UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2005

OR

[  ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to ____________ .

Commission File Number	Exact name of registrants as specified in their charters, state of incorporation, address of principal executive offices, and telephone number	I.R.S. Employer  Identification      Number
1-15929                                  1-3382                                          1-3274	Progress Energy, Inc.      410 South Wilmington Street   Raleigh, North Carolina 27601-1748       Telephone: (919) 546-6111 State of Incorporation: North Carolina     Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.      410 South Wilmington Street   Raleigh, North Carolina 27601-1748       Telephone: (919) 546-6111 State of Incorporation: North Carolina       Florida Power Corporation  d/b/a Progress Energy Florida, Inc.           100 Central Avenue     St. Petersburg, Florida 33701        Telephone (727) 820-5151    State of Incorporation: Florida	56-2155481 56-0165465 59-0247770

None

(Former Name or Former Address, if Changed Since Last Report)

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No     

Indicate by check mark whether each registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Progress Energy, Inc. (Progress Energy)
Carolina Power & Light Company (PEC)
Florida Power Corporation (PEF) Yes (X)
Yes (   )
Yes (   ) No (   )
No (X)
No (X)

Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes      No X


Indicate the number of shares outstanding of each registrants’ classes of common stock, as of the latest practicable date. As of October 31, 2005, each registrant had the following shares of common stock outstanding:

Registrant	Description	Shares
Progress Energy PEC PEF	Common Stock (Without Par Value) Common Stock (Without Par Value) Common Stock (Without par value)	251,662,294 159,608,055 (all of which were held directly by Progress Energy, Inc.) 100 (all of which were held indirectly by Progress Energy, Inc.)

This combined Form 10-Q is filed separately by three registrants: Progress Energy, PEC and PEF. Information contained herein relating to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other registrants.

PEF meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format.

PROGRESS ENERGY, INC., PROGRESS ENERGY CAROLINAS, INC.
AND PROGRESS ENERGY FLORIDA, INC.
FORM 10-Q – For the Quarter Ended September 30, 2005

Glossary of Terms

Safe Harbor for Forward-Looking Statements

PART I.

Item 1.

         

         
         
         
         

         
         
         
         
         

         
         
         
         
         

         
         
         

Item 2.

Item 3.

Item 4.

PART II.

Item 1.

Item 2.

Item 6.

Signatures


FINANCIAL INFORMATION

Financial Statements

   Interim Financial Statements:

   Progress Energy, Inc.
   Consolidated Statements of Income
   Consolidated Balance Sheets
   Consolidated Statements of Cash Flows

   Carolina Power & Light Company
   d/b/a Progress Energy Carolinas, Inc. (PEC)
   Consolidated Statements of Income
   Consolidated Balance Sheets
   Consolidated Statements of Cash Flows

   Florida Power Corporation
   d/b/a Progress Energy Florida, Inc. (PEF)
   Statements of Income
   Balance Sheets
   Statements of Cash Flows

Combined Notes to Interim Financial Statements for Progress Energy, Inc., Carolina Power &
Light Company d/b/a Progress Energy Carolinas, Inc. and Florida Power Corporation d/b/a
Progress Energy Florida, Inc.

Management's Discussion and Analysis of Financial Condition and Results of Operations

Quantitative and Qualitative Disclosures about Market Risk

Controls and Procedures

OTHER INFORMATION

Legal Proceedings

Unregistered Sales of Equity Securities and Use of Proceeds

Exhibits

 

GLOSSARY OF TERMS

We use the words “Progress Energy”, “our”, “we” or “us” with respect to certain information to indicate that such information relates to Progress Energy, Inc. and its subsidiaries on a consolidated basis. When appropriate, the parent holding company or the subsidiaries of Progress Energy are identified specifically as we discuss their various business activities.

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

TERM

DEFINITION

401(k) AFUDC the Agreement APB ARO the Average Annual Price                              Base Rate Settlement                              Belleair Bcf Btu CAIR CAMR CCO CERCLA or Superfund                              the Code Colona Corporate Corporate and Other                              CR3 CVO DMT DOE DWM                              Earthco ECRC EIA EITF EMCs EPA EPA of 1992 EPACT FASB FDEP FERC FIN No. 45                                                           FIN No. 46R                              Florida Progress FPSC Fuels Funding Corp.                              GAAP Global IRS Jackson LIBOR MACT Medicare Act MGP MW MWh Moody's NCNG NSR NCUC NEIL Norfolk Southern the Notes Guarantee NOx NOx SIP Call                              NRC Nuclear Waste Act NYMEX OCI O&M OPEB the Parent PEC                              PEC Electric                              PEF PESC PFA the Phase Out Price                              PLR Preferred Securities                              the Preferred Securities    Guarantee Progress Energy Progress Registrants                              Progress Fuels Progress Fuels   Subsidiaries Progress Rail Progress Ventures                                                           PRP PSSP PTC PT LLC PUHCA PVI                              Rail Services RBCA or Global RBCA RCA ROE SCPSC SEC Section 29 S&P SFAS SFAS No. 5                              SFAS No. 71                              SFAS No. 109                              SFAS No. 123R                              SFAS No. 131                              SFAS No. 133                              SFAS No. 138                                                           SFAS No. 143                              SFAS No. 148                                                           Smokestacks Act SO2           SRS STB Subordinated Notes                              the Threshold Price                              the Trust the Utilities Winter Park

Progress Energy 401(k) Savings and Stock Ownership Plan Allowance for funds used during construction Stipulation and Settlement Agreement related to retail rate matters Accounting Principles Board Asset retirement obligation Average wellhead price per barrel for unregulated domestic crude oil for the year Settlement reached with the FPSC on September 7, 2005 on PEF's base rate proceeding Town of Belleair, Florida Billion cubic feet British thermal unit Clean Air Interstate Rule Clean Air Mercury Rule Competitive Commercial Operations business segment Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended Internal Revenue Code Colona Synfuel Limited Partnership, LLLP Collectively, the Parent, PESC and consolidation entities Corporate and Other segment includes Corporate as well as other nonregulated business areas Crystal River Unit No. 3 Contingent value obligation Dynegy Marketing and Trade United States Department of Energy North Carolina Department of Environment and Natural Resources, Division of Waste Management Four wholly owned synthetic fuel limited liability companies Environmental Cost Recovery Clause Energy Information Agency Emerging Issues Task Force Electric Membership Cooperatives United States Environmental Protection Agency Energy Policy Act of 1992 Energy Policy Act of 2005 Financial Accounting Standards Board Florida Department of Environment and Protection Federal Energy Regulatory Commission Financial Accounting Standards Board (FASB) Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" FASB Interpretation No. 46R, "Consolidation of Variable Interest Entities - an Interpretation of ARB No. 51" Florida Progress Corporation, one of our wholly owned subsidiaries Florida Public Service Commission Fuels business segment Florida Progress Funding Corporation, a wholly owned subsidiary of Florida Progress Accounting principles generally accepted in the United States of America U.S. Global LLC Internal Revenue Service Jackson Electric Membership Corporation London Inter Bank Offering Rate Maximum Achievable Control Technology Medicare Prescription Drug, Improvement and Modernization Act of 2003 Manufactured Gas Plant Megawatt Megawatt-hour Moody's Investor Services North Carolina Natural Gas Corporation New Source Review requirements by EPA North Carolina Utilities Commission Nuclear Electric Insurance Limited Norfolk Southern Railway Company Florida Progress' full and unconditional guarantee of the Subordinated Notes Nitrogen Oxide EPA rule which requires 22 states including North Carolina and South Carolina (but excluding Florida) to further reduce nitrogen oxide emissions. United States Nuclear Regulatory Commission Nuclear Waste Policy Act of 1982 New York Mercantile Exchange Other comprehensive income as defined by GAAP Operation and maintenance expense Postretirement benefits other than pensions Progress Energy, Inc. holding company on an unconsolidated basis Progress Energy Carolinas, Inc., formerly referred to as Carolina Power & Light Company PEC Electric business segment made up of the utility operations and excludes immaterial operations of PEC's nonregulated subsidiaries Progress Energy Florida, formerly referred to as Florida Power Corporation Progress Energy Service Company, LLC IRS Prefiling Agreement Price per barrel of unregulated domestic crude oil at which Section 29 tax credits are fully eliminated Private Letter Ruling 7.10% Cumulative Quarterly Income Preferred Securities due 2039, Series A issued by the Trust Florida Progress' guarantee of all distributions related to the Preferred Securities Progress Energy, Inc. and subsidiaries on a consolidated basis The individual reporting registrants within the Progress Energy consolidated group. Collectively, Progress Energy, Inc., PEC and PEF Progress Fuels Corporation, formerly Electric Fuels Corporation Progress Fuels subsidiaries that purchased Earthco synthetic fuel facilities Progress Rail Services Corporation Business unit of Progress Energy primarily made up of nonregulated energy generation and marketing activities, as well as gas, coal and synthetic fuel operations Potentially responsible party, as defined in CERCLA Performance Share Sub-Plan Progress Telecommunications Corporation Progress Telecom, LLC Public Utility Holding Company Act of 1935, as amended Progress Energy Ventures, Inc. (formerly referred to as Progress Ventures, Inc.) Rail Services business segment Risk-based corrective action Revolving credit agreement Return on Equity Public Service Commission of South Carolina United States Securities and Exchange Commission Section 29 of the Internal Revenue Service Code Standard & Poor's, a division of The McGraw-Hill Companies, Inc. Statement of Financial Accounting Standards Statement of Financial Accounting Standards No. 5, "Accounting for Contingencies" Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" Statement of Financial Accounting Standards No. 123R, "Accounting for Stock-Based Compensation" Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information" Statement of Financial Accounting Standards No. 133, "Accounting for Derivative and Hedging Activities" Statement of Financial Accounting Standards No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - An Amendment of FASB Statement No. 133" Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" Statement of Financial Accounting Standards No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - An Amendment of FASB Statement No. 123" North Carolina Clean Smokestacks Act enacted in June 2002 Sulfur dioxide 1 Strategic Resource Solutions Corp. Surface Transportation Board 7.10% Junior Subordinated Deferrable Interest Notes due 2039 issued by Funding Corp. Price per barrel of unregulated domestic crude oil at which Section 29 tax credits are reduced FPC Capital I, a wholly owned subsidiary of Florida Progress Collectively, PEC and PEF City of Winter Park, Florida

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

In this combined report, the Progress Registrants make forward-looking statements within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The matters discussed throughout this combined Form 10-Q that are not historical facts are forward-looking and, accordingly, involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements.

In addition, forward-looking statements are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” including, but not limited to, statements under the sub-heading “Results of Operations” about trends and uncertainties, “Liquidity and Capital Resources” about future liquidity requirements and “Other Matters” about our synthetic fuel facilities.

Any forward-looking statement is based on information current as of the date of this report and speaks only as of the date on which such statement is made, and the Progress Registrants undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made.

Examples of factors that you should consider with respect to any forward-looking statements made throughout this document include, but are not limited to, the following: the impact of fluid and complex laws and regulations, including those relating to the environment and the recently enacted Energy Policy Act of 2005; deregulation or restructuring in the electric industry that may result in increased competition and unrecovered or stranded costs; the uncertainty regarding the timing, creation and structure of GridSouth, GridFlorida or other transmission organizations; weather conditions that directly influence the demand for electricity; the timing and recovery of the costs associated with the four hurricanes that impacted our service territory in 2004 or the ability to recover through the regulatory process costs associated with other future significant weather events; recurring seasonal fluctuations in demand for electricity; fluctuations in the price of energy commodities and purchased power; economic fluctuations and the corresponding impact on our commercial and industrial customers; the ability of our subsidiaries to pay upstream dividends or distributions to the Parent; the impact on our facilities and businesses from a terrorist attack; the inherent risks associated with the operation of nuclear facilities, including environmental, health, regulatory and financial risks; the future need for additional baseload generation in our regulated service territories and the accompanying regulatory and financial risks; the ability to successfully access capital markets on favorable terms; our ability to maintain our current credit ratings and the impact on our financial condition and ability to meet our cash and other financial obligations in the event our credit ratings are downgraded below investment grade; the impact that increases in leverage may have on each of the Progress Registrants; the impact of derivative contracts used in the normal course of business; investment performance of pension and benefit plans; the Progress Registrants’ ability to control costs, including pension and benefit expense, and achieve our cost management targets for 2007; the availability and use of Internal Revenue Code Section 29 (Section 29) tax credits by synthetic fuel producers and our continued ability to use Section 29 tax credits related to our coal-based solid synthetic fuel businesses; the impact to our financial condition and performance in the event it is determined we are not entitled to previously taken Section 29 tax credits; the impact of the proposed accounting pronouncement regarding uncertain tax positions; the impact that future crude oil prices may have on the value of our Section 29 tax credits; our ability to manage the risks involved with the operation of nonregulated plants, including dependence on third parties and related counter-party risks, and a lack of operating history of such plants; the ability to manage the risks associated with our energy marketing operations; the outcome of any ongoing or future litigation or similar disputes and the impact of any such outcome or related settlements; and unanticipated changes in operating expenses and capital expenditures. Many of these risks similarly impact our non-reporting subsidiaries.

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

PROGRESS ENERGY, INC.
CONSOLIDATED INTERIM FINANCIAL STATEMENTS
September 30, 2005

UNAUDITED CONSOLIDATED STATEMENTS of INCOME

	Three Months Ended    September 30				Nine Months Ended   September 30
(in millions except per share data)	2005		2004		2005		2004
Operating revenues
Utility	$ 2,412		$ 2,043		$ 5,963		$ 5,449
Diversified business	685		427		1,665		1,150
Total operating revenues	3,097		2,470		7,628		6,599
Operating expenses
Utility
Fuel used in electric generation	633		556		1,712		1,517
Purchased power	424		269		839		671
Operation and maintenance	408		324		1,357		1,059
Depreciation and amortization	232		213		647		622
Taxes other than on income	131		114		356		328
Other	1		—		(24	)	—
Diversified business
Cost of sales	662		350		1,596		1,049
Depreciation and amortization	46		47		128		130
Other	23		34		86		95
Total operating expenses	2,560		1,907		6,697		5,471
Operating income	537		563		931		1,128
Other income
Interest income	3		3		11		9
Other, net	10		28		6		3
Total other income	13		31		17		12
Interest charges
Net interest charges	165		156		499		474
Allowance for borrowed funds used during construction	(3	)	(2	)	(10	)	(5	)
Total interest charges, net	162		154		489		469
Income from continuing operations before income tax and minority interest	388		440		459		671
Income tax (benefit) expense	(55	)	154		(78	)	140
Income from continuing operations before minority interest	443		286		537		531
Minority interest in subsidiaries' loss, net of tax	7		6		24		6
Income from continuing operations	450		292		561		537
Discontinued operations, net of tax	(1	)	11		(20	)	28
Income before cumulative effect of change in accounting principle	449		303		541		565
Cumulative effect of change in accounting principle, net of tax	1		—		1		—
Net income	$    450		$    303		$    542		$    565
Average common shares outstanding - basic	248		243		246		242
Basic earnings per common share
Income from continuing operations	$   1.82		$   1.20		$   2.28		$   2.21
Discontinued operations, net of tax	—		0.05		(0.08	)	0.12
Net income	$   1.82		$   1.25		$   2.20		$   2.33
Diluted earnings per common share
Income from continuing operations	$   1.81		$   1.19		$   2.28		$   2.20
Discontinued operations, net of tax	—		0.05		(0.08	)	0.12
Net income	$   1.81		$   1.24		$   2.20		$   2.32
Dividends declared per common share	$ 0.590		$ 0.575		$ 1.770		$ 1.725

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

PROGRESS ENERGY, INC.
UNAUDITED CONSOLIDATED BALANCE SHEETS

(in millions) ASSETS	September 30                  2005		December 31               2004
Utility Plant
Utility plant in service	$ 22,450		$ 22,103
Accumulated depreciation	(9,447	)	(8,783	)
Utility plant in service, net	13,003		13,320
Held for future use	14		13
Construction work in progress	1,068		799
Nuclear fuel, net of amortization	237		231
Total utility plant, net	14,322		14,363
Current assets
Cash and cash equivalents	205		56
Short-term investments	—		82
Receivables, net	1,200		911
Inventory	802		805
Deferred fuel cost	535		229
Deferred income taxes	45		114
Assets of discontinued operations	—		577
Prepayments and other current assets	404		174
Total current assets	3,191		2,948
Deferred debits and other assets
Regulatory assets	1,082		1,064
Nuclear decommissioning trust funds	1,115		1,044
Diversified business property, net	1,924		1,838
Miscellaneous other property and investments	489		444
Goodwill	3,719		3,719
Intangibles, net	310		337
Other assets and deferred debits	386		262
Total deferred debits and other assets	9,025		8,708
Total assets	$ 26,538		$ 26,019
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value, 500 million shares authorized,
252 and 247 million shares issued and outstanding, respectively	$   5,548		$   5,360
Unearned restricted shares	—		(13	)
Unearned ESOP shares	(63	)	(76	)
Accumulated other comprehensive loss	(212	)	(164	)
Retained earnings	2,630		2,526
Total common stock equity	7,903		7,633
Preferred stock of subsidiaries-not subject to mandatory redemption	93		93
Minority interest	41		36
Long-term debt, affiliate	270		270
Long-term debt, net	8,989		9,251
Total capitalization	17,296		17,283
Current liabilities
Current portion of long-term debt	852		349
Accounts payable	684		630
Interest accrued	166		219
Dividends declared	148		145
Short-term obligations	517		684
Customer deposits	195		180
Liabilities of discontinued operations	—		152
Other current liabilities	845		703
Total current liabilities	3,407		3,062
Deferred credits and other liabilities
Noncurrent income tax liabilities	399		625
Accumulated deferred investment tax credits	166		176
Regulatory liabilities	2,600		2,654
Asset retirement obligations	1,248		1,282
Accrued pension and other benefits	1,045		634
Other liabilities and deferred credits	377		303
Total deferred credits and other liabilities	5,835		5,674
Commitments and contingencies (Note 15)
Total capitalization and liabilities	$ 26,538		$ 26,019

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

PROGRESS ENERGY, INC.
UNAUDITED CONSOLIDATED STATEMENTS of CASH FLOWS

(in millions) Nine Months Ended September 30,	2005		2004
Operating activities
Net income	$    542		$    565
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations, net of tax	20		(28	)
Cumulative effect of changes in accounting principles	(1	)	—
Charges for voluntary enhanced retirement program	159		—
Depreciation and amortization	863		844
Deferred income taxes	(145	)	129
Investment tax credit	(10	)	(11	)
Tax levelization	(27	)	6
Deferred fuel credit	(276	)	(65	)
Other adjustments to net income	105		56
Cash provided (used) by changes in operating assets and liabilities:
Receivables	(266	)	(51	)
Inventory	(95	)	(44	)
Prepayments and other current assets	(72	)	(94	)
Accounts payable	183		24
Other current liabilities	3		(16	)
Regulatory assets and liabilities	(50	)	(73	)
Other	2		25
Net cash provided by operating activities	935		1,267
Investing activities
Gross utility property additions	(772	)	(691	)
Diversified business property additions	(167	)	(140	)
Nuclear fuel additions	(98	)	(63	)
Proceeds from sales of subsidiaries and other investments, net of cash divested	459		112
Purchases of short-term investments	(2,865	)	(816	)
Proceeds from sales of short-term investments	2,947		1,042
Other	(59	)	(43	)
Net cash used in investing activities	(555	)	(599	)
Financing activities
Issuance of common stock	193		59
Issuance of long-term debt	792		1
Net (decrease) increase in short-term indebtedness	(167	)	664
Retirement of long-term debt	(562	)	(905	)
Dividends paid on common stock	(435	)	(418	)
Other	(22	)	(48	)
Net cash used in financing activities	(201	)	(647	)
Cash (used) provided by discontinued operations
Operating activities	(26	)	16
Investing activities	(4	)	(16	)
Financing activities	—		—
Net increase in cash and cash equivalents	149		21
Cash and cash equivalents at beginning of period	56		35
Cash and cash equivalents at end of period	$    205		$      56

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

CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED INTERIM FINANCIAL STATEMENTS
September 30, 2005

UNAUDITED CONSOLIDATED STATEMENTS of INCOME

	Three Months Ended                              September 30				Nine Months Ended                          September 30
(in millions)	2005		2004		2005		2004
Operating revenues
Electric	$ 1,185		$ 1,014		$ 2,980		$ 2,776
Diversified business	—		—		1		1
Total operating revenues	1,185		1,014		2,981		2,777
Operating expenses
Fuel used in electric generation	282		220		746		637
Purchased power	154		96		294		238
Operation and maintenance	235		197		719		632
Depreciation and amortization	130		139		389		393
Taxes other than on income	49		44		137		132
Total operating expenses	850		696		2,285		2,032
Operating income	335		318		696		745
Other income (expense)
Interest income	2		—		5		2
Other, net	5		7		4		(1	)
Total other income	7		7		9		1
Interest charges
Interest charges	59		50		161		146
Allowance for borrowed funds used during construction	(1	)	(1	)	(4	)	(2	)
Total interest charges, net	58		49		157		144
Income before income tax	284		276		548		602
Income tax expense	100		101		181		216
Net income	$    184		$    175		$    367		$    386
Preferred stock dividend requirement	1		1		2		2
Earnings for common stock	$    183		$    174		$    365		$    384

See Notes to PEC Consolidated Interim Financial Statements.

CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
UNAUDITED CONSOLIDATED BALANCE SHEETS

(in millions) ASSETS	September 30      2005		December 31                     2004
Utility plant
Utility plant in service	$ 13,832		$ 13,521
Accumulated depreciation	(6,008	)	(5,806	)
Utility plant in service, net	7,824		7,715
Held for future use	5		5
Construction work in progress	473		379
Nuclear fuel, net of amortization	165		186
Total utility plant, net	8,467		8,285
Current assets
Cash and cash equivalents	52		18
Short-term investments	—		82
Receivables, net	488		397
Receivables from affiliated companies	17		20
Inventory	403		390
Deferred fuel cost	257		140
Prepayments and other current assets	73		135
Total current assets	1,290		1,182
Deferred debits and other assets
Regulatory assets	479		473
Nuclear decommissioning trust funds	628		581
Miscellaneous other property and investments	208		158
Other assets and deferred debits	156		108
Total deferred debits and other assets	1,471		1,320
Total assets	$ 11,228		$ 10,787
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value	$   1,994		$   1,975
Unearned ESOP common stock	(63	)	(76	)
Accumulated other comprehensive loss	(164	)	(114	)
Retained earnings	1,309		1,287
Total common stock equity	3,076		3,072
Preferred stock - not subject to mandatory redemption	59		59
Long-term debt, net	3,264		2,750
Total capitalization	6,399		5,881
Current liabilities
Current portion of long-term debt	—		300
Accounts payable	235		254
Payables to affiliated companies	68		83
Notes payable to affiliated companies	80		116
Short-term obligations	187		221
Customer deposits	50		45
Other current liabilities	298		256
Total current liabilities	918		1,275
Deferred credits and other liabilities
Noncurrent income tax liabilities	939		991
Accumulated deferred investment tax credits	134		140
Regulatory liabilities	1,198		1,052
Asset retirement obligations	964		924
Accrued pension and other benefits	579		428
Other liabilities and deferred credits	97		96
Total deferred credits and other liabilities	3,911		3,631
Commitments and contingencies (Note 15)
Total capitalization and liabilities	$ 11,228		$ 10,787

See Notes to PEC Consolidated Interim Financial Statements.

CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
UNAUDITED CONSOLIDATED STATEMENTS of CASH FLOWS

(in millions) Nine Months Ended September 30,	2005		2004
Operating activities
Net income	$    367		$    386
Adjustments to reconcile net income to net cash provided by operating activities:
Charges for voluntary enhanced retirement program	42		—
Depreciation and amortization	450		460
Deferred income taxes	(19	)	(20	)
Investment tax credit	(6	)	(6	)
Deferred fuel credit	(146	)	(57	)
Other adjustments to net income	68		7
Cash provided (used) by changes in operating assets and liabilities:
Receivables	(88	)	(5	)
Receivables from affiliated companies	14		14
Inventory	(54	)	3
Prepayments and other current assets	(13	)	5
Accounts payable	30		32
Payables to affiliated companies	(15	)	(67	)
Other current liabilities	96		86
Regulatory assets and liabilities	2		10
Other	(29	)	33
Net cash provided by operating activities	699		881
Investing activities
Gross property additions	(453	)	(357	)
Nuclear fuel additions	(52	)	(63	)
Contributions to nuclear decommissioning trust	(26	)	(26	)
Purchases of short-term investments	(1,160	)	(816	)
Proceeds from sales of short-term investments	1,242		1,042
Other investing activities	3		12
Net cash used in investing activities	(446	)	(208	)
Financing activities
Issuance of long-term debt, net	495		—
Net (decrease) increase in short-term obligations	(34	)	142
Net change in intercompany notes	(36	)	(42	)
Retirement of long-term debt	(300	)	(339	)
Dividends paid to parent	(343	)	(426	)
Dividends paid on preferred stock	(2	)	(2	)
Other financing activities	1		—
Net cash used in financing activities	(219	)	(667	)
Net increase in cash and cash equivalents	34		6
Cash and cash equivalents at beginning of period	18		12
Cash and cash equivalents at end of period	$      52		$      18

See Notes to PEC Consolidated Interim Financial Statements.

FLORIDA POWER CORPORATION
d/b/a PROGRESS ENERGY FLORIDA, INC.
INTERIM FINANCIAL STATEMENTS
September 30, 2005

UNAUDITED STATEMENTS of INCOME

	Three Months Ended                                September 30				Nine Months Ended                                September 30
(in millions)	2005		2004		2005		2004
Operating revenues	$ 1,227		$ 1,029		$ 2,983		$ 2,673
Operating expenses
Fuel used in electric generation	351		335		966		880
Purchased power	270		173		545		433
Operation and maintenance	181		138		658		450
Depreciation and amortization	95		68		236		209
Taxes other than on income	82		70		215		196
Other	1		—		(24	)	—
Total operating expenses	980		784		2,596		2,168
Operating income	247		245		387		505
Other income
Other, net	4		1		6		—
Total other income	4		1		6		—
Interest charges
Interest charges	28		27		96		87
Allowance for borrowed funds used during construction	(2	)	(1	)	(6	)	(3	)
Total interest charges, net	26		26		90		84
Income before income taxes	225		220		303		421
Income tax expense	74		80		98		147
Net income	$    151		$    140		$    205		$    274
Preferred stock dividend requirement	—		—		1		1
Earnings for common stock	$    151		$    140		$    204		$    273

See Notes to PEF Interim Financial Statements.

FLORIDA POWER CORPORATION
d/b/a PROGRESS ENERGY FLORIDA, INC.
UNAUDITED BALANCE SHEETS

(in millions) ASSETS	September 30                   2005		December 31                   2004
Utility plant
Utility plant in service	$ 8,435		$ 8,387
Accumulated depreciation	(3,394	)	(2,978	)
Utility plant in service, net	5,041		5,409
Held for future use	9		8
Construction work in progress	595		420
Nuclear fuel, net of amortization	72		45
Total utility plant, net	5,717		5,882
Current Assets
Cash and cash equivalents	15		12
Receivables, net	402		266
Receivables from affiliated companies	6		16
Deferred income taxes	—		42
Inventory	304		279
Deferred fuel cost	278		89
Prepayments and other current assets	192		12
Total current assets	1,197		716
Deferred debits and other assets
Regulatory assets	419		524
Nuclear decommissioning trust funds	487		463
Miscellaneous other property and investments	40		46
Prepaid pension costs	195		234
Other assets and deferred debits	75		59
Total deferred debits and other assets	1,216		1,326
Total assets	$ 8,130		$ 7,924
CAPITALIZATION AND LIABILITIES
Common stock equity
Common stock without par value	$ 1,096		$ 1,081
Retained earnings	1,444		1,240
Total common stock equity	2,540		2,321
Preferred stock - not subject to mandatory redemption	34		34
Long-term debt, net	2,108		1,912
Total capitalization	4,682		4,267
Current liabilities
Current portion of long-term debt	48		48
Accounts payable	256		262
Payables to affiliated companies	85		80
Notes payable to affiliated companies	31		178
Short-term obligations	292		293
Customer deposits	145		135
Other current liabilities	217		161
Total current liabilities	1,074		1,157
Deferred credits and other liabilities
Noncurrent income tax liabilities	454		489
Accumulated deferred investment tax credits	31		35
Regulatory liabilities	1,231		1,362
Asset retirement obligations	259		337
Accrued pension and other benefits	280		201
Other liabilities and deferred credits	119		76
Total deferred credits and other liabilities	2,374		2,500
Commitments and contingencies (Note 15)
Total capitalization and liabilities	$ 8,130		$ 7,924

See Notes to PEF Interim Financial Statements.

FLORIDA POWER CORPORATION
d/b/a PROGRESS ENERGY FLORIDA, INC.
UNAUDITED STATEMENTS of CASH FLOWS

(in millions) Nine Months Ended September 30,	2005		2004
Operating activities
Net income	$ 205		$ 274
Adjustments to reconcile net income to net cash provided by operating activities:
Charges for voluntary enhanced retirement program	91		—
Depreciation and amortization	262		239
Deferred income taxes and investment tax credits, net	4		281
Deferred fuel credit	(130	)	(8	)
Other adjustments to net income	33		(1	)
Cash provided/(used) by changes in operating assets and liabilities:
Receivables	(140	)	(64	)
Receivables from affiliated companies	10		1
Inventory	(38	)	(7	)
Prepayments and other current assets	(18	)	(11	)
Accounts payable	75		47
Payables to affiliated companies	5		25
Other current liabilities	(35	)	(181	)
Regulatory assets and liabilities	(52	)	(83	)
Other	31		10
Net cash provided by operating activities	303		522
Investing activities
Property additions	(336	)	(336	)
Nuclear fuel additions	(46	)	—
Proceeds from sales of assets	42		—
Other	(5	)	(3	)
Net cash used in investing activities	(345	)	(339	)
Financing activities
Issuance of long-term debt, net	297		1
Net (decrease) increase in short-term obligations	(1	)	323
Retirement of long-term debt	(101	)	(41	)
Net change in intercompany notes	(147	)	(345	)
Dividends paid to parent	—		(117	)
Dividends paid on preferred stock	(1	)	(1	)
Other	(2	)	—
Net cash provided by (used in) financing activities	45		(180	)
Net increase in cash and cash equivalents	3		3
Cash and cash equivalents at beginning of period	12		10
Cash and cash equivalents at end of period	$   15		$   13

See Notes to PEF Interim Financial Statements.

COMBINED NOTES TO INTERIM FINANCIAL STATEMENTS FOR PROGRESS ENERGY, INC.
CAROLINA POWER & LIGHT COMPANY d/b/a/ PROGRESS ENERGY CAROLINAS, INC.
FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.

INDEX TO APPLICABLE NOTES TO FINANCIAL STATEMENTS BY REGISTRANT

Each of the following combined notes to interim financial statements of the Progress Registrants are applicable to us but not to each of PEC and PEF. The following table sets forth which notes are applicable to each of PEC and PEF.

Registrant	Applicable Notes
PEC PEF	1, 2, 5, 6, 7 and 9 through 15 1, 2, 3, 5, 6, 7 and 9 through 15

PROGRESS ENERGY, INC.
CAROLINA POWER & LIGHT COMPANY d/b/a/ PROGRESS ENERGY CAROLINAS, INC.
FLORIDA POWER CORPORATION d/b/a PROGRESS ENERGY FLORIDA, INC.

COMBINED NOTES TO INTERIM FINANCIAL STATEMENTS

In this report, Progress Energy (which includes Progress Energy, Inc. holding company (the Parent) and its regulated and nonregulated subsidiaries on a consolidated basis), is at times referred to as “we”, “our” or “us”. When discussing Progress Energy’s financial information, it necessarily includes the results of PEC and PEF (collectively, the Utilities). The term “Progress Registrants” refers to each of the three separate registrants: Progress Energy, PEC and PEF. The information in these combined notes relates to each of the Progress Registrants as noted in the Index to the Combined Notes. However, neither of the Utilities makes any representation as to information related solely to Progress Energy or the subsidiaries of Progress Energy other than itself.

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A.      Organization

The Parent is a holding company headquartered in Raleigh, North Carolina and is registered under the Public Utility Holding Company Act of 1935 (PUHCA), as amended. As such, we are subject to the regulatory provisions of PUHCA.

Through our wholly owned subsidiaries, PEC and PEF, our PEC Electric and PEF business segments are primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina, South Carolina and Florida. Our Progress Ventures business unit consists of the following segments: Fuels, Competitive Commercial Operations (CCO) and Synthetic Fuels. Our Fuels segment is involved in natural gas drilling and production, coal terminal services, coal mining and fuel transportation and delivery. Our CCO segment includes nonregulated electric generation and energy marketing activities. Our Synthetic Fuels segment is involved in the production and sale of coal-based synthetic fuel as defined under the Internal Revenue Code (the Code). Synthetic Fuels activities were reported in the Fuels segment prior to 2005 and now are considered a separate reportable segment. Prior to its divestiture in 2005, Rail Services was reported as a separate segment (see Note 3). The operations of Rail Services were reclassified to discontinued operations in the first quarter of 2005 and therefore are not included in the results from continuing operations during the periods reported. Through our other business units, we engage in other nonregulated business areas, including telecommunications and energy management and related services which are included in our Corporate and Other segment (Corporate and Other). Our legal structure is not currently aligned with the functional management and financial reporting of the Progress Ventures business unit. Whether, and when, the legal and functional structures will converge depends upon legislative and regulatory action, which cannot currently be anticipated.

PEC’s subsidiaries are involved in insignificant nonregulated business activities.

B.     Basis of Presentation

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q and Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for annual financial statements. Because the accompanying interim financial statements do not include all of the information and footnotes required by GAAP for annual financial statements, they should be read in conjunction with the audited financial statements and notes thereto included in the annual reports on Form 10-K for the year ended December 31, 2004 filed by each of the Progress Registrants.

These combined notes accompany and form an integral part of Progress Energy’s and PEC’s consolidated financial statements and PEF’s financial statements. The Utilities are subsidiaries of Progress Energy and as such their financial condition and results of operations and cash flows are also consolidated, along with our nonregulated subsidiaries, in our consolidated financial statements.

In accordance with the provisions of Accounting Principles Board Opinion (APB) No. 28, “Interim Financial Reporting,” GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. The intra-period tax allocation, which will have no impact on total year net income, maintains an effective tax rate consistent with the estimated annual effective tax rate. The fluctuations in the effective tax rate for interim periods are primarily due to the recognition of synthetic fuel tax credits and seasonal fluctuations in energy sales and earnings from the Utilities. Income tax expense was increased (decreased) for the Progress Registrants for the three and nine months ended September 30, 2005 and 2004, as follows:

	Three Months Ended                                 September 30				Nine Months Ended                                   September 30
(in millions)	2005		2004		2005		2004
Progress Energy (a)	$(91	)	$(38	)	$(27	)	$6
PEC	$   3		$ —		$   6		$—
PEF	$  (9	)	$ —		$ —		$—

(a)         Amounts for Progress Energy may not equal the sum of PEC and PEF due to amounts recorded at non-utility subsidiaries.

The Utilities collect from customers certain excise taxes levied by the state or local government upon the customers. The Utilities account for excise taxes on a gross basis. The amount of gross receipts tax, franchise taxes and other excise taxes included in utility revenues and taxes other than on income in the statements of income are as follows:

	Three Months Ended    September 30		Nine Months Ended   September 30
(in millions)	2005	2004	2005	2004
Progress Energy	$80	$69	$194	$183
PEC	$27	$24	$  68	$  69
PEF	$53	$45	$126	$114

The amounts included in these financial statements are unaudited but, in the opinion of management, reflect all normal recurring adjustments necessary to fairly present our financial position and results of operations for the interim periods. Due to seasonal weather variations and the timing of outages of electric generating units, especially nuclear-fueled units, the results of operations for interim periods are not necessarily indicative of amounts expected for the entire year or future periods.

In preparing financial statements that conform with GAAP, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and amounts of revenues and expenses reflected during the reporting period. Actual results could differ from those estimates. Certain amounts for 2004 have been reclassified to conform to the 2005 presentation.

C.     Consolidation of Variable Interest Entities

We consolidate all voting interest entities in which we own a majority voting interest and all variable interest entities for which we 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).

Progress Energy

In addition to the variable interests listed below for PEC and PEF, we have interests through other subsidiaries in several variable interest entities for which we are not the primary beneficiary. These arrangements include investments in four limited partnerships and limited liability corporations. At September 30, 2005, the aggregate additional maximum loss exposure that we could be required to record in our income statement as a result of these arrangements was approximately $8 million. The creditors of these variable interest entities do not have recourse to our general credit in excess of the aggregate maximum loss exposure.

PEC

PEC is the primary beneficiary of and consolidates two limited partnerships that qualify for federal affordable housing and historic tax credits under Section 42 of the Code. At September 30, 2005, the total assets of the two entities were $38 million, the majority of which are collateral for the entities’ obligations and are included in miscellaneous other property and investments in the Consolidated Balance Sheets.

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

PEC also has interests in several other variable interest entities for which PEC is not the primary beneficiary. These arrangements include investments in approximately 22 limited partnerships, limited liability corporations and venture capital funds and two building leases with special-purpose entities. At September 30, 2005, the aggregate maximum loss exposure that PEC could be required to record in its income statement as a result of these arrangements was approximately $23 million. The creditors of these variable interest entities do not have recourse to the general credit of PEC in excess of the aggregate maximum loss exposure.

PEF

PEF has interests in three variable interest entities for which PEF is not the primary beneficiary. These arrangements include investments in one limited liability corporation, one venture capital fund and one building lease with a special-purpose entity. At September 30, 2005, the aggregate maximum loss exposure that PEF could be required to record in its income statement as a result of these arrangements was approximately $6 million. The creditors of these variable interest entities do not have recourse to the general credit of PEF in excess of the aggregate maximum loss exposure.

2. IMPACT OF NEW ACCOUNTING STANDARDS

Refer to Note 6D for information regarding our third quarter 2005 implementation of a new stock-based compensation standard.

FASB EXPOSURE DRAFT ON ACCOUNTING FOR UNCERTAIN TAX POSITIONS, AN INTERPRETATION OF SFAS NO. 109, "ACCOUNTING FOR INCOME TAXES"

On July 14, 2005, the Financial Accounting Standards Board (FASB) issued an exposure draft of a proposed interpretation of SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109), that would address the accounting for uncertain tax positions. The proposed interpretation would require that uncertain tax benefits be probable of being sustained in order to record such benefits in the consolidated financial statements. We currently account 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 not be sustained and the amount of the disallowance can be reasonably estimated. As currently drafted, the proposed interpretation would apply to all uncertain tax positions and be effective for us on December 31, 2005. However, the FASB has publicly stated that it expects to issue the final interpretation in the first quarter of 2006, which is expected to delay the effective date of the interpretation past 2005.

As discussed in Note 15, the Internal Revenue Service (IRS) field auditors have recommended that the Section 29 tax credits generated by our Earthco facilities, totaling $1.2 billion through September 30, 2005, be disallowed. We disagree with the field audit team’s findings and have requested that the National Office of the IRS review this issue. We have not yet determined how the proposed interpretation would impact our various income tax positions, including the status of the Earthco tax credits.  Depending on the provisions of the FASB’s final interpretation and our facts and circumstances that exist at the date of implementation, including our assessment of the probability of sustaining any currently recorded and future tax benefits, the proposed interpretation could have a material adverse impact on our financial position and results of operations.

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

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

3.  DIVESTITURES

Progress Rail Divestiture

On March 24, 2005, we completed the sale of Progress Rail Services Corporation (Progress Rail) to One Equity Partners LLC, a private equity firm unit of J.P. Morgan Chase & Co. Gross cash proceeds from the sale were approximately $429 million, consisting of $405 million base proceeds plus a working capital adjustment. Proceeds from the sale were used to reduce debt.

Based on the gross proceeds associated with the sale of $429 million, we recorded an estimated after-tax loss on disposal of $25 million during the nine months ended September 30, 2005.

The accompanying consolidated interim financial statements have been restated for all periods presented to reflect the operations of Progress Rail as discontinued operations. Interest expense has been allocated to discontinued operations based on the net assets of Progress Rail, assuming a uniform debt-to-equity ratio across our operations. Interest expense allocated for the three months ended September 30, 2004 was $4 million. Interest expense allocated for the nine months ended September 30, 2005 and 2004 was $4 million and $12 million, respectively. We ceased recording depreciation upon classification of the assets as discontinued operations in February 2005. After-tax depreciation expense recorded by Progress Rail during the three months ended September 30, 2004 was $3 million. After-tax depreciation expense during the nine months ended September 30, 2005 and 2004 was $3 million and $8 million, respectively. Results of discontinued operations were as follows:

	Three Months Ended    September 30			Nine Months Ended   September 30
(in millions)	2005		2004	2005		2004
Revenues	$ —		$291	$ 358		$816
Earnings before income taxes	$ —		$  17	$     8		$  44
Income tax expense	—		6	3		17
Net earnings from discontinued operations	—		11	5		27
Estimated loss on disposal of discontinued operations,
including income tax benefit of $0 and $15 for the
three and nine months ended September 30, 2005,
respectively	(1	)	—	(25	)	—
(Loss) earnings from discontinued operations	$(1	)	$  11	$(20	)	$  27

In connection with the sale, Progress Fuels Corporation (Progress Fuels) and Progress Energy provided guarantees and indemnifications of certain legal, tax and environmental matters to One Equity Partners, LLC. See general discussion of guarantees at Note 15B. The ultimate resolution of these matters could result in adjustments to the loss on sale in future periods.

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

(in millions)
Accounts receivable	$172
Inventory	177
Other current assets	15
Total property, plant and equipment, net	174
Total other assets	39
Assets of discontinued operations	$577
Accounts payable	$113
Accrued expenses	39
Liabilities of discontinued operations	$152

In February 2004, we sold the majority of the assets of Railcar Ltd., a subsidiary of Progress Rail, to The Andersons, Inc. for proceeds of approximately $82 million.

NCNG Divestiture

In October 2002, we announced the Board of Directors’ approval to sell North Carolina Natural Gas Corporation (NCNG) and our equity investment in Eastern North Carolina Natural Gas Company to Piedmont Natural Gas Company, Inc. On September 30, 2003, we completed the sale. During the nine months ended September 30, 2004, we recorded an additional gain after taxes of approximately $1 million related to deferred taxes on the loss from the NCNG sale.

Winter Park Divestiture

As discussed in Note 5, PEF sold certain electric distribution assets to the City of Winter Park, Florida (Winter Park) on June 1, 2005.

4.   ACQUISITIONS

In May 2005, Winchester Production Company, Ltd., an indirectly wholly owned subsidiary of Progress Fuels, acquired an interest in approximately 11 natural gas producing wells and proven reserves of approximately 25 billion cubic feet equivalent from a privately-owned company headquartered in Texas. In addition to the natural gas reserves, the transaction also included a 50 percent interest in the gas gathering systems related to these reserves. The total cash purchase price for the transaction was $46 million.

5.   REGULATORY MATTERS

PEC Retail Rate Matters

On April 27, 2005, PEC filed for an increase in the fuel rate charged to its South Carolina retail customers with the Public Service Commission of South Carolina (SCPSC). PEC requested the increase for underrecovered fuel costs for the previous 15 months and to meet future expected fuel costs. On June 23, 2005, the SCPSC approved a settlement agreement filed jointly by PEC and all other parties to the proceeding. The settlement agreement levelizes the collection of underrecovered fuel costs over a three-year period ending June 30, 2008, and allows PEC to charge and recover carrying costs on the monthly unpaid balance, beginning July 1, 2006, at an interest rate of 6% compounded annually. An annual increase in PEC’s rates of $55 million, or 12 percent, was effective July 1, 2005.

On June 3, 2005, PEC filed for an increase in the fuel rate charged to its North Carolina retail customers with the North Carolina Utilities Commission (NCUC). PEC asked the NCUC to approve a $276 million, or 11 percent, increase in rates. PEC requested the increase for underrecovered fuel costs for the previous 12 months and to meet future expected fuel costs.

On July 25, 2005, PEC, the NCUC Public Staff and the Carolina Industrial Group for Fair Utility Rates jointly filed a proposed settlement agreement with the NCUC to resolve issues concerning PEC’s 2005 North Carolina fuel adjustment proceeding. The settlement was approved by order of the NCUC on September 26, 2005. In the settlement, PEC will collect all of its fuel cost undercollections that occurred during the test year ended March 31, 2005 over a one-year period beginning October 1, 2005. Additionally, PEC agreed to reduce its proposed billing increment, designed to collect future fuel costs, in order to address customer concerns regarding the magnitude of the proposed increase. The NCUC approved an average increase of approximately 4.4 percent for residential customers, 5.6 percent for commercial customers and 7.4 percent for industrial customers. In recognition of the likely undercollection that will result during the year ending September 30, 2006, PEC is allowed to calculate and collect interest at 6% on the difference between its collection factor in the original request to the NCUC and the factor included in the settlement agreement until such amounts have been collected. The increase was effective October 1, 2005.

PEF Retail Rate Matters

During September and October 2005, PEF filed requests with the Florida Public Service Commission (FPSC) seeking a total increase of $605 million over 2005 to cover rising fuel and other costs to generate electricity. Fuel costs of $560 million were the largest component of the total increase. The fuel cost increase includes $17 million from 2004 under-recoveries, $222 million from 2005 under-recoveries and a $321 million increase for 2006. The proposed new charges for all the cost recovery clauses would take effect January 1, 2006. The FPSC is scheduled to hold hearings on the proposals on November 7 through 9, 2005. If the FPSC approves the increases, residential electric bills would increase by $11.78 to $109.56 per 1,000 kWhs.

On July 14, 2005, the FPSC issued an order authorizing PEF to recover $232 million over a two-year period, including interest, of the costs it incurred and previously deferred related to PEF’s restoration of power to customers associated with the four hurricanes in 2004. The ruling allowed PEF to include a charge of approximately $3.27 on the average residential monthly customer bill beginning August 1, 2005. The ruling by the FPSC approved the majority of PEF’s requests with two exceptions: the reclassification of $8 million of previously deferred costs to utility plant and the reclassification of $17 million of previously deferred costs as normal operation and maintenance (O&M) expense which was expensed in the second quarter of 2005.

The amount included in the original petition requesting recovery of $252 million in November 2004 was an estimate, as actual total costs were not known at that time. On September 12, 2005, PEF filed a true-up to the original amount requested. PEF incurred an additional $19 million in costs in excess of the amount requested in the original petition. The recovery of this difference is still subject to FPSC approval and will be determined during the hearings to be held on November 7 through 9, 2005. If the FPSC approves the increase, the impact will be included in customer bills beginning January 1, 2006.

On June 1, 2005, the Governor of Florida signed into law a bill that would allow utilities to petition the FPSC to use securitized bonds to recover storm related costs. PEF is reviewing whether it will seek FPSC approval to issue securitized debt to recover any outstanding balance of its 2004 storm costs and to replenish its storm reserve fund, or to seek replenishment of its storm reserve fund through base rates or a surcharge mechanism. If PEF seeks recovery through securitization and assuming FPSC approval, PEF expects the process to take six to nine months to complete.

On April 29, 2005, PEF submitted minimum filing requirements, based on a 2006 projected test year, to initiate a base rate proceeding regarding its future base rates. In its filing, PEF requested a $206 million annual increase in base rates effective January 1, 2006. On September 7, 2005, the FPSC approved an agreement (Base Rate Settlement) that maintains PEF’s base rates at their current level through late 2007. The new base rates will take effect the first billing cycle of January 2006 and will remain in effect through the last billing cycle of December 2009 with PEF having sole option to extend through the last billing cycle of June 2010.

Under the Base Rate Settlement, PEF will continue to collect a return on and depreciation of the Hines 2 generation facility through the fuel clause, as was permitted under the terms of the existing Stipulation and Settlement Agreement (the Agreement), through late 2007 when it will be transferred into base rates. This transfer will correspond with the in-service dates of the Hines 4 generation facility, which will also be recovered through base rates. PEF will recover the cost of its Hines 3 generating facility through existing base rates when it goes into service in late 2005, similar to other utility property additions.

The Base Rate Settlement authorizes PEF to recover certain costs through clauses, such as the continued recovery of post-9/11 security costs through the capacity clause and the carrying costs of coal inventory in transit and coal procurement costs through the fuel clause.

The Base Rate Settlement also provides for revenue sharing between PEF and its customers. In 2006, PEF will refund two-thirds of revenues between the $1.499 billion threshold and the $1.549 billion cap and 100 percent of revenues above the $1.549 billion cap. Both the threshold and cap will be adjusted annually for rolling average ten-year retail kWh sales growth.

The Base Rate Settlement authorizes PEF to include an adjustment to increase common equity for the impact of Standard & Poor’s (S&P’s) imputed off-balance sheet debt for future capacity payments to qualifying facilities and other entities under long-term purchase power agreements. This adjusted capital structure will be used for surveillance reporting with the FPSC and pass-through clause return calculations. PEF will use an authorized 11.75% return on equity for cost recovery clauses and Allowance for Funds Used During Construction (AFUDC). In addition, PEF’s adjusted equity ratio will be capped at 57.83%. If PEF’s regulatory return on equity falls below 10%, PEF is authorized to petition the FPSC for a base rate increase.

The FPSC requires that PEF perform a depreciation study no less than every four years. PEF filed a depreciation study with the FPSC on April 29, 2005, as part of its base rate filing, which would increase depreciation expense by $14 million beginning in 2006 if approved by the FPSC. PEF reduced its estimated removal costs to take into account the estimates used in the depreciation study. This resulted in a downward revision in the PEF estimated removal costs, a component of regulatory liabilities, and an equal increase in accumulated depreciation of approximately $401 million. On September 7, 2005, the FPSC approved a modification to the study which resulted in a decrease to the filed report of $40 million. Consequently, the impact of the rate changes in the depreciation study will decrease annual depreciation expense by $26 million beginning in 2006.

The FPSC requires that PEF update its cost estimate for fossil plant dismantlement every four years. PEF filed an updated fossil dismantlement study with the FPSC on April 29, 2005, as part of its base rate filing. The new study called for an increase in the annual accrual of $10 million beginning in 2006. PEF’s retail reserve for fossil plant dismantlement was approximately $133 million at September 30, 2005. Retail accruals on PEF’s reserves for fossil plant dismantlement were previously suspended through December 2005 under the terms of PEF’s existing Agreement. The Base Rate Settlement continued the suspension of PEF’s collection from customers of the expenses to dismantle fossil plants.

The FPSC requires that PEF update its cost estimate for nuclear decommissioning every five years. PEF filed a new site-specific estimate of decommissioning costs for the Crystal River Nuclear Plant Unit No. 3 (CR3) with the FPSC on April 29, 2005 as part of PEF’s base rate filing. PEF’s estimate is based on prompt decommissioning. The estimate, in 2005 dollars, is $614 million and is subject to change based on a variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear decommissioning and changes in federal, state or local regulations. The cost estimate excludes the portion attributable to other co-owners of CR3. The NRC operating license held by PEF for CR3 currently expires in December 2016. An application to extend this license 20 years is expected to be submitted in the first quarter of 2009. As part of this new estimate and assumed license extension, PEF reduced its ARO liability by approximately $88 million. Retail accruals on PEF’s reserves for nuclear decommissioning were previously suspended through December 2005 under the terms of the Agreement and the new Base Rate Settlement continues that suspension.

PEF Franchise Matters

On June 1, 2005, Winter Park acquired PEF’s electric distribution system that serves Winter Park for approximately $42 million. PEF transferred the distribution system to Winter Park on June 1, 2005 and recognized a pre-tax gain of approximately $25 million on the transaction, which is included as an offset to other utility expense on the Statements of Income. This amount was decreased $1 million in the third quarter of 2005 upon accumulation of the final capital expenditures incurred since arbitration. PEF also recorded a regulatory liability of $8 million for stranded cost revenues which will be amortized to revenues over the next six years in accordance with the provisions of the transfer agreement with Winter Park.

6.  EQUITY AND COMPREHENSIVE INCOME

A.     Earnings Per Common Share

A reconciliation of our weighted-average number of common shares outstanding for basic and dilutive earnings per share purposes is as follows:

	Three Months Ended    September 30		Nine Months Ended    September 30
(in millions)	2005	2004	2005	2004
Weighted-average common shares - basic	248	243	246	242
Restricted stock awards	—	—	—	1
Weighted-average shares - fully dilutive	248	243	246	243

B.     Comprehensive Income

Progress Energy

	Three Months Ended    September 30				Nine Months Ended   September 30
(in millions)	2005		2004		2005		2004
Net income	$ 450		$ 303		$ 542		$ 565
Other comprehensive income (loss):
Reclassification adjustments included in net income:
Change in cash flow hedges (net of tax expense of
$11, $4, $15 and $8, respectively)	20		6		25		14
Foreign currency translation adjustments included
in discontinued operations	—		—		(6	)	—
Minimum pension liability adjustment included in
discontinued operations (net of tax expense of $-,
$-, $1 and $-, respectively)	—		—		1		—
Changes in net unrealized losses on cash
flow hedges (net of tax benefit of $28,
$7, $3 and $15, respectively)	(51	)	(11	)	(1	)	(26	)
Minimum pension liability adjustment (net of tax
benefit of $45, $-, $45 and $-, respectively)	(70	)	—		(70	)	—
Foreign currency translation adjustment and other	2		(1	)	3		—
Other comprehensive loss	$(99	)	$  (6	)	$(48	)	$(12	)
Comprehensive income	$ 351		$ 297		$ 494		$ 553

PEC

	Three Months Ended    September 30				Nine Months Ended   September 30
(in millions)	2005		2004		2005		2004
Net income	$ 184		$ 175		$ 367		$ 386
Changes in net unrealized gains (losses) on cash
flow hedges (net of tax expense (benefit) of $-,
$(2), $1 and $(1), respectively)	—		(4	)	2		(1	)
Minimum pension liability adjustment (net of tax
benefit of $35, $-, $35 and $-, respectively)	(55	)	—		(55	)	—
Other	2		(1	)	3		(1	)
Other comprehensive loss	$(53	)	$  (5	)	$(50	)	$  (2	)
Comprehensive income	$ 131		$ 170		$ 317		$ 384

PEF

Comprehensive income and net income for PEF for the three months ended September 30, 2005 and 2004 were $151 million and $140 million, respectively. Comprehensive income and net income for PEF for the nine months ended September 30, 2005 and 2004 were $205 million and $274 million, respectively.

C.      Common Stock

At December 31, 2004, we had 500 million shares of common stock authorized under our charter, of which 247 million were outstanding. At December 31, 2004, we had approximately 63 million shares of common stock authorized by the Board of Directors that remained unissued and reserved, primarily to satisfy the requirements of our stock plans. In 2002, the Board of Directors authorized meeting the requirements of the Progress Energy 401(k) Savings and Stock Ownership Plan and the Investor Plus Stock Purchase Plan with original issue shares. For the three and nine months ended September 30, 2005, we issued approximately 0.4 million shares and 4.3 million shares, respectively, under these plans for net proceeds of approximately $18 million and $187 million, respectively.

D.      Stock-Based Compensation

In December 2004, the FASB issued SFAS No. 123R, which revises SFAS No. 123, “Accounting for Stock-Based Compensation,” and supersedes 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, net of estimated forfeitures. Previously, entities could elect to continue accounting for such awards at their grant date intrinsic value under APB Opinion No. 25, and we made that election. The intrinsic value method resulted in our recording no compensation expense for stock options granted to employees. Also, as previously allowed, we recognized the expense effects of forfeitures as they occurred. SFAS No. 123R also changes prospectively the presentation of certain stock-based compensation excess income tax benefits in the statement of cash flows, with such excess tax benefits shown as financing cash inflows rather than operating cash inflows.

We adopted SFAS No. 123R as of July 1, 2005 using the required modified prospective method. Under that method, we will record compensation expense under SFAS No. 123R for all awards granted after July 1, 2005 and will record compensation expense (as previous awards continue to vest) for the unvested portion of previously granted awards that were outstanding at July 1, 2005. For awards with graded-vesting features, we will recognize expense using the grading-vesting method alternative in SFAS No. 123R.

Progress Energy

The adoption of SFAS No. 123R resulted in our recognizing approximately $2 million of pre-tax expense for stock options during the three months ended September 30, 2005, which would not have been recognized under the prior accounting treatment. Additionally, we recognized a cumulative pre-tax benefit from the accounting change of approximately $1 million which reflects the cumulative impact of estimating forfeitures in the determination of period expense for other stock-based compensation plans, rather than recording the effect of forfeitures as they occur. As a result of the adoption of SFAS No. 123R, on a prospective basis we will not show unearned restricted shares as a negative component of common stock equity; rather, such amounts will be included in the determination of common stock presented in the Consolidated Balance Sheets. The adoption of SFAS No. 123R did not have a material impact on our income, earnings per share or our presentation of cash flows for the three months and nine months ended September 30, 2005.

The disclosures provided below are representative of annual disclosures required by SFAS No. 123R. These disclosures should be read in conjunction with plan descriptions and other pertinent information in Note 11 of our annual report on Form 10-K for the year ended December 31, 2004.

Stock Option Agreements

During 2004, we made the decision to cease granting stock options. An immaterial number of stock options were granted in 2004 and no stock options have been granted in 2005. We issue new shares to satisfy the exercise of currently outstanding stock options.

A summary of the status of our stock options as of September 30, 2005, and changes during the periods then ended, is presented below:

	Three Months Ended September 30, 2005				Nine Months Ended September 30, 2005
(option quantities in millions)	Number of  Options		Weighted-Average Exercise Price		Number of  Options		Weighted-Average Exercise Price
Options outstanding, beginning	7	.1	$43	.57	7	.4	$43	.57
Granted	—		—		—		—
Forfeited	—		$44	.10	(0	.1)	$44	.11
Canceled	—		$44	.42	(0	.2)	43	.73
Exercised	(0	.1)	$42	.72	(0	.1)	$42	.79
Options outstanding, ending	7	.0	$43	.57	7	.0	$43	.57
Options exercisable, end of period	4	.4	$43	.38	4	.4	$43	.38

The options outstanding at September 30, 2005 had a weighted-average remaining contractual life of 6.8 years and an aggregate intrinsic value of $8 million. The options exercisable at September 30, 2005 had a weighted-average remaining contractual life of 6.3 years and an aggregate intrinsic value of $6 million.

The total intrinsic value of options exercised during the three and nine months ended September 30, 2005 and the three months ended September 30, 2004 was not significant. The total intrinsic value of options exercised during the nine months ended September 30, 2004 was $1 million.

Stock option expense totaling $2 million was recognized in income during the three and nine months ended September 30, 2005, with a recognized tax benefit of $1 million. No compensation cost related to stock options was capitalized during those periods. No compensation cost was recognized for stock options prior to the adoption of FAS 123R, including the three and nine months ended September 30, 2004.

As of September 30, 2005, there was $2 million of total unrecognized compensation cost related to nonvested stock options; that cost will be recognized over one year.

Cash received from the exercise of stock options totaled $3 million and $6 million during the three and nine months ended September 30, 2005, respectively. Cash received from the exercise of stock options totaled $0.1 million and $10 million during the three and nine months ended September 30, 2004, respectively. The actual tax benefit for tax deductions from stock option exercises for the three and nine months ended September 30, 2005 and 2004 was not significant.

As previously indicated, we did not record stock option expense prior to the adoption of SFAS No. 123R as of July 1, 2005. The following table illustrates the effect on our net income and earnings per share if the fair value method had been applied to all outstanding and nonvested awards in each period:

	Three Months Ended		Nine Months Ended          September 30
(in millions except per share data)	September 30, 2004		2005		2004
Net income, as reported	$  303		$  542		$  565
Deduct: Total stock option expense determined under
fair value method for all awards, net of related
tax effects	3		2		9
Pro forma net income	$  300		$  540		$  556
Earnings per share
Basic - as reported	$1	.25	$2	.20	$2	.33
Basic - pro forma	$1	.23	$2	.19	$2	.29
Diluted - as reported	$1	.24	$2	.20	$2	.32
Diluted - pro forma	$1	.23	$2	.19	$2	.29

Other Stock-Based Compensation Plan

All outstanding awards under our Performance Share Sub-Plan (PSSP) will be settled in cash. Future awards under the PSSP will be settled in our stock. PSSP liabilities totaling $4 million were paid in the nine months ended September 30, 2005. PSSP liabilities paid during the three months ended September 30, 2005 were not significant. PSSP liabilities totaling $1 million and $8 million were paid in the three and nine months ended September 30, 2004, respectively.

Restricted stock shares are issued pursuant to our Restricted Stock Awards program. A summary of the status of the nonvested restricted stock shares as of September 30, 2005, and changes during the periods then ended, is presented below:

	Three Months Ended September 30, 2005		Weighted-Average Grant Date Fair      Value		Nine Months Ended September 30, 2005		Weighted-Average Grant Date Fair    Value
Beginning balance	646,347		$     43	.04	645,176		$     42	.32
Granted	—		—		192,800		$     42	.56
Vested	(12,699	)	$     32	.43	(109,094	)	$     37	.18
Forfeited	(4,500	)	$     44	.03	(99,734	)	$     42	.53
Ending balance	629,148		$     43	.25	629,148		$     43	.25

The weighted-average grant date fair value of restricted stock granted during the nine months ended September 30, 2004 was $46.95. No restricted stock was granted during the three months ended September 30, 2004. The total fair value of restricted stock vested during the three and nine months ended September 30, 2005 was $1 million and $5 million, respectively. The total fair value of restricted stock vested during the three and nine months ended September 30, 2004 was $1 million and $14 million, respectively. Cash expended to purchase shares for the restricted stock program totaled $8 million and $7 million during the nine months ended September 30, 2005 and 2004, respectively. There were no cash expenditures to purchase shares for the restricted stock program during the three months ended September 30, 2005 or 2004.

Our Consolidated Statements of Income included total recognized expense reversal for other stock-based compensation plans of $2 million and recognized expense of $2 million for the three and nine months ended September 30, 2005, respectively, with a recognized tax expense of $1 million and a tax benefit of $1 million, respectively. The total expense reversal recognized on our Consolidated Statements of Income for other stock-based compensation plans was $8 million for the three months ended September 30, 2004, with a recognized tax expense of $3 million. Recognized compensation expense and the related tax benefit were not significant for the nine months ended September 30, 2004. No compensation cost related to other stock-based compensation plans was capitalized.

As of September 30, 2005, there was $18 million of total unrecognized compensation cost related to nonvested other stock-based compensation plan awards; that cost is expected to be recognized over a weighted-average period of 2.6 years.

PEC

PEC participates in the Progress Energy stock option and other stock based compensation plans. The information below should be read in conjunction with the plan descriptions and other pertinent information in Note 8 of PEC’s Form 10-K for the year ended December 31, 2004.

The adoption of SFAS No. 123R resulted in the recognition of approximately $1 million of pre-tax expense for stock options for PEC, during the three months ended September 30, 2005, which would not have been recognized under the prior accounting treatment. Additionally, PEC recognized an immaterial amount of cumulative pre-tax benefit from the accounting change which reflects the cumulative impact of estimating forfeitures in the determination of period expense for other stock-based compensation plans, rather than recording the effect of forfeitures as they occur. The adoption of SFAS No. 123R did not have a material impact on PEC’s income or PEC’s presentation of cash flows for the three months and nine months ended September 30, 2005.

The following table illustrates the effect on PEC’s net income if the fair value method had been applied to all outstanding and nonvested awards in each period:

	Three Months Ended	Nine Months Ended     September 30
(in millions except per share data)	September 30, 2004	2005	2004
Net income, as reported	$175	$367	$386
Deduct: Total stock option expense determined under
fair value method for all awards, net of related
tax effects	2	2	5
Pro forma net income	$173	$365	$381

PEF

PEF participates in the Progress Energy stock option and other stock based compensation plans. The information below should be read in conjunction with the plan descriptions and other pertinent information in Note 11 of PEF’s Form 10-K for the year ended December 31, 2004.

The adoption of SFAS No. 123R resulted in the recognition of approximately $1 million of pre-tax expense for stock options for PEF, during the three months ended September 30, 2005, which would not have been recognized under the prior accounting treatment. Additionally, PEF recognized an immaterial amount of cumulative pre-tax benefit from the accounting change which reflects the cumulative impact of estimating forfeitures in the determination of period expense for other stock-based compensation plans, rather than recording the effect of forfeitures as they occur. The adoption of SFAS No. 123R did not have a material impact on PEF’s income or PEF’s presentation of cash flows for the three months and nine months ended September 30, 2005.

The following table illustrates the effect on PEF’s net income if the fair value method had been applied to all outstanding and nonvested awards in each period:

		Nine Months Ended          September 30
(in millions except per share data)	Three Months Ended September 30, 2004	2005	2004
Net income, as reported	$140	$205	$274
Deduct: Total stock option expense determined under
fair value method for all awards, net of related
tax effects	1	1	2
Pro forma net income	$139	$204	$272

7.   DEBT AND CREDIT FACILITIES AND FINANCING ACTIVITIES

Changes to Progress Energy’s, PEC’s and PEF’s debt and credit facilities and financing activities since December 31, 2004, discussed in Note 13 of our 2004 annual report on Form 10-K, Note 9 of PEC’s 2004 annual report on Form 10-K, and Note 12 of PEF’s 2004 annual report on Form 10-K, respectively, are described below.

In January 2005, Progress Energy used proceeds from the issuance of commercial paper to pay off $260 million of revolving credit agreement (RCA) loans at the Utilities, which included $90 million at PEC and $170 million at PEF. PEF subsequently used money pool borrowings to reduce its outstanding commercial paper balance.

On January 31, 2005, Progress Energy entered into a new $600 million RCA, which was scheduled to expire on December 30, 2005. This facility was added to provide additional liquidity, to the extent necessary, during 2005 due in part to the uncertainty of the timing of storm restoration cost recovery from the hurricanes in Florida during 2004. On February 4, 2005, $300 million was drawn under the new facility to reduce commercial paper and pay off the remaining amount of loans outstanding under other RCA facilities, which consisted of $160 million at Progress Energy and, through the money pool, $55 million at PEF. As discussed below, the maximum size of this RCA was reduced to $300 million on March 22, 2005 and subsequently terminated on May 16, 2005.

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

In March 2005, Progress Energy’s $1.1 billion five-year credit facility was amended to increase the maximum total debt to total capital ratio from 65% to 68% due to the potential impacts of a proposed interpretation of SFAS No. 109 regarding accounting rules for uncertain tax positions (See Note 2).

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

On March 28, 2005, PEC entered into a new $450 million five-year RCA with a syndication of financial institutions. The PEC RCA will be used to provide liquidity support for PEC’s issuances of commercial paper and other short-term obligations. The PEC RCA is scheduled to expire on June 28, 2010. The new $450 million PEC RCA replaced PEC’s $285 million three-year RCA and $165 million 364-day RCA, which were each terminated effective March 28, 2005. Fees and interest rates under the new PEC RCA are to be determined based upon the credit rating of PEC’s long-term unsecured senior non-credit enhanced debt, currently rated as Baa1 by Moody’s and BBB by S&P. The PEC RCA includes a defined maximum total debt to capital ratio of 65%. The RCA also contains various cross-default and other acceleration provisions, including a cross-default provision for defaults of indebtedness in excess of $35 million. The PEC RCA does not include a material adverse change representation for borrowings, which had been a provision in the terminated agreements.

In May 2005, Progress Energy used proceeds from the issuance of commercial paper to pay off $300 million of its $600 million RCA.

On May 16, 2005, PEF issued $300 million of First Mortgage Bonds, 4.50% Series due 2010. The net proceeds from the sale of the bonds were used to reduce the outstanding balance of commercial paper. Pursuant to the terms of the Progress Energy $600 million RCA, commitments were completely reduced and the RCA was terminated, effective May 16, 2005.

On July 1, 2005, PEF paid at maturity $45 million of its 6.72% Medium-Term Notes, Series B with commercial paper proceeds.

On July 28, 2005, PEC filed a shelf registration statement with the SEC to provide an additional $1.0 billion of capacity in addition to the $400 million remaining on PEC’s current shelf registration statement. The shelf registration statement, when declared effective, will allow PEC to issue various securities, including First Mortgage Bonds, Senior Notes, Debt Securities and Preferred Stock.

On July 28, 2005, PEF filed a shelf registration statement with the SEC to provide an additional $1.0 billion of capacity in addition to the $450 million remaining on PEF’s current shelf registration statement. The shelf registration statement, when declared effective, will allow PEF to issue various securities, including First Mortgage Bonds, Debt Securities and Preferred Stock.

8.  CONDENSED CONSOLIDATING STATEMENTS

Presented below are the condensed consolidating Statements of Income, Balance Sheets and Cash Flows as required by Rule 3-10 of Regulation S-X. In September 2005, we issued our guarantee of certain payments of two wholly owned indirect subsidiaries, FPC Capital I (the Trust) and Florida Progress Funding Corporation (Funding Corp.). Our guarantees are in addition to the previously issued guarantees of our wholly owned subsidiary, Florida Progress Corporation (Florida Progress).

The Trust, a finance subsidiary, was established in 1999 for the sole purpose of issuing $300 million of 7.10% Cumulative Quarterly Income Preferred Securities due 2039, Series A (Preferred Securities) and using the proceeds thereof to purchase from Funding Corp. $300 million of 7.10% Junior Subordinated Deferrable Interest Notes due 2039 (Subordinated Notes). The Trust has no other operations and its sole assets are the Subordinated Notes and Notes Guarantee (as discussed below). Funding Corp. is a wholly owned subsidiary of Florida Progress and was formed for the sole purpose of providing financing to Florida Progress and its subsidiaries. Funding Corp. does not engage in business activities other than such financing and has no independent operations. Since 1999, Florida Progress has fully and unconditionally guaranteed the obligations of Funding Corp. under the Subordinated Notes (the Notes Guarantee). In addition, Florida Progress 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 (the Preferred Securities Guarantee). The Preferred Securities Guarantee, considered together with the Notes Guarantee, constitutes a full and unconditional guarantee by Florida Progress of the Trust’s obligations under the Preferred Securities. The Preferred Securities and Preferred Securities Guarantee are listed on the New York Stock Exchange.

We have guaranteed the payment of all distributions related to the Trust’s Preferred Securities. As of September 30, 2005, the Trust had outstanding 12 million shares of the Preferred Securities with a liquidation value of $300 million. Our guarantees are joint and several, full and unconditional and are in addition to the joint and several, full and unconditional guarantees previously issued to the Trust and Funding Corp. by Florida Progress. Our subsidiaries have provisions restricting the payment of dividends to the Parent in certain limited circumstances and as disclosed in Note 13B of our annual report on Form 10-K for the year ended December 31, 2004, there were no restrictions on PEC’s or PEF’s retained earnings.

The Trust is a special-purpose entity and in accordance with the provisions of FIN No. 46, we deconsolidated the Trust on December 31, 2003. The deconsolidation was not material to our financial statements and resulted in recording an additional equity investment in the Trust of approximately $9 million, an increase in outstanding debt of approximately $8 million and a gain of approximately $1 million relating to the cumulative effect of a change in accounting principle. Separate financial statements and other disclosures concerning the Trust have not been presented because we believe that such information is not material to investors.

In the following tables, the Parent column includes the financial results of the parent holding company only. The Subsidiary Guarantor column includes the financial results of Florida Progress. The Other column includes the consolidated financial results of all other non-guarantor subsidiaries and elimination entries for all intercompany transactions. All applicable corporate expenses have been allocated appropriately among the guarantor and non-guarantor subsidiaries.

Condensed Consolidating Statement of Income
Three Months Ended September 30, 2005

(in millions)	Parent	Subsidiary Guarantor		Other		Progress Energy,   Inc.
Operating revenues
Utility	$    —	$ 1,227		$ 1,185		$ 2,412
Diversified business	—	453		232		685
Total operating revenues	—	1,680		1,417		3,097
Operating expenses
Utility
Fuel used in electric generation	—	351		282		633
Purchased power	—	270		154		424
Operation and maintenance	2	181		225		408
Depreciation and amortization	—	95		137		232
Taxes other than on income	—	82		49		131
Other	—	1		—		1
Diversified business
Cost of sales	—	402		260		662
Other	—	45		24		69
Total operating expenses	2	1,427		1,131		2,560
Equity in earnings of consolidated
subsidiaries	494	—		(494	)	—
Other income (expense), net	15	(2	)	—		13
Interest charges, net	70	39		53		162
Income (loss) from continuing operations
before income tax and minority interest	437	212		(261	)	388
Income tax benefit	13	39		3		55
Minority interest in subsidiaries' loss, net of tax	—	7		—		7
Income (loss) from continuing operations	450	258		(258	)	450
Discontinued operations, net of tax	—	(1	)	—		(1	)
Income (loss) before cumulative effect of
change in accounting principle	450	257		(258	)	449
Cumulative effect of change in accounting
principle, net of tax	—	—		1		1
Net income (loss)	$450	$    257		$  (257	)	$    450

Condensed Consolidating Statement of Income
Three Months Ended September 30, 2004

(in millions)	Parent		Subsidiary Guarantor	Other		Progress Energy,    Inc.
Operating revenues
Utility	$     —		$1,029	$ 1,014		$2,043
Diversified business	—		350	77		427
Total operating revenues	—		1,379	1,091		2,470
Operating expenses
Utility
Fuel used in electric generation	—		335	221		556
Purchased power	—		173	96		269
Operation and maintenance	2		138	184		324
Depreciation and amortization	—		68	145		213
Taxes other than on income	(2	)	70	46		114
Diversified business
Cost of sales	—		307	43		350
Other	—		47	34		81
Total operating expenses	—		1,138	769		1,907
Equity in earnings of consolidated subsidiaries	339		—	(339	)	—
Other income (expense), net	33		1	(3	)	31
Interest charges, net	73		37	44		154
Income (loss) from continuing operations
before income tax and minority interest	299		205	(64	)	440
Income tax (benefit) expense	(4	)	74	84		154
Minority interest in subsidiaries' loss, net of tax	—		6	—		6
Income (loss) from continuing operations	303		137	(148	)	292
Discontinued operations, net of tax	—		11	—		11
Net income (loss)	$ 303		$   148	$  (148	)	$   303

Condensed Consolidating Statement of Income
Nine Months Ended September 30, 2005

(in millions)	Parent		Subsidiary Guarantor		Other		Progress Energy,    Inc.
Operating revenues
Utility	$     —		$ 2,983		$ 2,980		$ 5,963
Diversified business	—		1,245		420		1,665
Total operating revenues	—		4,228		3,400		7,628
Operating expenses
Utility
Fuel used in electric generation	—		966		746		1,712
Purchased power	—		545		294		839
Operation and maintenance	11		658		688		1,357
Depreciation and amortization	—		236		411		647
Taxes other than on income	4		215		137		356
Other	—		(24	)	—		(24	)
Diversified business
Cost of sales	—		1,129		467		1,596
Other	—		135		79		214
Total operating expenses	15		3,860		2,822		6,697
Equity in earnings of consolidated subsidiaries	682		—		(682	)	—
Other income (expense), net	49		(6	)	(26	)	17
Interest charges, net	225		131		133		489
Income (loss) from continuing operations
before income tax and minority interest	491		231		(263	)	459
Income tax (benefit) expense	(51	)	(50	)	23		(78	)
Minority interest in subsidiaries' loss, net of tax	—		24		—		24
Income (loss) from continuing operations	542		305		(286	)	561
Discontinued operations, net of tax	—		(37	)	17		(20	)
Income (loss) before cumulative effect of
change in accounting principle	542		268		(269	)	541
Cumulative effect of change in accounting
principle, net of tax	—		—		1		1
Net income (loss)	$ 542		$    268		$  (268	)	$    542

Condensed Consolidating Statement of Income
Nine Months Ended September 30, 2004

(in millions)	Parent		Subsidiary Guarantor		Other		Progress Energy,  Inc.
Operating revenues
Utility	$     —		$ 2,673		$ 2,776		$5,449
Diversified business	—		985		165		1,150
Total operating revenues	—		3,658		2,941		6,599
Operating expenses
Utility
Fuel used in electric generation	—		880		637		1,517
Purchased power	—		433		238		671
Operation and maintenance	8		450		601		1,059
Depreciation and amortization	—		209		413		622
Taxes other than on income	(2	)	196		134		328
Diversified business
Cost of sales	—		871		178		1,049
Other	—		128		97		225
Total operating expenses	6		3,167		2,298		5,471
Equity in earnings of consolidated subsidiaries	710		—		(710	)	—
Other income (expense), net	44		(4	)	(28	)	12
Interest charges, net	221		119		129		469
Income (loss) from continuing operations
before income tax and minority interest	527		368		(224	)	671
Income tax (benefit) expense	(38	)	61		117		140
Minority interest in subsidiaries' loss, net of tax	—		6		—		6
Income (loss) from continuing operations	565		313		(341	)	537
Discontinued operations, net of tax	—		25		3		28
Net income (loss)	$ 565		$    338		$  (338	)	$   565

Condensed Consolidating Balance Sheet
September 30, 2005

(in millions)	Parent	Subsidiary  Guarantor	Other		Progress Energy,   Inc.
Utility plant, net	$         —	$5,717	$   8,605		$14,322
Current assets
Cash and cash equivalents	115	36	54		205
Receivables, net	—	605	595		1,200
Deferred fuel cost	—	278	257		535
Other current assets	939	632	(320	)	1,251
Total current assets	1,054	1,551	586		3,191
Deferred debits and other assets
Investment in consolidated subsidiaries	11,391	—	(11,391	)	—
Miscellaneous other property and investments	—	101	388		489
Goodwill	—	2	3,717		3,719
Other assets and deferred debits	13	2,168	2,636		4,817
Total deferred debits and other assets	11,404	2,271	(4,650	)	9,025
Total assets	$12,458	$9,539	$   4,541		$26,538
Capitalization
Common stock equity	$  7,903	$2,901	$(2,901	)	$  7,903
Preferred stock of subsidiaries-not
subject to mandatory redemption	—	34	59		93
Minority interest	—	36	5		41
Long-term debt, affiliate	—	440	(170	)	270
Long-term debt, net	3,477	2,248	3,264		8,989
Total capitalization	11,380	5,659	257		17,296
Current liabilities
Current portion of long-term debt	803	49	—		852
Short-term obligations	38	292	187		517
Other current liabilities	215	1,367	456		2,038
Total current liabilities	1,056	1,708	643		3,407
Deferred credits and other liabilities
Noncurrent income tax liabilities	—	57	342		399
Regulatory liabilities	—	1,231	1,369		2,600
Accrued pension and other benefits	12	328	705		1,045
Other liabilities and deferred credits	10	556	1,225		1,791
Total deferred credits and other liabilities	22	2,172	3,641		5,835
Total capitalization and liabilities	$12,458	$9,539	$   4,541		$26,538

Condensed Consolidating Balance Sheet
December 31, 2004

(in millions)	Parent	Subsidiary Guarantor	Other		Progress Energy,   Inc.
Utility plant, net	$       —	$5,882	$   8,481		$14,363
Current assets
Cash and cash equivalents	5	24	27		56
Receivables, net	—	476	435		911
Deferred fuel cost	—	89	140		229
Assets of discontinued operations	—	590	(13	)	577
Other current assets	1,438	474	(737	)	1,175
Total current assets	1,443	1,653	(148	)	2,948
Deferred debits and other assets
Investment in consolidated subsidiaries	11,061	—	(11,061	)	—
Miscellaneous other property and investments	—	95	349		444
Goodwill	—	2	3,717		3,719
Other assets and deferred debits	16	2,053	2,476		4,545
Total deferred debits and other assets	11,077	2,150	(4,519	)	8,708
Total assets	$12,520	$9,685	$   3,814		$26,019
Capitalization
Common stock equity	$  7,633	$2,681	$(2,681	)	$  7,633
Preferred stock of subsidiaries-not
subject to mandatory redemption	—	34	59		93
Minority interest	—	32	4		36
Long-term debt, affiliate	—	809	(539	)	270
Long-term debt, net	4,449	2,052	2,750		9,251
Total capitalization	12,082	5,608	(407	)	17,283
Current liabilities
Current portion of long-term debt	—	49	300		349
Short-term obligations	170	293	221		684
Liabilities of discontinued operations	—	152	—		152
Other current liabilities	245	1,376	256		1,877
Total current liabilities	415	1,870	777		3,062
Deferred credits and other liabilities
Noncurrent income tax liabilities	—	64	561		625
Regulatory liabilities	—	1,362	1,292		2,654
Accrued pension and other benefits	10	249	375		634
Other liabilities and deferred credits	13	532	1,216		1,761
Total deferred credits and other liabilities	23	2,207	3,444		5,674
Total capitalization and liabilities	$12,520	$9,685	$   3,814		$26,019

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2005

(in millions)	Parent		Subsidiary  Guarantor		Other		Progress Energy,    Inc.
Net cash provided by operating activities	$    168		$ 334		$    433		$    935
Investing activities
Gross utility property additions	—		(336	)	(436	)	(772	)
Diversified business property additions	—		(149	)	(18	)	(167	)
Nuclear fuel additions	—		(46	)	(52	)	(98	)
Proceeds from sales of subsidiaries and
other investment, net of cash divested	—		450		9		459
Purchases of short-term investments	(1,705	)	—		(1,160	)	(2,865	)
Proceeds from sales of short-term investments	1,705		—		1,242		2,947
Changes in advances to affiliates	496		1		(497	)	—
Other	(11	)	(21	)	(27	)	(59	)
Net cash provided by (used in) investing activities	485		(101	)	(939	)	(555	)
Financing activities
Issuance of common stock	193		—		—		193
Issuance of long-term debt	—		297		495		792
Net decrease in short-term indebtedness	(132	)	(1	)	(34	)	(167	)
Retirement of long-term debt	(160	)	(101	)	(301	)	(562	)
Dividends paid on common stock	(435	)	—		—		(435	)
Changes in advances from affiliates	—		(414	)	414		—
Other	(9	)	28		(41	)	(22	)
Net cash (used in) provided by financing activities	(543	)	(191	)	533		(201	)
Cash used by discontinued operations
Operating activities	—		(26	)	—		(26	)
Investing activities	—		(4	)	—		(4	)
Financing activities	—		—		—		—
Net increase in cash and cash equivalents	110		12		27		149
Cash and cash equivalents at beginning of period	5		24		27		56
Cash and cash equivalents at end of period	$    115		$   36		$      54		$    205

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2004

(in millions)	Parent		Subsidiary  Guarantor		Other		Progress Energy,    Inc.
Net cash provided by operating activities	$ 305		$ 547		$    415		$ 1,267
Investing activities
Gross utility property additions	—		(336	)	(355	)	(691	)
Diversified business property additions	—		(126	)	(14	)	(140	)
Nuclear fuel additions	—		—		(63	)	(63	)
Proceeds from sales of subsidiaries and
other investment, net of cash divested	—		93		19		112
Purchases of short-term investments	—		—		(816	)	(816	)
Proceeds from sales of short-term investments	—		—		1,042		1,042
Changes in advances to affiliates	382		—		(382	)	—
Other	(15	)	(20	)	(8	)	(43	)
Net cash provided by (used in) investing activities	367		(389	)	(577	)	(599	)
Financing activities
Issuance of common stock	59		—		—		59
Issuance of long-term debt	—		1		—		1
Net increase in short-term indebtedness	199		323		142		664
Retirement of long-term debt	(500	)	(66	)	(339	)	(905	)
Dividends paid on common stock	(418	)	—		—		(418	)
Dividends paid to parent	—		(117	)	117		—
Changes in advances from affiliates	—		(300	)	300		—
Other	(8	)	17		(57	)	(48	)
Net cash (used in) provided by financing activities	(668	)	(142	)	163		(647	)
Cash provided (used) by discontinued operations
Operating activities	—		16		—		16
Investing activities	—		(16	)	—		(16	)
Financing activities	—		—		—		—
Net increase in cash and cash equivalents	4		16		1		21
Cash and cash equivalents at beginning of period	—		15		20		35
Cash and cash equivalents at end of period	$     4		$   31		$      21		$      56

9.  BENEFIT PLANS

We have a noncontributory defined benefit retirement plan for substantially all full-time employees that provides pension benefits. We also have supplementary defined benefit pension plans that provide benefits to higher-level employees. In addition to pension benefits, we provide contributory other postretirement benefits (OPEB), including certain health care and life insurance benefits, for retired employees who meet specified criteria. The components of the net periodic benefit cost for the respective Progress Registrants for the three and nine months ended September 30 are:

Progress Energy

	Pension Benefits				Other Postretirement       Benefits
Three Months Ended September 30 (in millions)	2005		2004		2005		2004
Service cost	$   5		$ 14		$ —		$ 1
Interest cost	31		27		9		6
Expected return on plan assets	(34	)	(41	)	(1	)	(2	)
Amortization of actuarial loss	14		4		4		1
Other amortization, net	—		—		1		—
Net periodic cost	$ 16		$   4		$ 13		$ 6
Additional cost / (benefit) recognition (a)	(3	)	(4	)	—		1
Net periodic cost recognized	$ 13		$ —		$ 13		$ 7

	Pension Benefits				Other Postretirement       Benefits
Nine Months Ended September 30 (in millions)	2005		2004		2005		2004
Service cost	$   35		$   40		$   6		$   9
Interest cost	88		82		25		23
Expected return on plan assets	(107	)	(116	)	(4	)	(4	)
Amortization of actuarial loss	26		16		6		3
Other amortization, net	1		—		2		1
Net periodic cost	$   43		$   22		$ 35		$ 32
Additional cost / (benefit) recognition (a)	(11	)	(12	)	1		2
Net periodic cost recognized	$   32		$   10		$ 36		$ 34

(a)        Relates to the acquisition of Florida Progress. See Note 17B of Progress Energy’s annual report on Form 10-K for year ended December 31, 2004.

Additionally, in the second quarter of 2005, we recorded costs for special termination benefits related to the voluntary enhanced retirement program (see Note 11) of approximately $122 million for pension benefits and $19 million for other postretirement benefits. In the third quarter of 2005, we recorded an additional $1 million in special termination charges for pension benefits.

Due to the effects of the voluntary enhanced retirement program and related remeasurement of pension assets and liabilities, in the third quarter of 2005, we recorded an additional minimum pension liability adjustment of $259 million. This adjustment resulted in a $143 million charge to a regulatory asset pursuant to a FPSC order and a pre-tax charge of $116 million to accumulated other comprehensive loss, a component of common stock equity. At September 30, 2005, pension and OPEB liabilities are included in other liabilities and deferred credits in the Consolidated Balance Sheets, and there is no prepaid pension cost recognized.

PEC

			Pension Benefits				Other Postretirement       Benefits
Three Months Ended September 30 (in millions)	2005		2004		2005		2004
Service cost	$   3		$   6		$ —		$ 1
Interest cost	13		13		5		3
Expected return on plan assets	(14	)	(18	)	(1	)	(1	)
Amortization of actuarial loss	5		—		3		—
Other amortization, net	—		—		—		—
Net periodic cost	$   7		$   1		$ 7		$ 3

			Pension Benefits				Other Postretirement       Benefits
Nine Months Ended September 30 (in millions)	2005		2004		2005		2004
Service cost	$ 17		$ 18		$   3		$   5
Interest cost	40		39		13		11
Expected return on plan assets	(46	)	(52	)	(3	)	(3	)
Amortization of actuarial loss	7		1		3		1
Other amortization, net	1		—		1		1
Net periodic cost	$ 19		$   6		$ 17		$ 15

Additionally, in the second quarter of 2005, PEC recorded costs for special termination benefits related to the voluntary enhanced retirement program (see Note 11) of approximately $21 million for pension benefits and $8 million for other postretirement benefits. These charges resulted in a $29 million increase in pension and OPEB liabilities, which are included in other liabilities and deferred credits on the Consolidated Balance Sheets.

Due to the effects of the voluntary enhanced retirement program and related remeasurement of pension assets and liabilities, in the third quarter of 2005, PEC recorded an additional minimum pension liability adjustment of $89 million. This adjustment resulted in a corresponding pre-tax charge to accumulated other comprehensive loss, a component of common stock equity.

PEF

			Pension Benefits			Other Postretirement       Benefits
Three Months Ended September 30 (in millions)	2005		2004		2005	2004
Service cost	$   1		$   5		$—	$1
Interest cost	13		11		3	2
Expected return on plan assets	(17	)	(20	)	—	—
Amortization of actuarial loss	4		—		1	—
Other amortization, net	—		—		1	1
Net periodic cost	$   1		$(4	)	$5	$4

			Pension Benefits				Other Postretirement       Benefits
Nine Months Ended September 30 (in millions)	2005		2004		2005		2004
Service cost	$ 12		$ 16		$   3		$   3
Interest cost	36		32		10		10
Expected return on plan assets	(53	)	(55	)	(1	)	(1	)
Amortization of actuarial loss	6		2		1		1
Other amortization, net	(1	)	(1	)	3		3
Net periodic cost	$ —		$(6	)	$ 16		$ 16

Additionally, in the second quarter of 2005, PEF recorded costs for special termination benefits related to the voluntary enhanced retirement program (see Note 11) of approximately $83 million for pension benefits and $7 million for other postretirement benefits. In the third quarter of 2005, PEF recorded an additional $1 million in special termination charges for pension benefits.

Due to the effects of the voluntary enhanced retirement program and related remeasurement of pension assets and liabilities, in the third quarter of 2005, PEF recorded an additional minimum pension liability adjustment of $26 million. This adjustment resulted in $25 million charge to a regulatory asset pursuant to a FPSC order and a $1 million charge to intangible assets, included in other assets and deferred debits. At September 30, 2005, PEF recognized prepaid pension costs in the Balance Sheets related to the nonbargaining plan; pension and OPEB liabilities are included in other liabilities and deferred credits.

10.   RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS

We are exposed to various risks related to changes in market conditions. We have a risk management committee that includes senior executives from various business groups. The risk management committee is responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Under our risk policy, we 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. We minimize such risk by performing credit reviews using, among other things, publicly available credit ratings of such counterparties. Potential nonperformance by counterparties is not expected to have a material effect on our financial position or results of operations. See Note 18 to our annual report on Form 10-K, Note 13 to PEC’s annual report on Form 10-K and Note 16 to PEF’s annual report on Form 10-K, respectively, for the year ended December 31, 2004.

A.     Commodity Derivatives

General

Most of our commodity contracts are not derivatives pursuant to SFAS No. 133, “Accounting for Derivative and Hedging Activities” (SFAS No. 133) or qualify as normal purchases or sales pursuant to SFAS No. 133. Therefore, such contracts are not recorded at fair value.

In 2003, PEC recorded a $38 million pre-tax ($23 million after-tax) fair value loss transition adjustment pursuant to the provisions of DIG Issue C20, “Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.” The related liability is being amortized to earnings over the term of the related contract (See Note 13). As of September 30, 2005 and December 31, 2004, the remaining liability was $20 million and $26 million, respectively.

Economic Derivatives

Derivative products, primarily electricity and natural gas contracts, may be entered into from time to time for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions. We manage open positions with strict policies that limit our exposure to market risk and require daily reporting to management of potential financial exposures. We recorded a pre-tax loss of $7 million and a pre-tax gain of $13 million on such contracts for the three months ended September 30, 2005 and 2004, respectively. We recorded pre-tax losses of $5 and $1 million on such contracts for the nine months ended September 30, 2005 and 2004, respectively. Gains and losses from such contracts at the Utilities were not material to results of operations during the three and nine months ended September 30, 2005. PEC did not have material outstanding positions in such contracts as of September 30, 2005 and December 31, 2004. We and PEF did not have material outstanding positions in such contracts as of September 30, 2005 and December 31, 2004, other than those receiving regulatory accounting treatment at PEF, as discussed below.

PEF has derivative instruments related to its exposure to price fluctuations on fuel oil and natural gas purchases. These instruments receive regulatory accounting treatment. Unrealized gains and losses are recorded in regulatory liabilities and regulatory assets, respectively, until the contracts are settled. Once settled, any realized gains or losses are passed through the fuel clause. As of September 30, 2005, the fair values of these instruments were a $105 million short-term derivative asset position included in other current assets, a $45 million long-term derivative asset position included in other assets and deferred debits and a $2 million long-term derivative liability position included in other liabilities and deferred credits. As of 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.

Cash Flow Hedges

Our 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 and power for our forecasted purchases and sales. Realized gains and losses are recorded net in operating revenues or operating expenses, as appropriate. The ineffective portion of commodity cash flow hedges for the three and nine months ending September 30, 2005 and 2004, was not material to our results of operations.

The fair values of our commodity cash flow hedges as of September 30, 2005 and December 31, 2004, were as follows:  

	September 30, 2005				December 31, 2004
(in millions)	Progress  Energy		PEC	PEF	Progress  Energy		PEC	PEF
Fair value of assets	$ 119		$—	$—	$ —		$—	$—
Fair value of liabilities	(100	)	—	—	(15	)	—	—
Fair value, net	$   19		$—	$—	$(15	)	$—	$—

The following table presents selected information related to our commodity cash flow hedges as of September 30, 2005:

	Maximum Term (a)			Accumulated Other     Comprehensive Income/(Loss), net of tax			Portion Expected to be    Reclassified to  Earnings during the   Next 12 Months(b)
(term in years/ millions of dollars)	Progress  Energy	PEC	PEF	Progress  Energy	PEC	PEF	Progress  Energy		PEC	PEF
Commodity cash flow
hedges	10	1	$—	$10	$—	$—	$(47	)	$—	$—

(a)
   
(b)
   
    Hedges in fair value liability positions primarily have a maximum term of less than two
years and hedges in fair value asset positions primarily have a maximum term of 10 years.
Due to the volatility of the commodities markets, the value in accumulated other
comprehensive income/(loss) (OCI) is subject to change prior to its reclassification into
earnings.

As of September 30, 2005, PEC had an immaterial amount of open commodity cash flow hedges and an immaterial amount recorded in OCI related to commodity cash flow hedges. As of December 31, 2004, the Utilities had no open commodity cash flow hedges or amounts recorded in OCI related to commodity cash flow hedges.

B.      Interest Rate Derivatives - Fair Value or Cash Flow Hedges

We use cash flow hedging strategies to reduce exposure to changes in cash flow due to fluctuating interest rates. We use fair value hedging strategies to reduce exposure to changes in fair value due to interest rate changes. The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss. In the event of default by the counterparty, the risk in these transactions is the cost of replacing the agreements at current market rates.

The fair values of interest rate hedges as of September 30, 2005 and December 31, 2004, were as follows:

	September 30, 2005				December 31, 2004
(in millions)	Progress  Energy		PEC	PEF	Progress  Energy		PEC		PEF
Interest rate cash flow hedges	$ —		$—	$—	$(2	)	$(2	)	$—
Interest rate fair value hedges	$(1	)	$—	$—	$ 3		$ —		$—

Cash Flow Hedges

Gains and losses from cash flow hedges are recorded in OCI and amounts reclassified to earnings are included in net interest charges as the hedged transactions occur. Amounts in OCI related to terminated hedges are reclassified to earnings as the interest expense is recorded. The ineffective portion of interest rate cash flow hedges for the three and nine months ending September 30, 2005 and 2004, was not material to results of operations.

The following table presents selected information related to interest rate cash flow hedges included in OCI as of September 30, 2005:

	Maximum Term			Accumulated Other     Comprehensive Income/(Loss), net of tax(a)					Portion Expected to be    Reclassified to  Earnings during the   Next 12 Months(b)
(term in years/ millions of dollars)	Progress  Energy	PEC	PEF	Progress  Energy		PEC		PEF	Progress  Energy		PEC	PEF
Interest rate cash
flow hedges	1	$—	$—	$(14	)	$(5	)	$—	$(2	)	$—	$—

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

As of September 30, 2005 and December 31, 2004, we had $300 million notional and $331 million notional, respectively, of interest rate cash flow hedges. The Utilities had no open interest rate cash flow hedges at September 30, 2005. As of December 31, 2004, PEC had $131 million notional of open interest rate cash flow hedges and PEF had no open interest rate cash flow hedges.

Fair Value Hedges

For interest rate fair value hedges, the change in the fair value of the hedging derivative is recorded in net interest charges and is offset by the change in the fair value of the hedged item. As of September 30, 2005 and December 31, 2004, we had $150 million notional of interest rate fair value hedges. As of September 30, 2005 and December 31, 2004, the Utilities had no open interest rate fair value hedges.

11.  SEVERANCE COSTS

On February 28, 2005, as part of a previously announced cost management initiative, we approved a workforce restructuring which resulted in a reduction of approximately 450 positions. The cost management initiative is designed to permanently reduce by $75 million to $100 million our projected growth in annual O&M expenses by the end of 2007. In addition to the workforce restructuring, the cost management initiative included a voluntary enhanced retirement program. In connection with this initiative, we incurred approximately $177 million of pre-tax charges for severance and postretirement benefits during the nine months ended September 30, 2005, as described below.

The cost management initiative charges are subject to revision in future quarters based on completion of the workforce restructuring and the potential additional impacts that the early retirements and outplacements may have on our postretirement plans. Such revisions may be significant and may adversely impact our results of operations in future periods. In addition, we expect to incur certain incremental costs for recruiting and staff augmentation activities that cannot be quantified at this time.

Progress Energy

We recorded $31 million of severance expense during the first quarter of 2005 for the workforce restructuring and implementation of an automated meter reading initiative at PEF based on the approximate number of positions to be eliminated. During the second quarter of 2005, 1,447 employees eligible for participation in the voluntary enhanced retirement program elected to participate. Consequently, in the second quarter of 2005, we decreased our estimated severance costs by $13 million due to the impact of the employees electing participation in the voluntary enhanced retirement program. The severance expenses are primarily included in O&M expense on the Consolidated Statements of Income.

The accrued severance expense will be paid over time. The activity in the severance liability is as follows:

(in millions)
Balance as of January 1, 2005	$   5
Severance costs accrued	31
Adjustments	(13	)
Payments	(2	)
Balance as of September 30, 2005	$ 21

During 2005, we recorded a $141 million charge in the second quarter and a $1 million charge in the third quarter related to postretirement benefits that will be paid over time to eligible employees who elected to participate in the voluntary enhanced retirement program (see Note 9). In addition, we recorded a $17 million charge for early retirement incentives to be paid over time to certain employees.

PEC

In connection with the cost management initiative, PEC incurred approximately $60 million of pre-tax charges for severance and postretirement benefits during the nine months ended September 30, 2005, as described below.

PEC recorded $14 million of severance expense during the first quarter of 2005 for the workforce restructuring based on the approximate number of positions to be eliminated. This amount included approximately $4 million of severance costs allocated from Progress Energy Service Company (PESC). During the second quarter of 2005, 553 PEC employees eligible for participation in the voluntary enhanced retirement program elected to participate. Consequently, in the second quarter of 2005, PEC decreased its estimated severance costs by $6 million due to the impact of the employees electing participation in the voluntary enhanced retirement program. This amount included approximately $2 million of decreased severance costs allocated from PESC. The severance expenses are primarily included in O&M expense on the Consolidated Statements of Income.

The accrued severance expense will be paid over time. The activity in the severance liability is as follows:

(in millions)
Balance as of January 1, 2005	$   2
Severance costs accrued	10
Adjustments	(4	)
Payments	(1	)
Balance as of September 30, 2005	$   7

PEC recorded a $29 million charge in the second quarter of 2005 related to postretirement benefits that will be paid over time to eligible employees who elected to participate in the voluntary enhanced retirement program (see Note 9). PEC also recorded a $13 million charge for early retirement incentives which will be paid over time to certain employees. In addition, PEC recorded approximately $10 million of postretirement benefits and early retirement incentives allocated from PESC during the nine months ended September 30, 2005.

PEF

In connection with the cost management initiative, PEF incurred approximately $108 million of pre-tax charges for severance and postretirement benefits during the nine months ended September 30, 2005, as described below.

PEF recorded $14 million of severance expense during the first quarter of 2005 for the workforce restructuring and implementation of an automated meter reading initiative at PEF based on the approximate number of positions to be eliminated. This amount included approximately $3 million of severance costs allocated from PESC. During the second quarter of 2005, 680 of PEF’s employees eligible for participation in the voluntary enhanced retirement program elected to participate. Consequently, in the second quarter of 2005, PEF decreased its estimated severance costs by $5 million due to the impact of the employees electing participation in the voluntary enhanced retirement program. This amount included approximately $1 million of decreased severance costs allocated from PESC. The severance expenses are primarily included in O&M expense on the Statements of Income.

The accrued severance expense will be paid over time. The activity in the severance liability is as follows:

(in millions)
Balance as of January 1, 2005	$ —
Severance costs accrued	11
Adjustments	(4	)
Payments	—
Balance as of September 30, 2005	$   7

During 2005, PEF recorded a $90 million charge in the second quarter and a $1 million charge in the third quarter related to postretirement benefits that will be paid over time to eligible employees who elected to participate in the voluntary enhanced retirement program (see Note 9). In addition, PEF recorded approximately $8 million of charges for postretirement benefits and early retirement incentives allocated from PESC during the nine months ended September 30, 2005.

12.  FINANCIAL INFORMATION BY BUSINESS SEGMENT

Our reportable segments are: PEC Electric, PEF, CCO, Fuels and Synthetic Fuels.

PEC Electric and PEF are primarily engaged in the generation, transmission, distribution and sale of electric energy in portions of (i) North Carolina and South Carolina and (ii) Florida, respectively. These electric operations are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC), the NCUC, the SCPSC, the FPSC and the NRC. These electric operations also distribute and sell electricity to other utilities, primarily on the east coast of the United States.

CCO is primarily engaged in nonregulated electric generation operations and marketing activities in Georgia, North Carolina and Florida.

Fuels is engaged in natural gas drilling and production in Texas and Louisiana, coal mining, coal terminal services and fuel transportation and delivery in Kentucky, West Virginia and Virginia. This segment also has an operating fee agreement with our Synthetic Fuel operations for the procuring and processing of coal and the transloading and marketing of synthetic fuel.

Synthetic Fuel operations include the production and sale of coal-based solid synthetic fuel (as defined under the Code) and the operation of synthetic fuel facilities for outside parties in West Virginia, Virginia and Kentucky. See Note 15 for more information.

In addition to the reportable operating segments, the Corporate and Other segment includes the operations of the Parent and PESC as well as other nonregulated business areas. These nonregulated business areas include telecommunications and energy service operations and other nonregulated subsidiaries that do not separately meet the disclosure requirements of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” (SFAS No. 131). The profit or loss of the identified segments plus the profit or loss of Corporate and Other represents our total income from continuing operations.

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

	Revenues
(in millions) Three Months Ended September 30, 2005	Unaffiliated	Intersegment		Total		Postretirement     and  Severance   Charges	Income    from Continuing Operations		Assets
PEC Electric	$1,185	$   —		$ 1,185		$—	$ 184		$ 11,104
PEF	1,227	—		1,227		1	151		8,130
Fuels	149	393		542		—	18		795
CCO	267	—		267		—	(13	)	1,928
Synthetic Fuels	251	—		251		—	71		301
Corporate and Other	18	105		123		—	39		17,905
Eliminations	—	(498	)	(498	)	—	—		(13,625	)
Consolidated totals	$3,097	$   —		$ 3,097		$1	$ 450		$ 26,538

	Revenues
(in millions) Three Months Ended September 30, 2004	Unaffiliated	Intersegment		Total		Postretirement     and  Severance   Charges	Income    from Continuing Operations
PEC Electric	$1,014	$   —		$ 1,014		$(2)	$ 175
PEF	1,029	—		1,029		—	140
Fuels	132	260		392		—	20
CCO	90	—		90		—	14
Synthetic Fuels	187	—		187		—	(57	)
Corporate and Other	18	112		130		—	—
Eliminations	—	(372	)	(372	)	—	—
Consolidated totals	$2,470	$   —		$ 2,470		$(2)	$ 292

	Revenues
(in millions) Nine Months Ended September 30, 2005	Unaffiliated	Intersegment		Total		Postretirement     and  Severance   Charges	Income    from Continuing Operations		Assets
PEC Electric	$2,980	$      —		$ 2,980		$  60	$ 368		$ 11,104
PEF	2,983	—		2,983		108	204		8,130
Fuels	464	1,034		1,498		6	41		795
CCO	490	—		490		2	(21	)	1,928
Synthetic Fuels	662	—		662		—	93		301
Corporate and Other	49	334		383		1	(124	)	17,905
Eliminations	—	(1,368	)	(1,368	)	—	—		(13,625	)
Consolidated totals	$7,628	$      —		$ 7,628		$177	$ 561		$ 26,538

	Revenues
(in millions) Nine Months Ended September 30, 2004	Unaffiliated	Intersegment		Total		Postretirement     and  Severance   Charges	Income                from             Continuing             Operations
PEC Electric	$2,776	$      —		$ 2,776		$3	$ 388
PEF	2,673	—		2,673		1	273
Fuels	387	792		1,179		—	47
CCO	196	—		196		—	11
Synthetic Fuels	512	—		512		—	15
Corporate and Other	55	315		370		—	(197	)
Eliminations	—	(1,107	)	(1,107	)	—	—
Consolidated totals	$6,599	$      —		$ 6,599		$4	$ 537

PEC’s segments consist almost exclusively of PEC Electric and the results of operations for the PEC Electric segment presented herein are substantially identical to the results of operations for PEC on a consolidated basis. The results of PEC’s nonutility subsidiaries do not meet the disclosure requirements of SFAS No. 131 for the three and nine months ended September 30, 2005 and 2004, are not material to PEC’s consolidated financial statements and are not presented herein.

13.  OTHER INCOME AND OTHER EXPENSE
Other income and expense includes interest income and other income and expense items as discussed below. Nonregulated energy and delivery services include power protection services and mass market programs such as surge protection, appliance services and area light sales, and delivery, transmission and substation work for other utilities. AFUDC equity represents the estimated equity costs of capital funds necessary to finance the construction of new regulated assets. The components of other, net as shown on the accompanying Statements of Income are as follows:

Progress Energy

	Three Months Ended    September 30		Nine Months Ended   September 30
(in millions)	2005	2004	2005	2004
Other income
Nonregulated energy and delivery services income	$  3	$  5	$20	$17
DIG Issue C20 Amortization (see Note 10)	3	3	6	8
Contingent value obligations unrealized gain	4	20	4	7
Investment gains	1	1	4	5
Income from equity investments	4	1	9	3
AFUDC equity	5	3	14	7
Other	13	10	24	27
Total other income	$33	$43	$81	$74
Other expense
Nonregulated energy and delivery services
expenses	$  7	$  5	$17	$15
Donations	3	2	14	12
Investment losses	—	1	—	3
Loss from equity investments	5	3	14	11
Write-off of non-trade receivables	—	—	—	7
FERC audit settlement	—	—	7	—
Other	8	4	23	23
Total other expense	$23	$15	$75	$71
Other, net - Progress Energy	$10	$28	$  6	$  3

PEC

	Three Months Ended    September 30			Nine Months Ended    September 30
(in millions)	2005		2004	2005	2004
Other income
Nonregulated energy and delivery services income	$(2	)	$  1	$  7	$   6
DIG Issue C20 Amortization (see Note 10)	3		3	6	8
Income from equity investments	1		2	1	1
AFUDC equity	1		1	3	3
Other	9		5	13	8
Total other income	$ 12		$12	$30	$ 26
Other expense
Nonregulated energy and delivery services
expenses	$   3		$  2	$  7	$   6
Donations	1		1	6	5
Write-off of non-trade receivables	—		—	—	7
FERC audit settlement	—		—	4	—
Other	3		2	9	9
Total other expense	$   7		$  5	$26	$ 27
Other, net - PEC	$   5		$  7	$  4	$(1	)

PEF

	Three Months Ended    September 30		Nine Months Ended    September 30
(in millions)	2005	2004	2005	2004
Other income
Nonregulated energy and delivery services income	$  5	$4	$14	$12
Investment gains	1	—	2	—
AFUDC equity	4	2	11	4
Other	—	—	—	2
Total other income	$10	$6	$27	$18
Other expense
Nonregulated energy and delivery services
expenses	$  4	$3	$  9	$  8
Donations	2	1	8	7
FERC audit settlement	—	—	3	—
Other	—	1	1	3
Total other expense	$  6	$5	$21	$18
Other, net - PEF	$  4	1	$  6	$—

FERC audit settlement includes amounts approved by the FERC on May 25, 2005, to settle the FERC Staff’s audit of the Utilities’ compliance with the FERC’s Standards of Conduct and Code of Conduct. In the settlement, PEC and PEF agreed to make certain operational and organizational changes and to provide their retail and wholesale customers a one-time credit of approximately $4 million and $3 million, respectively, which was recorded as other expense in the second quarter of 2005.

14.  ENVIRONMENTAL MATTERS

We are subject to federal, state and local regulations addressing hazardous and solid waste management, air and water quality and other environmental matters. See Note 22 of our 2004 annual report on Form 10-K, Note 17 of PEC’s 2004 annual report on Form 10-K, and Note 20 of PEF’s 2004 annual report on Form 10-K, respectively, for a more detailed, historical discussion of these federal, state, and local regulations.

HAZARDOUS AND SOLID WASTE MANAGEMENT

The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the Environmental Protection Agency (EPA) to require the cleanup of hazardous waste sites. This statute imposes retroactive joint and several liabilities. Some states, including North Carolina, South Carolina and Florida, have similar types of legislation. We are periodically notified by regulators, including the EPA and various state agencies, of our involvement or potential involvement in sites that may require investigation and/or remediation. There are presently several sites with respect to which we have been notified by the EPA, the State of North Carolina or the State of Florida of our potential liability, as described below in greater detail. Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. PEC and PEF are each potentially responsible parties (PRPs) at several manufactured gas plant (MGP) sites. We are also currently in the process of assessing potential costs and exposures at other sites. A discussion of sites by legal entity follows below.

We record accruals for probable and estimable costs related to environmental sites on an undiscounted basis. We measure our liability for these sites based on available evidence including our experience in investigating and remediating environmentally impaired sites. The process often involves assessing and developing cost-sharing arrangements with other PRPs. For all sites, as assessments are developed and analyzed, we will accrue costs for the sites to the extent our liability is probable and the costs can be reasonably estimated. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet reached the stage where a reasonable estimate of the remediation costs can be made, we cannot determine the total costs that may be incurred in connection with the remediation of all sites at this time.

We and PEF have filed claims with general liability insurance carriers to recover costs arising from actual or potential environmental liabilities. Almost all claims have been settled and a few are still pending. While the outcome of this matter cannot be predicted, the outcome is not expected to have a material effect on our or PEF’s financial position or results of operations. PEC’s previous claims have been settled other than with insolvent carriers and those settlements did not have a material effect on PEC’s financial position or results of operations. PEC may file claims with respect to liabilities from sites described below. The outcome of these matters cannot be predicted.

Progress Energy

In addition to the Utilities’ sites, discussed under “PEC” and “PEF” below, our environmental sites include the following related to our nonregulated operations.

In 2001, we, through our Progress Fuels subsidiary, established an accrual to address indemnities and retained an environmental liability associated with the sale of our Inland Marine Transportation business. In 2003, the accrual was reduced to $4 million based on a change in estimate. As of September 30, 2005 and December 31, 2004, the remaining accrual balance was approximately $3 million. Expenditures related to this liability were not material to our financial condition for the three and nine months ended September 30, 2005.

We are voluntarily addressing certain historical sites. An immaterial accrual has been established to address investigation expenses related to these sites. At this time, the total costs that may be incurred in connection with these sites cannot be determined.

On March 24, 2005, we completed the sale of our Progress Rail subsidiary. In connection with the sale, we incurred indemnity obligations related to certain pre-closing liabilities, including certain environmental matters (see discussion under Guarantees in Note 15B).

PEC

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

In September 2005, the EPA advised PEC that it had been identified as a PRP at the Carolina Transformer site located in Fayetteville, North Carolina. The EPA offered PEC and a number of other PRPs the opportunity to share the reimbursement of approximately $36 million to the EPA for past expenditures in addressing conditions at the site. Although a loss is considered probable, an agreement among PRP’s has not been reached; consequently, it is not possible at this time to reasonably estimate the total amount of PEC’s obligation for remediation of the Carolina Transformer site.

During the fourth quarter of 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site located in Raleigh, North Carolina. The EPA offered PEC and a number of other PRPs the opportunity to negotiate cleanup of the site and reimbursement to the EPA for EPA’s past expenditures in addressing conditions at the site. In September 2005, PEC and several other PRPs signed a settlement agreement, which requires the participating PRPs to provide approximately $5 million to cover the cleanup cost and repay less than $1 million of EPA’s past costs.

As of September 30, 2005 and December 31, 2004, PEC’s accruals for probable and estimable costs related to various environmental sites, which are included in other liabilities and deferred credits and are expected to be paid out over one to five years, were:

(in millions)	September 30, 2005	December 31, 2004
MGP and other sites, including insurance fund	$6	$7
Transferred from NCNG at time of sale	2	2
Total accrual for environmental sites	$8	$9

The amounts for MGP and other sites, in the table above, relate to nine former MGP sites and other sites associated with PEC that have required or are anticipated to require investigation and/or remediation. The amount includes insurance fund proceeds which PEC received to address costs associated with environmental liabilities related to its involvement with some sites. All eligible expenses related to these sites are charged against a specific fund containing these proceeds. For the three and nine months ended September 30, 2005, PEC accrued approximately $3 million, received no insurance proceeds, and spent approximately $1 million and $4 million, respectively, related to environmental remediation.

On March 30, 2005, the North Carolina Division of Water Quality renewed a PEC permit for the continued use of coal combustion products generated at any of its coal-fired plants located in the state. Following review of the permit conditions, which could significantly restrict the reuse of coal ash and result in higher ash management costs, the permit was adjudicated. The outcome of this matter cannot be predicted.

PEF

As of September 30, 2005 and December 31, 2004, PEF’s accruals for probable and estimable costs related to various environmental sites, which are included in other liabilities and deferred credits and are expected to be paid out over one to fifteen years, were:

(in millions)	September 30, 2005	December 31, 2004
Remediation of distribution and substation	$21	$27
transformers
MGP and other sites	19	18
Total accrual for environmental sites	$40	$45

PEF has received approval from the FPSC for recovery of costs associated with the remediation of distribution and substation transformers through the Environmental Cost Recovery Clause (ECRC). Under agreements with the Florida Department of Environmental Protection (FDEP), PEF is in the process of examining distribution transformer sites and substation sites for potential equipment integrity issues that could result in the need for mineral oil impacted soil remediation. PEF has reviewed a number of distribution transformer sites and all substation sites. Based on changes to the estimated timeframe for review of distribution transformer sites, PEF currently expects to have completed its review by the end of 2008. As of December 31, 2004 , PEF expected to have completed its review of distribution transformer sites by the end of 2007. Should further sites be identified, PEF believes that any estimated costs would also be recovered through the ECRC. For the three and nine months ended September 30, 2005, PEF accrued approximately $1 million and spent approximately $2 million and $7 million, respectively, related to the remediation of transformers. PEF has recorded a regulatory asset for the probable recovery of these costs through the ECRC.

The amounts for MGP and other sites, in the table above, relate to two former MGP sites and other sites associated with PEF that have required or are anticipated to require investigation and/or remediation. In 2004, PEF received approximately $12 million in insurance claim settlement proceeds and recorded a related accrual for associated environmental expenses, as these insurance proceeds are restricted for use in addressing costs associated with environmental liabilities. For the three and nine months ended September 30, 2005, PEF made no additional accruals or material expenditures and received approximately $1 million of additional insurance proceeds.

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

AIR QUALITY

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

New Source Review (NSR)

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 NSR requirements or New Source Performance Standards under the Clean Air Act. We were 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.

On June 24, 2005, the Court of Appeals for the District of Columbia Circuit rendered a decision in a suit regarding EPA’s NSR rules. As part of the decision, the court struck down a provision excluding pollution control projects from NSR requirements. As a result of this decision, additional regulatory review of our pollution control equipment proposals will be required adding time and cost to the overall project.

NOx SIP Call Rule under Section 110 of the Clean Air Act (NOx SIP Call)

The NOx SIP Call is an EPA rule that requires 22 states, including North Carolina, South Carolina and Georgia, to further reduce nitrogen oxide emissions. The NOx SIP Call is not applicable to Florida. Total capital expenditures to meet the requirements of the final rule under the NOx SIP Call in North Carolina and South Carolina could reach approximately $370 million at PEC. This amount also includes the cost to install NOx controls under North Carolina’s and South Carolina’s programs to comply with the federal 8-hour ozone standard. However, further technical analysis and rulemaking may result in requirements for additional controls at some units. To date, we have spent approximately $330 million at PEC related to these projected amounts. Increased O&M expenses relating to the NOx SIP Call are not expected to be material to our or PEC’s results of operations. Further controls are anticipated as electricity demand increases.

Parties unrelated to us have undertaken efforts to have Georgia excluded from the rule and its requirements. Georgia has not yet submitted a state implementation plan to comply with the Section 110 NOx SIP Call. The outcome of this matter and the impact to our non-regulated operations in Georgia cannot be predicted.

Smokestacks Act

In April 2005, PEC filed its annual estimate with the NCUC for the total capital costs to meet emission targets for NOx and SO₂ from coal-fired power plants under the Smokestacks Act of approximately $895 million. PEC is scheduled to file its next annual estimate in April 2006. PEC anticipates that the estimated project cost will increase above the April 2005 estimate based on scope modifications and other factors involved with the project. PEC has expended approximately $237 million of these capital costs through September 30, 2005. The Smokestacks Act requires PEC to amortize 70 percent of the original cost estimate of $813 million, during a five-year rate freeze period. PEC recognized amortization of $26 million and $80 million, respectively, for the three and nine months ended September 30, 2005, and has recognized $328 million in cumulative amortization through September 30, 2005. The remaining amortization requirement will be recorded over the future period ending December 31, 2007. The Smokestacks Act permits PEC the flexibility to vary the amortization schedule for recording the compliance costs from zero up to $174 million of amortization expense per year. The NCUC will hold a hearing prior to December 31, 2007, to determine cost recovery amounts for 2008 and future periods. O&M expenses will significantly increase due to the additional materials, personnel and general maintenance associated with the equipment. O&M expenses are recoverable through base rates, rather than as part of this program. The future regulatory interpretation, implementation or impact of the Smokestacks Act cannot be predicted.

Clean Air Interstate Rule (CAIR) and Mercury Rules

On March 10, 2005, the EPA issued the final CAIR. The EPA’s rule requires 28 states, including North Carolina, South Carolina, Georgia and Florida, and the District of Columbia to reduce NOx and SO₂ emissions in order to reduce levels of fine particulate matter and impacts to visibility. Installation of additional air quality controls is likely to be needed to meet the CAIR requirements. We are in the process of determining compliance plans and the cost to comply with the rule. The air quality controls already installed for compliance with the NOx SIP Call and currently planned by us to comply with the Smokestacks Act will reduce the costs required to meet the CAIR requirements for our North Carolina units at PEC. We currently estimate compliance costs for PEF could be approximately $1.3 billion over the next ten years. The current estimate has increased above the previous cost of approximately $1.0 billion based on scope modifications and other factors involved with the project. We will continue to review these estimates as our compliance plans are further developed. PEF has joined a coalition of Florida utilities that has filed a challenge to CAIR as it applies to Florida. A petition for reconsideration and stay and a petition for judicial review of CAIR were filed on July 11, 2005. On October 27, 2005, the DC Circuit Court issued an order granting the motion for stay of the proceedings. The outcome of this matter cannot be predicted.

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

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

On May 6, 2005, PEF filed a petition with the FPSC through the ECRC program for recovery of costs associated with the development and implementation of an integrated strategy to comply with the CAIR and CAMR. PEF is developing an integrated compliance strategy for the CAIR and CAMR rules because NOx and SO₂ controls also are effective in reducing mercury emissions. PEF estimates the program costs for 2005 to be approximately $2 million for preliminary engineering activities and strategy development work necessary to determine our integrated compliance strategy. PEF currently projects approximately $54 million in program costs for 2006. These costs may increase or decrease depending upon the results of the engineering and strategy development work. Among other things; subsequent rule interpretations, equipment availability, or the unexpected acceleration of the initial NOx or other compliance dates could require acceleration of some projects and therefore result in additional costs in 2005 and 2006. PEF expects to incur significant additional capital and O&M expenses to achieve compliance with the CAIR and CAMR through 2015 and beyond. The timing and extent of the costs for future projects will depend upon the final compliance strategy.

North Carolina Attorney General Petition under Section 126 of the Clean Air Act

In March 2004, the North Carolina Attorney General filed a petition with the EPA under Section 126 of the Clean Air Act, asking the federal government to force coal-fired power plants in 13 other states, including South Carolina, to reduce their NOx and SO₂ emissions. The state of North Carolina contends these out-of-state emissions interfere with North Carolina’s ability to meet national air quality standards for ozone and particulate matter. On August 1, 2005, the EPA issued a proposed response denying the petition. The EPA’s rationale for denial is that compliance with CAIR will reduce the emissions from surrounding states sufficiently to address North Carolina’s concerns. The EPA must take final action by March 15, 2006. The outcome of this matter cannot be predicted.

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 the Utilities in the immediate and extended future.

Based on new cost information and changes to the engineering strategy and estimated time frame of expenditures since December 31, 2004, we have revised the estimated amounts and time period for expenditures to meet Section 316(b) requirements of the Clean Water Act. We currently estimate that from 2006 through 2010 the range of expenditures will be approximately $70 million to $95 million. The range includes approximately $5 million to $10 million at PEC and approximately $65 million to $85 million at PEF.

OTHER ENVIRONMENTAL MATTERS

The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of carbon dioxide and other greenhouse gases. 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 our financial position or results of operations if associated costs of control or limitation cannot be recovered from customers. We favor the voluntary program approach recommended by the Bush administration and continually evaluate options for the reduction, avoidance and sequestration of greenhouse gases. However, the outcome of this matter cannot be predicted.

In a decision issued July 15, 2005, a three-judge panel of the U.S. Court of Appeals for the District of Columbia Circuit denied petitions for review filed by several states, cities and organizations seeking the regulation by the EPA of carbon dioxide emissions under the Clean Air Act. In a 2-1 decision, the court held that the EPA Administrator properly exercised his discretion in denying the request for regulation. Officials from five states and the District of Columbia have asked the full U.S. Court of Appeals for the D.C. Circuit to review the decision made by the three-judge panel. The outcome of this matter cannot be predicted.

We have announced our plan to issue a report on our activities associated with current and future environmental requirements. The report will include a discussion of the environmental requirements that we currently face and expect to face in the future with respect to our air emissions. The report is expected to be issued by March 31, 2006.

15.  COMMITMENTS AND CONTINGENCIES

Contingencies and significant changes to the commitments discussed in Note 23 of our 2004 annual report on Form 10-K, Note 18 of PEC’s Annual Report on Form 10-K, and Note 21 of PEF’s Annual Report on Form 10-K, respectively, are described below.

A.     Purchase Obligations

Progress Energy

As part of our ordinary course of business, we enter into various long and short term contracts for fuel requirements at our generating plants. Through September 30, 2005, contracts procured through the Utilities and other businesses have increased our aggregate purchase obligations for fuel and purchased power by approximately $1.83 billion as compared to the amount stated in our annual report on Form 10-K for the year ended December 31, 2004. The increase primarily relates to the period ranging from 2005 through 2009. A majority of the contracts related to this increase are for future coal purchases primarily with fixed prices and future gas purchases primarily with variable prices.

PEC

As part of PEC’s ordinary course of business, it enters into various long and short term contracts for fuel requirements at our generating plants. Through September 30, 2005, contracts procured at PEC have increased its aggregate purchase obligations for fuel and purchased power by approximately $1.15 billion as compared to the amount stated in PEC’s annual report on Form 10-K for the year ended December 31, 2004. The increase primarily relates to the period ranging from 2005 through 2009. A majority of the contracts related to this increase are for future coal purchases primarily with fixed prices.

PEF

As part of PEF’s ordinary course of business, it enters into various long and short term contracts for fuel requirements at its generating plants. Through September 30, 2005, contracts procured at PEF have increased its aggregate purchase obligations for fuel and purchased power by approximately $360 million as compared to the amount stated in PEF’s annual report on Form 10-K for the year ended December 31, 2004. The increase primarily relates to the period ranging from 2005 through 2009. A majority of the contracts related to this increase are for future gas purchases primarily with variable prices.

B.     Guarantees

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties, which are outside the scope of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN No. 45). Such agreements include guarantees, standby letters of credit and surety bonds. As of September 30, 2005, we do not believe conditions are likely for significant performance under these guarantees. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included in the accompanying Balance Sheets.

As of September 30, 2005, we have issued guarantees and indemnifications of certain legal, tax and environmental matters to third parties in connection with sales of businesses and for timely payment of obligations in support of our non-wholly owned synthetic fuel operations. Related to the sales of businesses, the notice period extends until 2012 for the majority of matters provided for in the indemnification provisions. For matters for which we receive timely notice, our indemnity obligations may extend beyond the notice period. Certain environmental indemnifications related to the sale of synthetic fuel operations have no limitations as to time or maximum potential future payments. Other guarantees and indemnifications have an estimated maximum exposure of approximately $152 million. As of September 30, 2005, we have recorded liabilities related to guarantees and indemnifications to third-parties of approximately $26 million. Management does not believe conditions are likely for significant performance under these agreements in excess of the recorded liabilities. As of September 30, 2005, the Utilities had no guarantees issued on behalf of unconsolidated subsidiaries or other third parties.

In addition, the Parent has issued $300 million of guarantees of certain payments of two wholly owned indirect subsidiaries. See Note 8 for additional information.

C.     Insurance

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

D.     Other Commitments

As discussed in Note 23B of our annual report on Form 10-K for the year ended December 31, 2004, we have certain future commitments related to four synthetic fuel facilities purchased that provide for contingent payments (royalties). We have exercised our right in the related agreements to escrow those payments if certain conditions in the agreements were met. We previously accrued and retained 2004 and 2003 royalty payments of approximately $41 million and $49 million, respectively. In May 2005, these funds were placed into escrow upon establishment of the necessary escrow accounts.

On May 15, 2005, the original owners of the Earthco synthetic fuel facilities filed suit in New York state court alleging breach of contract against the Progress Fuels subsidiaries that purchased the Earthco facilities (Progress Fuels Subsidiaries). The plaintiffs also named us as a defendant. The plaintiffs’ complaint is that periodic payments otherwise due to them under the sales arrangement with the Progress Fuels Subsidiaries are, contrary to the sales agreement, being escrowed pending the outcome of the ongoing IRS audit of the Earthco facilities. The Progress Fuels Subsidiaries believe that the parties’ agreements allow for the payments to be escrowed in such event and also allow for the use of such escrowed amounts to satisfy any potential disallowance of tax credits that arises out of such an event. Currently, the escrowed amount in question is $87 million, which reflects periodic payments that would have been paid to the plaintiffs beginning April 30, 2003 through September 30, 2005. This amount will increase as future periodic payments are made to the escrow which would otherwise have been payable to the plaintiffs. We intend to vigorously defend their actions, but cannot predict the outcome of this matter.

E.     Other Contingencies

1.       Pursuant to the Nuclear Waste Policy Act of 1982, the predecessors to the Utilities 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.

The DOE failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004, the Utilities filed a complaint in the United States Court of Federal Claims against the DOE, claiming that the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel by failing to accept spent nuclear fuel from various of our facilities on or before January 31, 1998. Our damages due to the DOE’s breach will be significant, but have yet to be determined. Approximately 60 cases involving the Government’s actions in connection with spent nuclear fuel are currently pending in the Court of Federal Claims.

The DOE and the Utilities 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 spent nuclear fuel and high level waste by which the Government was contractually obligated to accept contract holders’ spent nuclear fuel and/or high level waste, and issues regarding recovery of damages under a partial breach of contract theory that will be alleged to occur in the future. These issues have been or are expected to be presented in the trials or appeals that are currently scheduled to occur during 2005. Resolution of these issues in other cases could facilitate agreements by the parties in the Utilities’ lawsuit, or at a minimum, inform the Court of decisions reached by other courts if they remain contested and require resolution in this case. In July 2005, the parties jointly requested a continuance of the stay through December 15, 2005, which the trial court granted.

In July 2002, Congress passed an override resolution to Nevada’s veto of the 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 the 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. In August 2005, the EPA issued new proposed standards. The proposed standards include a 1,000,000-year compliance period in the radiation protection standard. Comments are due November 21, 2005. The 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, the 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 the DOE but approximately the same as approved in 2004. The DOE has acknowledged that a working repository will not be operational until sometime after 2010, but the DOE has not identified a new target date. The Utilities cannot predict the outcome of this matter.

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

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

With certain modifications and additional approval by the NRC, including the installation of onsite dry storage facilities at PEF’s nuclear unit, 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.

2.      In 2001, PEC entered into a contract to purchase coal from Dynegy Marketing and Trade (DMT). After DMT experienced financial difficulties, including credit ratings downgrades by certain credit reporting agencies, PEC requested credit enhancements in accordance with the terms of the coal purchase agreement in July 2002. When DMT did not offer credit enhancements, as required by a provision in the contract, PEC terminated the contract in July 2002.

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

On May 4, 2004, PEC authorized its outside counsel to file a notice of appeal of the April 6, 2004 judgment, and on May 7, 2004, the notice of appeal was filed with the United States Court of Appeals for the Fourth Circuit. On June 8, 2004, DMT filed a motion to dismiss PEC’s appeal on the ground that it was untimely. On July 20, 2005, the appellate court denied DMT’s motion to dismiss and ruled that the time for PEC to appeal had not yet expired. The appellate court remanded the case to the trial court for further proceedings.

In the first quarter of 2004, PEC recorded a liability for the judgment of approximately $10 million and a regulatory asset for the probable recovery through its fuel adjustment clause. PEC cannot predict the outcome of this matter.

3.       On February 1, 2002, PEC filed a complaint with the Surface Transportation Board (STB) challenging the rates charged by Norfolk Southern Railway Company (Norfolk Southern) for coal transportation to certain generating plants. In a decision served in December, 2003, the STB found that the challenged rates exceeded maximum reasonable rate levels and prescribed lower rates. In a subsequent decision on reconsideration the STB concluded that the rates had not been shown to be unreasonable, following which PEC requested the STB to consider requiring that the rates be phased in over a period of time. During the course of the complaint process, PEC accrued a liability of $42 million. The liability was comprised of $23 million of reparations remitted to PEC by Norfolk Southern that were subject to refund and an additional $19 million, of which $17 million was recorded as deferred fuel cost on the Consolidated Balance Sheet. This matter has now been settled by mutual agreement, and the STB has issued an order dismissing the case. As a result of the settlement, PEC reversed the previously recorded deferred fuel cost and settled the remaining obligations for the approximate amount previously accrued. The settlement did not have a material impact on PEC’s results of operations.

4.       PEF has resolved all but one of its outstanding franchise matters. On August 25, 2005, the City Council of Edgewood, Florida approved a new 30-year electric utility franchise agreement with PEF, which resolved all outstanding litigation with the City of Edgewood (1,400 customers). On August 22, 2005, the 7,000-customer City of Maitland also entered into a new 30-year franchise agreement with PEF. As previously noted, in accordance with the terms of an arbitration panel’s award issued in May 2003 and after satisfying regulatory and operational requirements, Winter Park acquired from PEF the electric distribution system that serves Winter Park (13,000 customers) and PEF transferred the distribution system to Winter Park on June 1, 2005. In addition, Winter Park executed a wholesale power supply contract with PEF with a five-year term from the date service begins and a renewal option. See Note 5.

The 2,500 customer Town of Belleair (Belleair) is the last municipality with pending litigation against PEF. Arbitration with Belleair to determine the value of PEF’s electric distribution system within 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 Belleair at approximately $6 million. The panel further required Belleair to pay to PEF its requested $1 million in separation and reintegration costs and $2 million in stranded costs. Belleair has not yet decided whether it will attempt to acquire the system; however, on January 18, 2005, it issued a request for proposals for wholesale power supply and to operate and maintain the distribution system. In March 2005, PEF submitted a bid to supply wholesale power to Belleair. Belleair received several other proposals for wholesale power and distribution services. In February 2005, the Town Commission also voted to put the issue of whether to acquire the distribution system to a voter referendum. A referendum is scheduled to occur on November 8, 2005. At this time, whether and when there will be further proceedings regarding Belleair cannot be determined.

5.      Through our subsidiaries, we are a majority owner in five entities and a minority owner in one entity that own facilities that produce coal-based solid synthetic fuel as defined under the Code. The production and sale of the synthetic fuel from these facilities qualify for tax credits under Section 29 if certain requirements are satisfied, including a requirement that the synthetic fuel differs significantly in chemical composition from the coal used to produce such synthetic fuel and that the fuel was produced from a facility that was placed in service before July 1, 1998. Qualifying synthetic fuel facilities 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 amount of Section 29 tax credits that we are allowed to claim in any calendar year is currently limited by the amount of our regular federal income tax liability. Synthetic fuel tax credit amounts allowed but not utilized are carried forward indefinitely as deferred alternative minimum tax credits. See “Energy Policy Act” discussion below regarding the redesignation of Section 29 tax credits effective January 1, 2006. Total Section 29 credits generated to date (including those generated by Florida Progress prior to our acquisition) are approximately $1.7 billion, of which $783 million have been used to offset regular federal income tax liability and $885 million are being carried forward as deferred alternative minimum tax credits. The current Section 29 tax credit program expires at the end of 2007.

During the third quarter of 2005, we recorded $27 million of tax credits that had previously not been recognized as part of finalizing our 2004 regular federal income tax liability. These credits were not previously recognized due to the decrease in tax liability resulting from expenses incurred for the 2004 hurricanes and loss on sale of Progress Rail.

IRS PROCEEDINGS

In September 2002, all of our majority-owned synthetic fuel entities were accepted into the IRS’s Pre-Filing Agreement (PFA) program in lieu of the ordinary IRS audit process. The PFA program allows taxpayers to voluntarily accelerate the IRS exam process in order to seek resolution of specific issues.

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

In July 2004, we were notified that the IRS field auditors anticipated taking an adverse position regarding the placed-in-service date of the Earthco facilities. Due to the IRS 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 our Earthco facilities is back on the normal procedural audit path of our tax returns.

On October 29, 2004, we received the IRS field auditors’ preliminary report concluding that the Earthco facilities had not been placed in service before July 1, 1998, and proposing that the tax credits generated by those facilities should be disallowed. We disagree with the field audit team’s factual findings and believe that the Earthco facilities were placed in service before July 1, 1998. We also believe that the report applies an inappropriate legal standard concerning what constitutes “placed in service.” We are currently contesting the field auditors’ findings and the field audit team’s proposed disallowance of the tax credits.

Because of the disagreement with the field auditors as to the proper legal standard to apply, we believe that it is appropriate and helpful to have this issue reviewed by the National Office of the IRS. Therefore, we have asked the National Office to review the issue and clarify the legal standard to be applied. We believe that the appeals process, including proceedings before the National Office, could take up to two years to complete; however, we cannot control the actual timing of resolution and cannot predict the outcome of this matter.

During October 2005, we and the IRS Examination Staff filed briefs with the National Office for the purpose of receiving technical advice on whether our Earthco facilities were placed in service prior to July 1, 1998 for purposes of determining if our synthetic fuel tax credits are allowable under Section 29 of the Internal Revenue Code. IRS procedures do not provide a specific timeframe for rendering the requested decision following the filing of such briefs. As such, we cannot predict when the National Office will provide technical guidance on this matter.

Through September 30, 2005, on a consolidated basis we have used or carried forward approximately $1.2 billion of tax credits generated by Earthco facilities. If these credits were disallowed, our one-time exposure for cash tax payments would be $311 million (excluding interest), and earnings and equity would be reduced by approximately $1.2 billion, excluding interest. These amounts have not been reduced for the use of any escrowed amounts to satisfy a potential disallowance of these tax credits (see Note 15D). Our amended $1.13 billion credit facility includes a covenant that limits the maximum debt-to-total capital ratio to 68%. This ratio includes other forms of indebtedness such as guarantees we issued, letters of credit and capital leases. As of September 30, 2005, our debt-to-total capital ratio was 60.0% based on the credit agreement definition for this ratio. The impact on this ratio of reversing approximately $1.2 billion of tax credits and paying $311 million for taxes would be an increase of the ratio to 64.4%.

We believe that we are complying with all the necessary requirements to qualify for Section 29 tax credits, and, although we cannot provide certainty, we believe that we will prevail in these matters. We have no current plans to alter our synthetic fuel production schedule for 2005 or future years as a result of the IRS field auditors’ report. However, should we fail to prevail in these matters, there could be material impact for previously used or carried forward Section 29 tax credits, with a material adverse impact on earnings and cash flows.

As discussed in Note 8F of our annual report on Form 10-K for the year ended December 31, 2004, we implemented changes in our capitalization policies for our Energy Delivery business units in the Utilities effective January 1, 2005. As a result of the changes in accounting estimates for the outage and emergency work and indirect costs, a lesser proportion of the Utilities’ costs will be capitalized on a prospective basis. We have requested a method change from the IRS that was granted in October 2005.

PROPOSED ACCOUNTING RULES FOR UNCERTAIN TAX POSITIONS

On July 14, 2005, the FASB issued an exposure draft of a proposed interpretation of SFAS No. 109 that would address the accounting for uncertain tax positions. The proposed interpretation would require that uncertain tax benefits be probable of being sustained in order to record such benefits in the consolidated financial statements. We currently account for uncertain tax benefits in accordance with SFAS No. 5. Under SFAS No. 5, contingent losses are recorded when it is probable that the tax position will not be sustained and the amount of the disallowance can be reasonably estimated. As currently drafted, the proposed interpretation would apply to all uncertain tax positions and be effective for us on December 31, 2005. However, the FASB has publicly stated that it expects to issue the final interpretation in the first quarter of 2006, which is expected to delay the effective date of the interpretation past 2005.

As discussed above, the IRS field auditors have recommended that the Section 29 tax credits generated by our Earthco facilities, totaling $1.2 billion through September 30, 2005, be disallowed. We disagree with the field audit team’s findings and have requested that the National Office of the IRS review this issue. We have not yet determined how the proposed interpretation would impact our various income tax positions, including the status of the Earthco tax credits. Depending on the provisions of the FASB’s final interpretation and our facts and circumstances that exist at the date of implementation, including our assessment of the probability of sustaining any currently recorded and future tax benefits, the proposed interpretation could have a material adverse impact on our financial position and results of operations.

PERMANENT SUBCOMMITTEE

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

IMPACT OF CRUDE OIL PRICES

Although the Section 29 tax credit program is expected to continue through 2007, recent market conditions and catastrophic weather events have increased the volatility and level of oil prices that could limit the amount of those credits or eliminate them entirely for one or more of the years following 2004. This possibility is due to a provision of Section 29 that provides that if the average wellhead price per barrel for unregulated domestic crude oil for the year (the Annual Average Price) exceeds a certain threshold price (the Threshold Price), the amount of Section 29 tax credits are reduced for that year. Also, if the Annual Average Price increases high enough (the Phase Out Price), the Section 29 tax credits are eliminated for that year. For 2004, the Threshold Price was $51.35 per barrel and the Phase Out Price was $64.47 per barrel. The Threshold Price and the Phase Out Price are adjusted annually for inflation.

If the Annual Average Price falls between the Threshold Price and the Phase Out Price for a year, the amount by which Section 29 tax credits are reduced will depend on where the Annual Average Price falls in that continuum. For example, for 2004, if the Annual Average Price had been $57.91 per barrel, there would have been a 50 percent reduction in the amount of Section 29 tax credits for that year.

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

We estimate that the 2005 Threshold Price will be approximately $52 per barrel and the Phase Out Price will be approximately $65 per barrel, based on an estimated 2005 inflation adjustment. The monthly Domestic Crude Oil First Purchases Price published by the EIA has recently averaged approximately $5 lower than the corresponding monthly New York Mercantile Exchange (NYMEX) settlement price for light sweet crude oil. Through October 17, 2005, the average NYMEX contract settlement price for light sweet crude oil was $55 per barrel and the average futures price for the remainder of 2005 was $64 per barrel. We estimate that NYMEX settlement price would have to average approximately $70 per barrel for the remainder of 2005 for the Threshold Price to be reached.

We cannot predict with any certainty the Annual Average Price of oil for 2005 or beyond. However, we do not currently believe that the 2005 Average Annual Price will trigger a phase out of the Section 29 tax credits in 2005.

We estimate that the 2006 Threshold Price will be approximately $52 per barrel and the Phase Out Price will be approximately $66 per barrel, based on estimated inflation adjustments for 2005 and 2006. The monthly Domestic Crude Oil First Purchases Price published by the EIA has recently averaged approximately $5 lower than the corresponding monthly NYMEX settlement price for light sweet crude oil. As of October 17, 2005, the average NYMEX futures price for light sweet crude oil for calendar year 2006 was $63 per barrel. Based upon the estimated 2006 Threshold Price and Phase Out Price, if oil prices for 2006 remained at the October 17, 2005 average futures price level of $63 per barrel for the entire year in 2006, we currently estimate that the Section 29 tax credit amount for 2006 would be reduced by approximately 35 percent to 40 percent.

Our future synthetic fuel production levels for 2006 and beyond remain uncertain because we cannot predict with any certainty the Annual Average Price of oil for 2005 or beyond. If oil prices for 2006 remained at the October 17, 2005 average futures price level of $63 per barrel for the entire year in 2006, it is unlikely that we would produce any synthetic fuel in 2006. This could have a material adverse impact on our results of operations. We will continue to monitor the level of oil prices and retain the ability to adjust production based on future oil price levels.

Due to the significant uncertainty surrounding our synthetic fuel production in 2006 and beyond based on the current level of oil prices, we evaluated our synthetic fuel and other related operating long-lived assets for impairment during the third quarter of 2005. We determined that no impairment of these assets was required this quarter, partly due to the estimated future cash flows from tax credits generated in the fourth quarter of 2005 from synthetic fuel production. However, a decrease in future synthetic fuel production and cash flows could require additional impairment evaluations in the fourth quarter of 2005, which could result in a future impairment of these assets which have total carrying values of approximately $115 million. The majority of these assets will be fully depreciated by the end of 2007, the scheduled end of the Section 29 tax credit program. The outcome of this matter cannot be determined.

SALE OF PARTNERSHIP INTEREST

In June 2004, through our subsidiary Progress Fuels, we sold in two transactions a combined 49.8 percent partnership interest in Colona, one of our 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 as the facility produces and sells synthetic fuel and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectability is reasonably assured. Based on projected production and tax credit levels, we anticipate receiving total gross proceeds of approximately $22 million in 2005, approximately $32 million in 2006, approximately $34 million in 2007 and approximately $10 million through the second quarter of 2008. Gain recognition is dependent on the synthetic fuel production qualifying for Section 29 tax credits and the value of such tax credits as discussed above. Until the gain recognition criteria are met, gains from selling interests in Colona will be deferred. It is possible that gains will be deferred in the first, second and/or third quarters of each year until there is persuasive evidence that no tax credit phase out will occur for the applicable calendar year. This could result in shifting earnings from earlier quarters to later quarters in a calendar year. In the event that the synthetic fuel tax credits from the Colona facility are reduced, including an increase in the price of oil that could limit or eliminate synthetic fuel tax credits, the amount of proceeds realized from the sale could be significantly impacted. As of September 30, 2005, a pre-tax gain on monetization of $17 million has been deferred. If oil prices remain at current levels as of October 17, 2005, we anticipate that this gain would be recognized in the fourth quarter of this year.

ENERGY POLICY ACT

On August 8, 2005, the Energy Policy Act of 2005 (EPACT) was signed into law. This new federal law contains key provisions affecting the electric power industry, including the redesignation of the Section 29 tax credit as a Section 45K general business credit. The amount of Section 29 tax credits that we are currently allowed to claim in any calendar year is limited by the amount of our regular federal income tax liability. Synthetic fuel tax credit amounts allowed but not utilized are currently carried forward indefinitely as deferred alternative minimum tax credits. The redesignation is effective on January 1, 2006 and removes the regular federal income tax liability limit on synthetic fuel production and subjects the credits to a 20-year carry forward period. This provision would allow us to produce synthetic fuel at a higher level should we choose to do so. We cannot currently predict what impact the new law will have on our future synthetic fuel production.

6.       We and our subsidiaries are involved in various litigation matters in the ordinary course of business, some of which involve substantial amounts. Where appropriate, we have made accruals and disclosures in accordance with SFAS No. 5 to provide for such matters. In the opinion of management, the final disposition of pending litigation would not have a material adverse effect on our consolidated results of operations or financial position.

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following Management’s Discussion and Analysis is presented on a combined basis for Progress Energy, Inc. (Progress Energy), Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF). As used in this report, Progress Energy (which includes Progress Energy, Inc. holding company (the Parent) and its regulated and nonregulated subsidiaries on a consolidated basis), is at times referred to as “we” “our” or “us”. When discussing Progress Energy’s financial information, it necessarily includes the results of PEC and PEF (collectively, the Utilities). The term “Progress Registrants” refers to each of the three separate registrants: Progress Energy, PEC and PEF.

The following Management’s Discussion and Analysis contains forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Please review “SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS” for a discussion of the factors that may impact any such forward-looking statements made herein and the Risk Factors sections of each of the Progress Registrants’ respective annual reports on Form 10-K for the year ended December 31, 2004.

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

This discussion should be read in conjunction with the accompanying financial statements found elsewhere in this report and in conjunction with the Progress Registrants’ respective 2004 annual reports on Form 10-K.

RESULTS OF OPERATIONS

Our reportable business segments and their primary operations include:

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

PEF - primarily engaged in the generation, transmission, distribution and sale of electricity in portions of
Florida;

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

Fuels - primarily engaged in natural gas drilling and production in Texas and Louisiana, coal mining, coal
terminal services and fuel transportation and delivery primarily in Kentucky, West Virginia and Virginia.
This segment also has an operating fee agreement with our Synthetic Fuel operations for the
procuring and processing of coal and the transloading and marketing of synthetic fuel; and

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

The Corporate and Other segment includes businesses which do not meet the requirements for separate segment reporting disclosure. These businesses are engaged in other nonregulated business areas, including telecommunications, primarily in the eastern United States, energy services operations, holding company operations and Progress Energy Service Company, LLC (PESC) operations.

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

In this section, earnings and the factors affecting earnings for the three and nine months ended September 30, 2005 as compared to the same periods in 2004 are discussed. The discussion begins with a summarized overview of our consolidated earnings, which is followed by a more detailed discussion and analysis by business segment.

OVERVIEW

For the quarter ended September 30, 2005, our net income was $450 million, or $1.82 per share, compared to net income of $303 million, or $1.25 per share, for the same period in 2004. The increase in net income as compared to prior year was due primarily to:

o
o
o
o
o Increased earnings from synthetic fuel operations.
Favorable weather at the Utilities.
The impact of tax levelization.
Non-recurring prior year income tax expenses and adjustments of certain tax matters.
Favorable customer growth and retail usage at the Utilities.

Partially offsetting these items were:

o
o
o
o
o
o
o Decreased nonregulated generation earnings.
The change in accounting estimates for certain Energy Delivery capital costs.
Increased outage costs and prior year project delays from storm restoration.
Increased employee pension and benefits expenses.
A reduction in unrealized gains recorded on contingent value obligations.
Discontinued operations at Progress Rail.
Increased interest expense.

For the nine months ended September 30, 2005, our net income was $542 million, or $2.20 per share, compared to $565 million, or $2.33 per share for the same period in 2004. The decrease in net income as compared to prior year was due primarily to:

o
o
o
o
o Postretirement and severance charges related to the cost management initiative.
Discontinued operations at Progress Rail.
Decreased nonregulated generation earnings.
The write-off of unrecoverable storm costs in Florida.
The change in accounting estimates for certain Energy Delivery capital costs.

Partially offsetting these items were:

o
o
o
o
o
o Increased synthetic fuel earnings.
Customer growth at the Utilities.
Favorable wholesale sales in Florida.
Gain recorded on the sale of distribution assets in Florida.
Non-recurring prior year income tax expenses and adjustments of certain tax matters.
The impact of tax levelization.

Basic earnings per share decreased in 2005 due in part to the factors outlined above. Dilution related to the issuances of an aggregate of approximately 4 million and 1 million shares of common stock under our Investor Plus Stock Purchase Plan and employee benefit programs for the year to date in 2005 and the year ended December 31, 2004, respectively, also reduced basic earnings per share by $0.04 for both the three and nine months ended September 30, 2005.

Our segments contributed the following profits or losses for the three and nine months ended September 30, 2005 and 2004:

	Three Months Ended   September 30,				Nine Months Ended   September 30,
(in millions)	2005		2004		2005		2004
Business Segment:
PEC Electric	$ 184		$ 175		$ 368		$ 388
PEF	151		140		204		273
Fuels	18		20		41		47
CCO	(13	)	14		(21	)	11
Synthetic Fuel	71		(57	)	93		15
Total Segment Profit	411		292		685		734
Corporate and Other	39		—		(124	)	(197	)
Income from continuing operations	450		292		561		537
Discontinued operations, net of tax	(1	)	11		(20	)	28
Cumulative effect of change in accounting principles	1		—		1		—
Net income	$ 450		$ 303		$ 542		$ 565

COST MANAGEMENT INITIATIVE

On February 28, 2005, as part of a previously announced cost management initiative, we approved a workforce restructuring which resulted in a reduction of approximately 450 positions. The cost management initiative is designed to permanently reduce by $75 million to $100 million our projected growth in annual operation and maintenance (O&M) expenses by the end of 2007. In addition to the workforce restructuring, the cost management initiative included a voluntary enhanced retirement program. In connection with this initiative, we incurred approximately $177 million of pre-tax charges for severance and postretirement benefits during the nine months ended September 30, 2005, as described below.

We recorded $31 million of severance expense during the first quarter of 2005 for the workforce restructuring and implementation of an automated meter reading initiative at PEF based on the approximate number of positions to be eliminated. During the second quarter of 2005, 1,447 employees eligible for participation in the voluntary enhanced retirement program elected to participate. Consequently, in the second quarter of 2005, we decreased our estimated severance costs by $13 million due to the impact of the employees electing participation in the voluntary enhanced retirement program. The severance expenses are primarily included in O&M expense on the Consolidated Statements of Income and will be paid over time.

During 2005, we recorded a $141 million charge in the second quarter and a $1 million charge in the third quarter related to postretirement benefits that will be paid over time to eligible employees who elected to participate in the voluntary enhanced retirement program. See Note 9 of the Combined Notes to Interim Financial Statements for additional information on postretirement benefits. In addition, we recorded a $17 million charge for early retirement incentives to be paid over time to certain employees.

The cost management initiative charges are subject to revision in future quarters based on completion of the workforce restructuring and the potential additional impacts that the early retirements and outplacements may have on our postretirement plans. Such revisions may be significant and may adversely impact our results of operations in future periods. In addition, we expect to incur certain incremental costs for recruiting and staff augmentation activities that cannot be quantified at this time.

PROGRESS ENERGY CAROLINAS ELECTRIC

PEC Electric’s operations are identical to PEC’s consolidated operations as PEC’s nonregulated activities are not material. PEC Electric contributed segment profits of $184 million and $175 million for the three months ended September 30, 2005 and 2004, respectively. Results for 2005 were impacted by favorable weather, customer growth and increased usage. These favorable items were partially offset by higher O&M expenses and higher interest expense.

PEC Electric contributed segment profits of $368 million and $388 million for the nine months ended September 30, 2005 and 2004, respectively. Results for 2005 were unfavorably impacted by higher O&M costs primarily due to postretirement and severance costs associated with the cost management initiative, the change in accounting estimates for certain Energy Delivery capital costs and higher interest expense. These unfavorable items were partially offset by favorable customer growth and usage, the impact of current year income tax adjustments and favorable weather.

Three months ended September 30, 2005 compared to the three months ended September 30, 2004

Revenues

PEC Electric’s revenues for the three months ended September 30, 2005 and 2004, and the percentage change by customer class are as follows:

	Three Months Ended September 30,
(in millions of $)	2005		Change		% Change		2004
Customer Class:
Residential	$    453		$   66		17	.1	$    387
Commercial	281		25		9	.8	256
Industrial	199		11		5	.9	188
Governmental	26		2		8	.3	24
Total retail revenues	959		104		12	.2	855
Wholesale	218		72		49	.3	146
Unbilled	(17	)	(6	)	—		(11	)
Miscellaneous	25		1		4	.2	24
Total electric revenues	$ 1,185		$ 171		16	.9	$ 1,014
Less:
Pass-through fuel revenues	(367	)	(115	)	—		(252	)
Revenues excluding fuel	$    818		$   56		7	.3	$    762

PEC Electric’s energy sales for the three months ended September 30, 2005 and 2004, and the amount and percentage change by customer class are as follows:

	Three Months Ended September 30,
(in millions of kWh)	2005		Change		% Change		2004
Customer Class:
Residential	5,058		653		14	.8	4,405
Commercial	4,008		256		6	.8	3,752
Industrial	3,481		(69	)	(1	.9)	3,550
Governmental	421		7		1	.7	414
Total retail energy sales	12,968		847		7	.0	12,121
Wholesale	4,356		1,112		34	.3	3,244
Unbilled	(516	)	(216	)	—		(300	)
Total kWh sales	16,808		1,743		11	.6	15,065

PEC Electric’s revenues, excluding recoverable fuel revenues of $367 million and $252 million for the three months ended September 30, 2005 and 2004, respectively, increased $56 million. The increase in revenues is attributable primarily to favorable weather and favorable retail growth and usage, partially offset by decreased wholesale revenues less fuel. The impact of weather was $51 million favorable with cooling degree days 33 percent above prior year. Favorable growth and usage of $11 million was driven by an increase in the average number of customers as of September 30, 2005, compared to September 30, 2004, of 27,000. The decrease in wholesale revenues less fuel of $4 million was driven primarily by the impact of higher fuel costs resulting from higher fuel prices, some of which related to Hurricanes Katrina and Rita, and changes in fuel mix related to outages. These unfavorable impacts to wholesale sales were partially offset by increased capacity under contract.

Expenses

Fuel and Purchased Power

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

PEC Electric’s fuel and purchased power expenses were $436 million for the three months ended September 30, 2005, which represents a $120 million increase compared to the same period in the prior year. Fuel used in electric generation increased $62 million to $282 million compared to the prior year. This increase is due to an increase in fuel used in generation of $146 million due primarily to higher fuel costs which are being driven primarily by rising coal, oil and natural gas prices. This increase in fuel used in generation was partially offset by a reduction in deferred fuel expense of $82 million due to the under-recovery of current year fuel costs (see Note 5 of the Combined Notes to Interim Financial Statements). Purchased power expense increased $58 million to $154 million compared to the prior year. Current year purchased power costs were higher due to price increases and changes in volume during the third quarter of 2005.

O&M

PEC Electric’s O&M expenses were $235 million for the three months ended September 30, 2005, which represents a $38 million increase compared to the same period in 2004. O&M expenses increased $13 million due to outages at the nuclear facilities; $11 million related to pension and benefit expense; $7 million due to higher emission allowance expense; and $7 million related to the change in accounting estimates for certain Energy Delivery capital costs. See discussion of change in Energy Delivery capitalization practice in Note 6E of PEC’s annual report on Form 10-K for the year ended December 31, 2004. In addition, expenses increased $6 million due to storm restoration costs associated with Hurricane Ophelia. These unfavorable items were partially offset by lower storm costs associated with Hurricanes Charley and Ivan, which were included in the prior quarter O&M expenses.

Depreciation and Amortization

PEC Electric’s depreciation and amortization expense was $130 million for the three months ended September 30, 2005, which represents a $9 million decrease compared to the same period in 2004. Depreciation expense decreased $13 million due to the impact of reduced depreciation rates from the 2004 depreciation study. This was partially offset by higher NC Clean Air amortization of $7 million.

Total interest charges, net

PEC Electric’s interest expense has increased $9 million for the three months ending September 30, 2005, as compared to the same period in the prior year. This fluctuation is due primarily to interest expense related to adjustments of certain tax matters, the impact of higher variable interest rates on pollution control bonds and the impact of increased short term borrowings.

Income tax expense

GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. PEC Electric’s income tax expense was increased by $3 million for the three months ended September 30, 2005, in order to maintain an effective tax rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent and temporary deductions can also cause fluctuations in the effective tax rate for interim periods. Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year. The remaining fluctuation in income tax expense is attributable to favorable adjustments of certain tax matters partially offset by the impact of higher earnings compared to prior year.

Nine months ended September 30, 2005 compared to the nine months ended September 30, 2004

Revenues

PEC Electric’s revenues for the nine months ended September 30, 2005 and 2004, and the percentage change by customer class are as follows:

	Nine Months Ended September 30,
(in millions of $)	2005		Change		% Change		2004
Customer Class:
Residential	$ 1,099		$   58		5	.6	$ 1,041
Commercial	709		32		4	.7	677
Industrial	512		16		3	.2	496
Governmental	64		2		3	.2	62
Total retail revenues	2,384		108		4	.7	2,276
Wholesale	546		105		23	.8	441
Unbilled	(20	)	(11	)	—		(9	)
Miscellaneous	70		2		2	.9	68
Total electric revenues	$ 2,980		$ 204		7	.3	$ 2,776
Less:
Pass-through fuel revenues	(877	)	(165	)	—		(712	)
Revenues excluding fuel	$ 2,103		$   39		1	.9	$ 2,064

PEC Electric's energy sales for the nine months ended September 30, 2005 and 2004, and the amount and percentage change by customer class are as follows:

	Nine Months Ended September 30,
(in millions of kWh)	2005		Change		% Change		2004
Customer Class:
Residential	13,015		344		2	.7	12,671
Commercial	10,175		193		1	.9	9,982
Industrial	9,641		(182	)	(1	.9)	9,823
Governmental	1,063		(33	)	(3	.0)	1,096
Total retail energy sales	33,894		322		1	.0	33,572
Wholesale	11,635		1,487		14	.7	10,148
Unbilled	(583	)	(303	)	—		(280	)
Total kWh sales	44,946		1,506		3	.5	43,440

PEC Electric’s revenues, excluding recoverable fuel revenues of $877 million and $712 million for the nine months ended September 30, 2005 and 2004, respectively, increased $39 million. The increase in revenues is attributable primarily to favorable retail growth and usage and favorable weather. Favorable growth and usage of $36 million was driven by an increase in the average number of customers as of September 30, 2005, compared to September 30, 2004, of 27,000. The impact of weather is $4 million favorable with cooling degree days five percent above prior year. Wholesale revenues less fuel was approximately the same as 2004 primarily due to higher fuel costs during the current period partially offset by increased capacity under contract.

Expenses

Fuel and Purchased Power

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

PEC Electric’s fuel and purchased power expenses were $1.04 billion for the nine months ended September 30, 2005, which represents a $165 million increase compared to the same period in the prior year. Fuel used in electric generation increased $109 million to $746 million compared to September 30, 2004. This increase is due to an increase in fuel used in generation of $216 million due primarily to higher coal costs and higher natural gas volumes and costs. The increase in fuel used in generation was offset by a reduction in deferred fuel expense of $106 million as a result of the under-recovery of current period fuel costs offset partially by the write-off of $5 million in deferred fuel costs as a result of the South Carolina annual fuel hearing. Purchased power expense increased $56 million to $294 million compared to prior year primarily due to a change in volumes in the current period.

O&M

PEC Electric’s O&M expenses were $719 million for the nine months ended September 30, 2005, which represents an $87 million increase compared to the same period in 2004. Postretirement and severance expenses related to the cost management initiative increased O&M expenses by $60 million during 2005. This is an increase of $57 million compared to the same period in 2004 as prior year expenses included $3 million related to a separate initiative. In addition, O&M expenses increased $20 million related to the change in accounting estimates for certain Energy Delivery capital costs, $19 million related to pension and benefit expenses, $15 million for higher emission allowance expenses and $6 million related to Hurricane Ophelia storm restoration costs. See discussion of change in Energy Delivery capitalization practice in Note 8F of Progress Energy’s annual report on Form 10-K for the year ended December 31, 2004. These unfavorable items were partially offset by decreased plant outage costs of $9 million compared to 2004, which included an additional nuclear plant outage. In addition, results for 2004 included $19 million of costs associated with an ice storm that impacted the Carolinas service territory in the first quarter of 2004 and Hurricanes Charley and Ivan that impacted the Carolinas service territory in the third quarter of 2004.

Depreciation and Amortization

PEC Electric’s depreciation and amortization expense was $389 million for the nine months ended September 30, 2005, which represents a $4 million decrease compared to the same period in 2004. The decrease is attributable to a reduction in depreciation expense of $42 million related to the depreciation studies filed in 2004 which reduced depreciation rates. Depreciation rates are the same for 2005 and 2004; however, the 2004 year to date retroactive adjustment for the new rates adopted related to the expanded lives of the nuclear units was made in November 2004. These decreases were partially offset by higher NC Clean Air amortization of $30 million and higher depreciation for assets placed in service of $8 million.

Other income, net

PEC Electric’s other income, net has increased $8 million for the nine months ending September 30, 2005 as compared to the same period in the prior year. This increase is due primarily to a write-off of $7 million of non-trade receivables in the prior year.

Total interest charges, net

PEC Electric’s interest expense has increased $13 million to $157 million for the nine months ending September 30, 2005, as compared to the same period in the prior year. This fluctuation is due primarily to interest expense related to adjustments of certain tax matters, the impact of higher variable interest rates on pollution control bonds and the impact of increased short term borrowings.

Income tax expense

GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. PEC Electric’s income tax expense was increased by $6 million for the nine months ended September 30, 2005, in order to maintain an effective tax rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent and temporary deductions can also cause fluctuations in the effective tax rate for interim periods. Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year. The remaining fluctuation in income tax expense is attributable primarily to reduced earnings compared to prior year, favorable adjustments of certain tax matters and current year tax reserve credits.

PROGRESS ENERGY FLORIDA

PEF contributed segment profits of $151 million and $140 million for the three months ended September 30, 2005 and 2004, respectively. The increase in profits for the three months ended September 30, 2005, when compared to 2004, is primarily due to the favorable impact of weather, favorable retail customer growth and usage and higher wholesale sales, partially offset by higher O&M expenses (as a result of certain planned O&M projects deferred during the third quarter of 2004 as result of hurricane restoration efforts, the change in accounting estimates for certain Energy Delivery capital costs and increased pension and benefit costs), and an increase in the provision for rate refund.

PEF contributed segment profits of $204 million and $273 million for the nine months ended September 30, 2005 and 2004, respectively. The decrease in profits for the nine months ended September 30, 2005, when compared to 2004, is primarily due to higher O&M expenses (as a result of postretirement and severance costs, the write-off of unrecovered storm costs and the change in accounting estimates for certain Energy Delivery capital costs) and lower average usage per retail customer partially offset by the favorable impact of weather, higher wholesale sales, favorable retail customer growth and the gain on the sale of the City of Winter Park, Florida (Winter Park) distribution system.

Three months ended September 30, 2005 as compared to the three months ended September 30, 2004

Revenues

PEF’s revenues for the three months ended September 30, 2005 and 2004, and the amount and percentage change by customer class are as follows:

	Three Months Ended September 30,
(in millions of $)	2005		Change		% Change		2004
Customer Class:
Residential	$    660		$ 106		19	.1	$    554
Commercial	283		41		16	.9	242
Industrial	77		13		20	.3	64
Governmental	68		12		21	.4	56
Retail revenue sharing	(2	)	(7	)	—		5
Total retail revenues	1,086		165		17	.9	921
Wholesale	96		17		21	.5	79
Unbilled	8		13		—		(5	)
Miscellaneous	37		3		8	.8	34
Total electric revenues	$ 1,227		$ 198		19	.2	$ 1,029
Less:
Pass-through revenues	(779	)	(156	)	—		(623	)
Revenues excluding pass-
through revenues	$    448		$   42		10	.3	$    406

PEF's electric energy sales for the three months ended September 30, 2005 and 2004, and the amount and percentage change by customer class are as follows:

	Three Months Ended September 30,
(in millions of kWh)	2005	Change	% Change		2004
Customer Class:
Residential	6,554	573	9	.6	5,981
Commercial	3,551	217	6	.5	3,334
Industrial	1,112	98	9	.7	1,014
Governmental	897	79	9	.7	818
Total retail energy sales	12,114	967	8	.7	11,147
Wholesale	1,408	14	1	.0	1,394
Unbilled	195	341	—		(146	)
Total kWh sales	13,717	1,322	10	.7	12,395

PEF’s revenues, excluding recoverable fuel and other pass-through revenues of $779 million and $623 million for the three months ended September 30, 2005 and 2004, respectively, increased $42 million. The increase in revenues is due to the favorable impact of weather of $22 million with cooling degree days 19 percent above prior year, favorable growth and usage of $20 million driven by a 30,000 average net increase in the number of customers as of September 30, 2005, compared to September 30, 2004, and favorable wholesale revenues, net of fuel, of $6 million. In addition to customer growth, the retail revenue increase related to growth and usage was impacted by a reduction in revenues of approximately $12 million in the third quarter of 2004 related to customer outages caused by Hurricanes Charley, Frances and Jeanne. Wholesale revenue favorability is attributable primarily to new contracts. These increases were partially offset by an unfavorable provision for rate refund of $7 million due to higher base revenues as indicated above.

Expenses

Fuel and Purchased Power

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

PEF’s fuel and purchased power expenses were $621 million for the three months ended September 30, 2005, which represents a $113 million increase compared to prior year. This increase is due to increases in fuel used in electric generation and purchased power expenses of $16 million and $97 million, respectively. Increased fuel costs in the current year account for $143 million of the increase in fuel used in electric generation. This was partially offset by a decrease of $129 million in deferred fuel expense as fuel expenses in the current year have been under-recovered. In December 2004, the FPSC approved PEF’s request for a cost recovery adjustment in its annual filing due to the rising cost of fuel. Fuel recovery rates increased effective January 1, 2005 (see Note 5 of the Combined Notes to Interim Financial Statements). The increase in purchased power expense was primarily due to higher prices of purchases in the current year as a result of increased fuel costs.

O&M

PEF’s O&M expenses were $181 million for the three months ended September 30, 2005, which represents an increase of $43 million, when compared to the $138 million incurred during the three months ended September 30, 2004. O&M expenses increased $11 million for increased pension and benefit expenses, $7 million primarily for certain planned O&M projects deferred during the third quarter of last year as a result of hurricane restoration efforts and $7 million primarily due to the timing of outages and maintenance projects. O&M expenses also increased $9 million primarily related to the change in accounting estimates for certain Energy Delivery capital costs. See discussion of change in Energy Delivery capitalization practice in Note 8F of Progress Energy’s annual report on Form 10-K for the year ended December 31, 2004. The remaining increase in O&M expense is attributable to higher environmental cost recovery expenses (primarily emission allowances) of $9 million. The environmental cost recovery expenses are pass-through expenses and have no impact on earnings.

Depreciation and Amortization

PEF’s depreciation and amortization expense increased $27 million to $95 million for the three months ended September 30, 2005. The increase is primarily due to the amortization of $24 million in storm costs which began in August 2005 (see Note 5 of the Combined Notes to the Interim Financial Statements). Storm cost amortization is a pass-through expense and has no impact on earnings.

Income tax expense

GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. PEF’s income tax expense was decreased by $9 million for the three months ended September 30, 2005, in order to maintain an effective tax rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent and temporary deductions can also cause fluctuations in the effective tax rate for interim periods. Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year. The remaining fluctuation in income tax expense is attributable to higher earnings compared to prior period and adjustments of certain tax matters.

Nine months ended September 30, 2005 as compared to nine months ended September 30, 2004

Revenues

PEF’s revenues for the nine months ended September 30, 2005 and 2004, and the amount and percentage change by customer class are as follows:

	Nine Months Ended September 30,
(in millions of $)	2005		Change		% Change		2004
Customer Class:
Residential	$ 1,522		$ 144		10	.4	$ 1,378
Commercial	711		74		11	.6	637
Industrial	211		19		9	.9	192
Governmental	178		23		14	.8	155
Retail revenue sharing	(3	)	(1	)	—		(2	)
Total retail revenues	2,619		259		11	.0	2,360
Wholesale	237		38		19	.1	199
Unbilled	22		9		—		13
Miscellaneous	105		4		4	.0	101
Total electric revenues	$ 2,983		$ 310		11	.6	$ 2,673
Less:
Pass-through revenues	(1,876	)	(259	)	—		(1,617	)
Revenues excluding pass-
through revenues	$ 1,107		$   51		4	.8	$ 1,056

PEF's electric energy sales for the nine months ended September 30, 2005 and 2004, and the amount and percentage change by customer class are as follows:

	Nine Months Ended September 30,
(in millions of kWh)	2005	Change	% Change		2004
Customer Class:
Residential	15,242	465	3	.1	14,777
Commercial	9,010	244	2	.8	8,766
Industrial	3,093	5	0	.2	3,088
Governmental	2,368	127	5	.7	2,241
Total retail energy sales	29,713	841	2	.9	28,872
Wholesale	4,063	254	6	.7	3,809
Unbilled	520	11	—		509
Total kWh sales	34,296	1,106	3	.3	33,190

PEF’s revenues, excluding recoverable fuel and other pass-through revenues of $1.876 billion and $1.617 billion for the nine months ended September 30, 2005 and 2004, respectively, increased $51 million. The increase in revenues is due to favorable current year weather of $15 million with cooling degree days 12 percent higher than prior year, favorable retail customer growth of $18 million driven by an net average increase in the number of customers as of September 30, 2005, compared to September 30, 2004, of 30,000 and $17 million of increased wholesale revenues net of fuel. In addition to customer growth, the retail revenue increase related to growth was impacted by a reduction in revenues of approximately $12 million in the third quarter of 2004 related to customer outages caused by Hurricanes Charley, Frances and Jeanne. Wholesale revenue improvement is attributable primarily to new contracts. These increases were partially offset by lower average usage per retail customer of $9 million.

Expenses

Fuel and Purchased Power

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

PEF’s fuel and purchased power expenses were $1.511 billion for the nine months ended September 30, 2005, which represents an $198 million increase compared to prior year. This increase is due to increases in fuel used in electric generation and purchased power expenses of $86 million and $112 million, respectively. Higher system requirements and increased fuel costs in the current year account for $196 million of the increase in fuel used in electric generation. This was offset by a decrease of $107 million in deferred fuel expense due to an under-recovery of fuel expenses in the current year. In December 2004, the FPSC approved PEF’s request for a cost recovery adjustment in its annual filing due to the rising cost of fuel. Fuel recovery rates increased effective January 1, 2005 (see Note 5 of the Combined Notes to Interim Financial Statements). The increase in purchased power expense was primarily due to higher prices of purchases in the current year as a result of increased fuel costs.

O&M

PEF’s O&M expenses were $658 million for the nine months ended September 30, 2005, which represents an increase of $208 million, when compared to the $450 million incurred during the nine months ended September 30, 2004. Postretirement and severance costs associated with the cost management initiative increased O&M costs by $108 million during 2005. In addition, PEF wrote-off $17 million of unrecoverable storm costs associated with the 2004 hurricanes (see Note 5 of the Combined Notes to Interim Financial Statements). O&M expense also increased $25 million primarily related to the change in accounting estimates for certain Energy Delivery capital costs. See discussion of change in Energy Delivery capitalization practice in Note 8F of Progress Energy’s annual report on Form 10-K for the year ended December 31, 2004. O&M expense increased $20 million due to higher environmental cost recovery expenses (primarily emission allowances). The environmental cost recovery expenses are pass-through expense and have no impact on earnings. The remaining increase in O&M expense is attributable to an $8 million workers compensation benefit adjustment recorded in 2005 as a result of an actuarial study and $9 million of increased pension and benefit expense.

Depreciation and Amortization

PEF’s depreciation and amortization expense increased $27 million to $236 million for the nine months ended September 30, 2005. The increase is primarily due to the amortization of $24 million in storm costs which began in August 2005 (see Note 5 of the Combined Notes to Interim Financial Statements). Storm cost amortization is a pass-through expense and has no impact on earnings.

Other

Other operating expenses decreased $24 million due to the pre-tax gain recognized on the sale of the Winter Park distribution system (see Note 5 of the Combined Notes to Interim Financial Statements).

Other income, net

PEF’s other income, net has increased $6 million for the nine months ended September 30, 2005 as compared to the prior year. This increase is due to an increase in the equity component of the allowance for funds used during construction of $7 million as a result of the Hines Unit 3 & Unit 4 construction projects. This favorable item was offset partially by the FERC Code of Conduct audit settlement that required $3 million to be refunded to customers (see Note 13 of the Combined Notes to Interim Financial Statements).

Total interest charges, net

PEF’s total interest charges, net increased $6 million to $90 million for the nine months ended September 30, 2005 as compared to $84 million for the nine months ended September 30, 2004. This increase is due primarily to additional commercial paper and internal money pool borrowings related to unrecovered storm and fuel costs and interest on long term debt.

Income tax expense

GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. PEF’s income tax expense was not changed for the nine months ended September 30, 2005, in order to maintain an effective tax rate consistent with the estimated annual rate. Fluctuations in estimated annual earnings and the timing of various permanent and temporary deductions can also cause fluctuations in the effective tax rate for interim periods. Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year. The remaining fluctuation in income tax expense is attributable to reduced earnings compared to prior year and adjustments of certain tax matters.

DIVERSIFIED BUSINESSES

Our diversified businesses consist of the Fuels segment, the CCO segment and the Synthetic Fuels segment. These businesses are explained in more detail below.

FUELS

The Fuels’ segment operations include natural gas drilling and production, coal terminal operations, coal mining, fuel transportation and delivery. This segment also has an operating fee agreement with our Synthetic Fuel operations for the procuring and processing of coal and the transloading and marketing of synthetic fuel. The following summarizes Fuels’ segment profits for the three and nine months ended September 30, 2005 and 2004:

	Three Months Ended   September 30,		Nine Months Ended     September 30,
(in millions)	2005	2004	2005	2004
Gas production	$17	$15	$41	$40
Coal fuel and other operations	1	5	—	7
Segment Profits	$18	$20	$41	$47

Natural Gas Operations

Natural gas operations generated profits of $17 million for the three months ended September 30, 2005 and $15 million for the three months ended September 30, 2004, and $41 million and $40 million for the nine months ended September 30, 2005 and 2004, respectively. The increase in gas earnings compared to prior year is attributable to higher natural gas prices partially offset by reduced production as a result of the sale of certain gas assets in 2004. In December 2004, we sold certain gas-producing properties and related assets owned by Winchester Production Company, Ltd., a subsidiary of Progress Fuels with gas operations in north Texas. In addition, results for the three and nine months ended September 30, 2005 were positively impacted by recognition in the third quarter of 2005 of a deferred gain of $5 million pre-tax on the sale of the North Texas gas operations. The following summarizes the gas production, revenues and gross margins for the three and nine months ended September 30, 2005 and 2004 by production facility:

	Three Months Ended     September 30,				Nine Months Ended    September 30,
	2005		2004		2005		2004
Production in Bcf equivalent
East Texas/LA gas operations	6.2		5.7		17.6		14.7
North Texas gas operations	—		2.9		—		8.2
Total Production	6.2		8.6		17.6		22.9
Revenues in millions
East Texas/LA gas operations	$43		$32		$115		$  80
North Texas gas operations	—		14		—		41
Total Revenues	$43		$46		$115		$121
Gross Margin
in millions of $	$34		$37		$  92		$  97
As a % of revenues	79	%	80	%	80	%	80	%

Coal Fuel and Other Operations

Coal fuel and other operations generated segment profits of $1 million for the three months ended September 30, 2005 compared to segment profits of $5 million for the three months ended September 30, 2004. The decrease in earnings compared to the prior period is due to higher coal mining costs (due to rising prices of fuel and steel) partially offset by increased sales volumes in the current year.

Coal fuel and other operations were essentially breakeven for the nine months ended September 30, 2005 compared to segment profit of $7 million for the nine months ended September 30, 2004. The decrease in earnings of $7 million is due primarily to higher coal mining costs of $39 million pre-tax (due to increased production volumes, poor mining conditions and mining start up costs), a workers compensation accrual adjustment booked during the first quarter of 2005 of $5 million pre-tax and postretirement and severance costs of $6 million pre-tax as a part of the cost management initiative. This unfavorability was partially offset by increased revenues as a result of higher coal prices.

We are exploring strategic alternatives regarding the Fuels’ coal mining business, which could include divesting these assets. As of September 30, 2005, the carrying value of long-lived assets of the coal mining business was $64 million. We cannot currently predict the outcome of this matter.

COMPETITIVE COMMERCIAL OPERATIONS

CCO’s operations generated segment losses of $13 million for the three months ended September 30, 2005 compared to segment profit of $14 million in the prior year. The decrease in earnings compared to prior year is due primarily to a reduction in gross margin of $47 million pre-tax ($28 million after-tax) offset partially by favorable interest expense. Contract margins are unfavorable compared to prior year due to the expiration of certain tolling agreements, decreased earnings from new and existing full-requirements contracts due to higher fuel and purchased power costs and unrealized mark-to-market losses. This margin unfavorability was partially offset by lower interest expense of $3 million pre-tax ($2 million after-tax) compared to the prior period due to the termination of CCO’s Genco financing arrangement in December 2004.

CCO’s operations generated segment losses of $21 million for the nine months ended September 30, 2005 compared to segment profit of $11 million in the prior period. The decrease in earnings compared to prior year is due primarily to a reduction in gross margin of $62 million pre-tax ($37 million after-tax) offset partially by favorable amortization expense and interest expense. Contract margins are unfavorable compared to prior year due to the expiration of certain tolling agreements, decreased earnings from new and existing full-requirements contracts due to higher fuel and purchased power costs and unrealized mark-to-market losses. In addition, results in the current year include $2 million pre-tax ($1 million after-tax) in postretirement and severance costs associated with the cost management initiative. Depreciation and amortization expenses decreased $5 million pre-tax ($3 million after-tax) as a result of the expiration of certain acquired contracts that were subject to amortization. Interest expense decreased $8 million pre-tax ($5 million after-tax) due to the termination of the Genco financing arrangement in December 2004.

	Three Months Ended     September 30,				Nine Months Ended    September 30,
(in millions)	2005		2004		2005		2004
Total revenues	$ 267		$90		$ 490		$196
Gross margin
In millions of $	$   16		$63		$   66		$128
As a % of revenues	6	%	70	%	13	%	65	%
Segment earnings (losses)	$  (13	)	$14		$  (21	)	$  11

We have contracts for our planned production capacity, which includes callable resources from the cooperatives, of approximately 77 percent for 2005, approximately 86 percent for 2006 and approximately 81 percent for 2007. We continue to seek opportunities to optimize our nonregulated generation portfolio.

In accordance with accounting standards for goodwill and long-lived assets, we have continued to monitor the carrying value of our goodwill and long-lived assets in our Georgia region. Our analyses have continued to support the carrying value of the $64 million of goodwill and the $960 million of long-lived assets in this region. Future adverse changes in market conditions or changes in business conditions could require future impairment evaluations of these or other assets, which could result in an impairment charge.

SYNTHETIC FUEL

The synthetic fuel operations generated segment profits of $71 million for the three months ended September 30, 2005, compared to a loss of $57 million for the three months ended September 30, 2004, and segment profits of $93 million and $15 million for the nine months ended September 30, 2005 and 2004, respectively. The production and sale of coal-based solid synthetic fuel generate operating losses, but qualify for tax credits under Section 29 of the Code, which typically more than offset the effect of such losses. See Note 15 of the Combined Notes to Interim Financial Statements.

The operations resulted in the following for the three and nine months ended September 30, 2005 and 2004:

	Three Months Ended    September 30,				Nine Months Ended   September 30,
(in millions)	2005		2004		2005		2004
Tons sold	3.0		2.1		7.3		7.7
Operating losses, excluding tax credits	$(38	)	$(33	)	$(116	)	$(110	)
Tax credits generated	82		55		199		204
Tax credits recognized (reversed)	27		(79	)	10		(79	)
Segment profits (losses)	$ 71		$(57	)	$   93		$   15

Synthetic fuels’ earnings for the three months ended September 30, 2005, as compared to the same period in the prior year, were positively impacted by higher sales in the current year, the reversal of $79 million of tax credits in the prior year as a result of hurricane costs which reduced our projected 2004 regular federal income tax liability and the recognition of $27 million of tax credits in the current year. During the third quarter of 2005, we recorded $27 million of tax credits that had previously not been recognized as part of finalizing our 2004 regular federal income tax liability. These credits were not previously recognized due to the decrease in tax liability resulting from expenses incurred for the 2004 hurricanes and loss on sale of Progress Rail. The increase in sales is due primarily to lower sales in the prior year due to the hurricanes.

Synthetic fuels’ earnings for the nine months ended September 30, 2005, as compared to the same period in the prior year, were positively impacted by the reversal of $79 million of tax credits in the prior year as a result of the impact of hurricane costs which reduced our projected 2004 regular tax liability and the recognition of $10 million of tax credits in the current year, partially offset by higher production costs. During the third quarter of 2005, we recorded $27 million of tax credits that had previously not been recognized as part of finalizing our 2004 regular federal income tax liability. This includes $17 million of tax credits that were reversed in the first quarter of 2005 due to the loss on sale of Progress Rail. See Note 15 of the Combined Notes to Interim Financial Statements for further discussion.

See“Other Matters” below for a discussion of uncertainties surrounding our synthetic fuel production in 2006.

CORPORATE AND OTHER

Corporate and Other consists of the operations of the Parent, PESC and other consolidating and non-operating entities. Corporate and Other also includes other nonregulated business areas including the telecommunications operations of Progress Telecom, LLC (PT LLC) and the energy management operations of Strategic Resource Solutions (SRS). PT LLC operations provide broadband capacity services, dark fiber and wireless services in Florida and the eastern United States. SRS was engaged in providing energy services to industrial, commercial and institutional customers to help manage energy costs primarily in the southeastern United States. During 2004, SRS sold its subsidiary, Progress Energy Solutions, and we exited this business area.

Other Nonregulated Business Areas

Other nonregulated businesses contributed segment profits of $2 million for the three months ended September 30, 2005 compared to segment losses of $2 million for the three months ended September 30, 2004. This favorability is due primarily to an increase in earnings at SRS. During the third quarter of 2005, SRS recorded insurance proceeds associated with the San Francisco United School District matter. This was partially offset by the recording of a settlement related to a military contract. In addition, PT LLC also increased earnings due to recording a litigation settlement during the third quarter of 2005.

Other nonregulated businesses were essentially break even for the nine months ended September 30, 2005 compared to segment losses of $36 million for the nine months ended September 30, 2004. This favorability is due primarily to the reduction of losses at SRS. During the second quarter of 2004, SRS recorded the litigation settlement reached with the San Francisco United School District related to civil proceedings which settled all outstanding claims for approximately $43 million pre-tax ($29 million after-tax).

Corporate Services

Corporate Services (Corporate) includes the operations of the Parent, PESC and consolidation entities. PESC’s expenses are allocated to the other business segments. The remaining Corporate income (expense), consisting primarily of interest expense and income taxes, is summarized below:

		Three Months Ended   September 30,				Nine Months Ended   September 30,
(in millions)	2005		2004		2005		2004
Other interest expense		$(68	)	$(64	)	$(211	)	$(202	)
Contingent value obligations		4		20		4		7
Tax levelization		85		38		33		(6	)
Tax reallocation		(10	)	(9	)	(29	)	(27	)
Other income taxes		26		13		87		72
Other		—		4		(8	)	(5	)
Segment profit (loss)		$ 37		$   2		$(124	)	$(161	)

Other interest expense increased $4 million compared to $64 million for the three months ended September 30, 2004 and increased $9 million compared to $202 million for the nine months ended September 30, 2004. Interest increased for the three months ended September 30, 2005 due primarily to the reversal of interest expense on income tax deficiencies in 2004. Other interest expense increased for the nine months ended September 30, 2005 due to increased rates on commercial paper borrowings, interest rate swaps, additional expenses incurred related to draw downs on revolving credit agreements and the 2004 reversal of interest expense on income tax deficiencies.

We issued 98.6 million contingent value obligations (CVOs) in connection with the 2000 acquisition of Florida Progress. Each CVO represents the right to receive contingent payments based on the performance of four synthetic fuel facilities we own. The payments, if any, are based on the net after-tax cash flows the facilities generate. At September 30, 2005 and 2004, the CVOs had fair market values of approximately $9 million and $16 million, respectively. We recorded unrealized gains of $4 million and $20 million for the three months ended September 30, 2005 and 2004, respectively, to record the changes in fair value of the CVOs, which had average unit prices of $0.09 and $0.16 at September 30, 2005 and 2004, respectively. We recorded an unrealized gain of $4 million and $7 million for the nine months ended September 30, 2005 and September 30, 2004.

GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. Income tax expense was decreased by $85 million and $38 million for the three months ended September 30, 2005 and 2004, respectively, in order to maintain an effective rate consistent with the estimated annual rate. For the nine months ended September 30, 2005, income tax expense was decreased by $33 million and for the nine months ended September 30, 2004, income tax expense was increased by $6 million. The tax credits associated with our synthetic fuel operations and seasonal fluctuations in our annual earnings primarily drive the fluctuations in the effective tax rate for interim periods. The tax levelization adjustment will vary each quarter, but it will have no effect on net income for the year.

Other income taxes benefit increased $13 million to $26 million for the three months ended September 30, 2005 and increased $15 million to $87 million for the nine months ended September 30, 2005. The tax benefit increases are primarily due to certain adjustments that increased income tax expense at the Parent during the third quarter of 2004, but were not recurring for the third quarter of 2005. The adjustments that increased income tax expense during the third quarter of 2004 were related to a reduction in the Parent’s allocation of Florida income tax consolidation benefit due to the impact of hurricanes in the third quarter of 2004 and the recording of a reserve related to identified state tax deficiencies.

DISCONTINUED OPERATIONS

On March 24, 2005, we completed the sale of Progress Rail to One Equity Partners LLC, a private equity firm unit of J.P. Morgan Chase & Co. Gross cash proceeds from the sale were $429 million, consisting of $405 million base proceeds plus a working capital adjustment. Proceeds from the sale were used to reduce debt. The accompanying Progress Energy consolidated interim financial statements have been restated for all periods presented for the discontinued operations of Progress Rail. See Notes 3 and 15B of the Combined Notes to Interim Financial Statements for additional discussion.

Rail discontinued operations resulted in losses of $1 million for the three months ended September 30, 2005 compared to profits of $11 million for the three months ended September 30, 2004. Earnings for 2005 include an adjustment of $1 million to the estimated after-tax loss on the sale related primarily to working capital adjustments. Results for 2004 include three months of operations. Results for the three months ended September 30, 2005 do not include any income or loss from operations as the sale closed in the first quarter. See discontinued earnings summary included at Note 3 of the Combined Notes to Interim Financial Statements.

Rail discontinued operations resulted in losses of $20 million for the nine months ended September 30, 2005 compared to profits of $27 million for the nine months ended September 30, 2004. Earnings for 2005 include an estimated after-tax loss on the sale of $25 million. Results for 2004 included nine months of earnings activity compared to only three months in 2005.

NCNG discontinued operations contributed $1 million of net income for the nine months ended September 30, 2004. The sale of NCNG to Piedmont Natural Gas Company closed in 2003; however, during the nine months ended September 30, 2004, we recorded an additional gain of $1 million after-tax related to deferred taxes on the loss from the sale.

LIQUIDITY AND CAPITAL RESOURCES

Progress Energy

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

Cash Flows from Operations

The majority of our operating costs are related to the Utilities. A significant portion of the Utilities’ costs, including the cost of fuel and purchased power, are recovered from customers in accordance with rate plans. As such, changes in the Utilities’ fuel and purchased power costs may affect the timing of cash flows but not net income.

Net cash provided by operating activities decreased by $332 million for the nine months ended September 30, 2005, when compared to the corresponding period in the prior year. The $332 million decrease in operating cash flow was primarily due to a $211 million increase in the under-recovery of fuel at the Utilities driven by rising fuel costs (see Note 5 to the Combined Notes to Interim Financial Statements) and increased working capital needs. The increase in working capital needs was mainly driven by a $215 million increase in the change in receivables and a $51 million increase in inventory purchases, primarily coal at PEC, partially offset by a $159 million increase in the change in accounts payable. The increase in the change in receivables is primarily due to increased sales at the Utilities driven by weather and timing of receipts, and increased sales at our nonregulated subsidiaries, mainly driven by rising gas prices and changes in the production level of our synthetic fuel plants over the prior year. The change in accounts payable is primarily due to higher fuel prices and increased quantities of fuel purchases at our nonregulated subsidiaries.

Investing Activities

Net cash used in investing activities decreased by $44 million for the nine months ended September 30, 2005, when compared to the corresponding period in the prior year. The decrease is due primarily to $405 million in base proceeds from the sale of Progress Rail in March 2005 and $42 million in proceeds from the sale of Winter Park assets in June 2005, compared to $112 million in proceeds from the sale of assets during the nine months ended September 30, 2004. See Note 3 of the Combined Notes to Interim Financial Statements. This was partially offset by $144 million of lower net proceeds from short-term investments, $81 million in additional capital expenditures for utility property and nuclear fuel additions, and $27 million in additional diversified business property additions. See Note 4 of the Combined Notes to Interim Financial Statements.

Financing Activities

Net cash used in financing activities was $201 million for the nine months ended September 30, 2005, compared to $647 million for the nine months ended September 30, 2004, or a net decrease of $446 million. The change in cash used in financing activities was due primarily to the March 1, 2004 maturity of $500 million 6.55% senior unsecured notes. These notes were paid with cash and commercial paper capacity which was created from the sale of assets during 2003.

In January 2005, Progress Energy used proceeds from the issuance of commercial paper to pay off $260 million of revolving credit agreement (RCA) loans at the Utilities, which included $90 million at PEC and $170 million at PEF. PEF subsequently used money pool borrowings to reduce its outstanding commercial paper balance.

On January 31, 2005, Progress Energy entered into a new $600 million RCA, which was scheduled to expire on December 30, 2005. This facility was added to provide additional liquidity, to the extent necessary, during 2005 due in part to the uncertainty of the timing of storm restoration cost recovery from the hurricanes in Florida during 2004. On February 4, 2005, $300 million was drawn under the new facility to reduce commercial paper and pay off the remaining amount of loans outstanding under other RCA facilities, which consisted of $160 million at Progress Energy and, through the money pool, $55 million at PEF. As discussed below, the maximum size of this RCA was reduced to $300 million on March 22, 2005 and subsequently terminated on May 16, 2005.

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

In March 2005, Progress Energy’s $1.1 billion five-year credit facility was amended to increase the maximum total debt to total capital ratio from 65% to 68% due to the potential impacts of a proposed interpretation of SFAS No. 109 regarding accounting rules for uncertain tax positions (See Note 2 of the Combined Notes to Interim Financial Statements).

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

On March 28, 2005, PEC entered into a new $450 million five-year RCA with a syndication of financial institutions. The PEC RCA will be used to provide liquidity support for PEC’s issuances of commercial paper and other short-term obligations. The PEC RCA is scheduled to expire on June 28, 2010. The new $450 million PEC RCA replaced PEC’s $285 million three-year RCA and $165 million 364-day RCA, which were each terminated effective March 28, 2005. Fees and interest rates under the new PEC RCA are to be determined based upon the credit rating of PEC’s long-term unsecured senior non-credit enhanced debt, currently rated as Baa1 by Moody’s and BBB by S&P. The PEC RCA includes a defined maximum total debt to capital ratio of 65%. The RCA also contains various cross-default and other acceleration provisions, including a cross-default provision for defaults of indebtedness in excess of $35 million. The PEC RCA does not include a material adverse change representation for borrowings, which had been a provision in the terminated agreements.

In May 2005, Progress Energy used proceeds from the issuance of commercial paper to pay off $300 million of its $600 million RCA.

On May 16, 2005, PEF issued $300 million of First Mortgage Bonds, 4.50% Series due 2010. The net proceeds from the sale of the bonds were used to reduce the outstanding balance of commercial paper. Pursuant to the terms of the Progress Energy $600 million RCA, commitments were completely reduced and the RCA was terminated, effective May 16, 2005.

On July 1, 2005, PEF paid at maturity $45 million of its 6.72% Medium-Term Notes, Series B with commercial paper proceeds.

On July 28, 2005, PEC filed a shelf registration statement with the SEC to provide an additional $1.0 billion of capacity in addition to the $400 million remaining on PEC’s current shelf registration statement. The shelf registration statement, when declared effective, will allow PEC to issue various securities, including First Mortgage Bonds, Senior Notes, Debt Securities and Preferred Stock.

On July 28, 2005, PEF filed a shelf registration statement with the SEC to provide an additional $1.0 billion of capacity in addition to the $450 million remaining on PEF’s current shelf registration statement. The shelf registration statement, when declared effective, will allow PEF to issue various securities, including First Mortgage Bonds, Debt Securities and Preferred Stock.

For the nine months ended September 30, 2005, we issued approximately 4.4 million shares representing approximately $193 million in proceeds from our Investor Plus Stock Purchase Plan and our employee benefit and stock option plans, net of purchases of restricted shares. For the year 2005, we expect to realize approximately $200 million aggregate amount from the sale of stock through these plans.

Future Liquidity and Capital Resources

As of September 30, 2005, there were no material changes in our “Capital Expenditures,” “Other Cash Needs,” “Credit Facilities,” or “Credit Rating Matters” as compared to those discussed under LIQUIDITY AND CAPITAL RESOURCES in Item 7 of the Progress Registrants’ annual reports on Form 10-K, other than “Environmental Matters” as described below and under “Financing Activities.”

As of September 30, 2005, the current portion of our long-term debt was $852 million, which includes $800 million of Progress Energy senior unsecured notes due March 1, 2006. We expect to refinance this note with issuances of new long-term debt.

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

On April 27, 2005, PEC filed for an increase in the fuel rate charged to its South Carolina retail customers with the Public Service Commission of South Carolina (SCPSC). PEC requested the increase for under-recovered fuel costs for the previous 15 months and to meet future expected fuel costs. On June 23, 2005, the SCPSC approved a settlement agreement that authorizes an annual increase of $55 million in PEC’s rates, effective July 1, 2005. See Note 5 of the Combined Notes to Interim Financial Statements.

On June 3, 2005, PEC filed for a $276 million increase in the fuel rate charged to its North Carolina retail customers with the North Carolina Utilities Commission (NCUC). PEC requested the increase for under-recovered fuel costs for the previous 12 months and to meet future expected fuel costs. On September 26, 2005, the NCUC approved a settlement that authorizes PEC to collect all of its fuel cost under-collections that occurred during the test year ended March 31, 2005 over a one-year period beginning October 1, 2005. Additionally, the NCUC approved a partial recovery of future expected fuel costs in order to address customer concerns regarding the magnitude of the proposed increase. The increase was effective October 1, 2005. See Note 5 of the Combined Notes to Interim Financial Statements.

In September and October 2005, PEF filed requests with the Florida Public Service Commission (FPSC) seeking a total increase of $605 million over 2005 to cover rising fuel and other costs to generate electricity. The proposed new charges would take effect January 1, 2006. The FPSC is scheduled to hold hearings on the proposals on November 7 through 9, 2005. See Note 5 of the Combined Notes to Interim Financial Statements.

On September 7, 2005, the FPSC approved an agreement (Base Rate Settlement) that maintains PEF’s base rates at the current level through 2007. The new base rates will take effect the first billing cycle of January 2006 and will remain in effect through the last billing cycle of December 2009 with PEF having sole option to extend through the last billing cycle of June 2010. PEF’s initial petition on April 29, 2005 was for an annual base revenue increase of $206 million. See Note 5 of the Combined Notes to Interim Financial Statements.

On July 14, 2005, the FPSC issued an order authorizing PEF to recover $232 million of storm costs over a two-year period, effective August 1, 2005. PEF’s initial petition in November 2004 for $252 million was an estimate. On September 12, 2005, PEF filed a true-up for an additional $19 million in storm costs in excess of the amount requested in the original petition. The recovery of this difference is still subject to FPSC approval and will be determined during the hearings being held on November 7 through 9, 2005. If the FPSC approves the storm cost increase, the impact will be included in customer bills beginning January 1, 2006. See Note 5 of the Combined Notes to Interim Financial Statements.

On June 1, 2005, the Governor of Florida signed into law a bill that would allow utilities to petition the FPSC to use securitized bonds to recover storm related costs. PEF is reviewing whether it will seek FPSC approval to issue securitized debt to recover any outstanding balance of its 2004 storm costs and to replenish its storm reserve fund or to seek replenishment of its storm reserve fund through base rates or a surcharge mechanism. If PEF seeks recovery through securitization and assuming FPSC approval, PEF expects the process to take six to nine months to complete. See Note 5 of the Combined Notes to Interim Financial Statements.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

Our off-balance sheet arrangements and contractual obligations are described below.

Guarantees

As a part of normal business, we enter into various agreements providing future financial or performance assurances to third parties that are outside the scope of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN No. 45). These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to Progress Energy or our subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. Our guarantees include performance obligations under power supply agreements, tolling agreements, transmission agreements, gas agreements, fuel procurement agreements and trading operations. Our guarantees also include standby letters of credit, surety bonds and guarantees in support of nuclear decommissioning. As of September 30, 2005, we have issued $1.68 billion of guarantees for future financial or performance assurance. We do not believe conditions are likely for significant performance under the guarantees of performance issued by or on behalf of affiliates.

The majority of contracts supported by the guarantees contain provisions that trigger guarantee obligations based on downgrade events to below investment grade (below BBB- or Baa3), ratings triggers, monthly netting of exposure and/or payments and offset provisions in the event of a default. As of September 30, 2005, no guarantee obligations had been triggered. If the guarantee obligations were triggered, the maximum amount of liquidity requirements to support ongoing operations within a 90-day period, associated with guarantees for Progress Energy’s nonregulated portfolio and power supply agreements was $606 million. We believe that we would be able to meet this obligation with cash or letters of credit.

As of September 30, 2005, we have issued guarantees and indemnifications of certain legal, tax and environmental matters to third parties in connection with sales of businesses and for timely payment of obligations in support of our non-wholly owned synthetic fuel operations. Related to the sales of businesses, the notice period extends until 2012 for the majority of matters provided for in the indemnification provisions. For matters for which we receive timely notice, our indemnity obligations may extend beyond the notice period. Certain environmental indemnifications related to the sale of synthetic fuel operations have no limitations as to time or maximum potential future payments. Other guarantees and indemnifications have an estimated maximum exposure of approximately $152 million. As of September 30, 2005, we have recorded liabilities related to guarantees and indemnifications to third-parties of approximately $26 million. Management does not believe conditions are likely for significant performance under these agreements in excess of the recorded liabilities.

As of September 30, 2005, the Utilities had no guarantees issued on behalf of unconsolidated subsidiaries or other third parties.

In addition, the Parent has issued $300 million of guarantees of certain payments of two wholly owned indirect subsidiaries. See Note 8 of the Combined Notes to Interim Financial Statements for additional information.

Market Risk and Derivatives

Under its risk management policy, we may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 10 of the Combined Notes to the Interim Financial Statements and Item 3, “Quantitative and Qualitative Disclosures about Market Risk,” for a discussion of market risk and derivatives.

Contractual Obligations

As part of our ordinary course of business, we enter into various long and short term contracts for fuel requirements at our generating plants. Through September 30, 2005, contracts procured through the Utilities and other businesses have increased our aggregate purchase obligations for fuel and purchased power by approximately $1.83 billion as compared to the amount stated in our annual report on Form 10-K for the year ended December 31, 2004. The increase primarily relates to the period ranging from 2005 through 2009. A majority of the contracts related to this increase are for future coal purchases primarily with fixed prices and future gas purchases primarily with variable prices.

OTHER MATTERS

Synthetic Fuels Tax Credits

We have substantial operations associated with the production of coal-based solid synthetic fuels. The production and sale of these products qualifies for federal income tax credits so long as certain requirements are satisfied. These operations are subject to numerous risks.

Although we believe that we operate our synthetic fuel facilities in compliance with applicable legal requirements for claiming the credits, our four Earthco facilities are under audit by the IRS. IRS field auditors have taken an adverse position with respect to compliance with the placed-in-service date requirements, and if we fail to prevail with respect to this position, we could incur significant liability and/or lose the ability to claim the benefit of tax credits carried forward or generated in the future. Similarly, in July 2005 the FASB issued proposed new accounting rules that would require that uncertain tax benefits (such as those associated with the Earthco facilities) be probable of being sustained in order to be recorded on the financial statements. If adopted as currently drafted, this provision could have a material adverse impact on our financial position and results of operations. See Notes 2 and 15 to the Combined Notes to Interim Financial Statements.

Our ability to utilize tax credits is currently dependent on having sufficient tax liability. Any conditions that reduce our tax liability, such as weather, could also diminish our ability to utilize credits, including those previously generated. Synthetic fuel is generally not economical to produce absent the tax credits.

As discussed in Note 15 to the Combined Interim Financial Statements, the tax credits associated with synthetic fuels may be phased out if market prices for crude oil exceed certain prices. While we cannot predict with any certainty the Annual Average Price for 2005 or beyond, we do not currently believe that the 2005 Average Annual Price will trigger a phase out of the Section 29 tax credits in 2005.

Our future synthetic fuel production levels for 2006 and beyond remain uncertain because we cannot predict with any certainty the Annual Average Price for 2005 or beyond., If oil prices for 2006 remained at the October 17, 2005 average futures price level of $63 per barrel for the entire year in 2006, it is unlikely that we would produce any synthetic fuel in 2006. This could have a material adverse impact on our results of operations. We will continue to monitor the level of oil prices and retain the ability to adjust production based on future oil price levels.

Due to the significant uncertainty surrounding our synthetic fuel production in 2006 and beyond based on the current level of oil prices, we evaluated our synthetic fuel and other related operating long-lived assets for impairment during the third quarter of 2005. We determined that no impairment of these assets was required this quarter, partly due to the estimated future cash flows from tax credits generated in the fourth quarter of 2005 from synthetic fuel production. However, a decrease in future synthetic fuel production and cash flows could require additional impairment evaluations in the fourth quarter of 2005, which could result in a future impairment of these assets, which have total carrying values of approximately $115 million. The majority of these assets will be fully depreciated by the end of 2007, the scheduled end of the Section 29 tax credit program. The outcome of this matter cannot be determined.

Our synthetic fuel operations and related risks are described in more detail in Note 15 of the Combined Notes to the Interim Financial Statements and in the Risk Factors section of Progress Energy’s annual report on Form 10-K for the year ended December 31, 2004.

Potential Submittal of Applications for Nuclear Power Plant Licenses

We have notified the NRC that we will potentially submit a combined construction and operating license application for one or more new nuclear power plants. We expect to select potential sites and a reactor vendor by the end of 2005. The notification does not bind us to take any action. Demand, fuel prices, security issues and other factors will affect any future plans. We cannot predict the outcome of this matter.

PEF Rate Case Settlement

On April 29, 2005, PEF submitted minimum filing requirements, based on a 2006 projected test year, to initiate a base rate proceeding regarding its future base rates. In its filing, PEF requested a $206 million annual increase in base rates effective January 1, 2006. On September 7, 2005, the FPSC approved the Base Rate Settlement, effective the first billing cycle of January 2006 through the last billing cycle of December 2009 with PEF having sole option to extend through the last billing cycle of June 2010. The Base Rate Settlement maintains PEF’s base rates at their current level through late 2007 and allows PEF to recover the cost of the Hines 4 generation facility when it goes into service in late 2007 and transfer recovery of the Hines 2 generation facility from the fuel clause, into base rates at the same time. Among other things, the Base Rate Settlement also provides for 1) revenue sharing, 2) the ability to petition for a rate increase if PEF’s regulatory return on equity falls below 10% 3) continued suspension of the fossil dismantlement and nuclear decommissioning accruals, 4) a $26 million decrease in depreciation expense, 5) an adjustment to capital structure to increase common equity for the impact of S&P’s imputed debt to qualifying facilities and certain other providers, 6) an 11.75% return on equity on the adjusted capital structure for clause recoveries and AFUDC calculations, 7) a maximum 57.83% adjusted equity ratio, and 8) capacity clause recovery of post-9/11 security costs and fuel clause recovery of coal inventory in transit and procurement costs.

PEF Storm Cost Recovery

On July 14, 2005, the FPSC issued an order authorizing PEF to recover $232 million over a two-year period, including interest, of the costs it incurred and previously deferred related to PEF’s restoration of power associated with the four hurricanes in 2004. The ruling allowed PEF to include a charge of approximately $3.27 on the average residential monthly customer bill beginning August 1, 2005. The ruling by the FPSC approved the majority of PEF’s requests with two exceptions: the reclassification of $8 million of previously deferred costs to utility plant and the reclassification of $17 million of previously deferred costs as normal O&M expense which was expensed in the second quarter of 2005.

The amount included in the original petition requesting recovery of $252 million in November 2004 was an estimate, as actual total costs were not known at that time. On September 12, 2005, PEF filed a true-up to the original amount requested. PEF incurred an additional $19 million in costs in excess of the amount requested in the original petition. The recovery of this difference is still subject to FPSC approval and will be determined during the hearings to be held on November 7 through 9, 2005. If the FPSC approves the increase, the impact will be included in customer bills beginning January 1, 2006.

On June 1, 2005, the Governor of Florida signed into law a bill that would allow utilities to petition the FPSC to use securitized bonds to recover storm related costs. PEF is reviewing whether it will seek FPSC approval to issue securitized debt to recover any outstanding balance of its 2004 storm cots and to replenish its storm reserve fund or to seek replenishment of its storm reserve fund through base rates or a surcharge mechanism. If PEF seeks recovery through securitization and assuming FPSC approval, PEF expects the process to take six to nine months to complete.

Energy Policy Act of 2005

On August 8, 2005, the Energy Policy Act of 2005 (EPACT) was signed into law. This new federal law contains key provisions affecting the electric power industry. These provisions include tax changes for the utility industry, incentives for emissions reductions, federal insurance and incentives to build new nuclear power plants, repeal of the Public Utility Holding Company Act (PUHCA) effective February 8, 2006, and protection for native retail load customers of utilities that are not in regional transmission organizations. It gives FERC “backstop” transmission siting authority as well as increased utility merger oversight. The law also provides incentives and funding for clean coal technologies and initiatives to voluntarily reduce greenhouse gases and redesignates the Section 29 tax credit as a general business credit. See Note 15 to the Combined Interim Financial Statements for additional information on the redesignation of the Section 29 tax credits.

The law requires FERC to issue certain regulations implementing EPACT within 120 days of enactment. FERC has commenced the rulemaking process and it is ongoing. We have reviewed the proposed rules and are participating in the public comment process. However, we cannot currently predict what impact the final rules will have on our financial condition and results of operations.

Franchise Litigation

PEF has resolved all but one of its outstanding franchise matters. On August 25, 2005, the City Council of Edgewood, Florida approved a new 30-year electric utility franchise agreement with PEF which resolved all outstanding litigation with the City of Edgewood (1,400 customers). On August 22, 2005, the 7,000-customer City of Maitland also entered into a new 30-year franchise agreement with PEF. As previously noted, in accordance with the terms of an arbitration panel’s award issued in May 2003 and after satisfying regulatory and operational requirements, Winter Park acquired from PEF the electric distribution system that serves Winter Park (13,000 customers) for approximately $42 million. PEF transferred the distribution system to Winter Park on June 1, 2005 and recognized a pre-tax gain of $25 million on the transaction, which is included as an offset to other utility expense on the Statements of Income. This amount was decreased $1 million in the third quarter of 2005 upon accumulation of the final capital expenditures since arbitration. PEF also recorded a regulatory liability of $8 million for stranded costs which will be amortized to revenues over the next six years in accordance with the provisions of the transfer agreement with Winter Park. In addition, Winter Park executed a wholesale power supply contract with PEF with a five-year term from the date service begins and a renewal option.

The 2,500 customer Town of Belleair (Belleair) is the last municipality with pending litigation against PEF. Arbitration with Belleair to determine the value of PEF’s electric distribution system within 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 Belleair at approximately $6 million. The panel further required Belleair to pay to PEF its requested $1 million in separation and reintegration costs and $2 million in stranded costs. Belleair has not yet decided whether it will attempt to acquire the system; however, on January 18, 2005, it issued a request for proposals for wholesale power supply and to operate and maintain the distribution system. In March 2005, PEF submitted a bid to supply wholesale power to Belleair. Belleair received several other proposals for wholesale power and distribution services. In February 2005, the Town Commission also voted to put the issue of whether to acquire the distribution system to a voter referendum. A referendum is scheduled to occur on November 8, 2005. At this time, whether and when there will be further proceedings regarding Belleair cannot be determined.

Environmental Matters

We are subject to federal, state and local regulations addressing air and water quality, hazardous and solid waste management and other environmental matters. We currently estimate total compliance costs for the Utilities, related to environmental laws and regulations addressing air and water quality, which will primarily be for capital expenditures, to be in excess of $2.0 billion over ten years. These environmental matters are discussed in detail in Note 14 of the Combined Notes to Interim Financial Statements. This discussion identifies specific environmental issues, the status of the issues, accruals associated with issue resolutions and our associated exposures. We accrue costs to the extent they are probable and can be reasonably estimated. It is reasonably possible that additional losses, which could be material, may be incurred in the future.

Progress Energy Carolinas, Inc.

The information required by this item is incorporated herein by reference to the following portions of Progress Energy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations, insofar as they relate to PEC: RESULTS OF OPERATIONS; LIQUIDITY AND CAPITAL RESOURCES and OTHER MATTERS.

RESULTS OF OPERATIONS

The results of operations for the PEC Electric segment are identical between PEC and Progress Energy. The results of operations for PEC’s nonutility subsidiaries for the three and nine months ended September 30, 2005 and 2004 are not material to PEC’s consolidated financial statements.

LIQUIDITY AND CAPITAL RESOURCES

Cash provided by operating activities decreased $182 million for the nine months ended September 30, 2005, when compared to the corresponding period in the prior year. The $182 million decrease in operating cash flow was primarily due to an $89 million increase in the under-recovery of fuel driven by rising fuel costs (see Note 5 to the Combined Notes to Interim Financial Statements) and a $98 million increase in working capital needs. The increase in working capital needs was primarily due to a $57 million increase in inventory purchases, primarily coal, an $83 million increase in the change in receivables and a change in emission allowance inventory fluctuations. The increase in the change in receivables is primarily due to increased sales driven by weather and the timing of receipts. These factors were partially offset by the timing of payables to affiliated companies.

Cash used in investing activities increased $238 million for the nine months ended September 30, 2005, when compared to the corresponding period in the prior year primarily due to $144 million of lower net proceeds from short-term investments and $96 million in additional capital expenditures for utility property additions.

See Progress Energy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations, “LIQUIDITY AND CAPITAL RESOURCES”, for a discussion of PEC’s financing activities.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

PEC’s off-balance sheet arrangements and contractual obligations are described below.

Market Risk and Derivatives

Under its risk management policy, PEC may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 10 of the Combined Notes to Interim Financial Statements and Item 3, “Quantitative and Qualitative Disclosures about Market Risk,” for a discussion of market risk and derivatives.

Contractual Obligations

As part of PEC’s ordinary course of business, it enters into various long and short term contracts for fuel requirements at its generating plants. Through September 30, 2005, these contracts have increased PEC’s aggregate purchase obligations for fuel and purchased power by approximately $1.15 billion as compared to the amount stated in PEC’s Form 10-K for the year ended December 31, 2004. The increase primarily relates to the period ranging from 2005 through 2009. A majority of the contracts related to this increase are for future coal purchases primarily with fixed prices.

Progress Energy Florida, Inc.

The information required by this item is incorporated herein by reference to the following portions of Progress Energy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations, insofar as they relate to PEF: RESULTS OF OPERATIONS; LIQUIDITY AND CAPITAL RESOURCES and OTHER MATTERS.

RESULTS OF OPERATIONS

The results of operations for the PEF segment are identical between PEF and Progress Energy.

LIQUIDITY AND CAPITAL RESOURCES

PEF’s net cash provided by operating activities decreased $219 million for the nine months ended September 30, 2005, when compared to the corresponding period in the prior year. The decrease was due primarily to a $122 million increase in the under-recovery of fuel driven by rising fuel costs (see Note 5 to the Combined Notes to Interim Financial Statements), a $76 million increase in the change in receivables and unfavorability from tax payments. The increase in the change in receivables is primarily due to increased sales driven by weather and timing of receipts.

Cash used in investing activities increased $6 million for the nine months ended September 30, 2005, when compared to the corresponding period in the prior year. The increase in cash used in investing activities is primarily due to $46 million in nuclear fuel additions related to a planned outage during the fourth quarter of 2005. These increases were partially offset by $42 million in proceeds from the sale of Winter Park assets (see Note 5 of the Combined Notes to Interim Financial Statements).

See Progress Energy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations, “LIQUIDITY AND CAPITAL RESOURCES”, for a discussion of PEF’s financing activities.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to various risks related to changes in market conditions. Market risk represents the potential loss arising from adverse changes in market rates and prices. We have a risk management committee that includes senior executives from various business groups. The risk management committee is responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. Under our risk policy, we 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 to the extent that the counterparty fails to perform under the contract. We mitigate such risk by performing credit reviews using, among other things, publicly available credit ratings of such counterparties. See Note 10 to the Combined Interim Financial Statements.

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

Progress Energy

Other than described below, the various risks that we are exposed to have not materially changed since December 31, 2004.

Interest Rate Risk

Our exposure to changes in interest rates from fixed rate and variable rate long-term debt at September 30, 2005 has changed from December 31, 2004. The total notional amount of fixed rate long-term debt as of September 30, 2005, was $9.31 billion, with an average interest rate of 6.40% and fair market value of $9.83 billion. The total notional amount of variable rate long-term debt as of September 30, 2005, was $861 million, with an average interest rate of 2.49% and fair market value of $861 million.

In addition to our variable rate long-term debt, we typically have commercial paper and/or loans outstanding under our RCA facilities, which are also exposed to floating interest rates. As of September 30, 2005, approximately 12.4 percent of consolidated debt, including interest rate swaps, was in floating rate mode compared to 16.1 percent at the end of 2004.

From time to time, we use interest rate derivative instruments to adjust the mix between fixed and floating rate debt in our debt portfolio, to mitigate our exposure to interest rate fluctuations associated with certain debt instruments, and to hedge interest rates with regard to future fixed rate debt issuances.

The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss. In the event of default by a counterparty, the risk in the transaction is the cost of replacing the agreements at current market rates. We only enter into interest rate derivative agreements with banks with credit ratings of single A or better.

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

In accordance with SFAS No. 133, interest rate derivatives that qualify as hedges are broken into one of two categories, cash flow hedges or fair value hedges. Cash flow hedges are used to reduce exposure to changes in cash flow due to fluctuating interest rates. Fair value hedges are used to reduce exposure to changes in fair value due to interest rate changes.

The following tables summarize the terms, fair market values and exposures of our interest rate derivative instruments.

Cash Flow Hedges

As of September 30, 2005 and December 31, 2004, we had $200 million notional of pay-fixed swaps to hedge cash flow for commercial paper interest. As of September 30, 2005, we also had $100 million notional of pay-fixed forward starting swaps to hedge cash flow risk with regard to future financing transactions. Under terms of these swap agreements, we will pay a fixed rate and receive a floating rate based on either 1-month or 3-month London Inter Bank Offering Rate (LIBOR), respectively.

Cash Flow Hedges (dollars in millions)                                               Progress Energy, Inc. -------------------------------------------------------	Notional  Amount ---------------	Pay -----------	Receive(b) -----------------------	Fair Value ---------------	Exposure(c) --------------
Risk hedged as of September 30, 2005: Commercial Paper interest rate risk through through 2005 Anticipated 10-year debt issue(d) ------------------------------------------- Total ------------------------------------------- Risk hedged as of December 31, 2004: Commercial Paper interest risk from 2005 through 2008	$ 200  $ 100 --------  $ 300 --------           $ 200	3.07%   4.87% ---------  3.67%(a) ---------            3.07%	1-month LIBOR  3-month LIBOR                                  1-month LIBOR	$ -  $ - ------  $ - ------       $ -	$ -  $ (2) ----------  $ (2) ----------  $ -

As of September 30, 2005, PEC had no open interest rate cash flow hedges. As of December 31, 2004, PEC had $131 million notional of pay-fixed forward starting swaps to hedge cash flow risk with regard to future financing transactions.

PEC -------------------------------------------------------
Risk hedged as of September 30, 2005: Risk hedged as of December 31, 2004: ---------------------------------------------- Anticipated 10-year debt issue Rail car lease payment ---------------------------------------------- Total ----------------------------------------------	None ------------  $ 110  $ 21 ------------  $ 131 ------------	-----------  4.85%  5.17% -----------  4.90%(a) -----------	-------------------------  3-month LIBOR  3-month LIBOR -------------------------	-----  $ (1)  $ (1) $ (2) -----	----- $(2) $ - $(2) -----

(a) Weighted average interest rate.
(b) 1-month LIBOR rate was 3.86% as of September 30, 2005, and 2.40% as of December 31, 2004.
      3-month LIBOR rate was 4.07% as of September 30, 2005, and 2.56% as of December 31, 2004.
(c) Exposure indicates change in value due to 25 basis point unfavorable shift in interest rates.
(d) Anticipated 10-year debt issue hedges mature on March 1, 2016, and require mandatory cash settlement
      on March 1, 2006.

Fair Value Hedges:

As of September 30, 2005 and December 31, 2004, we had $150 million notional of fixed rate debt swapped to floating rate debt. Under terms of these swap agreements, we will receive a fixed rate and pay a floating rate based on 3-month LIBOR.

As of September 30, 2005 and December 31, 2004, PEC had no open interest rate fair value hedges.

Fair Value Hedges (dollars in millions)
Progress Energy, Inc. ---------------------------------------------- Risk hedged as of September 30, 2005: ---------------------------------------------- 5.85% Notes due 10/30/2008                                                7.10% Notes due 3/1/2011 ---------------------------------------------- Total ---------------------------------------------- Risk hedged as of December 31, 2004: ---------------------------------------------- 5.85% Notes due 10/30/2008 7.10% Notes due 3/1/2011 ---------------------------------------------- Total ----------------------------------------------	Notional  Amount ------------- -------------   $ 100   $ 50 -------------   $ 150 ------------- -------------   $ 100   $ 50 -------------   $ 150 -------------	Receive ------------ ------------  4.10%               4.65% ------------  4.28%(a) ------------ ------------  4.10%  4.65% ------------  4.28%(a) ------------	Pay(b) ------------------------ ------------------------  3-month LIBOR               3-month LIBOR ------------------------   ------------------------  3-month LIBOR  3-month LIBOR ------------------------	Fair Value ------------ ------------    $ (1)    $ -             ------------    $ (1) ------------ ------------     $ 1     $ 2 ------------     $ 3 ------------	Exposure (c) --------------- ---------------     $ (1)      $ - ---------------     $ (1) --------------- ---------------     $ (1)     $ (1) ---------------     $ (2) ---------------

(a) Weighted average interest rate.
(b) 3-month LIBOR rate was 4.07% as of September 30, 2005, and 2.56% as of December 31, 2004.
(c) Exposure indicates change in value due to 25 basis point unfavorable shift in interest rates.

Marketable Securities Price Risk

As of September 30, 2005 and December 31, 2004, the fair value of our nuclear decommissioning trust funds was $1.11 billion and $1.04 billion, respectively, including $628 million and $581 million, respectively, for PEC and $487 million and $463 million, respectively, for PEF. The accounting for nuclear decommissioning recognizes that the Utilities’ regulated electric rates provide for recovery of these costs net of any trust fund earnings, and, therefore, fluctuations in trust fund marketable security returns do not affect earnings.

CVO Market Value Risk

CVOs are recorded at fair value, and unrealized gains and losses from changes in fair value are recognized in earnings. As of September 30, 2005 and December 31, 2004, the fair value of CVOs was $9 million and $13 million, respectively. A hypothetical 10 percent change in the market price would not have had a material effect on our financial position, results of operations or cash flows as of September 30, 2005.

Commodity Price Risk

We are exposed to the effects of market fluctuations in the price of natural gas, coal, fuel oil, electricity and other energy-related products marketed and purchased as a result of our ownership of energy-related assets. Our exposure to these fluctuations is significantly limited by the cost-based regulation of the Utilities. Each state commission allows electric utilities to recover certain of these costs through various cost recovery clauses to the extent the respective commission determines that such costs are prudent. Therefore, while there may be a delay in the timing between when these costs are incurred and when these costs are recovered from the ratepayers, changes from year to year have no material impact on operating results. In addition, many of our long-term power sales contracts shift substantially all fuel responsibility to the purchaser. We also have oil price risk exposure related to synfuel tax credits. See Note 15E of the Combined Notes to Interim Financial Statements.

Derivative products, primarily electricity and natural gas contracts, may be entered into from time to time for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions. We manage open positions with strict policies that limit our exposure to market risk and require daily reporting to management of potential financial exposures. We recorded a pre-tax loss of $7 million and a pre-tax gain of $13 million on such contracts for the three months ended September 30, 2005 and 2004, respectively. We recorded pre-tax losses of $5 and $1 million on such contracts for the nine months ended September 30, 2005 and 2004, respectively. Gains and losses from such contracts at the Utilities were not material to results of operations during the three and nine months ended September 30, 2005. PEC did not have material outstanding positions in such contracts as of September 30, 2005 and December 31, 2004. We and PEF did not have material outstanding positions in such contracts as of September 30, 2005 and December 31, 2004, other than those receiving regulatory accounting treatment at PEF, as discussed below.

PEF has derivative instruments related to its exposure to price fluctuations on fuel oil and natural gas purchases. These instruments receive regulatory accounting treatment. Unrealized gains and losses are recorded in regulatory liabilities and regulatory assets, respectively, until the contracts are settled. Once settled, any realized gains or losses are passed through the fuel clause. As of September 30, 2005, the fair values of these instruments were a $105 million short-term derivative asset position included in other current assets, a $45 million long-term derivative asset position included in other assets and deferred debits and a $2 million short-term derivative liability position included in other current liabilities. As of 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.

We use natural gas and power hedging instruments to manage a portion of the market risk associated with fluctuations in the future purchase and sales prices of natural gas and power. Our subsidiaries designate a portion of commodity derivative instruments as cash flow hedges under SFAS No. 133. As of September 30, 2005, PEC had an immaterial amount of open commodity cash flow hedges. As of December 31, 2004, the Utilities had no open commodity cash flow hedges. The fair values of commodity cash flow hedges as of September 30, 2005 and December 31, 2004 were as follows:

                September 30, 2005
                                                    December 31, 2004
                                  --------------------------

                                  
 (in millions)
----------------------------------
 Fair value of assets
----------------------------------
 Fair value of liabilities
----------------------------------
 Fair value, net   Progress
   Energy
------------
    $ 119
------------
     (100)
------------
    $   19         
  PEC
--------
  $ -
--------
    -
--------
  $ -         
  PEF
--------
  $ -
--------
    -
--------
  $ -   Progress
   Energy
------------
    $ -
------------
     (15)
------------
    $(15)         
   PEC
--------
  $ -
--------
    -
--------
  $ -        
  PEF
-------
  $ -
-------
    -
-------
  $ -

We perform sensitivity analyses to estimate our exposure to the market risk of our commodity positions. Our exposure to commodity price risk has not changed materially since December 31, 2004. A hypothetical 10 percent increase or decrease in quoted market prices in the near term on our derivative commodity instruments would not have had a material effect on our financial position, results of operations or cash flows as of September 30, 2005.

See Note 10 of the Combined Notes to Interim Financial Statements for additional information with regard to our commodity contracts and use of derivative financial instruments.

Progress Energy Carolinas, Inc.

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

PEC has certain market risks inherent in its financial instruments, which arise from transactions entered into in the normal course of business. PEC’s primary exposures are changes in interest rates with respect to long-term debt and commercial paper, fluctuations in the return on marketable securities with respect to its nuclear decommissioning trust funds, and changes in energy related commodity prices. Other than as discussed above, PEC’s exposure to these risks has not materially changed since December 31, 2004.

Progress Energy Florida, Inc.

Other than as discussed above, the information called for by Item 3 is omitted pursuant to Instruction H(2)(c) to Form 10-Q (Omission of Information by Certain Wholly Owned Subsidiaries).

Item 4: Controls and Procedures

Progress Energy

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

There has been no change in our internal control over financial reporting during the quarter ended September 30, 2005, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PEC

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

There has been no change in PEC’s internal control over financial reporting during the quarter ended September 30, 2005, that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

PEF

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

There has been no change in PEF’s internal control over financial reporting during the quarter ended September 30, 2005, that has materially affected, or is reasonably likely to materially affect, PEF’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Legal aspects of certain matters are set forth in Part I, Item 1. For a discussion of certain other legal matters, see Note 15 of the Combined Notes to Interim Financial Statements.

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

c. ISSUER PURCHASES OF EQUITY SECURITIES FOR THIRD QUARTER OF 2005

Period  --------------------------------	(a)                  Total Number   of Shares   (or Units)   Purchased     (1)(2) ---------------	(b)                               Average  Price Paid  Per Share  (or Unit) -------------	(c)                              Total Number of Shares  (or Units) Purchased as     Part of Publicly    Announced Plans or       Programs (1) --------------------------	(d)    Maximum Number (or    Approximate Dollar   Value) of Shares (or  Units) that May Yet Be    Purchased Under the   Plans or Programs (1) --------------------------
July 1 - July 31 -------------------------------- August 1- August 31 -------------------------------- September 1 - September 30 -------------------------------- Total: --------------------------------	- ---------------     32,850 ---------------     38,800 ---------------     71,650 ---------------	- -------------    42.88 -------------    43.63 -------------     43.29 -------------	N/A --------------------------            N/A --------------------------            N/A --------------------------            N/A --------------------------	N/A --------------------------            N/A --------------------------            N/A --------------------------            N/A --------------------------

(1) As of September 30, 2005, Progress Energy does not have any publicly announced plans or programs to purchase shares of its common stock.

(2) All shares were purchased in open-market transactions by the plan administrator to meet share delivery obligations under the Progress Energy 401(k) Savings and
     Stock Ownership Plan.

ITEM 6. Exhibits

(a) Exhibits

Exhibit
Number

 10(a)
      
      
      
      
      
      
      

 10(b)
      
      

 10(c)
      
      

 31(a)
      
      

 31(b)
      
      

 32(a)
      
      

 32(b)
      
                                                           
                    Description

 Agreement and Plan of Merger by and among
 Progress Rail Services Holdings Corp., PRSC
 Acquisition Corp., PMRC Acquisition Co.,
 Progress Rail Services Corporation, Progress
 Metal Reclamation Company, Progress Fuels
 Corporation and Progress Energy, Inc. (with
 respect to Articles III, VI, VIII and IX), dated
 February 17, 2005

 Executive and Key Manager Performance Share
 Sub-Plan, Exhibit A to 2002 Equity Incentive
 Plan (Effective January 1, 2005)

 Broad-Based Performance Share Sub-Plan, Exhibit
 B to 2002 Equity Incentive Plan (Effective
 January 1, 2005)

 Certifications pursuant to Section 302 of the
 Sarbanes-Oxley Act of 2002 - Chairman and Chief
 Executive Officer

 Certifications pursuant to Section 302 of the
 Sarbanes-Oxley Act of 2002 - Executive Vice
 President and Chief Financial Officer

 Certifications pursuant to Section 906 of the
 Sarbanes-Oxley Act of 2002 - Chairman and Chief
 Executive Officer

 Certifications pursuant to Section 906 of the
 Sarbanes-Oxley Act of 2002 - Executive Vice
 President and Chief Financial Officer
  Progress
Energy, Inc.

      X








      X



      X



      X



      X



      X



      X

Progress Energy
Carolinas, Inc.










       X



       X



       X



       X



       X



       X

Progress Energy
 Florida, Inc.










       X



       X



       X



       X



       X



       X

   SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

                                 
                                 
                                 
Date: November 7, 2005


                                 
                                 
                                 
                                 

                                 
                                 
                                 
                                  PROGRESS ENERGY, INC.
CAROLINA POWER & LIGHT COMPANY
FLORIDA POWER CORPORATION
(Registrants)


By: /s/ Geoffrey S. Chatas
Geoffrey S. Chatas
Executive Vice President and
Chief Financial Officer

By: /s/ Jeffrey M. Stone
Jeffrey M. Stone
Controller and Chief Accounting Officer
Controller - Florda Power Corporation