------------------------------------------------------------
Deferred fuel cost  - current (Note 8B)                           $    89      $   204
-------------------------------------------------------------------------------------------
Deferred fuel cost - long-term (Note 8B)                               79            -
Storm deferral (Note 3)                                               291            -
Income taxes recoverable through future rates (Note 14)                49           42
Loss on reacquired debt (Note 1D)                                      31           33
Other                                                                  74           51
-------------------------------------------------------------------------------------------
     Total long-term regulatory assets                                524          126
-------------------------------------------------------------------------------------------
Deferred energy conservation cost - current                            (8)          (7)
-------------------------------------------------------------------------------------------
Non-ARO cost of removal (Note 6D)                                  (1,210)      (1,150)
Deferred impact of ARO (Note 1D)                                      (26)          (8)
Net nuclear decommissioning trust unrealized gains (Note 6D)          (99)        (105)
Storm reserve (Note 3)                                                  -         (41)
Other                                                                 (27)         (11)
-------------------------------------------------------------------------------------------
     Total long-term regulatory liabilities                        (1,362)      (1,315)
-------------------------------------------------------------------------------------------
Net regulatory assets (liabilities)                               $  (757)     $  (992)
-------------------------------------------------------------------------------------------

Except for portions of deferred fuel and deferred storm costs, all 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 utility expects to fully recover these assets and refund the liabilities through customer rates under current regulatory practice.

B. Retail Rate Matters

On November 9, 2004, the FPSC approved PEF's under-recovered fuel costs of $156 million for 2004, of which PEF plans to defer $79 million until 2006 to mitigate the impact on customers resulting from the need to also recover hurricane-related costs. Therefore, $79 million of deferred fuel cost has been classified as a long-term asset. As of December 31, 2004, PEF was under-recovered 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 $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 under runs. Any costs that exceed this estimate will not be recoverable absent extraordinary circumstances as found by the FPSC in subsequent proceedings.

PEF RATE CASE SETTLEMENT

The FPSC initiated a rate proceeding in 2001 regarding PEF's future base rates. In March 2002, the parties in PEF's rate case entered into a Stipulation and Settlement Agreement (the Agreement) related to retail rate matters. The Agreement was approved by the FPSC in April 2002. The Agreement is generally effective from May 2002 through December 2005, provided, however, that if PEF's base rate earnings fall below a 10% return on equity, PEF may petition the FPSC to amend its base rates.

The Agreement provides that PEF will reduce its retail revenues from the sale of electricity by an annual amount of $125 million. The Agreement also provides that PEF will operate under a Revenue Sharing Incentive Plan (the Plan) through 2005, and thereafter until terminated by the FPSC, that establishes annual revenue caps and sharing thresholds. The Plan provides that retail base rate revenues between the sharing thresholds and the retail base rate revenue caps will be divided into two shares - a 1/3 share to be received by PEF's shareholders, and a 2/3 share to be refunded to PEF's retail customers, provided, however, that for the year 2002 only, the refund to customers was limited to 67.1% of the 2/3 customer share. The retail base rate revenue sharing threshold amounts for 2004, 2003 and 2002 were $1.370 billion, $1.333 billion and $1.296 billion, respectively, and will increase $37 million in 2005. The Plan also provides that all retail base rate revenues above the retail base rate revenue caps established for each year will be refunded to retail customers on an annual basis. For 2002, the refund to customers was limited to 67.1% of the retail base rate revenues that exceeded the 2002 cap. The retail base revenue caps for 2004, 2003 and 2002 were $1.430 billion, $1.393 billion and 1.356 billion, respectively, and will increase $37 million in 2005. Any amounts above the retail base revenue caps will be refunded 100% to customers. At December 31, 2004, $9 million has been accrued and will be refunded to retail customers by March 2005. The 2003 revenue sharing amount was $18 million, and was refunded to customers by April 30, 2004. Approximately $5 million was originally returned in March 2003 related to 2002 revenue sharing. However, in February 2003, the parties to the Agreement filed a motion seeking an order from the FPSC to enforce the Agreement. In this motion, the parties disputed PEF's calculation of retail revenue subject to refund and contended that the refund should be approximately $23 million. In July 2003, the FPSC ruled that PEF must provide an additional $18 million to its retail customers related to the 2002 revenue sharing calculation. PEF recorded this refund in the second quarter of 2003 as a charge against electric operating revenue and refunded this amount by October 2003.

The Agreement also provides that beginning with the in-service date of PEF's Hines Unit 2 and continuing through December 2005, PEF will be allowed to recover through the fuel cost recovery clause a return on average investment and depreciation expense for Hines Unit 2, to the extent such costs do not exceed the Unit's cumulative fuel savings over the recovery period. Hines Unit 2 is a 516 MW combined-cycle unit that was placed in service in December 2003. In 2004, PEF recovered $36 million through this clause related to Hines Unit 2.

In addition, PEF suspended retail accruals on its reserves for nuclear decommissioning and fossil dismantlement through December 2005. Additionally, for each calendar year during the term of the Agreement, PEF will record a $63 million depreciation expense reduction, and may at its option, record up to an equal annual amount as an offsetting accelerated depreciation expense. No accelerated depreciation expense was recorded during 2004 and 2003. In addition, PEF is authorized, at its discretion, to accelerate the amortization of certain regulatory assets over the term of the Agreement.

Under the terms of the Agreement, PEF agreed to continue the implementation of its four-year Commitment to Excellence Reliability Plan and expected to achieve a 20% improvement in its annual System Average Interruption Duration Index by no later than 2004. If this improvement level was not achieved for calendar years 2004 or 2005, PEF would have provided a refund of $3 million for each year the level is not achieved to 10% of its total retail customers served by its worst performing distribution feeder lines. PEF achieved this improvement level in 2004.

In January 2005, in anticipation of the expiration of its Stipulation and Settlement approved by the FPSC in 2002 to conclude PEF's then-pending rate case, PEF notified the FPSC that it intends to request an increase in its base rates, effective January 1, 2006. In its notice, PEF requested the FPSC to approve calendar year 2006 as the projected test period for setting new base rates. The request for increased base rates is based on the fact that PEF has faced significant cost increases over the past decade and expects its operational costs to continue to increase. These costs include the costs associated with completion of the Hines 3 generation facility, extraordinary hurricane damage costs including capital costs which are not expected to be directly recoverable, the need to replenish the depleted storm reserve and the expected infrastructure investment necessary to meet high customer expectations, coupled with the demands placed on PEF as a result of strong customer growth. On February 7, 2005, the FPSC acknowledged receipt of PEF's notice and authorized minimum filing requirements and testimony to be filed May 1, 2005.

C. Regional Transmission Organizations and Standard Market Design

In 2000, the Federal Energy Regulatory Commission (FERC) issued Order No. 2000 regarding regional transmission organizations (RTOs). This Order set minimum characteristics and functions that RTOs must meet, including independent transmission service. In July 2002, the FERC issued its Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). If adopted as proposed, the rules set forth in the SMD NOPR would have materially altered the manner in which transmission and generation services are provided and paid for. In April 2003, the FERC released a White Paper on the Wholesale Market Platform. The White Paper provided an overview of what the FERC intended to include in a final rule in the SMD NOPR docket. The White Paper retained the fundamental and most protested aspects of SMD NOPR, including mandatory RTOs and the FERC's assertion of jurisdiction over certain aspects of retail service. The FERC has not yet issued a final rule on SMD NOPR. The Company cannot predict the outcome of these matters or the effect that they may have on the GridFlorida proceedings currently ongoing before the FERC.

The Florida Public Service Commission (FPSC) ruled in December 2001 that the formation of GridFlorida by the three major investor-owned utilities in Florida, including PEF, was prudent but ordered changes in the structure and market design of the proposed organization. In September 2002, the FPSC set a hearing for market design issues; this order was appealed to the Florida Supreme Court by the consumer advocate of the state of Florida. In June 2003, the Florida Supreme Court dismissed the appeal without prejudice. In September 2003, the FERC held a Joint Technical Conference with the FPSC to consider issues related to formation of an RTO for peninsular Florida. In December 2003, the FPSC ordered further state proceedings and established a collaborative workshop process to be conducted during 2004. In June 2004, the workshop process was abated pending completion of a cost-benefit study currently scheduled to be presented at a FPSC workshop on May 25, 2005, with subsequent action by the FPSC to be thereafter determined.

PEF has $4 million invested in GridFlorida related to startup costs at December 31, 2004. PEF expects to recover these startup costs in conjunction with the GridFlorida original structure or in conjunction with any alternate combined transmission structure that emerges.

D. Energy Delivery Capitalization Practice

PEF has reviewed its capitalization policy for its Energy Delivery business unit. That review indicated that in the areas of outage and emergency work not associated with major storms and allocation of indirect costs, PEF should revise the way that it estimates the amount of capital costs associated with such work. PEF 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 PEF's costs will be capitalized on a going forward basis. PEF estimates that the impact in 2005 will be that approximately $30 million of costs that would have been capitalized under the previous policies will be expensed. Pursuant to SFAS No. 71, PEF has informed the state regulators having jurisdiction over them of this change and that the new estimation process will be implemented effective January 1, 2005. The Company has also requested a method change from the IRS.

---------------------------------------------------------------------------
                                       Energy and
(in millions)                       Related Services     Other      Total
---------------------------------------------------------------------------
Balance as of January 1, 2003             $ 11            $  -      $ 11
Divestitures                                (1)              -        (1)
Acquisition                                  -               7         7
---------------------------------------------------------------------------
Balance as of December 31, 2003           $ 10            $  7      $ 17
Impairment loss                             (8)              -        (8)
Purchase accounting adjustment               -              (7)       (7)
---------------------------------------------------------------------------
Balance as of December 31, 2004           $  2            $  -      $  2
---------------------------------------------------------------------------

In connection with a review of strategic alternatives regarding the Fuels' coal mining business, the Company performed an impairment test of the goodwill of the coal mining business in the fourth quarter of 2004. As a result of the impairment test, the Company recorded an impairment loss of $8 million to write off all of the goodwill of the coal mining business. The Company used a probability-weighted discounted cash flow analysis to perform the assessment.

In December 2003, $7 million in goodwill was acquired based on a preliminary purchase price allocation as part of the Progress Telecommunications Corporation partial acquisition of EPIK and was reported in the Other segment. As discussed in Note 5, the Company revised the preliminary EPIK purchase price allocation as of September 2004, and the $7 million of goodwill was reallocated to certain tangible assets acquired based on the results of valuations and appraisals.

The Company has $10 million and $9 million of net amortizable intangible assets at December 31, 2004 and 2003, respectively. The Company's intangibles are primarily acquired customer contracts that are amortized over their respective lives. Amortization expense recorded on intangible assets for the years ended December 31, 2004 and 2003, and estimated annual amortization expense for intangible assets for 2004 through 2008 are not material to the results of operations. PEF has no intangible assets at December 31, 2004 or 2003.

10. IMPAIRMENT OF LONG-LIVED ASSETS AND INVESTMENTS

Effective January 1, 2002, the Company adopted SFAS No. 144, which provides guidance for the accounting and reporting of impairment or disposal of long-lived assets. The statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." In 2003 and 2002, the Company recorded impairments and other charges of approximately $15 million and $300 million, respectively.

Due to the reduction in coal production at the Kentucky May Coal Mine, the Company evaluated its 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 $15 million on a pre-tax basis during the fourth quarter of 2003.

The 2002 amount includes an estimated impairment of assets held for sale of $67 million related to Railcar Ltd., (See Note 4C). In 2002, the Company also initiated an independent valuation study to assess the recoverability of the long-lived assets of PTC. Based on this assessment, the Company recorded asset impairments of $215 million on a pre-tax basis and other charges of $18 million on a pre-tax basis in the third quarter of 2002. This write-down constitutes a significant reduction in the book value of these long-lived assets. The long-lived asset impairments include an impairment of property, plant and equipment, construction work in process and intangible assets. The impairment charge represents the difference between the fair value and carrying amount of these long-lived assets. The fair value of these assets was determined using a valuation study heavily weighted on the discounted cash flow methodology, using market approaches as supporting information.

------------------------------------------------------------------------------------------
(in millions except share data)                                         2004         2003
------------------------------------------------------------------------------------------
Florida Progress
Common stock without par value, 250,000,000 shares authorized;       $ 1,712      $ 1,699
     98,616,658 shares outstanding in 2004 and 2003
Progress Energy Florida
Common stock without par value, 60,000,000 shares authorized; 100    $ 1,081      $ 1,081
     shares outstanding in 2004 and 2003
------------------------------------------------------------------------------------------

From time-to-time the Company and its subsidiaries may receive equity contributions from and pay dividends to Progress Energy. The Company received equity contributions from Progress Energy of $13 million, $168 million and $220 million during 2004, 2003 and 2002, respectively. The Company paid dividends to Progress Energy of $340 million, $301 million and $303 million during 2004, 2003 and 2002, respectively.

The authorized capital stock of the Company includes 10 million shares of preferred stock, without par value, including 2 million shares designated as Series A Junior Participating Preferred Stock. No shares of the Company's preferred stock are issued or outstanding.

The authorized capital stock of PEF includes three classes of preferred stock: 4 million shares of Cumulative Preferred Stock, $100 par value; 5 million shares of Cumulative Preferred Stock, without par value; and 1 million shares of Preference Stock, $100 par value. No shares of PEF's Cumulative Preferred Stock, without par value, or Preference Stock are issued or outstanding. All Cumulative Preferred Stock series are without sinking funds and are not subject to mandatory redemption.

Preferred stock outstanding at December 31, 2004 and 2003 consisted of the following (in millions, except share data and par value):

-------------------------------------------------------------------------
4.00% - 39,980 shares outstanding (redemption price $104.25)       $   4
4.40% - 75,000 shares outstanding (redemption price $102.00)           8
4.58% - 99,990 shares outstanding (redemption price $101.00)          10
4.60% - 39,997 shares outstanding (redemption price $103.25)           4
4.75% - 80,000 shares outstanding (redemption price $102.00)           8
-------------------------------------------------------------------------
Total Preferred Stock of PEF                                       $  34
-------------------------------------------------------------------------

B. Stock-Based Compensation

EMPLOYEE STOCK OWNERSHIP PLAN

Progress Energy sponsors the Progress Energy 401(k) Savings and Stock Ownership Plan (401(k)) for which substantially all full-time nonbargaining unit employees and certain part-time nonbargaining employees within participating subsidiaries are eligible. Effective January 1, 2002, Florida Progress is a participating subsidiary of the 401(k), which has matching and incentive goal features, encourages systematic savings by employees and provides a method of acquiring Progress Energy common stock and other diverse investments. The 401(k), as amended in 1989, is an Employee Stock Ownership Plan (ESOP) that can enter into acquisition loans to acquire Progress Energy common stock to satisfy 401(k) common stock needs. Qualification as an ESOP did not change the level of benefits received by employees under the 401(k). Common stock acquired with the proceeds of an

ESOP loan is held by the 401(k) Trustee in a suspense account. The common stock is released from the suspense account and made available for allocation to participants as the ESOP loan is repaid. Such allocations are used to partially meet common stock needs related to Progress Energy matching and incentive contributions and/or reinvested dividends.

Florida Progress' matching and incentive goal compensation cost under the 401(k) is determined based on matching percentages and incentive goal attainment as defined in the plan. Such compensation cost is allocated to participants' accounts in the form of Progress Energy common stock, with the number of shares determined by dividing compensation cost by the common stock market value at the time of allocation. The 401(k) common stock share needs are met with open market purchases, with shares released from the ESOP suspense account and with newly issued shares. Costs for incentive goal compensation are accrued during the fiscal year and typically paid in shares in the following year; while costs for the matching component are typically met with shares in the same year incurred. Florida Progress' matching and incentive cost which was and will be met with shares released from the suspense account totaled approximately $5 million, $4 million and $2 million for the years ended December 31, 2004, 2003 and 2002, respectively. Matching and incentive costs totaled approximately $7 million, $11 million and $10 million for the years ended December 31, 2004, 2003 and 2002, respectively. PEF's matching and incentive cost which was and will be met with shares released from the suspense account totaled approximately $5 million, $4 million and $2 million for the year ended December 31, 2004, 2003 and 2002, respectively. Matching and incentive costs totaled approximately $7 million, $10 million and $9 million for the years ended December 31, 2004, 2003 and 2002, respectively.

STOCK OPTION AGREEMENTS

Pursuant to the Progress Energy's 1997 Equity Incentive Plan and 2002 Equity Incentive Plans as amended and restated as of July 10, 2002, Progress Energy may grant options to purchase shares of common stock to directors, officers and eligible employees. For the years ended December 31, 2004, 2003 and 2002 approximately 28 thousand, 3.0 million and 2.9 million common stock options were granted, respectively. Of these amounts, approximately 1.0 million and 0.8 million options, respectively, were granted to officers and eligible employees of Florida Progress and PEF in 2003 and approximately 0.5 million and 0.4 million options, respectively, were granted in 2002. No stock options were granted to officers and employees of Florida Progress and PEF in 2004. The Company expects to begin expensing stock options on July 1, 2005 by adopting new FASB guidance on accounting for stock-based compensation that was issued (See Note 2). In 2004, however, Progress Energy made the decision to cease granting stock options and intends to replace that compensation program with other programs. Therefore, the amount of stock option expense expected to be recorded in 2005 is below the amount that would have been recorded if the stock option program had continued.

The pro forma information presented in Note 1 regarding net income and earnings per share is required by SFAS No. 148. Under this statement, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the vesting period. The pro forma amounts presented in Note 1 have been determined as if the Company had accounted for its employee stock options under SFAS No. 123.

OTHER STOCK-BASED COMPENSATION PLANS

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

Under the terms of the PSSP, officers and key employees are granted performance shares on an annual basis that vest over a three-year consecutive period. Each performance share has a value that is equal to, and changes with, the value of a share of Progress Energy's common stock, and dividend equivalents are accrued on, and reinvested in, the performance shares. The PSSP has two equally weighted performance measures, both of which are based on Progress Energy's results as compared to a peer group of utilities. Compensation expense is recognized over the vesting period based on the expected ultimate cash payout and is reduced by any forfeitures.

The RSA program allows Progress Energy to grant shares of restricted common stock to officers and key employees of Progress Energy. The restricted shares generally vest on a graded vesting schedule over a minimum of three years. Compensation expense, which is based on the fair value of common stock at the grant date, is recognized over the applicable vesting period and is reduced by any forfeitures.

The total amount expensed by the Company for other stock-based compensation under these plans was $2 million, $9 million and $5 million in 2004, 2003 and 2002, respectively. The total amount expensed by PEF for other stock-based compensation under these plans was $2 million, $7 million and $4 million in 2004, 2003 and 2002, respectively.

----------------------------------------------------------------------------------------------------
                                                     Florida Progress       Progress Energy Florida
                                                  ----------------------   -------------------------
(in millions)                                       2004         2003           2004       2003
----------------------------------------------------------------------------------------------------
Loss on cash flow hedges                           $  (5)       $  (9)         $   -      $   -
Minimum pension liability adjustments                 (7)          (9)             -         (4)
Foreign currency translation and other                 5            1              -          -
----------------------------------------------------------------------------------------------------
Total accumulated other comprehensive loss         $  (7)       $ (17)         $   -      $  (4)
----------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------
(in millions)                                                Rate         2004       2003
------------------------------------------------------------------------------------------
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 17)
Debt to affiliated trust, maturing 2039                      7.10%         309        309
------------------------------------------------------------------------------------------
Progress Capital Holdings, Inc.
Medium-term notes, maturing 2006-2008                        6.84%         140        165
Unsecured note with parent, maturing 2011                    6.45%         500        500
Miscellaneous notes                                                          1          1
------------------------------------------------------------------------------------------
                                                                           641        666
------------------------------------------------------------------------------------------
Current portion of long-term debt                                          (49)       (68)
------------------------------------------------------------------------------------------
        Total long-term debt                                           $ 2,861    $ 2,854
------------------------------------------------------------------------------------------

In February 2005, PEF used proceeds from money pool borrowings to pay off $55 million of RCA loans and in January 2005, PEF used proceeds from the issuance of commercial paper to pay off $170 million of RCA loans.

At December 31, 2004, PEF had committed lines of credit which are used to support its commercial paper borrowings. The 3-year credit facility is included in long-term debt. The 364-day credit facility is included in short-term obligations and had $170 million of outstanding borrowings at December 31, 2004, at an interest rate of 3.13%. No amount was outstanding under the committed lines of credit at December 31, 2003. PEF is required to pay minimal annual commitment fees to maintain its credit facilities.

The following table summarizes PEF's credit facilities:

----------------------------------------------------------------------------
(in millions)
Description                      Total     Outstanding      Available
----------------------------------------------------------------------------
364-Day (expiring  3/29/05)      $ 200       $ 170          $   30
3-Year (expiring  4/01/06)         200          55             145
Less: amounts reserved(a)                                     (123)
----------------------------------------------------------------------------
Total credit facilities          $ 400       $ 225          $   52
----------------------------------------------------------------------------
(a) To the extent  amounts are reserved for commercial  paper  outstanding,
    they are not available for additional borrowings.

At December 31, 2004, PEF had $123 million of outstanding commercial paper and other short-term debt classified as short-term obligations. The weighted-average interest rate of such short-term obligations at December 31, 2004 was 2.80%. At December 31, 2003, PEF had no outstanding commercial paper and other short-term debt classified as short-term obligations.

The combined aggregate maturities of Florida Progress long-term debt for 2005 through 2008 are approximately, in millions, $49, $163, $124 and $127, respectively. PEF's aggregate maturities of long-term debt for 2005 through 2008 are approximately, in millions, $48, $103, $89 and $82, respectively. There are no long-term debt maturities in 2009 for PEF or Florida Progress.

B. Covenants and Default Provisions

FINANCIAL COVENANTS

PEF's credit line contains various terms and conditions that could affect PEF's ability to borrow under these facilities. These include a maximum debt to total capital ratio, an interest test, a material adverse change clause and a cross-default provision. PEF's credit line requires a maximum total debt to total capital ratio of 65.0%. Indebtedness as defined by the bank agreement includes certain letters of credit and guarantees which are not recorded on the Balance Sheets. At December 31, 2004, PEF's total debt to total capital ratio was 50.8%.

PEF's 364-day and 3-year credit facility have a financial covenant for interest coverage. The covenant requires PEF's EBITDA to interest expense to be at least 3 to 1. For the year ended December 31, 2004, this ratio was 7.93 to 1.

MATERIAL ADVERSE CHANGE CLAUSE

The credit facility of PEF includes 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.

CROSS-DEFAULT PROVISIONS

PEF's credit lines include cross-default provisions for defaults of indebtedness in excess of $10 million. PEF's cross-default provisions only apply to defaults of indebtedness by PEF and not to other affiliates of PEF. The credit lines of Progress Energy include a similar provision. Progress Energy's cross-default provisions only apply to defaults of indebtedness by Progress Energy and its significant subsidiaries, which includes PEF, Florida Progress, Progress Fuels and Progress Capital.

In the event that either of these cross-default provisions were triggered, the lenders could accelerate payment of any outstanding debt. Any such acceleration would cause a MAC in the respective company's financial condition. Certain agreements underlying the Company's indebtedness also limit the Company's ability to incur additional liens or engage in certain types of sale and leaseback transactions.

OTHER RESTRICTIONS

PEF's mortgage indenture provides that it will not pay any cash dividends upon its common stock, or make any other distribution to the stockholders, except a payment or distribution out of net income of PEF subsequent to December 31, 1943. At December 31, 2004, none of PEF's retained earnings were restricted.

In addition, PEF's Articles of Incorporation provide that no cash dividends or distributions on common stock shall be paid, if the aggregate amount thereof since April 30, 1944, including the amount then proposed to be expended, plus all other charges to retained earnings since April 30, 1944, exceed (a) all credits to retained earnings since April 30, 1944, plus (b) all amounts credited to capital surplus after April 30, 1944, arising from the donation to PEF of cash or securities or transfers amounts from retained earnings to capital surplus. At December 31, 2004, none of PEF's retained earnings was restricted.

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. Secured Obligations

PEF's first mortgage bonds are secured by its mortgage indenture. PEF's mortgage constitutes a first lien on substantially all of its fixed properties, subject to certain permitted encumbrances and exceptions. The PEF mortgage also constitutes a lien on subsequently acquired property. At December 31, 2004, PEF had approximately $1.571 billion in aggregate principal amount of first mortgage bonds outstanding including those related to pollution control obligations. The PEF mortgage allows the issuance of additional mortgage bonds upon the satisfaction of certain conditions.

D. Guarantees of Subsidiary Debt

See Note 17 on related party transactions for a discussion of obligations guaranteed or secured by affiliates.

E. Hedging Activities

PEF uses interest rate derivatives to adjust the fixed and variable rate components of its debt portfolio and to hedge cash flow risk of fixed rate debt to be issued in the future. See discussion of risk management and derivative transactions at Note 16.

13. FAIR VALUE OF FINANCIAL INSTRUMENTS

At December 31, 2004 and 2003, there were miscellaneous investments, consisting primarily of investments in company-owned life insurance and other benefit plan assets, with carrying amounts of approximately $73 million and $66 million, respectively, included in miscellaneous other property and investments. At PEF, these investments had carrying amounts of $34 million and $33 million at December 31, 2004 and 2003, respectively. The carrying amount of these investments approximates fair value due to the short maturity. The carrying amount of the Company's long-term debt, including current maturities, was $2,910 million and $2,922 million at December 31, 2004 and 2003, respectively. The estimated fair value of this debt, as obtained from quoted market prices for the same or similar issues, was $3,121 million and $3,105 million at December 31, 2004 and 2003, respectively. The carrying amount of PEF's long-term debt, including current maturities, was $1,960 million and $1,947 million 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 $2,080 million and $2,061 million 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.

14. INCOME TAXES

Deferred income taxes have been provided for temporary differences. These occur when there are differences between book and tax carrying amounts of assets and liabilities. Investment tax credits related to regulated operations have been deferred and are being amortized over the estimated service life of the related properties. To the extent that the establishment of deferred income taxes under SFAS No. 109 is different from the recovery of taxes by PEF through the ratemaking process, the differences are deferred pursuant to SFAS No. 71. A regulatory asset or liability has been recognized for the impact of tax expenses or benefits that are recovered or refunded in different periods by the utility pursuant to rate orders.

Accumulated deferred income tax assets (liabilities) at December 31 are (in millions):

---------------------------------------------------------------------------------------------
  Florida Progress                                                       2004          2003
---------------------------------------------------------------------------------------------
     Current portion of deferred income tax asset
         Unbilled revenue                                              $   35         $   18
         Other                                                             33             42
---------------------------------------------------------------------------------------------
         Net current portion of deferred income tax asset              $   68         $   60
---------------------------------------------------------------------------------------------
     Noncurrent deferred income tax asset (liability):
         Accumulated depreciation and property cost differences        $ (400)        $ (359)
         Investments                                                       49            (17)
         Supplemental executive retirement plans                           19             19
         Other post-employment benefits (OPEB)                             65             64
         Other pension plans                                              (89)           (85)
         Goodwill                                                          34             46
         Deferred storm costs                                            (113)             -
         Storm damage reserve                                               -             16
         Premium on reacquired debt                                       (12)           (13)
         State NOL carry forward                                           23             28
         Federal and state income tax credit carry forward                494            437
         Miscellaneous other temporary differences, net                    57             25
         Valuation allowance                                              (27)           (29)
---------------------------------------------------------------------------------------------
     Total noncurrent deferred income tax asset                           100            132
---------------------------------------------------------------------------------------------
     Less amount included in other assets and deferred debits             161            172
---------------------------------------------------------------------------------------------
     Net noncurrent deferred income tax liability                      $  (61)        $  (40)
---------------------------------------------------------------------------------------------

---------------------------------------------------------------------------------------------
  Progress Energy Florida                                                2004           2003
---------------------------------------------------------------------------------------------
     Current portion of deferred income tax asset
         Unbilled revenue                                              $   35         $   18
         Other                                                              7             21
---------------------------------------------------------------------------------------------
         Net current portion of deferred income tax asset              $   42         $   39
---------------------------------------------------------------------------------------------
     Noncurrent deferred income tax asset (liability):
         Accumulated depreciation and property cost differences        $ (389)        $ (368)
         Other post-employment benefits (OPEB)                             63             62
         Other pension plans                                              (89)           (85)
         Deferred storm costs                                            (113)             -
         Storm damage reserve                                               -             16
         Miscellaneous other temporary differences, net                    39             17
---------------------------------------------------------------------------------------------
     Total noncurrent deferred income tax liability                    $ (489)        $ (358)
---------------------------------------------------------------------------------------------

The Company's total deferred income tax liabilities were $997 million and $824 million at December 31, 2004 and 2003, respectively. Total deferred income tax assets were $1,165 million and $1,016 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 $2 and $7 million, respectively, related to contingent tax liabilities on which the Company accrues interest that would be payable with the related tax amount in future years.

PEF's total deferred income tax liabilities were $620 million and $476 million at December 31, 2004 and 2003, respectively. Total deferred income tax assets were $173 million and $157 million at December 31, 2004 and 2003, respectively. Total noncurrent income tax liabilities on the Balance Sheets at December 31, 2004 and 2003 include none and $5 million, respectively, related to contingent tax liabilities on which the company accrues interest that would be payable with the related tax amount in future years.

The Company's federal income tax credit carry forward at December 31, 2004 consists of $484 million of alternative minimum tax credit with an indefinite carry forward period and $9 million of general business credit with a carry forward period that will begin to expire in 2022. The Company's alternative minimum tax credit carry forward at December 31, 2004 includes $3 million that would be limited if a change in ownership were to occur with respect to certain indirect wholly owned subsidiary companies.

As of December 31, 2004, the Company had a state net operating loss carry forward of $2 million that will begin to expire in 2007.

The Company decreased its valuation allowance during 2004 by $2 million and established additional valuation allowances of $3 million and $5 million during 2003 and 2002, respectively, due to the uncertainty of realizing certain future state tax benefits. The Company decreased its 2004 beginning-of-the-year valuation allowance by $8 million for a change in circumstances related to net operating losses. 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.

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 current Taxes Accrued on the Consolidated Balance Sheets. At December 31, 2004 and 2003, PEF had recorded $7 million of tax contingency reserves, excluding accrued interest and penalties, which are included in other current liabilities on the 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 21E).

Reconciliations of the Company's effective income tax rate to the statutory federal income tax rate are:

------------------------------------------------------------------------------------------
     Florida Progress                                  2004          2003          2002
------------------------------------------------------------------------------------------
     Effective income tax rate                        13.3%        (32.6)%      (304.8)%
     State income taxes, net of federal benefit       (6.1)         (2.5)        (10.3)
     AFUDC amortization                               (0.5)         (0.7)         (4.1)
     Federal tax credits                              24.4          63.5         311.3
     Investment tax credit amortization                1.2           1.8          11.3
     Progress Energy tax allocation benefit            2.7           3.8          35.2
     Other differences, net                             --           1.7          (3.6)
------------------------------------------------------------------------------------------
           Statutory federal income tax rate          35.0%         35.0%         35.0%
------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------
     Progress Energy Florida                           2004          2003          2002
------------------------------------------------------------------------------------------
     Effective income tax rate                        34.2%         33.1%         33.6%
     State income taxes, net of federal benefit       (3.5)         (3.5)         (3.4)
     Investment tax credit amortization                1.2           1.4           1.3
     Progress Energy tax allocation benefit            2.5           2.7           3.8
     Other differences, net                            0.6           1.3          (0.3)
------------------------------------------------------------------------------------------
           Statutory federal income tax rate          35.0%         35.0%         35.0%
------------------------------------------------------------------------------------------

Income tax expense (benefit) applicable to continuing operations is comprised of (in millions):

---------------------------------------------------------------------------------------
     Florida Progress                                 2004         2003         2002
---------------------------------------------------------------------------------------
     Current  -  federal                             $  46       $    6      $   43
                 State                                  31           18          23
     Deferred -  federal                               (16)        (123)       (220)
                 State                                  15           (5)        (13)
     Investment tax credit                              (6)          (6)         (6)
---------------------------------------------------------------------------------------
           Total income tax expense (benefit)        $  70       $ (110)     $ (173)
---------------------------------------------------------------------------------------

---------------------------------------------------------------------------------------
     Progress Energy Florida                          2004         2003         2002
---------------------------------------------------------------------------------------
     Current  -  federal                             $  55       $  145      $  172
                 State                                   9           27          29
     Deferred -  federal                                98          (16)        (29)
                 State                                  18           (3)         (3)
     Investment tax credit                              (6)          (6)         (6)
---------------------------------------------------------------------------------------
           Total income tax expense (benefit)        $ 174       $  147      $  163
---------------------------------------------------------------------------------------

Florida Progress and each of its wholly-owned subsidiaries have entered into a Tax Agreement with Progress Energy (See Note 1D). The Company's intercompany tax payable was approximately $72 million and $17 million at December 31, 2004 and 2003, respectively. Progress Energy Florida's intercompany tax payable was approximately $21 million and $16 million at December 31, 2004 and 2003, respectively.

Florida Progress, through its subsidiaries, is a majority owner in two entities and a minority owner in four entities 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 21E).

15. BENEFIT PLANS

The Company and some of its subsidiaries (including PEF) have a non-contributory 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 (including PEF) provide contributory other postretirement benefits (OPEB), including certain health care and life insurance benefits, for retired employees who meet specified criteria. The Company uses a measurement date of December 31 for its pension and OPEB plans.

The components of the net periodic benefit cost for the years ended December 31 are:

-----------------------------------------------------------------------------------------------------------
                                                  Pension Benefits            Other Postretirement Benefits
                                            -----------------------------     -----------------------------
(in millions)                                2004         2003       2002      2004     2003     2002
-----------------------------------------------------------------------------------------------------------
Service cost                                $  22        $  21      $  19     $   4    $   5    $   5
Interest cost                                  48           46         44        14       16       15
Expected return on plan assets                (77)         (62)       (76)       (1)      (1)      (1)
Net amortization                                1            3         (7)        5        5        4
-----------------------------------------------------------------------------------------------------------
Net cost/(benefit) recognized by            $  (6)       $   8      $ (20)    $  22    $  25    $  23
  Florida Progress
-----------------------------------------------------------------------------------------------------------
Net cost/(benefit) recognized by PEF        $  (8)       $   5      $ (22)    $  21    $  24    $  22
-----------------------------------------------------------------------------------------------------------

The net periodic cost for other postretirement benefits decreased during 2004 due to the implementation of FASB Staff Position 106-2 (See Note 2).

Prior service costs and benefits are amortized on a straight-line basis over the average remaining service period of active participants. Actuarial gains and losses in excess of 10% of the greater of the obligation or the market-related value of assets are amortized over the average remaining service period of active participants. The Company uses fair value for the market-related value of assets.

Reconciliations of the changes in the plans' benefit obligations and the plans' funded status are:

--------------------------------------------------------------------------------------------------------------
                                                        Pension Benefits         Other Postretirement Benefits
                                                   ---------------------------   -----------------------------
(in millions)                                            2004         2003              2004             2003
--------------------------------------------------------------------------------------------------------------
Obligation at January 1                                $  780       $  714            $  224           $  236
Service cost                                               22           21                 4                5
Interest cost                                              48           46                14               15
Plan amendments                                             2            -                 -                -
Benefit payments                                          (42)         (41)              (17)             (15)
Actuarial loss (gain)                                      39           40                15              (17)
--------------------------------------------------------------------------------------------------------------
Obligation at December 31                                 849          780               240              224
Fair value of plan assets at December 31                  919          849                20               18
--------------------------------------------------------------------------------------------------------------
Funded status                                              70           69              (220)            (206)
Unrecognized transition obligation                          -            -                28               31
Unrecognized prior service cost (benefit)                 (14)         (18)                6                7
Unrecognized net actuarial loss                           117          111                30               15
Minimum pension liability adjustment                      (14)         (11)                -                -
--------------------------------------------------------------------------------------------------------------
Prepaid (accrued) cost at December 31, net -           $  159       $  151            $ (156)          $ (153)
Florida Progress
--------------------------------------------------------------------------------------------------------------
Prepaid (accrued) cost at December 31, net - PEF       $  192       $  183            $ (150)          $ (148)
--------------------------------------------------------------------------------------------------------------

The 2003 OPEB obligation information above has been restated due to the implementation of FASB Staff Position 106-2 (See Note 2).

The Florida Progress net prepaid pension cost of $159 million and $151 million at December 31, 2004 and 2003, respectively, is included in the Company's Consolidated Balance Sheets as prepaid pension cost of $238 million and $223 million, respectively, which is included in other assets and deferred debits, and accrued benefit cost of $79 million and $72 million, respectively, which is included in accrued pension and other benefits. The PEF net prepaid pension cost of $192 million and $183 million at December 31, 2004 and 2003, respectively, is included in the Balance Sheets as prepaid pension cost of $234 million and $220 million, respectively, and accrued benefit cost of $42 million and $37 million, respectively, which is included in accrued pension and other benefits. For Florida Progress, the defined benefit pension plans with accumulated benefit obligations in excess of plan assets had projected benefit obligations totaling $80 million and $74 million at December 31, 2004 and 2003, respectively. Those plans had accumulated benefit obligations totaling $77 million and $73 million, respectively, and no plan assets. For PEF, the defined benefit pension plans with accumulated benefit obligations in excess of plan assets had projected benefit obligations totaling $41 million and $38 million at December 31, 2004 and 2003, respectively. Those plans had accumulated benefit obligations totaling $39 million and $37 million, respectively, and no plan assets. For Florida Progress, the total accumulated benefit obligation for pension plans was $797 million and $736 million at December 31, 2004 and 2003, respectively. For PEF, the total accumulated benefit obligation for pension plans was $718 million and $659 million at December 31, 2004 and 2003, respectively. Accrued other postretirement benefit cost is included in accrued pension and other benefits in the respective Balance Sheets of Florida Progress and PEF.

Florida Progress and PEF recorded a minimum pension liability adjustment of $14 million and $7 million, respectively, at December 31, 2004, with a corresponding charge of $7 million to a regulatory asset and, for Florida Progress, a pre-tax charge of $7 million to accumulate other comprehensive loss, a component of common stock equity. Florida Progress and PEF recorded a minimum pension liability adjustment of $11 million and $6 million, respectively, at December 31, 2003, with a corresponding pre-tax charge to accumulated other comprehensive loss, a component of common stock equity.

Reconciliations of the fair value of plan assets are:

-------------------------------------------------------------------------------------------------
                                               Pension Benefits     Other Postretirement Benefits
                                            ---------------------- ------------------------------
(in millions)                                2004         2003           2004              2003
-------------------------------------------------------------------------------------------------
Fair value of plan assets January 1         $ 849        $ 687          $  18             $  16
Actual return on plan assets                  108          199              1                 1
Benefit payments                              (42)         (41)           (18)              (15)
Employer contributions                          4            4             19                16
-------------------------------------------------------------------------------------------------
Fair value of plan assets at December 31    $ 919        $ 849          $  20             $  18
-------------------------------------------------------------------------------------------------

In the table above, substantially all employer contributions represent benefit payments made directly from Company assets. The remaining benefits payments were made directly from plan assets. The OPEB benefit payments represent the net Company cost after participant contributions. Participant contributions represent approximately 10% of gross benefit payments.

The asset allocation for the Company's plans at the end of 2004 and 2003 and the target allocation for the plans, by asset category, are as follows:

--------------------------------------------------------------------------------------------------------
                                       Pension Benefits                 Other Postretirement Benefits
                           ------------------------------------       ----------------------------------
                              Target         Percentage of Plan         Target        Percentage of Plan
                           Allocations       Assets at Year End       Allocations     Assets at Year End
                           -----------       ------------------       -----------     ------------------
Asset Category                 2005             2004       2003          2005          2004        2003
--------------------------------------------------------------------------------------------------------
  Equity - domestic             48%              47%        49%            -             -            -
  Equity - international        15%              21%        22%            -             -            -
  Debt - domestic               12%               9%        11%          100%          100%         100%
  Debt - international          10%              11%        11%            -             -            -
  Other                         15%              12%         7%            -             -            -
--------------------------------------------------------------------------------------------------------
  Total                        100%             100%       100%          100%          100%         100%
--------------------------------------------------------------------------------------------------------

With regard to its pension assets, the Company sets strategic 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 five percent) in asset allocation from the strategic allocations are made based on the near-term view of the risk and return tradeoffs of the asset classes. The Company's OPEB assets are invested solely in fixed income securities.

In 2005, the Company expects to make no required contributions to pension plan assets and $1 million of discretionary contributions to 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 $43, $45, $47, $51, $55 and $337, respectively. The expected benefit payments for the OPEB plan for 2005 through 2009 and in total for 2010-2014, in millions, are approximately $17, $19, $20, $21, $22 and $126, 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 $2, $2, $2, $2 and $14, respectively. PEF represents a significant majority of the Company's expected benefit payments and expected subsidies to be received. The expected benefit payments above do not include the potential effects of a 2005 voluntary early retirement program (see Note 22).

The following weighted-average actuarial assumptions were used in the calculation of the year-end obligation:

------------------------------------------------------------------------------------------------------------
                                                          Pension Benefits    Other Postretirement Benefits
                                                         ------------------   ------------------------------
                                                          2004        2003           2004            2003
------------------------------------------------------------------------------------------------------------
Discount rate                                             5.90%      6.30%          5.90%           6.30%
Rate of increase in future compensation
  Bargaining                                              3.50%      3.50%             -               -
  Supplementary plans                                     5.25%      5.00%             -               -
Initial medical cost trend rate for pre-Medicare             -          -
benefits                                                                            7.25%           7.25%
Initial medical cost trend rate for post-Medicare            -          -
benefits                                                                            7.25%           7.25%
Ultimate medical cost trend rate                             -          -           5.00%           5.25%
Year ultimate medical cost trend rate is achieved            -          -           2008            2009
------------------------------------------------------------------------------------------------------------

The Company's primary defined benefit retirement plan for nonbargaining employees is a "cash balance" pension plan as defined in Emerging Issues Task Force Issue No. 03-4. Therefore, effective December 31, 2003, the Company began to use the traditional unit credit method for purposes of measuring the benefit obligation of this plan. Under the traditional unit credit method, no assumptions are included about future changes in compensation and the accumulated benefit obligation and projected benefit obligation are the same.

The following weighted-average actuarial assumptions were used in the calculation of the net periodic cost:

------------------------------------------------------------------------------------------------------------
                                                     Pension Benefits          Other Postretirement Benefits
                                                ------------------------    --------------------------------
                                                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 plan                            5.00%    4.00%     4.00%           -          -          -
Expected long-term rate of return on plan
  assets                                        9.25%    9.25%     9.25%        5.00%      5.00%      5.00%
---------------------------------------------------------------------------------------------------------------

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 pension plan 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 OPEB expected long-term rate of return of 5.0% reflects that the OPEB assets are invested solely in fixed income securities.

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 $13 million. Assuming a 1% decrease in the medical cost trend rates, the aggregate of the service and interest cost components of the net periodic OPEB cost for 2004 would decrease by $1 million and the OPEB obligation at December 31, 2004, would decrease by $12 million.

16. RISK MANAGEMENT ACTIVITIES AND DERIVATIVES TRANSACTIONS

Under its risk management policy, the Company and PEF 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 and PEF minimize such risk by performing credit reviews using, among other things, publicly available credit ratings of such counterparties. Potential non-performance by counterparties is not expected to have a material effect on the consolidated financial position or consolidated results of operations of the Company or PEF.

A. Commodity Derivatives

GENERAL

Most of the Company's and PEF's commodity contracts either are not derivatives or qualify as normal purchases or sales pursuant to SFAS No.
133. Therefore, such contracts are not recorded at fair value.

ECONOMIC DERIVATIVES

Derivative products, primarily electricity forward contracts, may be entered into for economic hedging purposes. While management believes these derivatives 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 during 2004, 2003 or 2002, and the Company did not have material outstanding positions in such contracts at December 31, 2004 or 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.

CASH FLOW HEDGES

The Company'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 sales. In the normal course of business, Progress Fuels through an affiliate, Progress Ventures, Inc. (PVI), enters natural gas cash flow hedging instruments, which PVI offsets with third party transactions. Progress Fuels accounts for such contracts as if it were transacted with a third party and records the contract using mark-to-market or accrual accounting, as applicable. At December 31, 2004, Progress Fuels is hedging exposures to the price variability of natural gas through December 2005.

The total fair value of these instruments at December 31, 2004 and 2003 was a $9 million and a $14 million liability position, respectively. The ineffective portion of commodity cash flow hedges was not material in 2004 and 2003. At December 31, 2004, there were $5 million of after-tax deferred losses in accumulated other comprehensive income (OCI). The entire amount is expected to be reclassified to earnings during the next 12 months as the hedged transactions occur. 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 (See Note 4A). 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 and PEF manage its interest rate exposure in part by maintaining its variable-rate and fixed rate-exposures within defined limits. In addition, the Company and PEF also enter into financial derivative instruments, including, but not limited to, interest rate swaps and lock agreements to manage and mitigate interest rate risk exposure.

The Company and PEF use cash flow hedging strategies to hedge variable interest rates on long-term debt and to hedge interest rates with regard to future fixed-rate debt issuances. The Company and PEF held no interest rate cash flow hedges at December 31, 2004 or 2003. At December 31, 2004, an immaterial amount of after-tax deferred losses in OCI, related to previously terminated hedges at PEF, is expected to be reclassified to earnings during the next 12 months as the hedged interest payments occur.

The Company and PEF use fair value hedging strategies to manage its exposure to fixed interest rates on long-term debt. At December 31, 2004 and 2003, the Company and PEF had no open interest rate fair value hedges.

The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss. In the event of default by a counterparty, the risk in these transactions is the cost of replacing the agreements at current market rates.

17. RELATED PARTY TRANSACTIONS

The Parent's subsidiaries provide and receive services, at cost, to and from the Company and its subsidiaries, in accordance with agreements approved by the U.S. Securities and Exchange Commission (SEC) pursuant to
Section 13(b) of the PUHCA. Services include purchasing, human resources, accounting, legal, transmission and delivery support, engineering materials, contract support, loaned employees payroll costs, constructions management and other centralized administrative, management and support services. The costs of the services are billed on a direct-charge basis, whenever possible, and on allocation factors for general costs which cannot be directly attributed. Billings from affiliates are capitalized or expensed depending on the nature of the services rendered. Amounts receivable from and/or payable to affiliated companies for these services are included in receivables from affiliated companies and payables to affiliated companies on the Consolidated Balance Sheets.

Progress Energy Service Company, LLC (PESC) provides the majority of the affiliated services under the approved agreements. Services provided by PESC during 2004, 2003 and 2002 to Florida Progress amounted to $199 million, $190 million and $173 million, respectively, and services provided to PEF were $165 million, $153 million and $161 million, respectively. Based on a standard review by the Office of Public Utility Regulation within the SEC the method for allocating certain PESC governance costs changed and retroactive reallocations for 2002 and 2001 charges were recorded in 2003. The net after-tax impact of the reallocation on 2003 was an increase in expenses of $5 million at Florida Progress and a reduction of expenses at PEF by $1 million. PEF and an affiliated utility also provide and receive services at cost. Services received by PEF during 2004, 2003 and 2002 amounted to $52 million, $35 million and $72 million, respectively. Services provided by PEF during 2004, 2003 and 2002 amounted to $16 million, $7 million and $16 million, respectively.

Progress Fuels sells coal to PEF for insignificant profits. These intercompany revenues and expenses are eliminated in consolidations; 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 Florida Progress' Consolidated and PEF's Statements of Income.

The Company and its subsidiaries participate in money pools, operated by Progress Energy, to more effectively utilize cash resources and to reduce outside short-term borrowings. The money pools are also used to settle intercompany balances. The weighted-average interest rate for the money pools was 1.72%, 1.47% and 2.18% at December 31, 2004, 2003 and 2002, respectively. Amounts payable to the money pool are included in notes payable to affiliated companies on the Balance Sheets. Net interest expense related to money pool borrowings was $7 million for 2004 and $5 million for Florida Progress for 2003 and 2002. PEF recorded insignificant interest expense related to the money pool for the three years presented.

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 certain subsidiaries issued guarantees of $140 million supporting obligations under coal brokering operations and other agreements of subsidiaries. Progress Energy and certain subsidiaries also purchased $33 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $40 million. Florida Progress has fully guaranteed the medium term notes outstanding for Progress Capital, a wholly owned subsidiary of Florida Progress. 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 Consolidated Balance Sheets.

In April 2000, Progress Ventures, Inc. (PVI), a wholly owned subsidiary of Progress Energy, purchased a 90% interest in an affiliate of Progress Fuels that owns a synthetic fuel facility located at the Company-owned mine site in Virginia. In May 2000, PVI purchased a 90% ownership interest in another synthetic fuel facility located in West Virginia. The purchase agreements contained a provision that would require PVI to sell, and the respective Progress Fuels affiliate to repurchase, the 90% interest had the share exchange among Florida Progress, Progress Energy and CP&L not occurred. Progress Fuels has accounted for the transactions as a sale for tax

purposes and, because of the repurchase obligation, as a financing for financial reporting purposes in the pre-acquisition period and as a transfer of assets within a controlled group as of the acquisition date. At the date of acquisition, assets of $8 million were transferred to Progress Energy. At December 31, 2004 and 2003, the Company has a note receivable of $28 million and $37 million from PVI that has been recorded as a reduction to equity for financial reporting purposes. Payments included insignificant amounts of interest for the three years presented.

PVI enters into derivative transactions on behalf of Progress Fuels, which are discussed further with the derivatives transactions (See Note 16A). PVI recorded $33 million, $28 million and $9 million of realized and unrealized gains for these derivative transactions in 2004, 2003 and 2002, respectively.

Progress Fuels sells coal feedstock to PVI to be used in its two synthetic fuel operations and is also the sales agent and operator of the facilities. The amount of revenue for sales and services during 2004, 2003 and 2002 was $134 million, $182 million and $197 million, respectively.

During 2003, in order to more effectively utilize cash resources, Progress Fuels and the two PVI synthetic fuel operations began to participate in a money pool with cash management functions provided by Progress Fuels. Amounts payable to the money pool of $61 million and $34 million are included in notes payable to affiliated companies on the Consolidated Balance Sheets. Interest related to the money pool was insignificant for the three years presented.

A Progress Fuels subsidiary sells coal feedstock to an equity investment. The amount of revenue during 2004, 2003 and 2002 was $150 million, $117 million and $101 million, respectively.

Long-term debt, affiliate on the Florida Progress' Consolidated Balance Sheet consists of $500 million for Progress Fuels' unsecured note with Parent and $309 million of debt to an affiliated trust (See Note 12A). Progress Fuels recorded interest expense related to the unsecured note with Parent of $32 million for 2004 and 2003. The annual interest expense to the affiliated trust is $21 million and is reflected in the Statements of Income.

Florida Progress Funding Corporation (Funding Corp.) $309 million 7.10% Junior Subordinated Deferrable Interest Notes (Subordinated Notes) are due to FPC Capital I (the Trust) (See Note 12A). 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. The Company has fully and unconditionally guaranteed the obligations of Funding Corp. under the Subordinated Notes (the Notes Guarantee). In addition, the Company has guaranteed the payment of all distributions related to the $300 million Preferred Securities required to be made by the Trust, but only to the extent that the Trust has funds available for such distributions (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. 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 Company and each of its wholly owned subsidiaries have entered into a Tax Agreement with Progress Energy (See Note 14).

18. FINANCIAL INFORMATION BY BUSINESS SEGMENT

The Company's principal business segment is PEF, a utility engaged in the generation, purchase, transmission, distribution and sale of electricity primarily in Florida. The other reportable business segments are Progress Fuels' Energy & Related Services and Rail Services. The Energy & Related Services segment includes coal and synthetic fuel operations, natural gas production and sales, river terminal services and off-shore marine transportation. Rail Services' operations include railcar repair, rail parts reconditioning and sales, railcar leasing and sales, providing rail and track material, and scrap metal recycling. The Other category consists primarily of PTC, the Company's telecommunications subsidiary and the holding company, Florida Progress Corporation and eliminations. PTC markets wholesale fiber-optic based capacity service in the Eastern United States and also markets wireless structure attachments to wireless communication companies and governmental entities. The Company allocates a portion of its operating expenses to business segments.

The Company's significant operations are geographically located in the United States with limited operations in Mexico and Canada. The Company's segments are based on differences in products and services, and therefore no additional disclosures are presented. Intersegment sales and transfers consist primarily of coal sales from the Energy and Related Services segment of Progress Fuels to PEF. The price Progress Fuels charges PEF is based on market rates for coal procurement and for water-borne transportation under a methodology approved by the FPSC. Rail transportation is also based on market rates plus a return allowed by the FPSC on equity in transportation equipment utilized in transporting coal to PEF. The allowed rate of return is currently 12%. No single customer accounted for 10% or more of unaffiliated revenues.

Segment net income (loss) for 2004 includes a gain on the sale of certain gas properties and assets of $56 million ($31 million after-tax) and a long-lived asset impairment on goodwill at Diamond May of $8 million before and after tax included in the Energy and Related Services segment. Segment net income (loss) for 2003 includes a long-lived asset impairment on certain assets at Kentucky May Mining Company of $15 million ($10 million after-tax) included in the Energy and Related Services segment. Segment net income (loss) for 2002 includes an estimated impairment on the assets held for sale of Railcar Ltd., of $67 million pre-tax ($45 million after-tax) included in the Rail Services segment and an asset impairment and other charges related to PTC totaling $233 million on a pre-tax basis ($144 million after-tax) included in the Other segment. The Company's business segment information for 2004, 2003 and 2002 is summarized below.

-------------------------------------------------------------------------------------------------------------
                                                           Energy
                                                            and
                                                          Related
(in millions)                                 Utility     Services     Services      Other    Consolidated
-------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2004
  Unaffiliated revenues                       $ 3,525     $  1,223     $  1,130     $   57        $ 5,935
  Intersegment revenues                             -          331            1       (332)             -
-------------------------------------------------------------------------------------------------------------
       Total revenues                           3,525        1,554        1,131       (275)         5,935
-------------------------------------------------------------------------------------------------------------
  Depreciation and amortization                   281           80           21         11            393
  Total interest charges, net                     114           20           27         19            180
  Gain on sale of assets                            -           54            -          -             54
  Impairment of goodwill and
      long-lived assets                             -            8            -          -              8
  Income tax expense (benefit)                    174         (106)          15        (13)            70
  Income (loss) from continuing
     operations                                   333          137           16        (12)           474
  Total segment assets                          7,924          855          596        311          9,686
  Capital and investment
     expenditures                                 482          157           40          6            685
-------------------------------------------------------------------------------------------------------------
Year Ended December 31, 2003
  Unaffiliated revenues                       $ 3,152     $    982     $    846     $   28        $ 5,008
  Intersegment revenues                             -          346            1       (347)             -
-------------------------------------------------------------------------------------------------------------
     Total revenues                             3,152        1,328          847       (319)         5,008
-------------------------------------------------------------------------------------------------------------
  Depreciation and amortization                   307           66           20           6           399
  Total interest charges, net                      91           22           29          21           163
  Impairment of goodwill and
      long-lived assets                             -           15            -           -            15
  Income tax expense (benefit)                    147         (246)           2         (13)         (110)
  Income (loss) from continuing
     operations                                   295          166           (1)        (17)          443
  Total segment assets                          7,280          977          586         350         9,193
  Capital and investment expenditures             526          310          103          11           950
-------------------------------------------------------------------------------------------------------------

Year Ended December 31, 2002
  Unaffiliated revenues                       $ 3,062     $    690     $    714     $    34       $ 4,500
  Intersegment revenues                             -          329            5        (334)            -
-------------------------------------------------------------------------------------------------------------
     Total revenues                             3,062        1,019          719        (300)        4,500
-------------------------------------------------------------------------------------------------------------
  Depreciation and amortization                   295           34           20          12           361
  Total interest charges, net                     106           22           33          22           183
  Impairment of goodwill and
      long-lived assets                             -            -           67         214           281
  Income tax expense (benefit)                    163         (207)         (19)       (110)         (173)
  Income (loss) from continuing
     operations                                   323          122          (47)       (168)          230
  Total segment assets                          6,678          794          529         137         8,138
  Capital and investment expenditures             535          121            8          42           706
-------------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------
                                             U.S.       Canada      Mexico    Consolidated
-------------------------------------------------------------------------------------------
2004
Consolidated revenues                     $ 5,807        $ 112         $ 16     $ 5,935
-------------------------------------------------------------------------------------------
2003
Consolidated revenues                     $ 4,891        $ 103         $ 14     $ 5,008
-------------------------------------------------------------------------------------------
2002
Consolidated revenues                     $ 4,393        $  93         $ 14     $ 4,500
-------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------
  (in millions)                                                  2004             2003             2002
--------------------------------------------------------------------------------------------------------
  Other income
     Nonregulated energy and delivery services income              17               14               17
     AFUDC equity                                                   7               12                2
     Other                                                          3                1                4
--------------------------------------------------------------------------------------------------------
         Total other income - Progress Energy Florida            $ 27             $ 27             $ 23
--------------------------------------------------------------------------------------------------------
     Other income - Florida Progress                               13                5                6
--------------------------------------------------------------------------------------------------------
         Total other income - Florida Progress                   $ 40             $ 32             $ 29
--------------------------------------------------------------------------------------------------------
  Other expense
     Nonregulated energy and delivery services expenses          $ 11             $ 11             $ 15
     Donations                                                      8                9               10
     Other                                                          3                -                5
--------------------------------------------------------------------------------------------------------
        Total other expense - Progress Energy Florida            $ 22             $ 20             $ 30
--------------------------------------------------------------------------------------------------------
     Loss from equity investments                                  12               15               14
     Other expense - Florida Progress                               5                5                5
--------------------------------------------------------------------------------------------------------
        Total other expense - Florida Progress                   $ 39             $ 40             $ 49
--------------------------------------------------------------------------------------------------------
     Other, net                                                   $ 1             $ (8)            $(20)
--------------------------------------------------------------------------------------------------------

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.

20. ENVIRONMENTAL MATTERS

The Company and PEF are 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, authorize the EPA to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liabilities. The Company and PEF are periodically notified by regulators such as the EPA and various state agencies of its involvement or potential involvement in sites, other than MGP sites, that may require investigation and/or remediation. The Company and PEF are also currently in the process of assessing potential costs and exposures at other environmentally impaired sites. For all sites the assessments are developed and analyzed, the Company and PEF will accrue costs for the sites to the extent the costs are probable and can be reasonably estimated.

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

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 has 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.

The Company and PEF have filed claims with the Company's general liability insurance carriers to recover costs arising out of actual or potential environmental liabilities. Some claims have been settled and others are still pending. The Company and PEF cannot predict the outcome of this matter.

--------------------------------------------------------------------------
(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
--------------------------------------------------------------------------

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 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 costs. In 2004, PEF received approximately $12 million in insurance claim settlement proceeds and recorded a related accrual for associated environmental expenses. The proceeds are restricted for use in addressing costs associated with environmental liabilities. Expenditures for the year were less than $1 million.

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

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 and is included in other liabilities and deferred credits. FPC measures its liability for this site 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, SO2, carbon dioxide and mercury. Some of these proposals establish nationwide caps and emission rates over an extended period of time. This national multi-pollutant approach to air pollution control could involve significant capital costs which could be material to the Company and PEF's consolidated financial position or results of operations. However, the Company and PEF 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 and PEF cannot predict the outcome of this matter.

In 2003, the EPA published a final rule addressing routine equipment replacement under the New Source Review program. The rule defines routine equipment replacement and the types of activities that are not subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The rule was challenged in the Federal Appeals Court and its implementation stayed. In July 2004, the EPA announced it will reconsider certain issues arising from the final routine equipment replacement rule. The comment period closed on August 30, 2004. The Company and PEF cannot predict the outcome of this matter.

In 1997, the EPA's Mercury Study Report and Utility Report to Congress concluded that mercury is not a risk to the average person in America and expressed uncertainty about whether reductions in mercury emissions from coal-fired power plants would reduce human exposure. Nevertheless, the EPA determined in 2000 that regulation of mercury emissions from coal-fired power plants was appropriate. In 2003, the EPA proposed alternative control plans that would limit mercury emissions from coal-fired power plants. The final rule was released on March 15, 2005. The EPA's rule establishes a mercury cap and trade program for coal-fired power plants that requires limits to be met in two phases, in 2010 and 2018. The Company and PEF are reviewing the final rule. Installation of additional air quality controls is likely to be needed to meet the mercury rule's requirements. Compliance plans and the cost to comply with the rule will be determined once the Company and PEF complete their review.

In conjunction with the proposed mercury rule, the EPA proposed a MACT standard to regulate nickel emissions from residual oil-fired units. The agency estimates the proposal will reduce national nickel emissions to approximately 103 tons. As proposed, the rule may require the company to install additional pollution controls on its residual oil-fired units, resulting in significant capital expenditures. PEF has eight units that are affected, and they currently do not have pollution controls in place that would meet the proposed requirements of the nickel rule. The EPA expects to finalize the nickel rule in March 2005. Compliance costs will be determined following promulgation of the rule.

In December 2003, the EPA released its proposed Interstate Air Quality Rule, currently referred to as the Clean Air Interstate Rule (CAIR). The final rule was enacted on March 10, 2005. The EPA's rule requires 28 states and the District of Columbia, including Florida, to reduce NOx and SO2 emissions in order to attain preset state NOx and SO2 emissions levels. The Company and PEF are reviewing the final rule. Installation of additional air quality controls is likely to be needed to meet the CAIR requirements. Compliance plans and the cost to comply with the rule, will be determined once the Company and PEF complete the review of the final rule.

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 PEF in the immediate and extended future.

After many years of litigation and settlement negotiations the EPA adopted regulations in February 2004 to implement Section 316(b) of the Clean Water Act. These regulations became effective September 7, 2004. The purpose of these regulations is to minimize adverse environmental impacts caused by cooling water intake structures and intake systems. Over the next several years these regulations will impact the larger base load generation facilities and may require the facilities to mitigate the effects to aquatic organisms by constructing intake modifications or undertaking other restorative activities. PEF 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 $65 million to $85 million.

OTHER ENVIRONMENTAL MATTERS

The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of carbon dioxide and other greenhouse gases. In 2004, Russia ratified the Protocol, and the treaty went into effect on February 16, 2005. The United States has not adopted the Kyoto Protocol, and the Bush administration has stated it favors voluntary programs. A number of carbon dioxide emissions control proposals have been advanced in Congress. Reductions in carbon dioxide emissions to the levels specified by the Kyoto Protocol and some legislative proposals could be materially adverse to 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 and PEF cannot predict the outcome of this matter.

Progress Energy has announced its plan to issue a report on the Progress Energy's activities associated with current and future environmental requirements. The report will include a discussion of the environmental requirements that the Company and PEF currently face and expect 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.

----------------------------------------------------------------------------------------------------
(in millions)                        2005        2006        2007       2008      2009    Thereafter
----------------------------------------------------------------------------------------------------
Fuel                               $ 1,571     $ 1,023      $ 270      $ 102     $ 116       $   684
Purchased power                        334         342        354        364       331         4,086
Construction obligations                51           -          -          -         -             -
Other purchase obligations              44          38         36         22        20            93
----------------------------------------------------------------------------------------------------
Total                              $ 2,000     $ 1,402      $ 660      $ 488     $ 467       $ 4,863
----------------------------------------------------------------------------------------------------

FUEL AND PURCHASED POWER

The Company has entered into various long-term contracts for oil, gas and coal. The Company's payments under these commitments were $1,620 million, $1,157 million and $891 million in 2004, 2003 and 2002, respectively. PEF's payments totaled $372 million, $208 million and $94 million in 2004, 2003 and 2002, respectively. The Company's estimated annual payments for firm commitments of fuel purchases and transportation costs under these contracts make up the fuel line in the previous table. PEF's future payments under these contracts at December 31, 2004 are $375 million, $258 million, $125 million, $102 million and $116 million for 2005 through 2009, respectively, and $684 million thereafter.

Progress Fuels had two coal supply contracts with PEF through 2005, which require PEF to buy and Progress Fuels to supply substantially all of the coal and transportation requirements of four of PEF's generating units. These contracts are renewable annually. Either party may terminate the contract with six months notice. In connection with these contracts, Progress Fuels has entered into several contracts with outside parties for the purchase of coal. The annual obligations for coal purchases and transportation under these contracts are $358 million and $286 million for 2005 and 2006, respectively, with no obligations thereafter. The total cost incurred for these commitments in 2004, 2003 and 2002 was $301 million, $284 million and $289 million, 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.

PEF has ongoing purchased power contracts with certain cogenerators (qualifying facilities) for 821 MW of capacity with expiration dates ranging from 2005 to 2025. These purchased power contracts provide for capacity and energy payments. Energy payments are based on the actual power taken under these contracts. Capacity payments are subject to the qualifying facilities meeting certain contract performance obligations. In most cases, these contracts account for 100% of the generating capacity of each of the facilities. All commitments have been approved by the FPSC. 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. The FPSC allows the capacity payments to be recovered through a capacity cost recovery clause, which is similar to, and works in conjunction with, energy payments recovered through the fuel cost recovery clause.

On December 2, 2004, PEF entered into precedent and related agreements with Southern Natural Gas Company (SNG), Florida Gas Transmission Company (FGT), and BG LNG Services, LLC, for the supply of natural gas and associated firm pipeline transportation to augment PEF's gas supply needs for the period from May 1, 2007 to April 30, 2027. The total cost to PEF associated with the agreements is approximately $3.3 billion. The transactions are subject to several conditions precedent, which include obtaining the Florida Public Service Commission's approval of the agreements, the completion and commencement of operation of the necessary related expansions to SNG's and FGT's respective natural gas pipeline systems, and other standard closing conditions. Due to the conditions in the agreements, the estimated costs associated with these agreements are not included in the contractual cash obligations table above.

CONSTRUCTION OBLIGATIONS

PEF has purchase obligations related to various plant capital projects at the Hines Complex. Total payments under these contracts were $97 million, $137 million and $130 million for 2004, 2003, and 2002, respectively. Future obligations under these contracts are $51 million for 2005.

OTHER PURCHASE OBLIGATIONS

PEF has long-term service agreements for the Hines Complex. Total payments under these contracts were $11 million, $3 million and $1 million for 2004, 2003 and 2002, respectively. Future obligations under these contracts are $6 million, $18 million, $11 million, $16 million and $14 million for 2005 through 2009, respectively, with approximately $93 million payable thereafter.

PEF has various purchase obligations and contractual commitments related to the purchase and replacement of machinery. At December 31, 2004, no purchases have been made under these contracts. Future obligations under these contracts are $34 million, $20 million and $25 million in 2005, 2006 and 2007, respectively, and $6 million in 2008 and 2009.

The Company incurred expenses related to various other purchase obligations allocated from PESC of $6 million for 2004 and 2003 and $5 million for 2002.

B. Other Commitments

The Company has certain future commitments related to synthetic fuel facilities purchased that provide for contingent payments (royalties). The related agreements and amendments require the payment of minimum annual royalties of which the Company's share is approximately $13 million through 2007. As a result of the amendment, 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 $37 million and $47 million at December 31, 2004 and 2003, representing the minimum amounts due through 2007, discounted at 6.05%. At December 31, 2004 and 2003, the portions of the asset and liability recorded that were classified as current were approximately $13 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, $1 million in 2003 and $24 million in 2002. Future expected royalty payments are approximately $13 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 $20 million and $22 million, respectively, pending the establishment of the necessary escrow accounts. Once established, these funds will be placed into escrow.

C. Leases

The Company leases transportation equipment, office buildings, computer equipment, and other property and equipment with various terms and expiration dates. The Company generally requires the subsidiaries to pay all executory costs such as maintenance and insurance. Some rental payments include minimum rentals plus contingent rentals based on mileage. These contingent rentals are not significant. Rent expense under operating leases totaled $45 million, $40 million and $49 million during 2004, 2003 and 2002, respectively. These amounts include rent expense allocated from PESC to the Company of $12 million for 2004, 2003 and 2002. PEF's rent expense totaled $14 million, $17 million and $16 million during 2004, 2003 and 2002, respectively. These amounts include rent expense allocated from PESC to PEF of $10 million for 2004, 2003 and 2002.

In addition, PTC has entered into capital leases for equipment. Assets recorded under capital leases totaled $2 million and $4 million at December 31, 2004 and 2003, respectively. Accumulated amortization was not significant. These assets were written down in conjunction with the impairments of PTC recorded during the third quarter of 2002 (See Note 10). PEF does not have any capital leases.

Minimum annual rental payments, excluding executory costs such as property taxes, insurance and maintenance, under long-term noncancelable leases at December 31, 2004 are:

--------------------------------------------------------------------------------------------------
                                                                      Operating Leases
                                                             -------------------------------------
                                                 Capital          Florida       Progress Energy
(in millions)                                    Leases           Progress           Florida
--------------------------------------------------------------------------------------------------
2005                                                 $ 2             $ 22                $ 11
2006                                                   2               19                   9
2007                                                   1               36                  28
2008                                                   1               37                  30
2009                                                   1               36                  29
Thereafter                                             8              170                 132
--------------------------------------------------------------------------------------------------
                                                  $   15             $320               $ 239
                                                             -------------------------------------
Less amount representing imputed interest             (5)
-----------------------------------------------------------
Present value of net minimum lease payments
  under capital lease                             $   10
--------------------------------------------------------------------------------------------------

FPC, excluding PEF, is also a lessor of land, buildings, railcars and other types of properties it owns under operating leases with various terms and expiration dates. The leased buildings and railcars are depreciated under the same terms as other buildings and railcars included in diversified business property. Minimum rentals receivable under noncancelable leases for 2005 through 2009, in millions is $31, $22, $13, $8 and $6, respectively and $16 million thereafter. Rents received under operating leases totaled $63 million, $46 million and $53 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 through 2009, in millions is $5, $1, $1, $1 and $1, respectively, 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 17). At December 31, 2004, Progress Fuels 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. Franchise Litigation

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

Arbitration in one of the cases (with the 13,000-customer City of Winter Park) was completed in February 2003. That arbitration panel issued an award in May 2003 setting the value of PEF's distribution system within the City of Winter Park (the City) at approximately $32 million, not including separation and reintegration and construction work in progress, which could add several million dollars to the award. The panel also awarded PEF approximately $11 million in stranded costs, which, according to the award, decrease over time. In September 2003, Winter Park voters passed a referendum that would authorize the City to issue bonds of up to approximately $50 million to acquire PEF's electric distribution system. While the City has not yet definitively decided whether it will acquire the system, on April 26, 2004, the City Commission voted to proceed with the acquisition. The City sought and received wholesale power supply bids and on June 24, 2004, executed a wholesale power supply contract with PEF. On May 12, 2004, the City solicited bids to operate and maintain the distribution system and awarded a contract in January 2005. The City has indicated that its goal is to begin electric operations in June 2005. On February 10, 2005, PEF filed a petition with the Florida Public Service Commission to relieve the Company of its statutory obligation to serve customers in Winter Park on June 1, 2005, or at such time when the City is able to provide retail service. At this time, whether and when there will be further proceedings regarding the City of Winter Park cannot be determined.

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

Arbitration in the remaining city's litigation (the 1,500-customer City of Edgewood) has not yet been scheduled. On February 17, 2005, the parties filed a joint motion to stay the litigation for a 90-day period during which the parties will discuss potential settlement.

A fourth city (the 7,000-customer City of Maitland) is contemplating municipalization and has indicated its intent to proceed with arbitration to determine the value of PEF's electric distribution system within the City. Maitland's franchise expires in August 2005. At this time, whether and when there will be further proceedings regarding the City of Maitland cannot be determined.

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

2. DOE Litigation

Pursuant to the Nuclear Waste Policy Act of 1982, the predecessors to PEF 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, PEF filed a complaint with 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 PEF 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 SNF are currently pending in the Court of Federal Claims.

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

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

In July 2002, Congress passed an override resolution to Nevada's veto of DOE's proposal to locate a permanent underground nuclear waste storage facility at Yucca Mountain, Nevada. In January 2003, the State of Nevada, Clark County, Nevada and the City of Las Vegas petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of the Congressional override resolution. These same parties also challenged EPA's radiation standards for Yucca Mountain. On July 9, 2004, the Court rejected the challenge to the constitutionality of the resolution approving Yucca Mountain, but ruled that the EPA was wrong to set a 10,000-year compliance period in the radiation protection standard. EPA is currently reworking the standard but has not stated when the work will be complete. DOE originally planned to submit a license application to the NRC to construct the Yucca Mountain 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. PEF cannot predict the outcome of this matter.

3. Advanced Separation Technologies (AST)

In 1996, Florida Progress sold its 80% interest in AST to Calgon Carbon Corporation (Calgon) for net proceeds of $56 million in cash. In 1998, Calgon filed a lawsuit against Florida Progress and the other selling shareholder and amended it in April 1998, alleging misstatement of AST's 1996 revenues, assets and liabilities, seeking damages and granting Calgon the right to rescind the sale. The lawsuit also accused the sellers of failing to disclose flaws in AST's manufacturing process and a lack of quality control.

All parties filed motions for summary judgment in July 2001. The summary judgment motions of Calgon and the other selling shareholder were denied in April 2002. The summary judgment motion of Florida Progress was withdrawn pending a legal challenge to portions of the report of Calgon's expert, Arthur Andersen, which had been used to oppose summary judgment. In September 2003, the United States District Court for the Western District of Pennsylvania issued final orders excluding from evidence in the case that portion of Arthur Andersen's damage analysis based on the discounted cash flow methodology of valuation. The Court did not exclude Arthur Andersen's use of the guideline publicly traded company methodology in its damage analysis. Florida Progress filed a renewed motion for summary judgment in October 2003, which is pending. Because the motion has now been outstanding for over a year, a ruling on the motion is expected at any time.

Florida Progress believes that the aggregate total of all legitimate warranty claims by customers of AST for which it is probable that Florida Progress will be responsible for under the Stock Purchase Agreement with Calgon is approximately $3 million, and accordingly, accrued $3 million in the third quarter of 1999 as an estimate of probable loss.

The Company cannot predict the outcome of this matter, but will vigorously defend against the allegations.

4. Synthetic Fuel Tax Credits

At December 31, 2003, Florida Progress, through its subsidiaries, was a majority-owner in three entities and a minority owner in three entities that own facilities that produce synthetic fuel as defined under the Internal Revenue Code (Code). In June 2004, Progress Fuels sold, in two transactions, a combined 49.8 percent partnership interest in Colona Synfuel Limited Partnership, LLLP (Colona), one of its majority owned synthetic fuel operations. The Company is now a minority owner in Colona, but continues to consolidate Colona in accordance with FASB Interpretation No. 46R. Florida Progress, through its subsidiaries, is currently a majority owner in two synthetic fuel entities and a minority owner in four synthetic fuel entities, including Colona. The production and sale of the synthetic fuel from these facilities qualifies for tax credits under

Section 29 of the Code (Section 29) if certain requirements are satisfied, including a requirement that the synthetic fuel differs significantly in chemical composition from the coal used to produce such synthetic fuel and that the fuel was produced from a facility that was placed-in-service before July 1, 1998. The amount of Section 29 credits that the Company is allowed to claim in any calendar year is limited by the amount of the Company's regular federal income tax liability. Synthetic fuel tax credit amounts allowed but not utilized are carried forward indefinitely as deferred alternative minimum tax credits. All majority-owned and minority-owned entities received private letter rulings (PLRs) from the Internal Revenue Service (IRS) with respect to their synthetic fuel operations. However, these PLR's do not address the placed-in-service date determinations. The PLRs do not limit the production on which synthetic fuel credits may be claimed. Total Section 29 credits generated to date are approximately $918 million, of which $432 million has been used to offset regular federal income tax liability and $481 million are being carried forward as deferred alternative minimum tax credits. Also $5 million has not been recognized due to the decrease in tax liability from 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 4.9 million tons of synthetic fuel and the Company recorded $127 million of Section 29 tax credits. The amount of synthetic fuel sold and tax credits recorded in 2004 was impacted by hurricane costs which reduced the Company's projected 2004 regular tax liability.

For the nine months ended September 30, 2004, the Company's synthetic fuel facilities sold 4.6 million tons of synthetic fuel, which generated an estimated $119 million of Section 29 tax credits. Due to the anticipated decrease in the Company's tax liability as a result of expenses incurred for the 2004 hurricane damage, the Company estimated that it would be able to use in 2004, or carry forward to future years, only $72 million of these
Section 29 tax credits. As a result, the Company recorded a charge of $47 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, $127 million of these Section 29 tax credits. Therefore, the Company recorded tax credits of $55 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 4.9 million tons of synthetic fuel, which generated an estimated $132 million of Section 29 tax credits. As of December 31, 2004, the Company anticipates that approximately $5 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 outcome of this matter. If the FPSC should deny PEF's petition for the recovery of storm costs in 2005, there could be a material impact on the amount of 2005 synthetic fuels production and results of operations.

IRS PROCEEDINGS

In September 2002, all of Florida Progress' majority-owned synthetic fuel entities at that time, including Colona, and two of the Company's minority 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 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 of the Code. The 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 anticipate 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 has 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 he Company's Earthco facilities is back on the normal procedural audit path of the Company's tax returns. Through December 31, 2004, based on its ownership percentage, the Company has used or carried forward $550 million of tax credits generated by Earthco facilities. If these credits were disallowed, Florida Progress' one time exposure for cash tax payments would be $64 million (excluding interest), and earnings and equity would be reduced by $550 million, excluding interest.

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

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

In management's opinion, the Company is complying with all the necessary requirements to be allowed such credits under Section 29, and, although it cannot provide certainty, it believes that it will prevail in these matters. Accordingly, while the Company has adjusted its synthetic fuel production for 2004 in response to the effects of the hurricane damage on its 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 a 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," that would address the accounting for uncertain tax positions. The FASB has indicated that the interpretation would require that uncertain tax benefits be probable of being sustained in order to record such benefits in the financial statements. The exposure draft is expected to be issued in the first quarter of 2005. The Company cannot predict what actions the FASB will take or how any such actions might ultimately affect the Company's financial position or results of operations, but such changes could have a material impact on the Company's evaluation and recognition of Section 29 tax credits.

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 of the Code. 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 $3 million. The Company received total gross proceeds of $10 million in 2004. Based on projected production and tax credit levels, the Company anticipates receiving approximately $24 million in 2005, approximately $31 million in 2006, approximately $32 million in 2007 and approximately $8 million through the second quarter of 2008. In the event that the synthetic fuel tax credits from the Colona facility are reduced, including an increase in the price of oil that could limit or eliminate synthetic fuel tax credits, the amount of proceeds realized from the sale could be significantly impacted.

IMPACT OF CRUDE OIL PRICES

Although the Internal Revenue Code Section 29 tax credit program is expected to continue through 2007, recent unprecedented and unanticipated increases in the price of oil could limit the amount of those credits or eliminate them altogether for one or more of the years following 2004. This possibility is due to a provision of Section 29 that provides that if the average wellhead price per barrel for unregulated domestic crude oil for the year (the "Annual Average Price") exceeds a certain threshold value (the "Threshold Price"), the amount of Section 29 tax credits are reduced for that year. Also, if the Annual Average Price increases high enough (the "Phase Out Price"), the Section 29 tax credits are eliminated for that year. For 2003, the Threshold Price was $50.14 per barrel and the Phase Out Price was $62.94 per barrel. The Threshold Price and the Phase Out Price are adjusted annually for inflation.

If the Annual Average Price falls between the Threshold Price and the Phase Out Price for a year, the amount by which Section 29 tax credits are reduced will depend on where the Average Annual Price falls in that continuum. For example, for 2003, if the Annual Average Price had been $56.54 per barrel, there would have been a 50% reduction in the amount of
Section 29 tax credits for that year.

The Secretary of the Treasury calculates the Annual Average Price based on the Domestic Crude Oil First Purchases Prices published by the Energy Information Agency (EIA). Because the EIA publishes its information on a three month lag, the Secretary of the Treasury finalizes its calculations three months after the year in question ends. Thus, the Annual Average Price for calendar year 2003 was published in April 2004.

Although the official notice for 2004 is not expected to be published until April of 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 it synthetic fuel business after 2004. However, if during 2005 through 2007, oil prices remain at historically high levels or increase, the Company's synthetic fuel business may be adversely affected for those years and, depending on the magnitude of such increases in oil prices, the adverse affect for those years could be material and could have an impact on the Company's results of operations and synthetic fuel production plans.

5. Other Legal Matters

Florida Progress and PEF are involved in various other claims and legal actions arising in the ordinary course of business, some of which involve claims for substantial amounts. Where appropriate, accruals have been made in accordance with SFAS No. 5, "Accounting for Contingencies," to provide for such matters. Florida Progress and PEF believe the ultimate disposition of these matters will not have a material adverse effect upon either Company's consolidated and PEF's financial position or results of operations.

22. SUBSEQUENT EVENTS

Sale of Progress Rail

On February 18, 2005, Progress Energy 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 at December 31, are as follows:

-------------------------------------------------------------------
(in millions)                                2004        2003
-------------------------------------------------------------------
Total current assets                        $ 378        $ 373
Total property, plant & equipment (net)       202          184
Total other assets                             28           64
Total current liabilities                     156          114
Total long-term liabilities                     3            3
Total capitalization                          449          504
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Cost Management Initiative

On February 28, 2005, as part of a previously announced cost management initiative, the executive officers of Progress Energy approved a workforce restructuring. The restructuring is expected to be completed in September of 2005. In addition to the workforce restructuring, the cost management initiative includes a voluntary enhanced retirement program.

In connection with the cost management initiative, the Company expects to incur one-time pre-tax charges of approximately $54 million. Approximately $9 million of that amount relates to payments for severance benefits, and will be recognized in the first quarter of 2005 and paid over time. The remaining approximately $45 million will be recognized in the second quarter of 2005 and relates primarily to post-retirement benefits that will be paid over time to those eligible employees who elect to participate in the voluntary enhanced retirement program. The total cost management initiative charges could change significantly depending upon how many eligible employees elect early retirement under the voluntary enhanced retirement program and the salary, service years and age of such employees.

23. SUPPLEMENTAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

The following supplemental unaudited information regarding the Company's oil and gas activities is presented pursuant to disclosure requirements of SFAS No. 69 "Disclosures About Oil and Gas Producing Activities."

----------------------------------------------------------------------------
(in millions)                                       2004        2003
----------------------------------------------------------------------------
Capitalized Costs -
     Proved Properties being amortized               $ 281       $ 352
     Unproved Properties not being amortized            55          60
----------------------------------------------------------------------------
                                                       336         412
Less - Accumulated depreciation, depletion,
and amortization                                       (52)        (35)
----------------------------------------------------------------------------
Net Capitalized Costs                                $ 284       $ 377
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---------------------------------------------------------------------
(in millions)                   2004        2003        2002
---------------------------------------------------------------------
  Property acquisition         $   7       $ 169        $ 141
  Development                     95         105           16
---------------------------------------------------------------------
Total Costs Incurred           $ 102       $ 274        $ 157
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