CORRESP 1 filename1.htm

September 9, 2005

VIA EDGAR

Securities and Exchange Commission
100 F Street, N.W.
Washington, D.C. 20549-0308
Attention: Mr. Jim Allegretto, Senior Assistant Chief Accountant
Division of Corporation Finance


	RE:	Progress Energy Inc. Form 10-K for the year ended December 31, 2004 Filed March 16, 2005 File No. 1-15929 Carolina Power and Light Company Form 10-K for the year ended December 31, 2004 Filed March 16, 2005 File No. 1-03382 Florida Progress Corporation Form 10-K for the year ended December 31, 2004 Filed March 16, 2005 File No. 1-08349 Florida Power Corporation Form 10-K for the year ended December 31, 2004 Filed March 16, 2005 File No. 1-03274

Dear Mr. Allegretto:

Progress Energy, Inc., a North Carolina corporation (“Progress Energy” or the “Company”), submits herewith its responses to the comments of the staff (the “Staff”) of the Securities and Exchange Commission (the “Commission”) to the above referenced filings contained in its letter to Mr. Robert McGehee of Progress Energy, dated July 27, 2005.

Set forth below are the responses of Progress Energy, Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (“CP&L” or “PEC”), Florida Progress Corporation (“Florida Progress” or “FPC”) and Florida Power Corporation d/b/a Progress Energy Florida, Inc. (“Florida Power” or “PEF”). For convenience of reference, each Staff comment is reprinted in bold, numbered to correspond with the paragraph numbers assigned in the July 27, 2005 comment letter, and is followed by the corresponding response of the respective company. Unless otherwise noted, all page references are to the pages of Progress Energy’s 2004 Form 10-K.

Comment 1

Retail Rate Matters, page 17

1. Explain to us why you have not had a rate case since 1988. In this regard, explain to us if you believe the cause and effect relationship still exists under paragraph 57 to SFAS No. 71. In particular, please specifically explain how the requirements of paragraph 5(b) with respect to PEC’s specific costs of providing service are met. Please be detailed in your response.

Response:

Progress Energy, Inc.

PEC has not had a base rate case since 1988 because PEC and its governing utilities commissions have periodically concluded that PEC’s base rates remain reasonable. Such determinations have been made each year given PEC’s then-current cost of providing service.

The Company believes it is clear that the referenced cause and effect relationship of costs and revenues stills exists. As stated in the last sentence of paragraph 57, “for an enterprise with prices regulated on the basis of its costs, allowable costs are the principal factor that influences its prices.” Specifically, Paragraph 5(b) of SFAS No. 71 requires that “rates are designed to recover the specific enterprise’s costs of providing the regulated services or products.” There is continuous review by PEC and by its governing utilities commissions as to whether such base rates are appropriate for PEC’s current cost of providing service. PEC files annual and/or quarterly surveillance reports with its commissions. These reports compare PEC’s base rate revenues with its current cost of providing service for the period of the report. In general, PEC or the utilities commissions can elect to initiate new base rate proceedings if base rates are considered to be too high or too low with regard to the current cost of providing service.

As indicated above, both PEC and its governing utilities commissions continually monitor PEC’s rates and revenues compared to its current costs of providing service, such that PEC’s current rates must be appropriate given its current allowable costs. Because PEC’s rates are continually assessed with regard to its current cost of providing service, the Company believes the paragraph 5(b) requirement is met.

Carolina Power and Light Company

See above response.

Florida Progress Corporation

Not applicable.

Florida Power Corporation

Not applicable.

Comment 2

Synthetic Fuels Tax Credits, page 24

2. Explain to us the type of synthetic fuel you produce and the IRS’s position on the synfuel tax credit including compliance with the “in service date”. Tell us whether any action has been taken by the Service to date. Advise as to whether you have recorded any allowance against the deferred tax assets or a tax cushion for benefits taken in light of the adverse IRS field auditors’ position or whether any amounts have been specifically disallowed. Finally, explain how an adverse outcome could impact your future regulatory proceedings or the market value of the CVO’s. Tell us the probability of recovery from ratepayers for any disallowed credits and the basis for your probability assessment. We may have further comment.

Response:

Progress Energy, Inc.

The Company, through its subsidiaries, produces a solid coal-based synthetic fuel that is eligible for federal income tax credits pursuant to Section 29 of the Internal Revenue Code (“Section 29”) if certain criteria are met. Qualifying synthetic fuel plants entitle their owners to federal income tax credits based on the barrel of oil equivalent of the synthetic fuel produced and sold by these plants. The Company, through its subsidiaries, indirectly owns 100% of the following four synthetic fuel limited liability companies: Solid Energy LLC, Ceredo Synfuel LLC, Solid Fuel LLC, and Sandy River Synfuel LLC (collectively referred to herein as “Earthco”). The Company also indirectly owns a cumulative total of 50.2% of Colona Synfuel Limited Partnership, LLLP (“Colona”) and 10% of New River Synfuel, LLC (equity method investment). See attached Schedule 4 which summarizes the ownership interests of the synthetic fuel entities.

During 2001, the Internal Revenue Service (“IRS”) released Revenue Procedure 2001-30 and Revenue Procedure 2001-34 that outline the conditions that must be met to receive a Private Letter Ruling (“PLR”) for Section 29 tax credits from the IRS. PLRs represent advance rulings from the IRS applying its interpretation of the tax law to an entity’s facts for a specific issue such as whether the proposed product meets the definition of a qualified fuel under Section 29. In December 2001 and January 2002, favorable PLRs were received for all four Earthco plants. These PLRs concluded, among other things, that the synthetic fuel produced by the Earthco plants resulted from a significant chemical change in the coal feedstock and therefore is a qualified fuel eligible for Section 29 tax credits. The PLRs establish the placed in service standard that a plant must meet, but do not contain a ruling on whether the Earthco plants were placed in service before July 1, 1998.

In September 2002, all four of the Earthco plants were accepted into the IRS’s Pre-Filing Agreement (“PFA”) program in lieu of the ordinary IRS audit process. The Colona plant, which was undergoing the ordinary IRS audit at the time, was subsequently accepted into the PFA Program. The PFA Program allows taxpayers to voluntarily accelerate the IRS audit process in order to seek resolution of specific issues.

In February 2004, Colona and the IRS agreed that the Colona plant was placed in service before July 1, 1998 and that the process used by Colona resulted in significant chemical change in accordance with Section 29. This concluded Colona’s participation in the PFA Program.

In July 2004, the Company was notified that the IRS field auditors anticipated taking an adverse position regarding the placed in service date of the Earthco plants. Due to the IRS field auditors’ position, the IRS exercised its right to withdraw from the PFA Program. With the IRS’s withdrawal from the PFA Program, the review of the Earthco plants was placed back on the ordinary IRS audit process.

On October 29, 2004, the Company received the IRS field auditors’ preliminary report concluding that the Earthco plants had not been placed in service before July 1, 1998, and proposing that the tax credits generated by those plants be disallowed. The Company disagrees with the field audit team’s factual findings and believes that the Earthco plants 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 currently is contesting the field auditors’ findings and the field audit team’s 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 to have this issue reviewed by the National Office of the IRS. Therefore, the Company has asked the National Office to review the issue and clarify the legal standard to be applied. 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 has complied and is complying with all the necessary requirements to qualify for Section 29 tax credits, and although it cannot provide certainty, it believes that it will prevail in these matters. The Company accounts for uncertain tax benefits in accordance with SFAS No. 5, Accounting for Contingencies (“SFAS No. 5”). Under SFAS No. 5, contingent losses are recorded when it is probable that the tax position will be disallowed and the amount of the disallowance can be reasonably estimated. Because the Company does not believe it is probable that the tax credits generated by the Earthco plants will be disallowed, no allowance or tax cushion has been recorded against the related deferred tax assets. Should the Company fail to prevail in these matters or a contingent loss otherwise becomes probable, there could be a material liability for previously used or carried forward Section 29 tax credits. A discussion of the potential impact on the Company is contained on pages 139-140 of the Company’s 2004 Form 10-K.

The Company’s Contingent Value Obligations (“CVOs”) are governed by an agreement that covers the years 2001-2007 (referred to in the agreement as “operation years”). CVO holders have the right to receive contingent payments equal to 50 percent of any net after-tax cash flow generated by the Earthco plants in excess of $80 million per year for each of the operation years. Payments on the CVOs will not be made until tax audit matters are resolved. If any of the tax credits generated by Earthco plants during the operation years are disallowed, net after-tax cash flow under the CVO agreement would be reduced by the amount of the lost income tax benefits, reducing the payments CVO holders would have otherwise received. In the event of a total disallowance of Section 29 tax credits generated by the Earthco plants, no payments would be made to holders of CVOs. A discussion of CVOs is contained on page 119 of the Company’s 2004 Form 10-K.

All of the Company’s investments in synthetic fuel plants are held in nonregulated subsidiaries, and none of the claimed credits have been reflected as a reduction of allowable costs in setting rates for the regulated subsidiaries. Therefore, a disallowance of Section 29 tax credits would not affect regulatory proceedings before any federal or state utility commission, because the Company cannot recover any disallowed Section 29 tax credits from ratepayers. Disallowances or losses from the Company’s nonregulated subsidiaries are not recoverable through the rates of the Company’s regulated utility subsidiaries.

Carolina Power and Light Company

Not applicable.

Florida Progress Corporation

See above response except that page references are to pages 90-91 of the Florida Progress Form 10-K. See Schedule 4 for applicable ownership percentages.

Florida Power Corporation

Not applicable.

Comment 3

Competitive Commercial Operations, page 24

3. Please explain to us what consideration you gave to possible impairment any of your CCO gas generation plants in light of high natural gas prices; which tend to reduce spark spreads. In particular, explain to us whether any of the CCO facilities are under long-term power contracts with similar long-term fixed price fuel arrangements. Please provide to us the results of any impairment testing performed. Supplement your response with the financial models used to estimate future cash flows. If none of the plants were tested for impairment, explain why. In this regard, we assume impairment testing would be done at the individual plant location. If otherwise, please justify. We may have further comment.

Response:

The Company’s Competitive Commercial Operations (CCO) segment is divided into three regions where it has generation plants that generate cash flow: South Florida, North Carolina and Georgia. The Company monitors events and circumstances relating to the CCO generation plants in each of these regions to determine if the criteria have been met which would require an impairment review under SFAS No. 144.

South Florida Region (DeSoto generation facility)

The Company has two combustion turbines at its DeSoto generation facility in the South Florida region. The output of these turbines is 100% contracted until May 2007 at prices that are expected to be above prevailing market prices. The contract is a tolling agreement and does not have a fixed fuel price component. The South Florida region is projected to be a robust energy market even beyond 2007, and it is expected that the Company will be able to contract the assets for several years beyond 2007 with existing parties to the current contracts or with new parties. One of the factors that has created the high demand for power generation in the South Florida region is that the market differs from other markets due to the unique geography of the transmission system and limited inter-connects to other transmission systems. This market has supply constraints since the only resources available off-system must come in through the constrained northern inter-connects.

Considering geographic factors, prevailing contract prices and other market conditions in the South Florida region, management did not believe that conditions existed during 2004 that indicated that the carrying value of the DeSoto generation facility was not recoverable. Therefore, no impairment test under SFAS No. 144 was performed.

North Carolina Region (Rowan generation facility)

The Company’s North Carolina region has three combustion turbines and a two-on-one combined cycle at its Rowan generation facility. The output of the three combustion turbines are contracted through December 2010 at prices that are expected to be above the prevailing market prices (contracts are specific to the three combustion turbines). These contracts are tolling agreements and do not have a fixed fuel price component. While the combustion turbines are 100% contracted, the combined cycle is available for market sales into North Carolina and PJM. (PJM is a regional transmission organization that operates in Pennsylvania, New Jersey and Maryland). The combined cycle generates cash flow primarily through spot market sales, mid-term structured contracts and the sale of power to the Georgia market to serve the Company’s full requirements contracts as described in the Georgia region below. Compared to other regions, the North Carolina region is a quickly growing market area with no significant over supply of generation. The PJM market also offers a robust liquid market for Rowan to sell electricity.

During 2004, management considered whether any criteria existed that would require an impairment review of the Rowan generation facility under SFAS No. 144. In contrast to other companies, which impaired uncontracted assets in the Southeast region because they classified them as assets held for sale, the Rowan generation facility has a portfolio containing combustion turbines, a combined cycle and existing contracts. In addition, the Company uses the Rowan generation facility to sell into the spot-market and to serve the Company’s load obligations of the Georgia region. Considering geographic factors, prevailing contract prices and other market conditions in the North Carolina region, management did not believe that conditions existed during 2004 that indicated that the carrying value of the Rowan generation facility was not recoverable. Therefore, no impairment test under SFAS No. 144 was performed.

Georgia Region (Washington, Walton, Effingham & Monroe generation facilities)

The Company’s Georgia region has nine combustion turbines and one combined cycle located at its Washington, Walton, Effingham and Monroe generation facilities. See the response to Comment 5 for further discussion of the Georgia region and why these plants are grouped together for goodwill impairment testing. The Company’s CCO segment has six full service, fixed price requirement contracts with 16 Georgia EMCs. (An EMC is an electrical membership cooperative). In addition, these contracts also provide for rights to EMC baseload, intermediate and peaking generation assets at primarily fixed prices. On average, these generation assets provide 55% of the Company’s Georgia region generation requirements. The remaining generation requirements are provided from the Company’s owned generation, such as from the Rowan generation facility, and the spot market. The Company’s CCO segment has further hedged 60% of the estimated gas requirements for the Company’s generation to serve the Georgia region power contracts with third parties for the remainder of such contracts.

During the first quarter of 2004, the Company performed and passed step 1 of the required annual SFAS No. 142 goodwill impairment test for its generation facilities in the Georgia region. The goodwill test utilized a discounted cash flow approach to determine the fair value of the reporting unit. Since the fair value of the reporting unit using a discounted cash flow basis exceeded its carrying value, the long-lived assets would be recoverable on an undiscounted basis and pass step 1 of a SFAS No. 144 long-lived asset impairment test. During 2004, management considered whether any criteria existed that would require an impairment review under SFAS No. 144 of the Georgia region generation facilities. Considering geographic factors, prevailing contract prices and other market conditions in the Georgia region, management did not believe that conditions existed during 2004 that indicated that the carrying value of the Georgia region generation facilities was not recoverable. Additionally, during the first quarter of 2005, the Company performed and passed step 1 of the 2005 SFAS No. 142 goodwill impairment test for the Georgia region, indicating that the entire carrying value of the assets continued to be recoverable.

Carolina Power and Light Company

Not applicable.

Florida Progress Corporation

Not applicable.

Florida Power Corporation

Not applicable.

Comment 4

Non-regulated Businesses, page 44

4. You state you are a majority owner in five of six tax credit generating entities that own facilities that produce synthetic fuel. Explain to us your consolidation policy with respect to your ownership interests in the entities and/or the facilities that produce the synfuel credits. Please also tell us the legal structure of the project and the type of synthetic fuel produced. If other than a wholly owned corporate subsidiary, tell us the identity of the owners and whether the entity is a variable interest.

Response:

Progress Energy, Inc.

The Company, through its subsidiaries, is a majority owner in five entities and a minority owner in one entity that own facilities that produce a solid coal-based synthetic fuel. The Company’s ownership interests in these six entities and the identity and ownership interests of the other owners are summarized on Schedule 4.

The Company consolidates the five entities for which it owns a majority of the voting interests. The Company uses the equity method of accounting to account for the one entity in which it owns a 10% minority interest. The Company performed a qualitative analysis of these entities in accordance with FIN 46R, Consolidation of Variable Interest Entities (“FIN No. 46R”). The qualitative analysis demonstrated that if the six entities were considered variable interest entities, the expected losses would be allocated to the equity holders in accordance with their pro-rata equity ownership interests. Therefore, the Company’s accounting for these entities did not change with the adoption of FIN No. 46R.

Carolina Power and Light Company

Not applicable.

Florida Progress Corporation

Florida Progress, through its subsidiaries, owns 33.2% of Colona. Progress Energy Ventures, Inc. (“Progress Ventures”) owns 17% of Colona, for a total Progress Energy ownership of 50.2%. Progress Energy’s ownership interests in Colona and the ownership interests of the other owners are summarized on Schedule 4. Progress Energy performed a qualitative analysis of Colona under FIN No. 46R, which indicated that Colona was a variable interest entity and that a wholly-owned subsidiary of Florida Progress was the primary beneficiary. Therefore, Florida Progress consolidates Colona in its consolidated financial statements in accordance with FIN No. 46R.

Florida Power Corporation

Not applicable.

Comment 5

Goodwill, page 59

5. We note that during 2002, you completed the acquisition of Walton County Power, LLC and Washington County Power, LLC which resulted in goodwill of $64 million and was included in the CCO segment. Please explain in detail why this acquisition was accounted for as a business combination as opposed to an asset acquisition. In addition, tell us what constitutes a reporting unit for your annual goodwill impairment test of the CCO segment. If your reporting unit for the CCO segment is one level below the operating segment, then provide us a summary of your goodwill impairment testing for the acquired projects since it appears the purchase of such projects resulted in the creation of the CCO segment’s goodwill.

Response:

Business combination versus asset acquisition

In February 2002, Progress Ventures completed the acquisition of Walton County Power, LLC (“Walton”) and Washington County Power, LLC (“Washington”) from Louisville Gas & Electric. Pursuant to SFAS No. 141 paragraph 9, SFAS No. 142 paragraph 9, and EITF 98-3, the Company accounted for the acquisition of Walton as a business combination and Washington as an asset acquisition.

The Walton generation facility was fully operational when the acquisition closed, with a self-sustaining integrated set of activities and assets that was conducted and managed for the purposes of providing a return to investors, including inputs, process and customer tolling agreements. Therefore, the Company believes it was appropriate to account for the Walton portion of the acquisition as a business combination pursuant to SFAS No. 141 paragraph 9 and EITF 98-3. The Washington generation facility, however was not fully operational when the acquisition closed. Although the Washington generation facility had various permits and licenses, equipment commitment contracts and existing equipment assets, construction on the plant itself had not yet been completed. In addition, the tolling and purchase power agreement for the Washington generation facility did not commence until plant completion. Therefore, the Company deemed that the Washington generation facility did not have all of the business processes required to meet the definition of a business and therefore accounted for the Washington portion of the acquisition as an asset acquisition pursuant to SFAS No. 142 paragraph 9 and EITF 98-3.

Reporting unit for annual goodwill testing

SFAS No. 142 paragraph 30 defines a reporting unit as an operating segment (defined under SFAS No. 131) or one level below an operating segment (referred to as a component). A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and management of the operating segment regularly reviews the operating results of that component. Two or more components of an operating segment shall be aggregated and deemed a single reporting unit if the components have similar economic characteristics.

SFAS No. 142 paragraph 34 requires that for purposes of testing goodwill for impairment, all goodwill acquired in a business combination shall be assigned to one or more reporting units as of the acquisition date. Goodwill shall be assigned to reporting units of the acquiring entity that are expected to benefit from the synergies of the combination even though other assets or liabilities of the acquired entity may not be assigned to that reporting unit.

Pursuant to SFAS No. 142, the Company groups the generation facilities in its Georgia region (Walton, Washington, Effingham and Monroe) as the reporting unit for goodwill impairment testing purposes because the cash flow benefits from the Georgia region are derived from all four Georgia generation facilities together. More specifically, providing system requirements instead of plant specific tolling agreements creates system cash flow. The most significant synergy anticipated while acquiring the Walton and Washington generation facilities was the benefit of creating the Georgia region. Coupled with the Company’s other Georgia generation facilities, Monroe and Effingham, the Company offers full service requirements contracts instead of plant specific tolling agreements. This strategy has been implemented as the original tolling agreements for the Monroe and Effingham generation facilities have expired. The business operates and schedules energy consistent with the described strategy. The Georgia control area views CCO as a single schedule entity. Pursuant to the SFAS No. 142 concept that goodwill is to be assigned to reporting units consistent with the expected benefit of the combination, the Company determined that it was appropriate that the goodwill be assigned to the Georgia region.

The Company’s testing of the goodwill within the Georgia region is one level below the CCO operating segment level, which also includes the results from its other two regions, South Florida (the Desoto generation facility) and North Carolina (the Rowan generation facility), which have separate financial information.

Carolina Power and Light Company

Not applicable.

Florida Progress Corporation

Not applicable.

Florida Power Corporation

Not applicable.

Comment 6

Consolidated Statement of Cash Flows, page 86

6. Explain to us what comprises other operating cash flows totaling $167 million for the year ended December 31, 2004. In this regard, it appears the majority of the amount is unrelated to PEC or PEF. Please ensure your description addresses the nature, amount and entity.

Response:

Progress Energy, Inc.

The Company has provided a schedule of the composition of other operating cash flows for the year ended December 31, 2004 as Schedule 6. As requested, the schedule addresses the nature, amount and entity for the items included in the other classification. The Company has subsequently identified several miscellaneous items that should be reclassified to several other line items within the category that totals to net cash provided by operating activities. The total of these reclassified items appears on Schedule 6. The Company believes these reclassifications within net cash provided by operating activities are immaterial both individually and in aggregate, and will reclassify these items as appropriate in future filings.

Carolina Power and Light Company

See above response.

Florida Progress Corporation

See above response.

Florida Power Corporation

See above response.

Comment 7

Note 1. Organization and Summary of Significant Accounting Policies
B. Basis of Presentation, page 88

7. Explain to us in detail why you have not provided any of the disclosure required by SFAS No. 115 with respect to investments held by your nuclear decommissioning trust. We may have further comment.

Response:

Progress Energy, Inc.

The Company has reviewed the requirements of SFAS No. 115 and does not consider them meaningful as related to the investments held by the nuclear decommissioning trust. The SFAS No. 115 disclosures are primarily oriented toward situations where shareholders benefit from or are harmed by investment results, which is not the case with the investments held by the Company’s nuclear decommissioning trust.

In accordance with the regulatory treatment prescribed by PEC’s and PEF’s regulators, the investment results of nuclear decommissioning trusts are effectively passed through to ratepayers as part of charges to the ratepayers for nuclear decommissioning costs. Investment gains and losses are factored into how much ratepayers must pay over time for decommissioning costs. Therefore, shareholders are not affected by such gains and losses. Unrealized gains on trust investments are included in the Company’s regulatory liabilities and disclosed in the regulatory asset/liability table in Note 8A, line entitled “net nuclear decommissioning treat unrealized gains.” Realized gains and losses are included in the determination of the “deferred impact of ARO” line items in that same regulatory asset/liability table. Therefore, the Company concluded that the disclosures pursuant to SFAS No. 115 were not meaningful as related to investments held by the nuclear decommissioning trust.

Carolina Power and Light Company

See above response. The corresponding referenced regulatory asset/liability note is Note 6A.

Florida Progress Corporation

See above response. The corresponding referenced regulatory asset/liability note is Note 8A.

Florida Power Corporation

See above response. The corresponding referenced regulatory asset/liability note is Note 8A.

Comment 8

Note 4. Divestitures, page 95

8. Provide to us the calculations you performed to determine that the sale of your gas producing properties significantly altered the ongoing relationship between capitalized costs and remaining proved reserves. Furthermore, describe the allocation method used to allocate costs between reserves sold and reserves retained. If you utilize relative fair value, explain to us how the fair value was calculated. Lastly, provide us the details of the calculation of the $56 million gain.

Response:

Progress Energy, Inc.

The Company, through its subsidiary, Progress Fuels Corporation (“PFC”) sold a portion of its natural gas reserves which were known as the North Texas Operations (“NTX”) for net proceeds of $240 million on December 17, 2004.

PFC uses the full cost method to account for its natural gas and oil properties. Under the full cost method as described by the Commission in Reg. S-X Rule 4-10, oil and gas properties are generally required to be combined into a common pool on a country by country basis resulting in each property losing its separate identity. Therefore, sales of properties within a pool are treated as adjustments of capitalized costs, and gains and losses are not recognized unless certain criteria are met as required by Reg. S-X Rule 4-10(c)(6)(i), which provides:

“Sales shall be accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proven reserves of oil and gas attributable to a cost center. For instance, a significant alteration would not ordinarily be expected to occur for salesinvolving less than 25% of the reserve quantities of a given cost center.”

The sale of the NTX reserves represented a sale of 38% of the pooled reserves of PFC. Based on the Company’s calculations, the deferral of a $67 million pretax gain would change the depreciation, depletion and amortization (DD&A) rate from $1.31/mcfe to $1.00/mcfe, a change of 24%. Since deferral of the gain on this transaction would significantly alter the DD&A rate pursuant to Rule 4-10, the Company recognized the gain.

The Company noted that the difference between the $67 million pretax gain mentioned in the paragraph above and the reported pretax gain of $56 million is $11 million of losses on hedging transactions designated internally against the reserves subject to this transaction.

Allocation of Basis and Calculation of the Gain

The determination of the book value that should be used in the gain calculation is governed by Reg S-X Rule 4-10 paragraph 6, which provides:

“If a gain or loss is recognized on the sale, total capitalized costs within the cost center shall be allocated between the reserves sold and reserves retained on the same basis used to compute amortization, unless there are substantial economic differences between the properties sold and those retained, in which case capitalized costs shall be allocated on the basis of the relative fair values of the properties.”

Pursuant to Reg S-X Rule 4-10, fair value is the appropriate method to use to allocate basis if there is substantial economic differences in the properties sold versus those retained. There were substantial economic differences between the NTX reserves and the East Texas (“ETX”) reserves that the Company retained. NTX was primarily horizontal drilling versus vertical drilling in ETX; horizontal drilling is more expensive to drill per well. It was also more expensive to operate the wells in NTX due to pipeline constraints in the Barnett Shale, CO2 problems that led to major repair expense and new rules and regulations for salt water disposal.

Based on the above guidance, the Company concluded that there were substantial differences in the properties sold versus retained and that it was appropriate to compute the gain to be recognized using the fair value allocation method. The relative fair values were determined using the NTX offer as the best evidence of fair value for the proven reserves sold and dividing by the fair value of all proven reserves held before the sale based on the most recent reserve study at the time, dated July 1, 2004. Based on this calculation, 38% of the book value of the total capitalized costs was allocated to the NTX assets which were sold calculating a basis of $174 million. Based on net proceeds of $240 million, this method resulted in a pretax gain of $56 million after including the pretax hedge losses of $11 million mentioned above and other miscellaneous adjustments.

Carolina Power and Light Company

Not applicable.

Florida Progress Corporation

See above response.

Florida Power Corporation

Not applicable.

Comment 9

Note 8. Regulatory Matters
Asset Retirement Obligations, page 101.

9. Explain in detail why you increase accumulated depreciation by $345 million. Please specifically explain how the reduction of estimated removal costs resulted from the depreciation studies in 2004. Please also provide us the accounting entries that were made and the rationale for such entries.

Response:

Progress Energy, Inc.

Upon adoption of SFAS No. 143 as of January 1, 2003, PEC estimated the amount of removal costs previously collected in rates for which the Company did not have a legal retirement obligation. These removal costs were previously included in the accumulated depreciation reserve, and as of January 1, 2003, were reclassified to a regulatory liability. This treatment was in accordance with SFAS No. 143, paragraphs 20 and B73.

During 2003, PEC engaged a third-party consultant to perform a depreciation study, which is common in the utility industry. As an integral part of that study, the consultant reallocated the components of the accumulated depreciation reserve, including the removal cost component, based on a comprehensive review of PEC’s historical property activity and PEC’s existing depreciation parameters. The study was completed in 2004 and filed with PEC’s utility commissions. As a result of the study, the Company reduced its estimate of removal costs for financial reporting purposes by $345 million. Therefore, the removal cost component was reduced by $345 million. This adjustment was recorded as a debit to regulatory liabilities and a credit to accumulated depreciation, and was accounted for as a change in accounting estimate.

Carolina Power and Light Company

See above response.

Florida Progress Corporation

Not applicable.

Florida Power Corporation

Not applicable.

Comment 10

Energy Delivery Capitalization Practice, page 101

10. Explain to us the changed methodology used to conclude that a revision to the amount of work capitalized was required. Also, confirm to us that your capitalization policies are consistent among each utility. Furthermore, tell us the extent to which your external auditors had any concerns related to amounts that were previously capitalized in your historical financial statements. In this regard, we presume the methodology to previously calculated non-capitalizable costs was used in your last rate case while the new method will be used in your next rate case. Please advise if our understanding is not correct.

Response:

Progress Energy, Inc.

Effective January 1, 2005, the Company implemented a revised methodology for the way PEC and PEF estimate the allocation of outage and emergency costs not associated with major storms as either capital or expense. The changed methodology resulted from reviews by Company personnel and a third party consultant of the capitalization practices of PEC’s and PEF’s Energy Delivery units that intended to identify potential operating efficiencies and ensure consistency among these units. Those reviews recommended revisions in the areas of outage and emergency work not associated with major storms and allocation of indirect costs. Specifically, it was recommended that PEC’s and PEF’s Energy Delivery units revise the way that they estimate the allocation of costs associated with such work as either capital or expense. The recommended methodology included more detailed classification of outage and emergency work between repair and replacement activities and between outage work and corrective maintenance work. The recommended methodology also included retesting of accounting estimates on an annual basis.

The Company implemented the recommended methodology prospectively at each of its utilities effective January 1, 2005. Prior to implementation, the Company’s utilities informed the applicable state utility commissions of the change in capitalization practices and also reviewed them with Deloitte & Touche (“D&T”), the Company’s independent registered public accountants. In accordance with SFAS No. 71, management concluded that no adjustments to prior year financial statements were necessary. Based on D&T’s review of the Company's actions and the audit procedures D&T performed, D&T’s local and national offices concurred with the Company’s prospective application of the new methodology and with its treatment of historical amounts.

The Company confirms to the staff that its capitalization policies are materially consistent among each utility except where state regulatory requirements may differ. The Company also confirms as correct your understanding that the methodology previously used to calculate non-capitalizable costs was used by the utilities in their recent regulatory filings and proceedings. The new methodology is being used in all regulatory filings and proceedings after January 1, 2005.

Carolina Power and Light Company

See above response.

Florida Progress Corporation

See above response.

Florida Power Corporation

See above response.

Comment 11

Note 17. Benefit Plans — A. Post Retirement Benefits, page 120

11. Tell us the method and length of time over which you are amortizing the gain associated with the adoption of FSP 106-2. In this regard, explain how you determine the average remaining service period of active participants and correlate that period to the reduction in pension expense relative to the decrease in the benefit obligation.

Response:

Progress Energy, Inc.

The gain associated with the adoption of FSP 106-2 is not subject to standalone amortization. Instead, the gain is considered an actuarial gain that is added to the pool of unrecognized net gain or loss in accordance with paragraph 14 of FSP 106-2. Under SFAS No. 106, a portion of the pool of unrecognized net gain or loss is amortized into net periodic cost when the amount of the pool exceeds a specified corridor amount (see SFAS No. 106 paragraph 59).

In 2004, the unrecognized net loss for Progress Energy’s non-union plan did exceed the specified corridor, and the applicable loss amount was amortized based on 11.7 years, the average remaining service period of active participants. In 2004, the unrecognized net gain for Progress Energy’s union plan did not exceed the specified corridor and, therefore, there was no amortization.

The average remaining service period of active participants is determined as of the beginning of the applicable year, based on the expected end of service life due to retirement or death while in service. The expected dates for retirement and death while in service are determined based on actuarial tables used in the SFAS No. 106 actuarial studies.

Carolina Power and Light Company

See Note 12 and the above response (except that PEC does not have union employees).

Florida Progress Corporation

See Note 15 and the above response.

Florida Power Corporation

See Note 15 and the above response.

Comment 12

Note 21. Other Income and Other Expense, page 128

12. Please explain to us what comprises non-regulated energy and delivery services income and expense, and why you believe it is appropriate to include such amounts in other income and expense as opposed to diversified business expense.

Response:

Progress Energy, Inc.

As discussed in the last paragraph of Note 21, 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. These ancillary services are immaterial to consolidated operating revenues or consolidated operating expense and are provided by PEC and PEF, the Company’s two regulated utilities, but are not recoverable through base rates or included in PEC and PEF’s surveillance reporting to state regulators. Because these services do not relate to providing power to customers under regulated rate structures, which is the primary business environment for PEC and PEF, the Company believes they are most appropriately presented as other income and expense as opposed to diversified business expense. The gross revenues and expenses related to these ancillary services are disclosed in Note 21.

Diversified business revenues and expenses represent the operating activities of the Company’s consolidated non-utility, nonregulated operations, which are primarily the CCO, Fuels and Rail operating segments. These operations are separate and distinct businesses from the Company’s regulated utilities.

Carolina Power and Light Company

See above response, except that the reference is to PEC’s Note 16.

Florida Progress Corporation

See above response, except that the reference is to FPC’s Note 19.

Florida Power Corporation

See above response, except that the reference is to PEF’s Note 19.

Comment 13

Carolina Power and Light Company Financial Statements

13. Please address the above comments, as applicable.

Response:

The response of PEC to other numbered comments are, as applicable, contained within the responses to each comment.

Comment 14

Note 4.C Joint Ownership of Generating Facilities, page 155

14. Please tell us why you have not reflected the SFAS No. 90 disallowances on the Harris Plant in your SAB 10:C disclosure.

Response:

Carolina Power and Light Company

The SFAS No. 90 disallowances on the Harris Plant are not included in PEC’s SAB 10:C disclosure due to the nature of the applicable disclosure, which is providing information about jointly-owned plants. Those disallowances are only applicable to PEC’s ownership portion of the plant. Therefore, PEC believes excluding the disallowances from the tabular information allows the reader to approximate the amount of the joint owner’s investment in the plant.

Florida Progress Corporation

Not applicable.

Florida Power Corporation

Not applicable.

Comment 15

Schedule II. Page 182

15. Please explain the nature of the “Fossil dismantlement reserve”. To the extent it represents amounts expensed due to collection in rates of an amount for closure costs of fossil fuel generating units, explain why it has not been classified as a regulatory liability pursuant to B73 of SFAS No. 143. Similarly, tell us the nature and classification of the “Nuclear refueling outage reserve”.

Response:

Progress Energy, Inc.

The Company does not believe the inclusion of these two regulatory liabilities in Schedule II is required, however, the Company has included them in Schedule II to provide enhanced disclosures. The nature of these two regulatory liabilities is as follows:

The “Fossil dismantlement reserve” shown in Schedule II, page 182, represents amounts collected in rates by PEF for the potential future closure of PEF’s fossil plants. The amount has been classified as a regulatory liability as discussed in the third paragraph on page 101, Note 6D and is included in the Non-ARO cost of removal line in the table of regulatory liabilities on page 104.

The “Nuclear refueling outage reserve” is made pursuant to a Florida Public Service Commission regulatory order to accrue for nuclear outage costs in advance of scheduled outages, which occur every two years. This reserve is recorded as a regulatory liability and is part of the “Other” line in the table of regulatory liabilities on page 104.

Carolina Power and Light Company

Not applicable.

Florida Progress Corporation

See above response, except that the references are to FPC’s Schedule II on page 98 and FPC’s Notes 6D and 8A (page 59 and page 62, respectively).

Florida Power Corporation

See above response, except that the references are to PEF’s Schedule II on page 99 and PEF’s Notes 6D and 8A (page 59 and page 62, respectively).

Comment 16

Florida Power Corporation Inc. Form 10-K for the Year Ended December 31, 2004

16. Please address the above comments, as applicable.

Response:

The response of PEF to other numbered comments are, as applicable, contained within the responses to each comment.

Comment 17

Consolidated Statements of Income, page 39

17. Explain to us what comprises other diversified operating expenses of $134 million for the year ended December 31, 2004. Contrast the composition of this line item to what is included in the same category for Progress Energy, Inc.

Response:

Progress Energy, Inc.

The Company has provided a schedule explaining the composition of other diversified business operating expenses for the year ended December 31, 2004, as Schedule 17. Such expenses are primarily selling, general and administrative expenses.

Carolina Power and Light Company

Not applicable.

Florida Progress Corporation

See above response.

Florida Power Corporation

Not applicable.

Comment 18

Consolidated Balance Sheets, page 40

18. Tell us whether there are any restrictions on the use of customer deposits that were received in cash and totaled $135 million as of December 31, 2004. If so, note the requirements of Rule 5-02.1 of Regulation S-X.

Response:

Florida Progress Corporation

See above response.

Florida Power Corporation

There are no restrictions on the use of customer deposits that totaled $135 million as of December 31, 2004.

Comment 19

Florida Progress Corporation Form 10-K for the Year Ended December 31, 2004

19. Please address the above comments, as applicable.

Response:

The response of FPC to other numbered comments are, as applicable, contained within the responses to each comment.

_________________

In connection with our response, each of Progress Energy, Inc.; Carolina Power and Light Company; Florida Progress Corporation and Florida Power Corporation acknowledge that:

(1) It is responsible for the adequacy and accuracy of the disclosure in its filings;

(2) Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and

(3) It may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

The Company will send a copy of this response to you and to Robert Babula by overnight delivery. Please direct any further questions or comments you may have regarding this filing to David Fountain at (919) 546-6164.


	Sincerely, /s/ Jeffrey M. Stone Jeffrey M. Stone Chief Accounting Officer & Controller Progress Energy, Inc.

Enclosures

cc:	Mr. Robert B. McGehee Mr. Geoffrey S. Chatas John R. McArthur, Esq. Frank A. Schiller, Esq. Timothy S. Goettel, Esq.

Schedule 4
Ownership of Synthetic Fuel Entities

	Legal Name of Entity	Legal Structure of Entity	Type of Synthetic Fuel Produced	% of Ownership Interests Held by PGN and Affiliates	PGN Method of Accounting	Lowest Level PGN Registrant Consolidating the Entity	Other Equity Interest Holders (Non-PGN Affiliates)
1 2 3 4 5 6	Solid Energy LLC Ceredo Synfuel LLC Solid Fuel LLC Sandy River Synfuel LLC Colona Synfuel Limited Partnership, LLLP New River Synfuel LLC	Limited Liability Company Limited Liability Company Limited Liability Company Limited Liability Company Limited Liability Limited Partnership Limited Liability Company	Solid coal-based synthetic fuel Solid coal-based synthetic fuel Solid coal-based synthetic fuel Solid coal-based synthetic fuel Solid coal-based synthetic fuel Solid coal-based synthetic fuel	100.0% 100.0% 100.0% 100.0% 50.2% 10%	Consolidation Consolidation Consolidation Consolidation Consolidation Equity method	Florida Progress Corporation Florida Progress Corporation Progress Energy, Inc. Progress Energy, Inc. Florida Progress Corporation None	None None None None 49.8% owned by third parties 90% owned by third parties

Schedule 6
Progress Energy, Inc.
Detail of Other Operating Cash Flows
For the year ended December 31, 2004
(in millions)

	*Progress Energy Florida		*Florida Progress Corporation		Progress Energy Carolinas, Inc.		Progress Energy Ventures, Inc.		All Other Non-Registrant Legal Entities (including Eliminations)		Progress Energy, Inc. Consolidated
Reserves (bad debt, inventory, etc.)	$ 6		$ 6		$ 20		$ -		$ -		$ 26
Pension-related transactions	(11	)	(13	)	3		1		27		18
ESOP share allocation	-		-		19		-		(5	)	14
Changes in noncurrent accrued liabilities	7		13		-		(1	)	7		19
AFUDC equity	(7	)	(7	)	(4	)	-		-		(11	)
Changes in derivative accounts	-		-		-		3		6		9
Net insurance proceeds	8		8		-		-		-		8
Changes in regulatory assets and liabilities	-		-		10		-		(10	)	-
Equity in earnings of minority interests	-		(5	)	-		(7	)	5		(7	)
(Gain) loss on sale of assets	(1	)	-		(10	)	13		(2	)	1
Miscellaneous adjustments to reconcile to net income	7		5		(3	)	-		10		12
Other	1		4		5		-		(5	)	4
**Reclassifications	18		30		10		25		9		74

Total Other Operating	$ 28		$ 41		$ 50		$ 34		$ 42		$ 167

* PEF is a wholly owned subsidiary of FPC, the operations of which have been consolidated into the FPC registrant.

** Sum of miscellaneous items to be prospectively reclassified to other line items within Cash Provided by Operating Activities.

Schedule 17
Progress Energy, Inc.
Detail of Other Diversified Business Operating Expenses
For the Year Ended December 31, 2004

(in millions)	Florida Progress Corporation	Progress Energy, Inc.

Compensation and related costs	$ 70	$ 86
Professional and outside services	31	39
Infrastructure and facilities	20	30
SRS litigation settlement	-	43
Other expenses	13	20

Total other diversified business operating expenses	$134	$218